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Exhibit A
Proposed Reliability Standard COM-001-2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard COM-001-2 — Communications
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To establish Interpersonal Communication capabilities necessary to
maintain reliability.
4.
Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal Communication capability with
the following entities (unless the Reliability Coordinator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
1.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communication capability with
the following entities (unless the Transmission Operator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
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Standard COM-001-2 — Communications
3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
5.1.
Its Reliability Coordinator.
5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.3.
Each Distribution Provider within its Balancing Authority Area.
5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
5.5.
Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
1.1.
Its Reliability Coordinator.
1.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
1.3.
Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider detects a failure of its Interpersonal
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]
7.1.
Its Balancing Authority.
7.2.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator detects a failure of its Interpersonal
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Standard COM-001-2 — Communications
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5, respectively within 60
minutes of the detection of a failure of its Interpersonal Communication capability that
lasts 30 minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
R11. Each Distribution Provider and Generator Operator that detects a failure of its
Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communication capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with each adjacent
Reliability Coordinator within the same Interconnection, which could include, but is
not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with each adjacent Reliability Coordinator within the same Interconnection,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R2.)
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Standard COM-001-2 — Communications
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
or synchronously connected, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Transmission Operator and its
Balancing Authority, which could include, but is not limited to:
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Standard COM-001-2 — Communications
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detected a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generator Operator, to
determine mutually agreeable action to restore the Interpersonal Communication
capability. Evidence could include, but is not limited to: dated operator logs, voice
recordings, transcripts of voice recordings, or electronic communications. (R11.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
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Standard COM-001-2 — Communications
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
The Reliability Coordinator for Requirements R1, R2, R9, and R10,
Measures M1, M2, M9, and M10 shall retain written documentation for the
most recent twelve calendar months and voice recordings for the most recent
90 calendar days.
The Transmission Operator for Requirements R3, R4, R9, and R10,
Measures M3, M4, M9, and M10 shall retain written documentation for the
most recent twelve calendar months and voice recordings for the most recent
90 calendar days.
The Balancing Authority forRequirements R5, R6, R9, and R10, Measures
M5, M6, M9, and M10 shall retain written documentation for the most
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
The Distribution Provider for Requirements R7 and R11, Measures M7 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
The Generator Operator for Requirements R8 and R11, Measures M8 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, or Generator Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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2.
R#
R1
R2
R3
R4
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
High VSL
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Transmission
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
N/A
N/A
Severe VSL
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Standard COM-001-2 — Communications
R#
R5
R6
R7
Lower VSL
N/A
N/A
N/A
Moderate VSL
High VSL
Severe VSL
N/A
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
N/A
N/A
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Standard COM-001-2 — Communications
R#
R8
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R11.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 2 hours
and less than or equal to 4 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 4 hours
and less than or equal to 6 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 6 hours
and less than or equal to 8 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to test the Alternative
Interpersonal Communication
capability once each calendar month.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
OR
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 8 hours
upon an unsuccessful test.
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Standard COM-001-2 — Communications
R#
R11
Lower VSL
N/A
Moderate VSL
N/A
High VSL
N/A
Severe VSL
The Distribution Provider or
Generator Operator that detected a
failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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Standard COM-001-2 — Communications
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Standard COM-001-2 — Communications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
November 7, 2012
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Replaced R1
with R1-R8; R2
replaced by R9; R3
included within new
R1; R4 remains enforce
pending Project 200702; R5 redundant with
EOP-008-0, retiring R5
as redundant with
EOP-008-0, R1;
retiring R6, relates to
ERO procedures; R10
& R11, new.
1.1
2
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
TelecommunicationsCommunications
2.
Number:
COM-001-1.12
3.
Purpose: Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating informationTo establish Interpersonal
Communication capabilities necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.Operator
4.2. Balancing Authorities.Authority
4.3. Reliability Coordinators.Coordinator
4.4. NERCNet User Organizations.
5.
Effective Date:
May 13, 2009
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1. Between shall have Interpersonal Communication capability with the following entities
(unless the Reliability Coordinator and itsdetects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
R1.2.
All Transmission Operators and Balancing Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
1.1.
Each within its Reliability Coordinator, Transmission Operator, and Balancing
Authority shall manage, alarm, test and/or actively monitor vital telecommunications
facilities. Special attention shall be given to emergency telecommunications facilities
and equipment not used for routine communications Area.
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Standard COM-001-2 — Communications
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
1.2.
Unless agreed to otherwise, each Each adjacent Reliability Coordinator within the
same Interconnection.
R2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use
English as the language for all communications between and among operating personnel
responsible for the real shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time generation control and operation of the interconnected Bulk Electric System.
Operations]
R3. 2.1.
All Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
Eachwithin its Reliability Coordinator, Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communication capability with
the following entities (unless the Transmission Operator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator, and synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
5.1.
Its Reliability Coordinator.
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Standard COM-001-2 — Communications
5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.1.5.3. Each Distribution Provider within its Balancing Authority shall have written
operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilitiesArea.
5.4.
Each NERCNet User OrganizationGenerator Operator that operates Facilities
within its Balancing Authority Area.
5.5.
Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall adhere to designate an Alternative Interpersonal
Communication capability with the requirementsfollowing entities: [Violation Risk
Factor: High] [Time Horizon: Real-time Operations]
1.1.
Its Reliability Coordinator.
1.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
1.3.
Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider detects a failure of its Interpersonal
Communication capability in Attachment which case Requirement R11 shall apply):
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
7.1-COM-001, “NERCNet Security Policy.”. Its Balancing Authority.
7.2.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator detects a failure of its Interpersonal
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5, respectively within 60
minutes of the detection of a failure of its Interpersonal Communication capability that
lasts 30 minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
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R11. Each Distribution Provider and Generator Operator that detects a failure of its
Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have
and provide upon request evidence that it has Interpersonal Communication capability
with all Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area and with each adjacent Reliability Coordinator within the same
Interconnection, which could include, but is not limited to communication facility testprocedure documents, records of testing, and maintenance records for communication
facilities:
physical assets, or equivalent that will be used to confirm that it manages, alarms, tests
and/or actively monitors vital telecommunications facilities. (Requirement 2 part 1)
The Reliability Coordinator, Transmission Operator or Balancing Authority shall have
and provide upon requestdated evidence that could include, but is not limited to, such
as, equipment specifications and installation documentation, test records, operator
logs, voice recordings or, transcripts of voice recordings, or electronic
communications, or equivalent, that will be used to determine compliance to
Requirement 4.. (R1.)
M1.M2.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
have and provide upon request its current operating instructions and procedures, either
electronic or hard copy that will be used to confirm that it meets Requirement 5. shall have
and provide upon request evidence that it designated an Alternative Interpersonal
Communication capability with all Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area and with each adjacent Reliability Coordinator
within the same Interconnection, which could include, but is not limited to:
The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to documented proceduresphysical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings or, transcripts of voice recordings, or
electronic communications. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
or synchronously connected, which could include, but is not limited to:
physical assets, or
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dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings,
electronic communications, etcor electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that will be
usedit has Interpersonal Communication capability with its Transmission Operator and
its Balancing Authority, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
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M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to determine if it adhered:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M2.M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to the (User Accountability and
Compliance) requirements in Attachment 1-COM-001. (Requirement 6)repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detected a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generator Operator, to
determine mutually agreeable action to restore the Interpersonal Communication
capability. Evidence could include, but is not limited to: dated operator logs, voice
recordings, transcripts of voice recordings, or electronic communications. (R11.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
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1.2. Compliance Monitoring and Reset Time FrameEnforcement Processes
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
For Measure 1 eachThe Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider, and Generator Operator shall keep data or
evidence ofto show compliance for the previous two calendar years plus the current
year. as identified below unless directed by its Compliance Enforcement Authority
to retain specific evidence for a longer period of time as part of an investigation:
For Measure 2 eachThe Reliability Coordinator, Transmission Operator for
Requirements R1, R2, R9, and Balancing AuthorityR10, Measures M1, M2,
M9, and M10 shall keepretain written documentation for the most recent
twelve calendar months and voice recordings for the most recent 90 calendar
days of historical data (evidence)..
For Measure 3, each Reliability Coordinator,The Transmission Operator, for
Requirements R3, R4, R9, and R10, Measures M3, M4, M9, and M10 shall
retain written documentation for the most recent twelve calendar months
and voice recordings for the most recent 90 calendar days.
The Balancing Authority shall have its current operating instructions and
procedures to confirm that it meets Requirement 5. forRequirements R5, R6, R9,
and R10, Measures M5, M6, M9, and M10 shall retain written
documentation for the most recent twelve calendar months and voice
recordings for the most recent 90 calendar days.
For Measure 4, eachThe Distribution Provider for Requirements R7 and R11,
Measures M7 and M11 shall retain written documentation for the most
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Standard COM-001-2 — Communications
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
The Generator Operator for Requirements R8 and R11, Measures M8 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority and
NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity, Distribution Provider, or Generator Operator is found non-compliant
the entity, it shall keep information related to the noncompliance non-compliance
until found compliantmitigation is complete and approved or for two years plus the
current yeartime specified above, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance MonitorEnforcement Authority shall keep the last periodic audit
reportrecords and all requested and submitted subsequent complianceaudit records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.2
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities as
specified in R5.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
None.
Page 8 of 15
2.
R#
R1
R2
R3
R4
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
High VSL
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Transmission
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
N/A
N/A
Severe VSL
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Standard COM-001-2 — Communications
R#
R5
R6
R7
Lower VSL
N/A
N/A
N/A
Moderate VSL
High VSL
Severe VSL
N/A
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
N/A
N/A
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R#
R8
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R11.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 2 hours
and less than or equal to 4 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 4 hours
and less than or equal to 6 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 6 hours
and less than or equal to 8 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to test the Alternative
Interpersonal Communication
capability once each calendar month.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
OR
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 8 hours
upon an unsuccessful test.
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Standard COM-001-2 — Communications
R#
R11
Lower VSL
N/A
Moderate VSL
N/A
High VSL
N/A
Severe VSL
The Distribution Provider or
Generator Operator that detected a
failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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Standard COM-001-2 — Communications
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Standard COM-001-1.1 — Telecommunications
E. Regional Differences
None Identifiedidentified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
November 7, 2012
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Replaced R1
with R1-R8; R2
replaced by R9; R3
included within new
R1; R4 remains enforce
pending Project 200702; R5 redundant with
EOP-008-0, retiring R5
as redundant with
EOP-008-0, R1;
retiring R6, relates to
ERO procedures; R10
& R11, new.
1.1
2
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Standard COM-001-1.1 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
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Standard COM-001-1.1 — Telecommunications
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation
or reporting requirement of any law enforcement or government body.
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Exhibit B
Proposed Reliability Standard COM-002-4
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COM-002-4 – Operating Personnel Communications Protocols
A. Introduction
1. Title: Operating Personnel Communications Protocols
2. Number:
COM-002-4
3. Purpose:
To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4. Applicability:
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
Effective Date: The standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is
twelve (12) months after the date the standard is adopted by the NERC Board of
Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop documented communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a minimum: [Violation
Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver.
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COM-002-4 – Operating Personnel Communications Protocols
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
conduct initial training for each of its operating personnel responsible for the Realtime operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual
operator issuing an Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall conduct initial training for
each of its operating personnel who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator receiving an oral two-party,
person-to-person Operating Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
at least once every twelve (12) calendar months: [Violation Risk Factor:
Medium][Time Horizon: Operations Planning]
4.1. Assess adherence to the documented communications protocols in Requirement
R1 by its operating personnel that issue and receive Operating Instructions,
provide feedback to those operating personnel and take corrective action, as
deemed appropriate by the entity, to address deviations from the documented
protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
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COM-002-4 – Operating Personnel Communications Protocols
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues an oral two-party, person-to-person Operating Instruction during an
Emergency, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
•
Confirm the receiver’s response if the repeated information is correct (in
accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R7. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction. [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its initial training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its initial training
records for its operating personnel such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence of its assessments, including spreadsheets, logs or other evidence of
feedback, findings of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in fulfillment of
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COM-002-4 – Operating Personnel Communications Protocols
Requirement R4. The entity shall provide, as part of its assessment, evidence of any
corrective actions taken where an operating personnel’s non-adherence to the protocols
developed in Requirement R1 is the sole or partial cause of an Emergency and for all
other instances where the entity determined that it was appropriate to take a corrective
action to address deviations from the documented protocols developed in Requirement
R1.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issued an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from the recipient of the
Operating Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence could include, but is not limited to, dated and timestamped voice recordings, or dated and time-stamped transcripts of voice recordings, or
dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings (if the entity has such
recordings), dated operator logs, an attestation from the issuer of the Operating
Instruction, memos or transcripts.
M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator that
issued a written or oral single or multiple-party burst Operating Instruction during an
Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings (if the entity has such recordings), dated operator logs,
electronic records, memos or transcripts.
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
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COM-002-4 – Operating Personnel Communications Protocols
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Page 5 of 12
COM-002-4 – Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity
did not specify the
instances that require
time identification
when issuing an oral
or written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.5
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.1. An alternate
language may be used for
internal operations.
The responsible entity did
not include Requirement
R1, Part 1.4 in its
documented
communication protocols.
Severe VSL
The responsible entity did not
include Requirement R1, Part
1.2 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
OR
The responsible entity
did not specify the
nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.6.
Page 6 of 12
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R2
Long-term
Planning
Low
N/A
N/A
An individual operator
responsible for the Realtime operation of the
interconnected Bulk
Electric System at the
responsible entity issued
an Operating Instruction,
prior to being trained on
the documented
communications protocols
developed in Requirement
R1.
An individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity issued an
Operating Instruction during an
Emergency prior to being trained
on the documented
communications protocols
developed in Requirement R1.
R3
Long-term
Planning
Low
N/A
N/A
An individual operator at
the responsible entity
received an Operating
Instruction prior to being
trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
Page 7 of 12
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Operations
Planning
Medium
The responsible entity
assessed adherence to
the documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible entity
assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive Operating
Instructions and
modified its
documented
communication
Moderate VSL
High VSL
Severe VSL
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions, but
did not provide feedback
to those operating
personnel
The responsible entity did
not assess adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating
Instructions
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions and
provided feedback to those
operating personnel but
did not take corrective
action, as appropriate
OR
The responsible entity did
not assess the
effectiveness of its
documented
communications protocols
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
Page 8 of 12
AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for
its operating personnel that issue
and receive Operating
Instructions.
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
protocols, as
necessary
AND
The responsible entity
exceeded twelve (12)
calendar months
between assessments.
Moderate VSL
High VSL
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions, but
did not modify its
documented
communication protocols,
as necessary.
Page 9 of 12
Severe VSL
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R5
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity that
issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
High VSL
N/A
Confirmed the
receiver’s response if
the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating Instruction
if the repeated
information was
incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or if
the Operating
Instruction was not
understood by the
receiver.
Severe VSL
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the Operating
Instruction was not
understood by the receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Page 10 of 12
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R6
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request that
the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
High VSL
N/A
Severe VSL
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or oral
single-party to multipleparty burst Operating
Instruction during an
Emergency did not
confirm or verify that the
Operating Instruction was
received by at least one
receiver of the Operating
Instruction.
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
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COM-002-4 – Operating Personnel Communications Protocols
E. Regional Variances
None
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
4
May 6, 2014
Adopted by Board of Trustees
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COM-002-4 – Operating Personnel Communications Protocols
A. Introduction
1.
Title:
Communication and Coordination
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To ensure Balancing Authorities, Transmission Operators, and Generator
Operators have adequate communications and that these communications capabilities
are staffed and available for addressing a real-time emergency condition. To ensure
communications by operating personnel are effective.
3.
Purpose: To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4.
Applicability:
COM-002-24
4.1. Functional Entities
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.4.1.3 Reliability Coordinators.Coordinator
4.2. Balancing Authorities.
4.3.4.1.4 Transmission Operators.Operator
4.4.4.1.5 Generator Operators.Operator
5.
Effective Date:
January 1, 2007
5.
Effective Date: The standard shall become effective on the first day of the first
calendar quarter that is twelve (12) months after the date that the standard is approved
by an applicable governmental authority or as otherwise provided for in a jurisdiction
where approval by an applicable governmental authority is required for a standard to
go into effect. Where approval by an applicable governmental authority is not required,
the standard shall become effective on the first day of the first calendar quarter that is
twelve (12) months after the date the standard is adopted by the NERC Board of
Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Transmission Operator, Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented communications protocols for its
operating personnel that issue and receive Operating Instructions. The protocols
shall, at a minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
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COM-002-4 – Operating Personnel Communications Protocols
1.1. Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver.
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
conduct initial training for each of its operating personnel responsible for the Realtime operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual
operator issuing an Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall have communications
(voice and data links) with conduct initial training for each of its operating personnel
who can receive an oral two-party, person-to-person Operating Instruction prior to
that individual operator receiving an oral two-party, person-to-person Operating
Instruction to either: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
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COM-002-4 – Operating Personnel Communications Protocols
R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
at least once every twelve (12) calendar months: [Violation Risk Factor:
Medium][Time Horizon: Operations Planning]
R1.4.1. Assess adherence to the documented communications protocols in
Requirement R1 by its operating personnel that issue and receive Operating
Instructions, provide feedback to those operating personnel and take corrective
action, as deemed appropriate Reliability Coordinators, Balancing Authorities,
and Transmission Operators. Such communications shall be staffed and
available for addressing a real-time emergency condition.by the entity, to
address deviations from the documented protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
R5. Each Balancing Authority and Transmission Operator shall notify its , Reliability
Coordinator, and all other potentially affected Balancing Authorities and
Transmission Operators through predetermined communication paths of any
condition that could threaten the reliability of its area or when firm load shedding
Transmission Operator that issues an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
5.1.• Confirm the receiver’s response if the repeated information is anticipated.
correct (in accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R2.R7. Each Balancing Authority, Reliability Coordinator, and Transmission Operator,
and Balancing Authority shall issue directives in a clear, concise, and definitive
manner; that issues a written or oral single-party to multiple-party burst Operating
Instruction during an Emergency shall ensure the recipient of the directive repeats the
information back correctly; and shall acknowledge the response as correct or repeat
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COM-002-4 – Operating Personnel Communications Protocols
the original statement to resolve any misunderstandings.confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction. [Violation Risk Factor: High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Transmission Operator, Balancing Authority and Generator Operator shall have
communication facilities (voice and data links) with appropriate Reliability Coordinators,
Balancing Authorities, and Transmission Operators and shall have and provide as
evidence, a list of communication facilities or other equivalent evidence that confirms that
the communications have been provided to address a real-time emergency condition.
(Requirement 1, part 1)
M1. TheEach Balancing Authority, Reliability Coordinator, and Transmission Operator
shall have and provide upon requestits documented communications protocols
developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its initial training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its initial training
records for its operating personnel such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence of its assessments, including spreadsheets, logs or other evidence of
feedback, findings of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in fulfillment of
Requirement R4. The entity shall provide, as part of its assessment, evidence of any
corrective actions taken where an operating personnel’s non-adherence to the protocols
developed in Requirement R1 is the sole or partial cause of an Emergency and for all
other instances where the entity determined that it was appropriate to take a corrective
action to address deviations from the documented protocols developed in Requirement
R1.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issued an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from the recipient of the
Operating Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence could include, but is not limited to, operator logs,dated
and time-stamped voice recordings, or dated and time-stamped transcripts of voice
recordings, or dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
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COM-002-4 – Operating Personnel Communications Protocols
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings (if the entity has such
recordings), dated operator logs, an attestation from the issuer of the Operating
Instruction, memos or transcripts.
M2.M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator
that issued a written or oral single or multiple-party burst Operating Instruction during
an Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings (if the entity has such recordings), dated operator logs,
electronic communications, or other equivalent evidence that will be used to determine
if it notified its Reliability Coordinator, and all other potentially affected Balancing
Authorities and Transmission Operators of a condition that could threaten the
reliability of its area or when firm load shedding was anticipated. (Requirement
1.1)records, memos or transcripts.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
Regional Reliability Organizations shall be responsible for compliance
monitoring.
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
- Spot Check Audits (Conducted anytime with up to 30 days notice given to
prepare.)
- Periodic Audit (Conducted once every three years according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 days to prepare for the investigation. An entity may request an
extension of the preparation period and the extension will be considered by
the Compliance Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
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COM-002-4 – Operating Personnel Communications Protocols
1.3.1.2.
Data Retention
Each Balancing Authority, Transmission Operator and Generator Operator shall keep
evidence of compliance for the previous two calendar years plus the current year.
(Measure 1)
EachThe following evidence retention periods identify the period of time an entity
is required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority and , Distribution Provider, Generator Operator,
Reliability Coordinator, or Transmission Operator shall keep 90 days of historical
data. (Measure 2).
If an entity is found non-compliant the entity, it shall keep information related to
the noncompliance non-compliance until found compliantmitigation is complete
and approved or for two years plus the current yeartime period specified above,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor.
The Compliance MonitorEnforcement Authority shall keep the last periodic audit
reportrecords and all requested and submitted subsequent complianceaudit
records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.4.1.3.
Additional Compliance Information
None.
Page 6 of
17
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COM-002-4 – Operating Personnel Communications Protocols
2.
Levels of Non-Compliance for Transmission Operator and Balancing Authority:
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: Not applicable.
2.4. Level 4: Communication did not occur as specified in R1.1.
3.
Levels of Non-Compliance for Generator Operator:
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Communication facilities are not provided to address a real-time
emergency condition as specified in R1.
Page 7 of
17
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible
entity did not specify
the instances that
require time
identification when
issuing an oral or
written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.5
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.1. An alternate
language may be used for
internal operations.
The responsible entity did
not include Requirement
R1, Part 1.4 in its
documented
communication protocols.
Page 8 of 3
OR
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
The responsible
entity did not specify
the nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.6.
Effective Date: January 1, 200712
The responsible entity did not
include Requirement R1, Part
1.2 in its documented
communications protocols
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
Adopted by Board of Trustees: November 1, 2006
Severe VSL
Page
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Adopted by Board of Trustees: November 1, 2006
Page 9 of 3
Effective Date: January 1, 200712
Moderate VSL
High VSL
Page
Severe VSL
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
R2
Long-term
Planning
Low
N/A
N/A
An individual operator
responsible for the Realtime operation of the
interconnected Bulk
Electric System at the
responsible entity issued
an Operating Instruction,
prior to being trained on
the documented
communications protocols
developed in Requirement
R1.
An individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity issued an
Operating Instruction during an
Emergency prior to being
trained on the documented
communications protocols
developed in Requirement R1.
R3
Long-term
Planning
Low
N/A
N/A
An individual operator at
the responsible entity
received an Operating
Instruction prior to being
trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Adopted by Board of Trustees: November 1, 2006
Page 10 of 3
Effective Date: January 1, 200712
Moderate VSL
High VSL
Page
Severe VSL
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
R4
Operations
Medium
Planning
The responsible
entity assessed
adherence to the
documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive
Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible
entity assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive
Operating
Instructions and
modified its
Adopted by Board of Trustees: November 1, 2006
Page 11 of 3
Effective Date: January 1, 200712
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions,
but did not provide
feedback to those
operating personnel
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
and provided feedback to
those operating personnel
but did not take corrective
action, as appropriate
The responsible entity did
not assess adherence to
the documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
OR
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1
by its operating personnel that
issue and receive Operating
Instructions
AND
The responsible entity did not
The responsible entity did assess the effectiveness of its
not assess the
documented communications
effectiveness of its
protocols in Requirement R1 for
documented
its operating personnel that
communications protocols issue and receive Operating
in Requirement R1 for its Instructions.
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
Page
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
documented
communication
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Adopted by Board of Trustees: November 1, 2006
Page 12 of 3
Effective Date: January 1, 200712
Moderate VSL
High VSL
Page
Severe VSL
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
protocols, as
necessary
AND
The responsible
entity exceeded
twelve (12) calendar
months between
assessments.
R#
VRF
Violation Severity Levels
Adopted by Board of Trustees: November 1, 2006
Page 13 of 3
Effective Date: January 1, 200712
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions,
but did not modify its
documented
communication protocols,
as necessary.
Page
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
Time
Horizon
R5
Real-time
Operations
Lower VSL
High
N/A
Moderate VSL
The responsible entity that N/A
issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
Adopted by Board of Trustees: November 1, 2006
Page 14 of 3
Effective Date: January 1, 200712
High VSL
Severe VSL
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
Confirmed the
receiver’s response
if the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating
Instruction if the
repeated information
was incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or
if the Operating
Instruction was not
understood by the
receiver.
•
Confirmed the receiver’s
response if the repeated
information was correct
(in accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the
Operating Instruction was
not understood by the
receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Page
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R6
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request
that the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
High VSL
N/A
Severe VSL
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer
that the response was correct, or
request that the issuer reissue
the Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or
oral single-party to
multiple-party burst
Operating Instruction
during an Emergency did
not confirm or verify that
Adopted by Board of Trustees: November 1, 2006
Page 15 of 3
Effective Date: January 1, 200712
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
Page
Standard COM-002-2 —4 – Operating Personnel Communications and CoordinationProtocols
the Operating Instruction
was received by at least
one receiver of the
Operating Instruction.
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Adopted by Board of Trustees: November 1, 2006
Page 16 of 3
Effective Date: January 1, 200712
Page
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard COM-002-2 —4 – Operating Personnel Communications and
CoordinationProtocols
E. Regional DifferencesVariances
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
RevisedAdded
November 1,
2006
Adopted by Board of Trustees
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
3
November 7,
2012
Adopted by Board of Trustees
4
May 6, 2014
Adopted by Board of Trustees
2
measures and
compliance elements
accordance with SAR
for Project 2006-06,
Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
Adopted by Board of Trustees: November 1,
2006
Project 2009-22
Page
Page 17 of 3
Effective Date: January 1, 200712
RevisedRevised in
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit C
Implementation Plan and Mapping Document COM-001-2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan and Mapping Document
COM-001-2 Communications
Requested Approval
COM-001-2 – Communications
Definition: Interpersonal Communication
Definition: Alternative Interpersonal Communication
Requested Retirement
COM-001-1.1 – Telecommunications, except Requirement R4
Requirement R4 is being revised for inclusion in Standard COM-002-4, Operating Personnel
Communications Protocols and will be requested for retirement upon the effective date
COM-002-4.
Prerequisite Approvals
None.
Defined Terms in the NERC Glossary
The RCSDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication
used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
The RCSDT proposes retiring COM-001-1.1 Requirement R5 as it is redundant with EOP-008-0,
Requirement R1 as well as EOP-008-1 Requirement R1.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1.1 standard proposes retiring four Requirements (R1, R4, R5, and R6).
The COM-001-1.1 standard, Requirement R1 is proposed for replacement with COM-001-2,
Requirements R1, R2, R3, R4, R5, R6, R7, and R8 to achieve clarity to which entities are required to have
to reliable communications. Requirement R2 in COM-001-1.1 will become Requirement R9 in COM001-2. Requirement R3 in COM-001-1.1 is included within Requirement R1 of COM-001-2.
Requirement R4 will remain effective until its inclusion in COM-002-4 that is currently under
development in Project 2007-02 – Operating Personnel Communication Protocols. Requirement R5 in
COM-001-1.1 is redundant with EOP-008-0, Requirement R1 and EOP-008-1, Requirement R1 and is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
proposed for retirement upon the effective date of COM-001-2. The COM-001-1.1 standard,
Requirement R6 is proposed for retirement as it is an ERO procedural requirement and does not impact
reliability. Requirements R10 and R11 are new requirements. Changes were made to eliminate
redundancies between standards (existing and proposed), to align with the ERO Rules of Procedure and
to address known issues and certain directives in FERC Order 693.
Applicable Entities
•
Reliability Coordinator
•
Balancing Authority
•
Transmission Operator
•
Generator Operator
•
Distribution Provider
Effective Date
New or Revised Standards
COM-001-2
The first day of the second calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day
of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard
COM-002-4 currently under development.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
New or Revised Definitions
Interpersonal Communication – The first day of the second calendar quarter beyond the date that this
standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective on the first day of the first calendar quarter
beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Alternative Interpersonal Communication – The first day of the second calendar quarter beyond the
date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day of the first calendar
quarter beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
3
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard becomes effective. If the
drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R1. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1. Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1. Internally. [Violation Risk Factor: High]
R1.2. Between the Reliability Coordinator and its Transmission
Operators and Balancing Authorities. [Violation Risk
Factor: High]
R1.3. With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary to
maintain reliability. [Violation Risk Factor: High]
R1.4. Where applicable, these facilities shall be redundant and
diversely routed. [Violation Risk Factor: High]
R1.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R2.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R2.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R3. Each Transmission Operator shall have Interpersonal
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
4
Already Approved Standard
Proposed Replacement Requirement(s)
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R3.1. Its Reliability Coordinator.
R3.2. Each Balancing Authority within its Transmission Operator
Area.
R3.3. Each Distribution Provider within its Transmission Operator
Area.
R3.4. Each Generator Operator within its Transmission Operator
Area.
R3.5. Each adjacent Transmission Operator synchronously
connected.
R3.6. Each adjacent Transmission Operator asynchronously
connected.
R4. Each Transmission Operator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.1. Its Reliability Coordinator.
R4.2. Each Balancing Authority within its Transmission Operator
Area.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
5
Already Approved Standard
Proposed Replacement Requirement(s)
R4.3. Each adjacent Transmission Operator synchronously
connected.
R4.4. Each adjacent Transmission Operator asynchronously
connected.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable communications.
COM-001-1.1
COM-001-2
R1.
R5. Each Balancing Authority shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R5.1. Its Reliability Coordinator.
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing Authorities.
[Violation Risk Factor: High]
R5.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R1.3.
R1.4.
With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary
to maintain reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation Risk
Factor: High]
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
R5.3. Each Distribution Provider within its Balancing Authority
Area.
R5.4. Each Generator Operator that operates Facilities within its
Balancing Authority Area.
R5.5. Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
6
Already Approved Standard
Proposed Replacement Requirement(s)
Operations]
R6.1. Its Reliability Coordinator.
R6.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R6.3. Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R7.1. Its Transmission Operator.
R7.2. Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1. Its Balancing Authority.
R8.2. Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable interpersonal
communications. Requirements R7 and R8 were created to address the FERC directive (Order No. 693, P508) to “(1) expand the applicability to
include generator operators and distribution providers and includes Requirements for their telecommunications facilities;”
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
7
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation Risk
Factor: Medium]
R9. Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall test its Alternative Interpersonal Communication
capability at least once each calendar month. If the test is
unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication
capability within 2 hours. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
Notes:
COM-001-1.1
COM-001-2
R3. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide a means to coordinate
telecommunications among their respective areas. This
coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas. [Violation Risk Factor: Lower]
R1. Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R1.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
Notes:
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
None - retire
This requirement is being vetted by the OPCPSDT in Project
8
Already Approved Standard
English as the language for all communications between and
among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
2007-02 – Operating Personnel Communication Protocols
(COM-002-4). This requirement and measure will be
removed from COM-001-1.1 upon the effective date of
COM-002-4.
Notes:
COM-001-1.1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall have a plan to continue reliability operations in the
event its control center becomes inoperable. The contingency plan
must meet the following requirements:
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions
and procedures to enable continued operation of the system
during the loss of telecommunications facilities. [Violation Risk
Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be
viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that
there is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control
of critical transmission facilities, generation control, voltage
control, time and frequency control, control of critical
substation devices, and logging of significant power system
events. The plan shall list the critical facilities.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
9
Already Approved Standard
Proposed Replacement Requirement(s)
R1.4. The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with
other areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure
viability of the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating personnel
are able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take
more than one hour to implement the contingency plan for
loss of primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and Transmission
Operator shall have a current Operating Plan describing the
manner in which it continues to meet its functional obligations
with regard to the reliable operations of the BES in the event that
its primary control center functionality is lost. This Operating Plan
for backup functionality shall include the following, at a minimum:
[Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
1.1.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
The location and method of implementation for providing
backup functionality for the time it takes to restore the
10
Already Approved Standard
Proposed Replacement Requirement(s)
primary control center functionality.
1.2.
A summary description of the elements required to support
the backup functionality. These elements shall include, at a
minimum:
1.2.1. Tools and applications to ensure that System
Operators have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
1.3.
An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4.
Operating Procedures, including decision authority, for use
in determining when to implement the Operating Plan for
backup functionality.
1.5.
A transition period between the loss of primary control
center functionality and the time to fully implement the
backup functionality that is less than or equal to two hours.
1.6.
An Operating Process describing the actions to be taken
during the transition period between the loss of primary
control center functionality and the time to fully implement
backup functionality elements identified in Requirement R1,
Part 1.2. The Operating Process shall include at a minimum:
11
Already Approved Standard
Proposed Replacement Requirement(s)
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the
transition from primary to backup functionality as
well as during outages of the primary or backup
functionality.
1.6.3. Identification of the roles for personnel involved
during the initiation and implementation of the
Operating Plan for backup functionality.
Notes: The RCSDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0, Requirement R1 as well as EOP-008-1
Requirement R1.
COM-001-1.1
R6. Each NERCNet User Organization shall adhere to the
requirements in Attachment 1-COM-001, “NERCNet Security
Policy.” [Violation Risk Factor: Lower]
None – retire
Notes: The RCSDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should be
included in the ERO Rules of Procedure.
None
New Requirement
R10. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall notify entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of
the detection of a failure of its Interpersonal Communication
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
12
Already Approved Standard
Proposed Replacement Requirement(s)
capability that lasts 30 minutes or longer. [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations]
None
New Requirement
R11.Each Distribution Provider and Generator Operator that detects a
failure of its Interpersonal Communication capabilities shall
consult with their Transmission Operator or Balancing Authority to
determine a mutually agreeable action to restore the
Interpersonal Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Communications
Reliability
Coordinator
Balancing
Authority
X
X
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit D
Implementation Plan COM-002-4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
• COM-002-4 – Operating Personnel Communications Protocols
Retirements:
• COM-001-1.1 Requirement R4 – Telecommunications
• COM-002-2 – Communication and Coordination
• COM-002-3 – Communication and Coordination
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real-time operation of the interconnected Bulk
Electric System to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A discussion of general information and of
potential options or alternatives to resolve Bulk Electric System operating concerns is not a command
and is not considered an Operating Instruction.)
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
None
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Effective Date
COM-002-4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM-001-1.1 Requirement R4, COM-002-2, and COM-002-3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM-002-4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit E
Mapping Document COM-002-4
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
COM-001-1.1 to COM-002-4
Board Approved Standard
COM-001-1.1
R4.Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use English
as the language for all communications between and among
operating personnel responsible for the real-time generation
control and operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
Proposed Replacement Requirement(s)
COM-002-4
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented
communications protocols. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Longterm Planning]
1.1. Require the issuer and receiver of an oral or written
Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may
be used for internal operations
Notes: Moved COM-001-1 R4 into COM-002-4 Requirement R1 Part 1.1 and modified language to include the defined term “Operating
Instruction.”
COM-002-2 to COM-002-3
Board Approved Standard
COM-002-2
R1. Each Transmission Operator, Balancing Authority, and
Generator Operator shall have communications (voice and data
links) with appropriate Reliability Coordinators, Balancing
Authorities, and Transmission Operators. Such communications
shall be staffed and available for addressing a real-time emergency
condition. [Violation Risk Factor: High]
Proposed Replacement Requirement(s)
The Project 2006-06 SDT proposed retiring COM-002-2, R1 and
R1.1 during the development of proposed standard COM-002-3.
The following rationale was provided by that drafting team in
the Implementation Plan for Draft 6 of Project 2006-06. The
same rationale continues to apply for the current version of
COM-002-4:
“The communications requirements of R1 are addressed in
existing COM-001-1.1 as well as the proposed COM-001-2
requirements. Additionally, IRO-010-1a addresses data
R1.1 Each Balancing Authority and Transmission Operator shall
notify its Reliability Coordinator, and all other potentially affected provisions.
Balancing Authorities and Transmission Operators through
The Project 2006-06 SDT contends that COM-002-2, R1.1 is a low
predetermined communication paths of any condition that could level facilitating requirement that is more appropriately and
threaten the reliability of its area or when firm load shedding is
inherently monitored under various higher level performanceanticipated. [Violation Risk Factor: High]
based reliability requirements for each entity throughout the
body of standards. Examples include:
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
•
EOP-002-1, R3 – outlines BA to RC communications.IRO001-1, R3 requires adequate telecommunication for the
Reliability Coordinator to direct actions of multiple
entities, including TOPs and BAs.
•
TOP-001-1, R3 requires adequate telecommunications
facilities for the TOP, BA, and GOP to be able to receive
directives from the RC.
•
TOP-001-1, R5 requires communications between TOPs
and RCs for emergency situations.
2
Board Approved Standard
Proposed Replacement Requirement(s)
•
TOP-005-1, R1 and R3 require adequate
telecommunications for BAs and TOPs to provide each
other with operating data as well as providing data to the
RC.
•
TOP-006-1, R1 requires adequate telecommunications for
the GOP to inform the BA and TOP of resources. The BA
and TOP will then inform the RC, other TOP and BAs of all
transmission and generation available for use.
•
PER-001-1, R1 and PER-004-1, R1 set forth the staffing
requirements.”
Notes: None. The rationale provided above is available at the following hyperlink: Project 2006-06 Draft 6 Implementation Plan
COM-002-2
COM-002-3
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and
definitive manner; shall ensure the recipient of the directive
repeats the information back correctly; and shall acknowledge the
response as correct or repeat the original statement to resolve any
misunderstandings. [Violation Risk Factor: Medium]
The Project 2006-06 expanded COM-002-2 R2 into three
requirements in COM-002-3:
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time
Horizon: Real-Time]
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
3
Board Approved Standard
Proposed Replacement Requirement(s)
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
•
Reissue the Reliability Directive to resolve any
misunderstandings.
Notes: The Project 2006-06 expanded the list of responsible entities to include the DP and GOP and subdivided the requirement to
improve clarity.
COM-002-3 to COM-002-4
Board Approved Standard
Proposed Replacement Requirement(s)
COM-002-3
COM-002-4
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
Horizon: Real-Time]
None
Notes: The Project 2007-02 SDT removed the term “Reliability Directive” in order to avoid complications that may result from the
Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission on November 21, 2014 proposing to remand the
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
4
Board Approved Standard
Proposed Replacement Requirement(s)
definition of “Reliability Directive”. COM-002-4 uses the defined term Operating Instruction to define the circumstances when
documented communications protocols must be used, and uses the phrase “Operating Instruction during an Emergency” to designate
Operating Instructions that would have qualified as Reliability Directives. The Project 2007-02 SDT coordinated with the Project 2009-02
Real time Operations team and Project 2006-06 SDT and all parties agreed that requirement for an issuer to identity a command as a
Reliability Directive is not a communication protocol, and will be considered by each team for future modifications.
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time Horizon:
Real-Time]
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented
communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
1.1
Require its operating personnel that issue and receive an
oral or written Operating Instruction to use the English
language, unless agreed to otherwise. An alternate
language may be used for internal operations.
1.2.
Require the issuer of an oral two-party, person-to-person
Operating Instruction to wait for a response from the
receiver. Once a response is received, or if no response is
received, require the issuer to take one of the following
actions:
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
Reissue the Reliability Directive to resolve any misunderstandings.
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
•
Confirm the receiver’s response if the repeated
information is correct.
•
Reissue the Operating Instruction if the repeated
information is incorrect or if requested by the receiver.
5
Board Approved Standard
Proposed Replacement Requirement(s)
•
1.3
Take an alternative action if a response is not received or
if the Operating Instruction was not understood by the
receiver.
Require its operating personnel that receive an oral two
party, person-to-person Operating Instruction to take
one of the following actions:
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the
issuer that the response was correct.
•
Request that the issuer reissue the Operating
Instruction.
1.4
Require its operating personnel that issue a written or
oral single-party to multiple-party burst Operating
Instruction to confirm or verify that the Operating
Instruction was received by at least one receiver of the
Operating Instruction.
1.5
Specify the instances that require time identification
when issuing an oral or written Operating Instruction and
the format for that time identification.
1.6
Specify the nomenclature for Transmission interface
Elements and Transmission interface Facilities when
issuing an oral or written Operating Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall conduct initial training for each
of its operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System on the
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
6
Board Approved Standard
Proposed Replacement Requirement(s)
documented communications protocols developed in
Requirement R1 prior to that individual operator issuing an
Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall
conduct initial training for each of its operating personnel
who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator
receiving an oral two-party, person-to-person Operating
Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R4.
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the issuer that
the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall at least once every twelve (12)
calendar months: [Violation Risk Factor: Medium][Time
Horizon: Operations Planning]
4.1. Assess adherence to the documented
communications protocols in Requirement R1 by
its operating personnel that issue and receive
Operating Instructions, provide feedback to those
operating personnel and take corrective action,
as deemed appropriate by the entity, to address
deviations from the documented protocols.
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
7
Board Approved Standard
Proposed Replacement Requirement(s)
4.2. Assess the effectiveness of its documented
communications protocols in Requirement R1 for
its operating personnel that issue and receive
Operating Instructions and modify its
documented communication protocols, as
necessary.
R5. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues an oral two-party, person-toperson Operating Instruction during an Emergency, excluding
written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Confirm the receiver’s response if the repeated
information is correct (in accordance with Requirement
R6).
•
Reissue the Operating Instruction if the repeated
information is incorrect or if requested by the receiver, or
•
Take an alternative action if a response is not received or
if the Operating Instruction was not understood by the
receiver.
R6. Each Balancing Authority, Distribution Provider, Generator
Operator, and Transmission Operator that receives an oral twoparty, person-to-person Operating Instruction during an
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
8
Board Approved Standard
Proposed Replacement Requirement(s)
Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
R7.
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the issuer that
the response was correct, or
•
Request that the issuer reissue the Operating
Instruction.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues a written or oral singleparty to multiple-party burst Operating Instruction during
an Emergency shall confirm or verify that the Operating
Instruction was received by at least one receiver of the
Operating Instruction. [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
Notes: COM-002-3 Requirements R2 and R3 were moved into COM-002-4. The Project 2007-02 SDT has developed COM-002-4 to
provide more stringent communication requirements during Emergencies and Alerts as well as establish communication protocols for
non-Emergency/non-alert communications that occur between entities.
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
9
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Exhibit F
Order No. 672 Criteria COM-001-2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit F
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
The proposed standard achieves the specific reliability goal of establishing requirements
for Interpersonal Communication and Alternative Interpersonal Communication capabilities
necessary to maintain reliability. First, proposed COM-001-2 eliminates ambiguous terms used
in COM-001-1 that do not adequately specify the desired actions that Reliability Coordinators,
Balancing Authorities, and Transmission Operators are expected to take with respect to each’s
telecommunication facilities. The proposed Reliability Standard includes two new defined
terms, “Interpersonal Communication” and “Alternative Interpersonal Communication,” which
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose a
topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should
be developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
collectively provide a comprehensive approach to establishing communications capabilities
necessary to maintain reliability. The defined terms used in the requirements of proposed COM001-2 are:
Interpersonal Communication – Any medium that allows two or
more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication – Any Interpersonal
Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Interpersonal
Communication used for day-to-day operation.
These definitions provide clarity that an entity’s communications capabilities must be
redundant and that each of the capabilities must not utilize the same medium. The new
definitions, therefore, improve upon the language used in the current COM-001-1.1 Reliability
Standard, which states “[e]ach Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide adequate and reliable telecommunications facilities for the exchange of
Interconnection and operating information.” COM-001-1.1, Requirement R1, Part R1.4 states
that “[w]here applicable, these facilities shall be redundant and diversely routed.” Use of the
defined terms eliminates the need to use the ambiguous phrases “adequate and reliable” and
“redundant and diversely routed, which were identified in the Preliminary Assessment as
potentially creating ambiguity in the Reliability Standard.
Second, proposed COM-001-2 clearly identifies the need to be capable of both
Interpersonal Communication and Alternative Interpersonal Communication. Requirements R1R6 address the Interpersonal Communication capability and Alternative Interpersonal
Communication capability of the Reliability Coordinator, Transmission Operator, and Balancing
Authority.
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Third, the use of word “capability” in the proposed Reliability Standard ensures the
standard is technologically agnostic, allowing for future changes in technology and advances in
communication to be employed without requiring a change to the Reliability Standard. Lastly,
the proposed Reliability Standard expands the applicability of the Reliability Standard to cover
Distribution Providers and Generator Operators. These functional entities are now required to
have an Interpersonal Communication capability with the listed entities in Requirements R7 and
R8, respectively.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
The proposed Reliability Standard applies to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Distribution Providers, and Generator Operators. The
proposed Reliability Standard is clear and unambiguous as to what is required and who is
required to comply. As noted above, the Requirements use two newly defined terms to clearly
define the required capability needed to support the Requirements. The Requirements also
clearly provide the communication capability necessary for each applicable entity.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The Violation Risk Factors (“VRF”) and Violation Severity Levels (“VSL”) for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
The assignment of the severity level for each VSL is consistent with the corresponding
Requirement and will ensure uniformity and consistency in the determination of penalties. The
VSLs do not use any ambiguous terminology, and support uniformity and consistency in the
determination of similar penalties for similar violations. For these reasons, the proposed
Reliability Standard includes clear and understandable consequences.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standard contains Measures that support the Requirements by
clearly identifying what is required and how the requirements will be measured for compliance.
The Measures, contained in Section C of the proposed COM-001-2 Reliability Standard, are as
follows:
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communication capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with each adjacent
Reliability Coordinator within the same Interconnection, which could include, but is
not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with each adjacent Reliability Coordinator within the same Interconnection,
which could include, but is not limited to:
• physical assets, or
5
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so
that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
•
dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
or synchronously connected, which could include, but is not limited to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that it has
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Interpersonal Communication capability with its Transmission Operator and its
Balancing Authority, which could include, but is not limited to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R7.)
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to:
• physical assets, or
• dated evidence, such as, equipment specifications and installation documentation, test
records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R8.)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
and provide upon request evidence that it tested, at least once each calendar month, its
Alternative Interpersonal Communication capability designated in Requirements R2, R4, or R6.
If the test was unsuccessful, the entity shall have and provide upon request evidence that it
initiated action to repair or designated a replacement Alternative Interpersonal Communication
capability within 2 hours. Evidence could include, but is not limited to: dated and time-stamped
test records, operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
and provide upon request evidence that it notified entities as identified in Requirements R1, R3,
and R5, respectively within 60 minutes of the detection of a failure of its Interpersonal
Communication capability that lasted 30 minutes or longer. Evidence could include, but is not
limited to: dated and time-stamped test records, operator logs, voice recordings, transcripts of
voice recordings, or electronic communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detected a failure of its
Interpersonal Communication capability shall have and provide upon request evidence that it
consulted with each entity affected by the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a Generator Operator, to determine mutually
agreeable action to restore the Interpersonal Communication capability. Evidence could include,
but is not limited to: dated operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R11.)
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design. 6
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The proposed Reliability Standard achieves the reliability goal effectively and efficiently in
accordance with Order No. 672. The proposed Reliability Standard establishes communications
capabilities and redundant communications capabilities necessary to maintain reliability. For
certain applicable entities, i.e., Distribution Providers and Generator Operators, a redundant
capability has not been mandated, but a Requirement to determine a mutually agreeable action
for the restoration of its Interpersonal Communication capability has been included for when the
applicable entity detects a failure of its Interpersonal Communication capability. This construct
ensures that the communications capabilities necessary to maintain reliability are reflected in the
proposed Reliability Standard while striking an appropriate balance on which applicable entities
must have redundant capabilities as part of the mandatory Reliability Standard.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability. 7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. On the contrary, the Reliability Standard establishes requirements for mandatory
redundancies in communications capabilities necessary to maintain reliability and the testing of
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
7
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those communications capabilities. The proposed Reliability Standard does not represent a
compromise that does not adequately protect Bulk-Power System reliability.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard.8
The proposed Reliability Standard applies throughout North America and does not favor one
geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
Proposed Reliability Standard COM-001-2 has no undue negative effect on competition.
Since the proposed Reliability Standard only concerns communications capabilities, it also does
not unreasonably restrict transmission or generation operation on the Bulk-Power System.
9. The implementation time for the proposed Reliability Standard is reasonable. 10
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
8
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The proposed effective date for the Reliability Standard appropriately balances the urgency
to implement the standard against the time needed by those who must comply to develop
necessary procedures and capabilities in support of the proposed Reliability Standard. To allow
entities adequate and reasonable time to comply with the proposed Reliability Standard, the effective
date is first day of the second calendar quarter beyond the date that the proposed Reliability Standard
is approved.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s Commissionapproved, ANSI- accredited processes for developing and approving Reliability Standards.
Exhibit M includes a summary of the Reliability Standard development proceedings, and details
the processes followed to develop the Reliability Standard. These processes included, among
other things, multiple comment periods, pre-ballot review periods, and balloting periods.
Additionally, all meetings of the standard drafting team were properly noticed and open to the
public.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
9
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NERC has identified no competing public interests regarding the request for approval of the
proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standards conflict with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 13
No other factors relevant to whether the proposed Reliability Standard is just and reasonable
were identified.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we
will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
10
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Exhibit G
Order No. 672 Criteria COM-002-4
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Exhibit G
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
Proposed Reliability Standard COM-002-4 achieves the specific reliability goal of improving
communications for the issuance of Operating Instructions. Proposed COM-002-4 accomplishes
this purpose by requiring the use of predefined communications protocols to reduce the
possibility of a miscommunication that could lead to action or inaction harmful to the reliability
of the Bulk Electric System. The proposed Reliability Standard combines proposed Reliability
Standard COM-002-3 and the former draft COM-003-1 into a single standard that addresses
communications protocols for operating personnel in Emergency and non-emergency conditions.
1
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power
System facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such
facilities include all those necessary for operating an interconnected electric energy transmission network, or any
portion of that network, including control systems. The proposed Reliability Standard may apply to any design of
planned additions or modifications of such facilities that is necessary to provide for reliable operation. It may also
apply to Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve this goal. Although any person may propose a
topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should
be developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.
1
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In proposed COM-002-4, the same protocols are required to be used in connection with
the issuance of Operating Instructions for all operating conditions – i.e., non-emergency and
Emergency communications. An entity should expect its operating personnel that issue and
receive Operating Instructions to use the entity’s documented communication protocols for the
issuance and receipt of all Operating Instructions. An entity reinforces its use of the documented
communication protocols through training, assessing adherence by its operating personnel to the
documented communication protocols, and providing feedback to those operating personnel on
their use of the protocols. During Emergencies, operating personnel must use the documented
communication protocols for three-part communications without exception, since clear
communication is essential to providing swift and coordinated response to events that are
directly impacting the reliability of the Bulk Electric System. In addition to Balancing
Authorities, Reliability Coordinators, and Transmission Operators, proposed COM-002-4 applies
to Distribution Providers and Generator Operators. The standard drafting team added these
entities in the Applicability section because they can be and in many cases are the recipients of
Operating Instructions.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
The proposed Reliability Standard applies to Balancing Authorities, Reliability
Coordinators, Transmission Operators, Distribution Providers, and Generator Operators. The
3
Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know
what they are required to do to maintain reliability.
2
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proposed Reliability Standard is clear and unambiguous as to what is required and who is
required to comply. The proposed Reliability Standard proposes a clear set of required protocols
(Requirement R1). It also mandates initial training on the protocols (Requirements R2 and R3).
As noted above, entities are further required to assess their protocols for effectiveness and assess
their operating personnel’s adherence to the documented communication protocols (Requirement
R4).
The language of Requirement R4 clearly and explicitly delineates the obligations and
expectations entities must meet. Requirement R4 requires that each entity maintain a successful
program and measure its own adherence to its documented communications protocols.
Requirement R4 intentionally does not specify a specific type of review to execute or mandate
that corrective actions be taken. Entities are better equipped to design an appropriate program to
meet their own operating environment and determine whether a corrective action is necessary.
Because almost all entities have these types of programs in place today, this approach also
provides an efficient means of establishing an assessment program by building on the programs
currently in use. The primary purpose of Requirement R4 is to provide assurance that an entity
is using its documented communications protocols, engaging its operators, and periodically
reviewing its communications for improvement. The program required in Requirement R4
requires applicable entities to conduct retrospective review of their communications practices
based on predefined documented communications protocols through an assessment design of
their choosing and requires corrective actions be taken if the entity deems a corrective action
necessary.
3
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3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factor (“VRF”) and Violation Severity Level (“VSL”) for the proposed
Reliability Standard comport with NERC and Commission guidelines related to their assignment.
The assignment of the severity level for the VSLs is consistent with the corresponding
Requirement and will ensure uniformity and consistency in the determination of penalties. The
VSLs do not use any ambiguous terminology, and supports uniformity and consistency in the
determination of similar penalties for similar violations. For these reasons, the proposed
Reliability Standard includes clear and understandable consequences.
4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standard contains Measures that support the Requirements by
clearly identifying what is required and how the requirements will be measured for compliance.
The Measures, contained in Section C of the proposed COM-002-4 Reliability Standard, are as
follows:
M1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide its documented communications
protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide its initial training records related
to its documented communications protocols developed for
Requirement R1 such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R2.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
5
Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so
that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
4
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M3. Each Distribution Provider and Generator Operator shall provide
its initial training records for its operating personnel such as
attendance logs, agendas, learning objectives, or course materials in
fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide evidence of its assessments,
including spreadsheets, logs or other evidence of feedback, findings
of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in
fulfillment of Requirement R4. The entity shall provide, as part of its
assessment, evidence of any corrective actions taken where an
operating personnel’s non-adherence to the protocols developed in
Requirement R1 is the sole or partial cause of an Emergency and for
all other instances where the entity determined that it was appropriate
to take a corrective action to address deviations from the documented
protocols developed in Requirement R1.
M5. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issued an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral singleparty to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from
the recipient of the Operating Instruction was correct; 2) reissued the
Operating Instruction if the repeated information was incorrect or if
requested by the receiver; or 3) took an alternative action if a response
was not received or if the Operating Instruction was not understood
by the receiver. Such evidence could include, but is not limited to,
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or dated operator logs in fulfillment of
Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator
Operator, and Transmission Operator that was the recipient of an oral
two-party, person-to-person Operating Instruction during an
Emergency, excluding oral single-party to multiple-party burst
Operating Instructions, shall have evidence to show that the recipient
either repeated, not necessarily verbatim, the Operating Instruction
and received confirmation from the issuer that the response was
correct, or requested that the issuer reissue the Operating Instruction
in fulfillment of Requirement R6. Such evidence may include, but is
not limited to, dated and time-stamped voice recordings (if the entity
has such recordings), dated operator logs, an attestation from the
issuer of the Operating Instruction, memos or transcripts.
M7. Each Balancing Authority, Reliability Coordinator and
Transmission Operator that issued a written or oral single or multiple-
5
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party burst Operating Instruction during an Emergency shall provide
evidence that the Operating Instruction was received by at least one
receiver. Such evidence may include, but is not limited to, dated and
time-stamped voice recordings (if the entity has such recordings),
dated operator logs, electronic records, memos or transcripts.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design. 6
The proposed Reliability Standard achieves the reliability goal effectively and efficiently in
accordance with Order No. 672. The proposed Reliability Standard expands on the mandated
documented protocols to be used through Requirement R1, but does not provide an exhaustive
list of all possible protocols that could be employed by an entity as part of its overall documented
communications protocols. This achieves the reliability goal of tightening communications
protocols while allowing entities to add additional protocols, as necessary and appropriate for the
operating environment. NERC has also developed a guideline of current industry practices on
system operator verbal communications (Exhibit Q) to assist entities in developing “best
practices” to support their documented communications protocols. Further, the requirements for
training are tailored to only initial training since entities currently conduct ongoing training
pursuant to the PER-005 Reliability Standard. In addition, Requirement R4 includes flexibility
for entities to design their assessment process and determine corrective actions necessary to
address deviations from the protocols in order to leverage the existing processes each entity
utilizes today to accomplish the same tasks. In aggregate, COM-002-4 provides an efficient and
effective means to achieve the reliability goal of improving communications for the issuance of
Operating Instructions.
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.
6
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6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability. 7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. This proposed Reliability Standard is the result of multiple industry ballots and
revisions that reflect an active comment and response process between industry and the standard
drafting team. NERC held a technical conference and did considerable amounts of outreach to
regulatory staff, industry and NERC’s technical committees in order to arrive at the final
language in the proposed Reliability Standard. The standard drafting team also received input
from the NERC Board of Trustees, NERC’s Reliability Issues Steering Committee (“RISC”), the
Independent Experts Review Panel, and NERC management during the standard development
process. The result of these efforts was a stronger final proposed Reliability Standard that
protects the Reliability of the Bulk-Power System, achieved industry approval, and provides
means of improving the effectiveness of communications practices.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
7
Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice — the socalled “lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that
must comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
7
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and regional variations in market design if these affect the proposed Reliability
Standard. 8
The proposed Reliability Standard applies throughout North America and does not favor one
geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
Proposed Reliability Standard COM-002-4 has no undue negative effect on competition.
Since the proposed Reliability Standard only concerns the use of documented protocols for
communication, it also does not unreasonably restrict transmission or generation operation on the
Bulk-Power System.
9. The implementation time for the proposed Reliability Standard is reasonable. 10
The proposed effective date for the Reliability Standard appropriately balance the urgency to
implement the standard against the time needed by those who must comply to develop necessary
procedures and protocols in support of the proposed Reliability Standard. To allow covered
Entities adequate and reasonable time to comply with the proposed Reliability Standard, the
effective date is twelve (12) months following the date that the standard is approved.
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.
9
Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed
Reliability Standard that has no undue negative effect on competition. Among other possible considerations, a
proposed Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power
System beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an
unduly preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable,
FERC will consider also the timetable for implementation of the new requirements, including how the proposal
balances any urgency in the need to implement it against the reasonableness of the time allowed for those who must
comply to develop the necessary procedures, software, facilities, staffing or other relevant capability.
8
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10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s Commissionapproved, ANSI- accredited processes for developing and approving Reliability Standards.
Exhibit N includes a summary of the Reliability Standard development proceedings, and details
the processes followed to develop the Reliability Standard. These processes included, among
other things, multiple comment periods, pre-ballot review periods, and balloting periods.
Additionally, all meetings of the standard drafting team were properly noticed and open to the
public.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of the
proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standards conflict with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 13
11
Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commission-approved
Reliability Standard development process for the development of the particular proposed Reliability Standard in a
proper manner, especially whether the process was open and fair. However, we caution that we will not be
sympathetic to arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s
Reliability Standard development process if it is conducted in good faith in accordance with the procedures
approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.
13
Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we
will consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.
9
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No other factors relevant to whether the proposed Reliability Standard is just and reasonable
were identified.
10
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Exhibit H
Rationale and Technical Justification COM-002-4
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Project 2007-02, COM-002-4 Operating
Personnel Communications Protocols
Rationale and Technical Justification
Background and Justification for COM-002-4 Requirements
The purpose of the proposed COM-002-4 Reliability Standard is to improve communications for
the issuance of Operating Instructions with predefined communications protocols to reduce the
possibility of miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES). The proposed Reliability Standard combines COM-002-3 and former draft
COM-003-1 into one standard that addresses communications protocols for operating personnel in
Emergency, alert and non-emergency conditions. The Operating Personnel Communications Protocols
Standard Drafting Draft (OPCP SDT) believes that one communications protocols standard that
addresses emergency and non-emergency situations will improve communications because operating
personnel will not need to refer to a different set of protocols during the different operating conditions.
A single standard will improve consistency of communications and mitigate confusion during stressful
emergency situations. As a result of the combination, the standard has been numbered as COM-002-4 to
maintain the consecutive numbering of the standards (e.g., COM-001, COM-002) since the combined
standard will replace COM-002-2 and COM-002-3, where necessary.
In preparing COM-002-4, the OPCP SDT considered industry comments and also drew from a
variety of other resources including:
•
•
•
•
1
the NERC Board of Trustees’ November 7th, 2013 Resolution for Operating Personnel
Communication Protocols, discussed below; 1
a survey distributed to a sample of industry experts by the Director of Standards Development
and the Standards Committee Chair requesting feedback on the draft standard in posting 8;
consultation on the use of the term “Reliability Directive” in the COM-002-4 standard with the
Project 2007-03 Real-time Transmission Operations Standard Drafting Team and the Project
2006-06 Reliability Coordination Standard Drafting Team; and
a full-day “Communications in Operations” technical conference held February 14-15, 2013 to
gather industry input on a consensus communications standard approach.
Resolution for Agenda Item 8.i: Operating Personnel Communication Protocols, NERC Board of Trustees Meeting,
Nov. 7, 2013, available at:
http://www.nerc.com/gov/bot/Board%20of%20Trustees%20Quarterly%20Meetings/Board%20COM%20Resolution%2011.7
.13%20v1%20AS%20APPROVED%20BY%20BOARD.pdf.
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Structure of the COM-002-4 Draft
In response to the Board of Trustees direction to draft a combined COM-002 and COM-003
standard that addresses, at a minimum certain protocols, NERC staff prepared a “strawman” draft
standard and provided it as a starting point for the standard drafting team to edit and adjust as it deemed
appropriate. The structure of posting 8 of COM-002-4 reflects the minimum elements listed by the
Board in its resolution (see below for detail on the Board resolution). The structure also allows for the
implementation of a compliance/enforcement approach also described by the Board’s resolution that
maintains the current requirement that entities should be accountable for incorrect use of communication
protocols in connection with emergency communications, without exception.
In COM-002-4, the same protocols are required to be used in connection with the issuance of
Operating Instructions for all operating conditions – i.e. non-emergency, alert, and Emergency
communications. However, the standard uses the phrase “Operating Instruction during an Emergency”
in certain Requirements (R5, R6, R7) to provide a demarcation for what is subject to a zero-tolerance
compliance/enforcement approach and what it not. This is necessary to allow the creation of Violation
Severity Levels for each compliance/enforcement approach. Where “Operating Instruction during an
Emergency” is not used, an entity will be assessed under a non-zero tolerance compliance/enforcement
approach that focuses on whether an entity met the initial training Requirement (either R2 or R3) and/or
whether an entity performed the assessment and took corrective actions according to Requirement R4.
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Their use is measured for compliance/enforcement differently using the operating
condition as an indicator of which compliance/enforcement approach applies.
For example, an entity should expect its operating personnel that issue and receive Operating
Instructions to use the documented communication protocols for all Operating Instructions. The way
that they reinforce that with its operating personnel is through training, assessing adherence by its
operating personnel to the documented communication protocols and providing feedback those
operating personnel on their use of the protocols. During Emergencies, operating personnel must use the
communication protocol without exception, since clear communication is essential to providing swift
and coordinated response to events that are directly impacting the reliability of the BES.
Definition of “Operating Instruction”
The current draft of COM-002-4 does not include the term “Reliability Directive,” which was
included in previous postings as a subset within the definition of “Operating Instruction.”
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The proposed definition of “Operating Instruction” in COM-002-4 reads as follows:
A command by operating personnel responsible for the Real-time operation
of the interconnected Bulk Electric System to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System. (A discussion of general information and of
potential options or alternatives to resolve Bulk Electric System operating
concerns is not a command and is not considered an Operating Instruction.)
The OPCP SDT debated whether to remove the term “Reliability Directive” in response to
comments suggesting it should be removed from the definition of “Operating Instruction” and in light of
FERC’s issuance of the TOP/IRO NOPR, which proposes to remand the definition of “Reliability
Directive.” A detailed description of the FERC action is included in the section below titled
“Developments Following Posting 7.”
In order to avoid unnecessary complications, the OPCP SDT consulted on the use of the term
“Reliability Directive” in the COM-002-4 standard with the Project 2007-03 Real-time Transmission
Operations and the Project 2006-06 Reliability Coordination Standard Drafting Teams to ask whether
they believed removal of the term would cause concerns. Both teams agreed that the COM-002-4
standard did not need to require a protocol to identify Reliability Directives as such and that the
definition of Operating Instruction could be used absent the term Reliability Directive in COM-002-4 to
set the protocols. The OPCP SDT ultimately voted to remove the term and incorporate the phrase
“Operating Instruction during an Emergency” in the Requirements where it was needed to preserve the
structure created to ensure that only an Operating Instruction issued during an Emergency is subject to a
zero-tolerance compliance/enforcement approach.
A “command” as used in the definition refers to both oral and written commands by operating
personnel. In the requirements of COM-002-4, the OPCP SDT has specified “oral” or “written” as
needed to define which Operating Instructions are covered by the requirement. The definition continues
to clarify that general discussions are not considered Operating Instructions.
Applicability
In addition to Balancing Authorities, Reliability Coordinators, and Transmission Operators, the
proposed standard applies to Distribution Providers and Generator Operators. The OPCP SDT added
these Functional Entities in the Applicability section because they can be and are on the receiving end of
some Operating Instructions. The OPCP SDT determined that it would leave a gap to not cover them in
a communications standard that addresses operating personnel. The addition of Distribution Providers as
an applicable entity also responds to FERC’s directive in Order No. 693 to add them as applicable
entities to the communications standard.
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Recognizing that Generator Operators and Distribution Providers typically only receive
Operating Instructions, the OPCP SDT proposed that only Requirements R3 and R6 apply to these
Functional Entities. In response to the comments and the NERC Board Resolution, the OPCP SDT
revised the standard to clarify that DPs and GOPs are required to a) train their operators prior to
receiving an Operating Instruction, and b) use three part communication when receiving an Operating
Instruction during an Emergency. In addition, the measures have been revised to show that a DP or
GOP can demonstrate compliance for use of three-part communication when receiving an Operating
Instruction during an Emergency by providing an attestation from the issuer of the Operating Instruction
(i.e., a voice recording is not required). If a DP or GOP never receives an Operating Instruction, no
requirement in COM-002-4 would apply to them. In both Requirements R3 and R6, qualifying language
that discusses the “receipt” of an Operating Instruction is included to make this point clear. This
construct ensures that appropriate entities are trained and able to use three-part communication for
reliability purposes, while seeking to minimize the compliance burden on DPs and GOPs.
Requirements in COM-002-4
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to have
documented communications protocols that include a minimum set of elements, outlined in Parts 1.1
through 1.6 of the requirement. Because Operating Instructions affect Facilities and Elements of the
Bulk Electric System, the communication of those Operating Instructions must be understood by all
involved parties, especially when those communications occur between Functional Entities. An EPRI
study reviewed nearly 400 switching mishaps by electric utilities and found that roughly 19% of errors
(generally classified as loss of load, breach of safety, or equipment damage) were due to communication
failures. 2 This was nearly identical to another study of dispatchers from 18 utilities representing nearly
2000 years of operating experience that found that 18% of the operators’ errors were due to
communication problems. 3 The necessary protocols include the use of the English language unless
agreed to otherwise (except for internal operations), protocols for use of a written or oral single-party to
multiple-party burst Operating Instruction, specification of instances that require time identification,
nomenclature for Transmission interface Elements, and three-part communications (including a protocol
for taking an alternate action if a response is not received or if the Operating Instruction was not
understood by the receiver).
The OPCP SDT drafted Requirement R1 to ensure consistency among communications protocols
while also allowing flexibility for entities to develop additional communications protocols. The OPCP
SDT determined that the inclusion of the elements in Parts 1.1 through 1.6 are necessary to improve
communications protocols but are not overly prescriptive. The OPCP SDT determined that this
2
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
3
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
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approach is the best way to promote effective communications while maintaining flexibility for entities
to include additional communications protocols based on its own operating environment.
It should be noted that requiring the use of alphanumeric clarifiers has been removed in this
posting. Several entities have provided the comment that it is unnecessary to include them in a
requirement, and pointed to the fact that the lack of use has not been shown to contribute to any
investigated event. The drafting team agreed to remove the term, and NERC will continue to monitor
events to determine if these clarifiers should be added in a future modification to the standard.
The term documented communication protocols in R1 refers to a set of required protocols
specific to the Functional Entity and the Functional Entities they must communicate with. An entity
should include as much detail as it believes necessary in their documented protocols, but they must
address all of the applicable parts of Requirement R1. Where an entity does not already have a set of
documented protocols that meet the parts of Requirement R1, the entity must develop the necessary
communications protocols. Entities may also adopt the documented protocols of another entity as its
own communications protocols, but the entity must maintain its own set of documented communications
protocols to meet Requirement R1.
On September 19, 2012, the NERC Operating Committee issued a Reliability Guideline entitled:
“System Operator Verbal Communications – Current Industry Practices.” As stated on page one, the
purpose of the Reliability Guideline “. . . is to document and share current verbal BES communications
practices and procedures from across the industry that have been found to enhance the effectiveness of
system operator communications programs.” This guideline serves as an additional source of
information on best practices that entities can draw on in creating the documented communications
protocols.
Each part of Requirement R1 is discussed below:
1.1.
Require its operating personnel that issue and receive an oral or written Operating
Instruction to use the English language, unless agreed to otherwise. An alternate language may
be used for internal operations.
The OPCP SDT has included this part to carry forward the same use of English language
included in COM-001-1.1, Requirement R4. Retirement of this Requirement in COM-001-1.1 was
specifically referred to this Project 2007-02. The requirement continues to permit the issuer and receiver
to use an agreed to alternate language. This has been retained since use of an alternate language on a
case-by-case basis may serve to better facilitate effective communications where the use of English
language may create additional opportunities for miscommunications. Part 1.1 requires the use of
English language when issuing oral or written (e.g. switching orders) Operating Instructions. This
creates a standard language (unless agreed to otherwise) for use when issuing commands that could
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System. It also clarifies that an alternate language can be used internally
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within the organization. The phrase has been modified slightly from the language in COM-001-1.1,
Requirement R4 to incorporate the term “Operating Instruction,” which defines the communications that
require the use of the documented communications protocols.
1.2.
Require its operating personnel that issue an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
•
•
•
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect, if the
receiver does not issue a response, or if requested by the receiver.
Take an alternative if a response is not received or if the Operating Instruction
was not understood by the receiver.
1.3.
Require the receiver of an oral two-party, person-to-person Operating Instruction to take
one of the following actions:
•
Repeat the Operating Instruction and wait for confirmation from the issuer that
the repetition was correct.
•
Request that the issuer reissue the Operating Instruction.
The OPCP SDT has included part 1.2 to require communications protocols for the use of threepart communications for oral two-party, person-to-person Operating Instructions by the issuer. The
OPCP SDT has included part 1.3 to require communications protocols for the use of three-part
communications for oral two-party, person-to-person Operating Instructions by the receiver. This
carries forward the requirement to use three-part communications in COM-002-2 and COM-002-3 and
also adds an option in part 1.2 for the issuer to take an alternative action to resolve the issue if the
receiver does not respond or understand the Operating Instruction. The addition of this third bullet
serves to clarify in the requirement language itself that the issuing entity can take alternate action in lieu
of reissuance if necessary.
The reliability benefits of using three-part communication (Requirement R1, parts 1.2 and 1.3)
are threefold:
1. The removal of any doubt that use of the documented communication protocols is required
when issuing or receiving Operation Instructions. This will reduce the opportunity for
confusion and misunderstanding during all operating conditions.
2. There will be no mental “transition” between protocols when operating conditions shift from
non-emergency to Emergency. The documented communication protocols for the operating
personnel will remain the same during transitions through all conditions.
3. The formal requirement for three-part communication will create a heightened sense of
awareness in operating personnel that the task they are about to execute is critical, and
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recognize the risk to the reliable operation of the BES is increased if the communication is
misunderstood.
1.4.
Require its operating personnel that issue a written or oral single-party to multiple-party
burst Operating Instruction to confirm or verify that the Operating Instruction was received by
at least one receiver of the Operating Instruction.
The OPCP SDT has included this part to require communications protocols for an issuer for the
use of a one-way burst messaging system. The drafting team has included this because the use of threepart communications is not practical when utilizing this type of communication. Therefore, it is
necessary to include a different set of protocols for these situations. In addition, many entities expressed
concern that if one-way burst messaging systems were not addressed, it would imply that three part
communication would be required for all participants. For this reason, the drafting team chose to
address one-way burst messaging systems.
1.5.
Specify the instances that require time identification when issuing an oral or written
Operating Instruction and the format for that time identification.
The OPCP SDT has included this part to add necessary clarity to Operating Instructions to
reduce the risk of mistakes. Clarifying time and time zone (where necessary) contributes to reducing
misunderstandings and reduces the risk of a grave error during BES operations, especially when
communicating across time zones or specifying an action that will take place at a future time. Note that
an action that is to occur immediately would not be required to have time identification, unless the entity
specified that requirement in its communication protocols.
1.6.
Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
Project 2007-03 chose to eliminate TOP-002-2a, Requirement R18 when it developed TOP-002-3. This
Requirement stated “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers when
referring to transmission facilities of an interconnected network.” COM-002-4, while reintroducing the
concept of line identifiers, limits the scope to only Transmission interface Elements or Transmission
interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are readily familiar
with each other’s interface Elements and Facilities, eliminating hesitation and confusion when referring
to equipment for the Operating Instruction. This shortens response time and improves situational
awareness. It also permits entities to jointly develop the nomenclature for their interface.
Requirements R2 and R3
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Requirement R2 requires the entities listed in Requirement R1 (i.e. each Balancing Authority,
Reliability Coordinator, and Transmission Operator) to conduct initial training for each of their
operating personnel responsible for the Real-time operation of the Bulk Electric System on the entity’s
documented communication protocols.
Requirement R3 requires Distribution Providers and Generator Operators to conduct initial
training on three part communication for each of their operating personnel who can who can receive an
oral two-party, person-to-person Operating Instruction prior to that individual operator receiving an oral
two-party, person-to-person Operating Instruction. Distribution Providers and Generator Operators
would have to train their operating personnel prior to placing them in a position to receive an oral twoparty, person-to-person Operating Instruction. Operating Personnel that would never be in a position to
receive an oral two-party, person-to-person Operating Instruction, therefore, would not need initial
training unless their circumstance changes. The purpose of the language in Requirement R3, is to
minimize the training burden, and demonstration of compliance, to only those operating personnel that
can receive an oral two-party, person-to-person Operating Instruction.
The OPCP SDT has included an initial training requirement in the standard in response to the NERC
Board of Trustees resolution, which directs that a training requirement be included in the COM-002-4
standard. Additionally, requiring entities who issue and or receive Operating Instructions to conduct
initial training with their operating personnel will ensure that all applicable operators will be trained in
three-part communication. The OPCP SDT believes this training will reduce the possibility of a
miscommunication, which could eventually lead to action or inaction harmful to the reliability of the
Bulk Electric System. Ongoing training would fall under an entities training program in PER-005 or
could be listed as a type of corrective action under Requirement R4.
Requirement R4
Requirement R4 requires Balancing Authorities, Reliability Coordinators, and Transmission
Operators to, at least once every 12 months, assess adherence by its operating personnel to the
documented communication protocols in Requirement R1 and to provide feedback to its operating
personnel on their performance. This also includes any corrective action taken, as appropriate, to
address deviations from the documented protocols. It also requires the aforementioned entities to assess
the effectiveness of their documented communications protocols and make changes, as necessary, to
improve the effectiveness of the protocols. An entity may determine that corrective action beyond
identification of the misuse of the documented communications protocols to the operating personnel is
not necessary, therefore, the phrase “as appropriate” is included in the Requirement R4 language to
indicate that whether to take additional corrective action is determined by the entity and not dictated by
the Requirement for all instances of a misuse of a documented communication protocol.
Requiring entities to assess, identify and provide feedback to its operating personnel, was also
included in the November 7, 2013 NERC Board of Trustees resolution as an element to include in the
standard. Further, the OPCP SDT believes that it is good operating practice for an entity to periodically
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evaluate the effectiveness of their protocols and improve them when possible. Most entities currently
engage in some type of assessment activity for their operating personnel. Additionally, the OPCP SDT
also believes it is good operating practice to provide operators with performance feedback on their
adherence to the entity’s documented protocols. Doing so, provides entities an opportunity to evaluate
the performance of their operating personnel and take corrective actions where necessary, which could
prevent a miscommunication from occurring and thus possibly prevent an event which could be harmful
to the reliability of the Bulk Electric System.
The associated Measure M4 for Requirement R4 lists the types of evidence that an entity can
provide to demonstrate compliance and also explains when an entity should show the corrective actions
taken. Of particular interest is any corrective action taken where the miscommunication is the sole or
partial cause of an Emergency and the entity has opted to take a corrective action. While the Measure
lists out this particular set of circumstances to highlight the importance, the Measure does not modify
the Requirement to require corrective action. Again, to reiterate, whether a corrective action is
necessary is best determined by the entity based on the facts and circumstances of the particular
communication.
Requirements R5 and R6
Requirement R5 requires entities that issue oral two-party, person-to-person Operating
Instructions during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, to use three-part communication or take an alternate action if the receiver does
not respond or if the Operating Instruction was not understood by the receiver. The language of
Requirement R5 specifically excludes written or oral single-party to multiple-party burst Operating
Instructions to make clear that three-part communication is not required when issuing Operating
Instructions in this manner. Requirement R5 applies to each Balancing Authority, Reliability
Coordinator, and Transmission Operator since these are the entities that would be in a position to issue
oral two-party, person-to-person Operating Instructions during an Emergency.
Requirement R6 requires entities that receive an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, to repeat (not necessarily verbatim) the Operating Instruction and receive
confirmation from the issuer that the response was correct or request that the issuer reissue the Operating
Instruction. Requirement R6 includes the same clarifying language as Requirement R5 for the exclusion
of single-party to multiple-party burst Operating Instructions. Requirement R6 applies to each
Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator since these
are the entities that would be in a position to receive oral two-party, person-to-person Operating
Instructions during an Emergency
The use of three-part communication when issuing and receiving Operating Instructions is
always important because a miscommunication could create an Emergency. An entity should expect its
operating personnel that issue and receive Operating Instructions to use the documented communication
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protocols for all Operating Instructions. The way that they reinforce that with its operating personnel is
through training, assessing adherence by its operating personnel to the documented communication
protocols and providing feedback those operating personnel on their use of the protocols. However, the
use of three-part communication is critically important if an Emergency condition already exists, as
further action or inaction could cause exponentially increase the harmful effects to the BES. Clear
communication is essential to providing swift and coordinated response to events that are directly
impacting the reliability of the BES.
Requirement R7
Requirement R7 requires that when a Balancing Authority, Reliability Coordinator, or
Transmission Operator issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency, it must confirm or verify that the Operating Instruction was received by at least
one receiver of the Operating Instruction. Because written or oral single-party to multiple-party burst
Operating Instruction during an Emergency are excluded from Requirements R5 and R6, this separate
Requirement is necessary to specify the standard an entity must meet to demonstrate clear
communication for the use of written or oral single-party to multiple-party burst Operating Instructions
during an Emergency. This prevents leaving a gap in the types of communications used during an
Emergency.
The OPCP SDT believes this requirement is necessary because without confirmation from at
least one receiver, the issuer has no way of confirming if the Operating Instruction was transmitted and
received by any of the recipients. Therefore, the issuer cannot know whether to resend the Operating
Instruction, wait for the recipient to take an action, or take an alternate action because the recipient
cannot perform the action. As a best practice, an entity can opt to confirm receipt from more than one
recipient, which is why the requirement states “at least one.”
NERC Board’s Resolution
At its November meeting, the Board passed a resolution that directs the Standards Committee and
the standard drafting team “to continue development of a combined COM-002 and COM-003 standard
that addresses, at a minimum, the following:
•
•
Draws on the Operating Committee Guideline for good communication practice;
Includes an essential set of communications protocols to be used by all entities that would be
included in an entity’s overall communications protocol approach;
o The protocol should at a minimum require the use of three-part communications for
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•
•
(i) emergency and alert communications (“Emergency Communications”) and (ii) nonemergency communications that change or preserve the state, status, output, or input of
the Bulk Electric System (“Non-Emergency Communications”);
Requires training and periodic review of communications subject to the communications
protocols; and
Requires each entity to (i) periodically self assess its effectiveness in implementing the
communications protocols, (ii) self identify any necessary changes to the entity’s
protocols based upon experience and the results of periodic review, and (iii) provide
feedback to its operators regarding their adherence to the protocols.”
The resolution further directs the standard drafting team to “consider the following
compliance/enforcement approach:
•
•
Maintain the current requirement that entities should be accountable for incorrect use of
communication protocols in connection with Emergency Communications, without exception.
For all other use of communication protocols in connection with Non-Emergency
Communications, the standard should provide that compliance with the standard should only
entail assessing whether an entity has: (i) adopted a communications protocol consistent with the
foregoing; (ii) implemented training and periodic review of communications subject to the
protocols; and (iii) implemented a process to (x) periodically self assess its effectiveness in
implementing the communications protocols, (y) self identify any necessary changes to the
entity’s protocols based upon experience and the results of periodic review, and (z) provide
feedback to its operators regarding their adherence to the protocols.”
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On November 21, 2013, the Commission issued the TOP/IRO NOPR, which proposes to remand the
proposed TOP and IRO standards. 4 In the TOP/IRO NOPR, the Commission raises a concern that
NERC “has removed critical reliability aspects that are included in the currently-effective standards
without adequately addressing these aspects in the proposed standards.” For the term “Reliability
Directive”, FERC states that the undefined term “reliability directive” used in prior standards does not
appear to be limited to a specific set of circumstances. FERC continues that, in contrast, application of
the proposed definition of “Reliability Directive” appears to require compliance with transmission
operator directives only in emergencies, not normal or pre-emergency times. FERC states that directives
from a reliability coordinator or transmission operatorshould be mandatory at all times, and not just
during emergencies (unless contrary to safety, equipment, regulatory or statutory requirements). FERC
states that the transition from normal to emergency operation can be sudden and indistinguishable until
recognized, often after the damage is done. FERC has requested additional explanation from NERC and
requested comments on its proposal to remand the term “Reliability Directive” along with the TOP and
IRO standards. FERC will take final action on its proposal at time to be determined in the future.
FERC’s proposal to remand the term “Reliability Directive” raised possible complications with
the draft COM-002-4 standard in Posting 7 since that term was included. Should the term be remanded
by FERC, the COM-002-4 standard could contain a term that is no longer acceptable. In order to avoid
unnecessary complications, the OPCP SDT consulted on the use of the term “Reliability Directive” in
the COM-002-4 standard with the Project 2007-03 Real-time Transmission Operations and the Project
2006-06 Reliability Coordination Standard Drafting Teams to ask whether they believed removal of the
term would cause concerns. Both teams agreed that the COM-002-4 standard did not need to require a
protocol to identify Reliability Directives as such and that the definition of Operating Instruction could
be used absent the term Reliability Directive in COM-002-4 to set the protocols. This would leave the
TOP and IRO standard drafting teams the flexibility to address the issues surrounding the term
“Reliability Directive” in response to the FERC TOP/IRO NOPR.
4
Monitoring System Conditions- Transmission Operations Reliability Standard Transmission Operations Reliability
Standards Interconnection Reliability Operations and Coordination Reliability Standards, NOPR, 145 FERC ¶ 61,158
(2013). The TOP/IRO NOPR is available at:
http://www.nerc.com/FilingsOrders/us/FERCOrdersRules/NOPR_TOP_IRO_RM13-12_RM13-14_RM13-15_20131121.pdf.
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Exhibit I
Frequency Asked Questions Document COM-002-4
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Project 2007-02 Posting 8
Frequently Asked Questions Guide
General Questions
1. What were the inputs that drove the development of posting 8 of Project 2007-02?
The NERC Board of Trustees’ November 7th, 2013 Resolution for Operating Personnel Communication
Protocols, discussed below;
Two separate surveys distributed to a sample of industry experts by the Director of Standards
Development and the Standards Committee Chair requesting feedback on the draft standard; and
Consultation on the use of the term “Reliability Directive” in the COM-002-4 standard with the Project
2007-03 Real-time Transmission Operations Standard Drafting Team and the Project 2006-06
Reliability Coordination Standard Drafting Team.
Industry stakeholder comments from previous drafts of Project 2007-02.
2. Why was the term “Reliability Directive” removed from the definition of Operating Instruction?
The OPCP SDT debated whether to remove the term “Reliability Directive” in response to comments
suggesting it should be removed from the definition of “Operating Instruction” and in light of FERC’s
issuance of the TOP/IRO Notice of Proposed Rulemaking (NOPR), which proposes to remand the definition
of “Reliability Directive” along with the proposed TOP and IRO standards. To avoid unnecessary
complications with the timing of the NOPR and posting 8, the OPCP SDT consulted with the Project 200703 Real-time Transmission Operations and the Project 2006-06 Reliability Coordination Standard Drafting
Teams to ask whether they believed removal of the term “Reliability Directive” in the COM-002-4
standard would cause concerns. Both teams agreed that the COM-002-4 standard did not need to require
a protocol to identify Reliability Directives as such and that the definition of Operating Instruction could
be used absent the term Reliability Directive in COM-002-4 to set the protocols. The OPCP SDT ultimately
voted to remove the term. The OPCP SDT also decided to incorporate the phrase “Operating Instruction
during an Emergency” in certain Requirements, where needed, to identify Requirements that are subject
to a zero-tolerance compliance/enforcement approach.
3. Why does this standard apply to Generator Operators and Distribution Providers?
The OPCP SDT included these Functional Entities in the Applicability section because they can be and are
on the receiving end of some Operating Instructions. The OPCP SDT determined that it would leave a gap
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to not cover them in a standard that addresses communications protocols for operating personnel. The
inclusion of Distribution Providers as an applicable entity also responds to FERC’s directive in Order No.
693 to add them as applicable entities to the communications standard. The inclusion of Distribution
Providers and Generator Operators is also consistent withwith the currently approved COM-002-3
standard, which the Board directed be combined with COM-003-1.
Recognizing that Generator Operators and Distribution Providers typically only receive Operating
Instructions, the OPCP SDT proposed that only Requirements R3 and R6 apply to these Functional Entities.
4. What does the term documented communications protocols refer to?
The term documented communication protocols in R1 refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. An entity should include as
much detail as it believes necessary in their documented protocols, but they must address all of the
applicable parts of Requirement R1. Where an entity does not already have a set of documented
protocols that meet the parts of Requirement R1, the entity must develop the necessary communications
protocols. Entities may also adopt the documented protocols of another entity as its own
communications protocols, but the entity must maintain its own set of documented communications
protocols to meet Requirement R1.
5. Is this a “zero tolerance” standard
The standard uses the phrase “Operating Instruction during an Emergency” in certain Requirements (R5,
R6, R7) to provide a demarcation for what is subject to a “zero tolerance” compliance/enforcement
approach and what is not. This is necessary to allow the creation of Violation Severity Levels for each
compliance/enforcement approach. Where “Operating Instruction during an Emergency” is not used, an
entity will be assessed under a compliance/enforcement approach that focuses on whether or not an
entity met the initial training Requirement (either R2 or R3) and whether or not an entity performed
the assessment and took corrective action according to Requirement R4. The proposed COM-002-4
does not contain a Requirement to adhere to all documented communications protocols during nonEmergency conditions. Under COM-002-4, the assessment and training documentation will provide
auditors assurance that responsible entities are using their documented communications protocols and
taking corrective actions, as necessary.
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Compliance/enforcement is measured differently using the operating condition as
an indicator of which compliance/enforcement approach applies.
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6. Do any of the proposed requirements require the use of three-part communication when issuing
or receiving an Operating Instruction outside of an Emergency?
Compliance with the standard during non-Emergencies is based on whether or not an entity met the
initial training Requirement (either R2 or R3) and whether or not an entity performed the assessment and
took corrective action according to Requirement R4. An instance of an Operating Instruction outside of
an Emergency not using three-part communication, or any of the other protocols in Requirement R1, is
not in and of itself a violation of any requirement of COM-002-4. However, an entity will need be using
three-part communication when issuing or receiving an Operating Instruction outside of an Emergency in
order to complete the assessment of adherence to the entities’ documented communications protocols.
7. Why are entities required to assess the adherence of its operating personnel to the documented
communication protocols the entity developed and provide feedback?
Requiring entities to assess and provide feedback to its operating personnel, was also included in the
November 7, 2013 NERC Board of Trustees’ resolution as an element to include in the standard. Further,
the OPCP SDT believes that it is good operating practice for an entity to periodically evaluate the
effectiveness of their protocols and improve them when possible. Most entities currently engage in this
type of assessment activity for their operating personnel. This assessment and feedback activity by the
entity improves reliability as it provides a shorter evaluation and correction cycle than a traditional audit
cycle, while reducing the associated compliance burden as well.
Additionally, the OPCP SDT believes it is good operating practice to provide operators with performance
feedback on their adherence to the entity’s documented protocols. Doing so, provides entities an
opportunity to evaluate the performance of their operating personnel and take corrective actions where
necessary, which could prevent a miscommunication from occurring and thus possibly prevent an event
which could be harmful to the reliability of the Bulk Electric System.
8. Should the BA, RC, and TOP provide their protocols to the GOPs and DPs and each other?
While an entity may choose to provide their protocols to entities to which they communicate, there is not
a mandatory and enforceable requirement that they do so.
9. Why is the standard not applicable to Transmission Owners?
Please refer to the Functional Model, found at http://www.nerc.com/pa/Stand/Pages/
FunctionalModel.aspx. In the document, the following is provided for the Transmission Operator:
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The Transmission Operator operates or directs the operation of transmission
facilities, and maintains local-area reliability, that is, the reliability of the
system and area for which the Transmission Operator has responsibility. The
Transmission Operator achieves this by operating the transmission system
within its purview in a manner that maintains proper voltage profiles and
System Operating Limits, and honors transmission equipment limits
established by the Transmission Owner. The Transmission Operator is under
the Reliability Coordinator’s direction respecting wide-area reliability
considerations, that is, considerations beyond those of the system and area for
which the Transmission Operator has responsibility and that include the
systems and areas of neighboring Reliability Coordinators. The Transmission
Operator, in coordination with the Reliability Coordinator, can take action,
such as implementing voltage reductions, to help mitigate an Energy
Emergency, and can take action in system restoration.
The following is provided for the Transmission Owner:
The Transmission Owner owns its transmission facilities and provides for the
maintenance of those facilities. It also specifies equipment operating limits,
and supplies this information to the Transmission Operator, Reliability
Coordinator, and Transmission Planner and Planning Coordinator. In many
cases, the Transmission Owner has contracts or interconnection agreements
with generators or other transmission customers that would detail the terms
of the interconnection between the owner and customer.
While the Transmission Owner owns the facilities, the Transmission Operator operates the
facilities, and as such is subject to this standard. In the case where a Transmission Owner
operates facilities, that Transmission Owner is bundled with a Reliability Coordinator or
Transmission Operator, and as such would be covered by the standard.
10. If an entity cannot complete a task included in an Operating Instruction, are they noncompliant?
COM-002-4 deals with communication protocols, not actions taken by any entity. If an entity does not
take action on an Operating Instruction, it may be a violation of another standard, but is not a violation of
COM-002-4.
11. A GOP contacts its TOP and notifies the TOP that a generator is about to trip due to a tube leak.
Is this considered an Operating Instruction?
No. This is not a command; it is simply relaying information about the generator to the Transmission
Operator.
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12. If a Distribution Provider cannot operate a BES Element, would this standard apply to them?
Distribution Providers are applicable entities for this standard. However, if they never receive an
Operating Instruction due to their particular circumstance, they would not need to prove compliance with
Requirements R3 and R6.
Requirement R1 and Measure M1
13. Pursuant to R1, is it correct that an oral two-party, person-to-person Operating Instruction
requires three part communication, but a single-party to multiple-party burst Operating
Instruction message only requires two part communication?
Yes. Since the use of three-part communications is not practical when issuing a single-party to multipleparty burst Operating Instruction, it is necessary to include a different set of protocols for these
situations.
14. Can you provide some examples of what is meant by written Operating Instructions as
contemplated in Requirement R1 Parts 1.1 and 1.4 - 1.6?
One example of a written Operating Instruction is a written switching order. Another example is an
Operating Instruction issued by using a text message.
15. Please explain how the current draft does not conflict with TOP-002 R18 (uniform line
identifiers)?
Project 2007-03 chose to eliminate TOP-002-2a, Requirement R18 when it developed TOP-002-3. This
Requirement stated “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers when referring
to transmission facilities of an interconnected network.” COM-002-4, while reintroducing the concept of
line identifiers, limits the scope to only Transmission interface Elements or Transmission interface
Facilities (e.g. tie lines and tie substations) for Operating Instructions. This supports both parties being
familiar with each other’s interface Elements and Facilities, minimizing hesitation and confusion when
referring to equipment for the Operating Instruction.
16. Can you explain what "specify when time identification required"? Is this just for entities in
multiple time zones?
The OPCP SDT has included this part to add necessary clarity to Operating Instructions to reduce the risk
of miscommunications. The inclusion of “specify when time identification required” allows for an entity to
evaluate its particular circumstances and communications to determine when it may be appropriate to
use time identification in its Operating Instructions. The drafting recognized from comments the need to
provide this flexibility while still requiring an entity to address this part in its documented communication
protocols. Clarifying time and time zone (where necessary) contributes to reducing misunderstandings
and reduces the risk of a grave error during BES operations. This is not exclusively for entities in multiple
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time zones, but Operating Instructions between entities in multiple time zones is one example of
instances that may need time identification when issuing and receiving Operating Instructions.
17. Why did the drafting team remove the protocol requiring alphanumeric clarifiers?
Based on feedback from industry and consideration of the NERC Board resolution, the drafting team
chose to remove alphanumeric clarifiers as a required protocol. Entities are free to include it in their
documented communication protocols.
18. Why is there a requirement for the use of the English language?
The drafting team included this part to carry forward the same use of English language included in COM001-1, Requirement R4 and to retire this requirement from COM-001. The requirement continues to
permit the issuer and receiver to use an agreed to alternate language. This has been retained since use of
an alternate language on a case-by-case basis may serve to better facilitate effective communications
where the use of English language may create additional opportunities for miscommunications. Part 1.1
requires the use of English language when issuing oral or written (e.g. switching orders) Operating
Instructions. This creates a standard language (unless agreed to otherwise) for use when issuing
commands that could change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. It also clarifies that an alternate language can be
used internally within the organization. The phrase has been modified slightly from the language in COM001-1, Requirement R4 to incorporate the term “Operating Instruction,” which defines the
communications that require the use of the documented communications protocols.
Requirements R2 and R3 and Measures M2 and M3
19. Is there an obligation on the part of the entity issuing an Operating Instruction to ensure the
receiving operator is trained to receive it?
No. It is the responsibility of the receiving entity to ensure that their operator has received training prior
to receiving an Operating Instruction.
20. Why is there a requirement to conduct initial training?
The OPCP SDT has included an initial training requirement in the standard in response to the NERC Board
of Trustees’ resolution, which directs that a training requirement be included in the COM-002-4 standard.
Additionally, requiring entities that issue and/or receive Operating Instructions to conduct initial training
with their operating personnel will ensure that all applicable operators will be trained in three-part
communication. The OPCP SDT believes this training will reduce the possibility of a miscommunication,
which could eventually lead to action or inaction harmful to the reliability of the Bulk Electric System.
Ongoing training would fall under an entity’s training program in PER-005 or could be listed as a type of
corrective action under Requirement R4. As such, this requirement is not in conflict with PER-005, but
complements it.
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21. Current operating personnel issue and receive Operating Instructions now and thus it is not
possible to train them on documented protocols *prior* to their issuing or receiving their first
Operating Instruction. If training takes place before the enforcement date for COM-002-4,
would an entity meet the expectations of Requirement R2 and/or R3?
Yes.
Requirement R4 and Measure M4
22. Would you please provide more specificity as to how the R.4.1 and 4.2 assessments may be
performed?
An entity could perform an assessment by listening to random samplings of each of their operating
personnel issuing and/or receiving Operating Instructions. If there were instances where an Operator
deviated from the entity’s protocols, the entity would provide feedback to the operator in question in any
method it sees as appropriate. An example would be counseling or retraining the operator on the
protocols.
An entity could assess the effectiveness of its protocols by reviewing instances where operators deviated
from those protocols and determining if whether the deviations were caused by operator error or by
flaws in the protocols that need to be changed.
23. Doesn’t Measure M4 extend beyond the scope of the requirement when it addresses
communications which deviated from the protocol and contributed to an emergency?
The purpose of COM-002-4 is “To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of miscommunication that could lead
to action or inaction harmful to the reliability of the Bulk Electric System (BES).” If the deviation from the
protocol contributed to an emergency, the purpose of this standard was not met. The entity must
determine what caused that deviation and address any necessary corrective actions.
Requirements R5 and R6 and Measures M5 and M6
24. What is defined as an Emergency and who is responsible for declaring when an Emergency
begins and ends?
The NERC Glossary of Terms defines Emergency as “Any abnormal system condition that requires
automatic or immediate manual action to prevent or limit the failure of transmission facilities or
generation supply that could adversely affect the reliability of the Bulk Electric System.” It is expected
that these are abnormal and rare circumstances. There is not an expectation that an Emergency be
declared. For further information, please refer to Question 15.
25. Is it a violation of R5 if three-part communication is not used, but an alternative action is taken?
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If an operator issues an Operating Instruction during an Emergency and, based on the response from the
receiver, or lack thereof, chooses to take an alternative action, that operator has satisfied Requirement R5
and is not in violation.
26. How does the SDT envision operators differentiating, during Real-time, between Emergency
Operating Instructions and non-emergency Operating Instructions? Are the operators to
explicitly say "this is an Emergency Operating Instruction"?
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Their use is measured for compliance/enforcement differently using the operating
condition as an indicator of which compliance/enforcement approach applies. In other words, it is not the
drafting team’s expectation that the operator must differentiate between Emergency and non-Emergency
Operating Instructions.
27. Does this standard require TOPs to provide evidence of another parties' compliance in Measure
M6?
No. The Measures provide various options that the drafting team considered as ways to demonstrate
compliance for Requirement R6. It is not an exhaustive list, and in no way places an expectation on any
entity that they must provide evidence of another party's compliance. It simply provides a few options to
consider.
28. Can you provide an example of an alternative action being taken?
The following scenario is provided as an example of an alternative action:
A Transmission Operator (TOP) calls a Generator Operator (GOP) to reduce generation due to an
Emergency. The GOP does not respond verbally. At that point the TOP could:
Ask if the GOP understood the Operating Instruction (alternative action).
Hang up and redial the GOP, assuming that the communication line was dead (alternative action),
Request a different generator that is effective to reduce (alternative action);
or
Call a different contact at the GOP (alternative action)
29. Must the receiver repeat the Operating Instruction back verbatim?
No. The Operating Instruction does not have to be repeated verbatim. The issuer must confirm that the
receiver’s response of the Operating Instruction was correct.
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Exhibit J
Table of Issues and Directives COM-002-4
Table of Issues and Directives
Project 2007-02
Operating Personnel Communications Protocols
Table of Issues and Directives Associated with COM-002-4
Source
FERC Order No.
693, P 512 and
540 (Part 1)
Directive Language
512. The Commission finds that, during both
normal and emergency operations, it is
essential that the transmission operator,
balancing authority and reliability coordinator
have communications with distribution
providers. In response to APPA, as discussed
above, any distribution provider that is not a
user, owner or operator of the Bulk-Power
System would not be required to comply with
COM-002-2, even though the Commission is
requiring the ERO to modify the Reliability
Standard to include distribution providers as
applicable entities. APPA’s concern that 2,000
public power systems would have to be added
to the compliance registry is misplaced, since,
as we explain in our Applicability discussion
above, we are approving NERC’s registry
process, including the registry criteria.
Therefore, we adopt our proposal to require
Disposition
Distribution Providers have been included as
applicable entities in COM-002-4
Section and/or
Requirement(s)
Applicability 4.1.2
Requirements R3 and R6
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
the ERO to modify COM-002-2 to apply to
distribution providers through its Reliability
Standards development process.
540. ... In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our
regulations, the Commission directs the ERO to
develop a modification to COM-002-2 through
the Reliability Standards development process
that: (1) expands the applicability to include
distribution providers as applicable entities; (2)
includes a new Requirement for the reliability
coordinator to assess and approve actions that
have impacts beyond the area view of a
transmission operator or balancing authority
and (3) requires tightened communications
protocols, especially for communications
during alerts and emergencies. Alternatively,
with respect to this final issue, the ERO may
develop a new Reliability Standard that
responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally,
we direct the ERO to include APPA’s
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
2
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
suggestions to complete the Measures and
Levels of Non-Compliance in its modification of
COM-002-2 through the Reliability Standards
development process.
FERC Order No.
693, P 531, 534,
535, 540 (Part 3)
531. We adopt our proposal to require the ERO
to establish tightened communication
protocols, especially for communications
during alerts and emergencies, either as part of
COM-002-2 or as a new Reliability Standard.
We note that the ERO’s response to the Staff
Preliminary Assessment supports the need to
develop additional Reliability Standards
addressing consistent communications
protocols among personnel responsible for the
reliability of the Bulk-Power System.
COM-002-4 improves communications
protocols for the issuance of Operating
Instructions, in order to reduce the possibility
of miscommunication that could lead to
action or inaction harmful to the reliability of
the Bulk Electric System.
Definition of Operating
Instruction
Requirements R1, R2,
R3, R4, R5, R6 and R7
534. In response to MISO’s contention that
Blackout Report Recommendation No. 26 has
been fully implemented, we note that
Recommendation No. 26 addressed two
matters. We believe MISO is referring to the
second part of the recommendation requiring
NERC to “[u]pgrade communication system
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
3
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
hardware where appropriate” instead of
tightening communications protocols. While we
commend the ERO for taking appropriate
action in upgrading its NERCNet, we remind the
industry to continue their efforts in addressing
the first part of Blackout Recommendation No.
26. (Emphasis added)
535. Accordingly, we direct the ERO to either
modify COM-002-2 or develop a new Reliability
Standard that requires tightened
communications protocols, especially for
communications during alerts and
emergencies.
FERC Order No.
693, P 532
532. While we agree with EEI that EOP-001-0,
Requirement R4.1 requires communications
protocols to be used during emergencies, we
believe, and the ERO agrees, that the
communications protocols need to be
tightened to ensure Reliable Operation of the
Bulk-Power System. We also believe an integral
component in tightening the protocols is to
establish communication uniformity as much as
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
Reliability Standard EOP-001-2.1b —
Emergency Operations Planning (successor
standard to EOP-001-0) requires that the
emergency plans for each Transmission
Operator and Balancing Authority include:
communications protocols to be used during
emergencies (Requirement R3.1). This
requirement is compatible with COM-002-4,
which establishes the documented
Requirements R1, R5,
R6, R7
4
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
practical on a continent-wide basis. This will
eliminate possible ambiguities in
communications during normal, alert and
emergency conditions. This is important
because the Bulk- Power System is so tightly
interconnected that system impacts often cross
several operating entities’ areas.
Disposition
Section and/or
Requirement(s)
communications protocols and requires their
use.
COM-002-4 requires a set of protocols be
used by all applicable entities, establishing
communication uniformity as much as
practical on a continent-wide basis
533. Regarding APPA’s suggestion that it may
be beneficial to include communication
protocols in the relevant Reliability Standard
that governs those types of emergencies, we
direct that it be addressed in the Reliability
Standards development process.
FERC Order No.
693, P 514, 515
514. APPA notes that the Levels of NonCOM-002-4 includes Measures, VRFs and VSLs
Compliance for COM-002-2 are inadequate in
for each requirement.
two respects: (1) reliability coordinators are not
included in any Level of Non-Compliance and
(2) the Levels of Non-Compliance for
transmission operators and balancing
authorities in Compliance D.2 do not reference
Requirements R1 and R2. Therefore, APPA
would support approval of COM-002-2 as a
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
Section C, Measures
Section D, Compliance
5
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
mandatory Reliability Standard, but would not
support levying penalties for violating
incomplete portions of the Reliability Standard.
515. As stated in the Common Issues section, a
Reliability Standard is enforceable even if it
does not contain Levels of Non-Compliance.
However, the Commission agrees with APPA
that this Reliability Standard could be improved
by incorporating the changes proposed by
APPA. Therefore, when reviewing the Reliability
Standard through the Reliability Standards
development process, the ERO should consider
APPA’s concerns.
2003 Blackout
Report
Recommendation
No. 26
NERC should work with reliability coordinators
and control area operators to improve the
effectiveness of internal and external
communications during alerts, emergencies, or
other critical situations, and ensure that all key
parties, including state and local officials,
receive timely and accurate information. NERC
should task the regional councils to work
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
The requirements in COM-002-4 require the
use of predefined communications protocols
in order to reduce the possibility of a
miscommunication(s) that could lead to
action or inaction harmful to the reliability of
the Bulk Electric System (BES).
Requirements R1, R2,
R3, R4, R5, R6, and R7
6
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
together to develop communications protocols
by December 31, 2004, and to assess and
report on the adequacy of emergency
communications systems within their regions
against the protocols by that date.
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols
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Exhibit K
Analysis of Violation Risk Factors and Violation Security Levels COM-001-2
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Violation Risk Factor and Violation
Severity Level Justifications
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 – Communications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and
FERC Guidelines when proposing VRFs and VSL for the requirements under this project.
NERC Criteria – Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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Low er R isk Requirem ent
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs: 1
Guideline 1 – Consistency w ith the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
Id. at footnote 15.
2
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 19, 2012)
2
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•
Appropriate use of transmission loading relief
Guideline 2 – Consistency w ithin a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Guideline 3 – Consistency am ong Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline 4 – Consistency w ith NER C’s Definition of the Violation R isk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline 5 – Treatm ent of Requirem ents that Co-m ingle M ore Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
There are eleven requirements in the standard. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 are assigned a “High” VRF while the other three requirements
are assigned a “Medium” VRF.
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs
for each requirement, some requirements do not have multiple “degrees” of noncompliant
performance, and may have only one, two, or three VSLs.
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Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance
or is missing a single
vital component.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.
The performance or
product has limited
value in meeting the
intent of the
requirement.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed
for each requirement in the standard meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2 – Violation Severity Level Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3 – Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
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Guideline 4 – Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Guideline 5- Treatment of Requirements that Co-mingle More than One
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
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VRF Justifications – COM-001-2, R1-R6
Proposed VRF
Discussion
High
Obligation:
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Proposed VSLs for COM-001-2, R1-R6
R#
R1
R2
R3
Lower
N/A
N/A
N/A
Moderate
High
Severe
N/A
The Reliability Coordinator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R1, Parts 1.1
or 1.2, except when the
Reliability Coordinator
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.
N/A
The Reliability Coordinator
failed to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R2, Parts 2.1 or 2.2.
The Reliability Coordinator failed
to designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R2, Parts 2.1 or 2.2.
N/A
The Transmission Operator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6,
except when the
Transmission Operator
detected a failure of its
Interpersonal Communication
The Transmission Operator failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R3, Parts 3.1, 3.2,
3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator
detected a failure of its
Interpersonal Communication
capability in accordance with
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Proposed VSLs for COM-001-2, R1-R6
R4
R5
R6
N/A
N/A
N/A
capability in accordance with
Requirement R10.
Requirement R10.
N/A
The Transmission Operator
failed to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R4, Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed
to designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R4, Parts 4.1, 4.2, 4.3, or 4.4.
N/A
The Balancing Authority failed
to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R5, Parts 5.1, 5.2,
5.3, 5.4, or 5.5, except when the
Balancing Authority detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R10.
N/A
The Balancing Authority failed
to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R6, Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R6, Parts 6.1, 6.2, or 6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a revision of COM001-1.1, R1 and its sub-requirements. Each subViolation Severity Level Assignments
requirement was separated out into a new standShould Not Have the Unintended
Consequence of Lowering the Current Level alone requirement. The VSLs for the approved
sub-requirements are binary; however, proposed
of Compliance
in these VSLs are increments because each entity
may have multiple entities for which it must have
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Proposed VSLs for COM-001-2, R1-R6
an Interpersonal Communication capability.
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments
Should Ensure Uniformity and Consistency
in the Determination of Penalties
N/A
Guideline 2a: The Single Violation Severity
Level Assignment Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R7
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements; only one VRF is assigned, so there
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VRF Justifications – COM-001-2, R7
Proposed VRF
Medium
is no conflict.
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, the Distribution Provider VRF is Medium because is not required
to have an Alternative Interpersonal Communication and is not subject to
Blackstart situations like that of the Generator Owner in Requirement R8.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly; however, Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
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Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
Severe
N/A
The Distribution Provider
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R7, Parts 7.1
or 7.2, except when the
Distribution Provider
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to the violation and the VSLs follow the guidelines
for incremental violations.
FERC VSL G1
The proposed requirement is a revision of COM-001-1.1,
R1 and its sub-requirements. Each sub-requirement was
separated out into a new stand-alone requirement. The
VSLs for the approved sub-requirements are incremental
and this is reflected in the proposed VSLs.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
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Proposed VSLs for COM-001-2, R7
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as used in
the associated requirement, and is, therefore, consistent
with the requirement.
The VSL is based on a single violation and not cumulative
violations.
VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High). The Generator Owner may be subject to Blackstart plans
and system restoration.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
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VRF Justifications – COM-001-2, R8
Proposed VRF
High
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R8
R#
R8
Lower
N/A
Moderate
High
N/A
The Generator Operator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R8, Parts 8.1
or 8.2, except when a
Generator Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
Severe
The Generator Operator failed
to have Interpersonal
Communication capability with
two or more of the entities
listed in Requirement R8, Parts
8.1 or 8.2, except when a
Generator Operator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to the violation and the VSLs follow the guidelines
for incremental violations..
FERC VSL G1
The most comparable VSLs for a similar requirement are
for the proposed analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This requirement specifies
the two-way nature of entities having Interpersonal
Communications capability. In other words, if one entity
is required to have Interpersonal Communications
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
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Proposed VSLs for COM-001-2, R8
capability with another entity, then the reciprocal should
also be required or the onus would be exclusively on one
entity. Since Requirement R3 and R5 are assigned
incremental VSLs, it appropriate for Requirement R8 to
also be assigned an incremental VSL.
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSLs use the same terminology as used in
the associated requirement, and are, therefore,
consistent with the requirement.
The VSLs are based on a single violation and not
cumulative violations.
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VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
The requirement contains only one objective; therefore, only one VRF was
assigned.
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Proposed VSLs for COM-001-2, R9
R#
R9
Lower
Moderate
High
Severe
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
equal to 4 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
equal to 6 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
equal to 8 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
OR
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
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Proposed VSLs for COM-001-2, R9
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
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VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
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Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes but
less than or equal to
70 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
80 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1, R3,
and R5, respectively
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes but
less than or equal to
90 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing
Authority failed to
notify the entities
identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 90 minutes.
VSL Justifications – COM-001-2, R10
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
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Proposed VSLs for COM-001-2, R10
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
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VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
R#
R11
Lower
N/A
Moderate
N/A
High
Severe
N/A
The Distribution Provider or Generator Operator that
detected a failure of its Interpersonal Communication
capability failed to consult with each entity affected by
the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a Generator
Operator, to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
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Proposed VSLs for COM-001-2, R11
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement.
The VSL is based on a single violation and not cumulative
violations.
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Violation Risk Factor and Violation
Severity Level Justifications
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 – Communications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and
FERC Guidelines when proposing VRFs and VSL for the requirements under this project.
NERC Criteria – Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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Low er R isk Requirem ent
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs: 1
Guideline 1 – Consistency w ith the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
Id. at footnote 15.
2
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•
Appropriate use of transmission loading relief
Guideline 2 – Consistency w ithin a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Guideline 3 – Consistency am ong Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline 4 – Consistency w ith NER C’s Definition of the Violation R isk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline 5 – Treatm ent of Requirem ents that Co-m ingle M ore Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
There are eleven requirements in the standard. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 are assigned a “High” VRF while the other three requirements
are assigned a “Medium” VRF.
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs
for each requirement, some requirements do not have multiple “degrees” of noncompliant
performance, and may have only one, two, or three VSLs.
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Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance
or is missing a single
vital component.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.
The performance or
product has limited
value in meeting the
intent of the
requirement.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed
for each requirement in the standard meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2 – Violation Severity Level Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3 – Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
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Guideline 4 – Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Guideline 5- Treatment of Requirements that Co-mingle More than One
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
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VRF Justifications – COM-001-2, R1-R6
Proposed VRF
Discussion
High
Obligation:
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Proposed VSLs for COM-001-2, R1-R6
R#
R1
Lower
N/A
Moderate
High
Severe
N/A
The Reliability
Coordinator failed to
have Interpersonal
Communication
capability with one of
the entities listed in
Requirement R1, Parts
1.1 or 1.2, except when
the Reliability
Coordinator detected a
failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
The Reliability Coordinator failed to
havedesignate Alternative
Interpersonal Communication capability
with twoone or more of the entities
listed in Requirement R1R2, Parts 12.1
or 1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication capability
in accordance with Requirement
R102.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with twoone or more of the
R2
N/A
N/A
The Reliability
Coordinator failed to
designate Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R2, Parts
2.1 or 2.2.N/A
R3
N/A
N/A
The Transmission
Operator failed to have
Interpersonal
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Proposed VSLs for COM-001-2, R1-R6
R4
R5
N/A
N/A
Communication
capability with one of
the entities listed in
Requirement R3, Parts
3.1, 3.2, 3.3, 3.4, 3.5, or
3.6, except when the
Transmission Operator
detected a failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
entities listed in Requirement R3, Parts
3.1, 3.2, 3.3, 3.4, 3.5, or 3.6, except
when the Transmission Operator
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Transmission
Operator failed to
designate Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R4, Parts
4.1, 4.2, 4.3, or 4.4.N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3, or
4.4.
N/A
The Balancing Authority
failed to have
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R5, Parts
5.1, 5.2, 5.3, 5.4, or 5.5,
except when the
Balancing Authority
detected a failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
The Balancing Authority failed to have
Interpersonal Communication capability
with twoone or more of the entities
listed in Requirement R5, Parts 5.1, 5.2,
5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
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Proposed VSLs for COM-001-2, R1-R6
R6
N/A
N/A
The Balancing Authority
failed to designate
Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R6, Parts
6.1, 6.2, or 6.3.N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or 6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is
an incremental aspect to - Severe: The
performance or product measured does
not substantively meet the violation
andintent of the VSLs follow the
guidelines for incremental
violationsrequirement.
FERC VSL G1
The proposed requirement is a revision
of COM-001-1.1, R1 and its subrequirements. Each sub-requirement
was separated out into a new standalone requirement. The VSLs for the
approved sub-requirements are binary;
however, proposed in these VSLs are
increments because each entity may
have multiple entities for which it must
have an Interpersonal Communication
capability. and this is reflected in the
proposed VSLs.
Violation Severity Level Assignments Should Not
Have the Unintended Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should Ensure
Uniformity and Consistency in the Determination of
Penalties
N/A
Guideline 2a: The Single Violation Severity Level
Assignment Category for "Binary" Requirements Is
Guideline 2b:
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and consistency
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Proposed VSLs for COM-001-2, R1-R6
Not Consistent
Guideline 2b: Violation Severity Level Assignments
that Contain Ambiguous Language
FERC VSL G3
in the determination of similar
penalties for similar violations.
The proposed VSL uses the same
terminology as used in the associated
requirement, and is, therefore,
consistent with the requirement.
Violation Severity Level Assignment Should Be
Consistent with the Corresponding Requirement
FERC VSL G4
Violation Severity Level Assignment Should Be Based
on A Single Violation, Not on A Cumulative Number
of Violations
The VSL is based on a single violation
and not cumulative violations.
VRF Justifications – COM-001-2, R7
Proposed VRF
MediumHigh
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF is assigned, so there
is no conflict.
COM-001-2, the Distribution Provider VRF is Medium because is not required
to have an Alternative Interpersonal Communication and is not subject to
Blackstart situations like that of the Generator Owner in Requirement
R8.COM-001-2, Requirement R7 is an analog to Parts 3.3 and 5.3 and they
have the same VRF (High).
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VRF Justifications – COM-001-2, R7
Proposed VRF
MediumHigh
Discussion
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly; however, affect the electrical
state or the capability of the Bulk Power System and could lead to Bulk Power
System instability, separation, or cascading failures are not likely to occur due
to a failure to notify another entity of the failure.. Therefore, this requirement
is assigned a MediumHigh VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
N/A
The Distribution Provider
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R7, Parts 7.1
or 7.2, except when the
Distribution Provider
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.N/A
Severe
The Distribution Provider failed
to have Interpersonal
Communication capability with
twoone or more of the entities
listed in Requirement R7, Parts
7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to - Severe: The performance or product measured
does not substantively meet the violation andintent of the
VSLs follow the guidelines for incremental
violationsrequirement.
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Proposed VSLs for COM-001-2, R7
FERC VSL G1
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
The proposed requirement is a revision of COM-001-1.1,
R1 and its sub-requirements. Each sub-requirement was
separated out into a new stand-alone requirement. The
VSLs for the approved sub-requirements are
incrementalbinary and this is reflected in the proposed
VSLs.
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as used in
the associated requirement, and is, therefore, consistent
with the requirement.
The VSL is based on a single violation and not cumulative
violations.
VRF Justifications – COM-001-2, R8
Proposed VRF
High
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VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
N/A
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High). The Generator Owner may be subject to Blackstart plans
and system restoration.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R8
R#
Lower
Moderate
R8
N/A
N/A
High
The Generator Operator
failed to have Interpersonal
Communication capability
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
Severe
The Generator Operator failed
to have Interpersonal
Communication capability with
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Proposed VSLs for COM-001-2, R8
with one of the entities listed
in Requirement R8, Parts 8.1
or 8.2, except when a
Generator Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.N/A
twoone or more of the entities
listed in Requirement R8, Parts
8.1 or 8.2, except when a
Generator Operator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to - Severe: The performance or product
measured does not substantively meet the violation
andintent of the VSLs follow the guidelines for
incremental violations..requirement.
FERC VSL G1
The most comparable VSLs for a similar requirement are
for the proposed analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This requirement specifies
the two-way nature of entities having Interpersonal
Communications capability. In other words, if one entity
is required to have Interpersonal Communications
capability with another entity, then the reciprocal should
also be required or the onus would be exclusively on one
entity. Since Requirement R3 and R5 are assigned
incrementalbinary VSLs, it appropriate for Requirement
R8R7 to also be assigned an incrementala binary VSL.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b: Violation Severity
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
13
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Proposed VSLs for COM-001-2, R8
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSLs use the same terminology as used in
the associated requirement, and are, therefore,
consistent with the requirement.
The VSLs are based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
COM-001-2, Requirement R9 is a requirement for entities to test their
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
14
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VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
Discussion
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R9
R#
Lower
Moderate
High
Severe
R9
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
equal to 4 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
equal to 6 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
equal to 8 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
OR
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
15
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Proposed VSLs for COM-001-2, R9
upon an
unsuccessful test.
upon an
unsuccessful test.
upon an
unsuccessful test.
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
16
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Proposed VSLs for COM-001-2, R9
Be Consistent with the Corresponding
Requirement
therefore, consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not
cumulative violations.
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
17
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VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes but
less than or equal to
70 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
80 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1, R3,
and R5, respectively
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes but
less than or equal to
90 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing
Authority failed to
notify the
identified entities
identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 90 minutes.
VSL Justifications – COM-001-2, R10
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
18
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Proposed VSLs for COM-001-2, R10
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Discussion
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
19
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VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
R#
Lower
Moderate
High
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
Severe
20
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Proposed VSLs for COM-001-2, R11
R11
N/A
N/A
N/A
The Distribution Provider or Generator Operator that
detected a failure of its Interpersonal Communication
capability failed to consult with each entity affected by
the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a
Generatorits Transmission Operator, and Balancing
Authority to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
21
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Proposed VSLs for COM-001-2, R11
Assignment Should Be
Consistent with the
Corresponding Requirement
requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative
violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
22
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Exhibit L
Analysis of Violation Risk Factors and Violation Security Levels COM-002-4
Project 2007-02 – Operating Personnel Communications Protocols
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM-002-4 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL Justifications
2
Project YYYY-##.# - Project Name
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL Justifications
3
Project YYYY-##.# - Project Name
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL Justifications
4
Project YYYY-##.# - Project Name
VRFs for COM-002-4:
There are seven requirements in COM-002-4, draft 2. Requirements R1,R2, and R3 are assigned a “Low” VRF. R1 now reads:
”Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop documented communications
protocols for its operating personnel that issue and receive Operating Instructions. The protocols shall, at a minimum:“ R2 now
reads:” Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall conduct initial training for each of its
operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual operator issuing an Operating Instruction.“ R3
now reads: “Each Distribution Provider and Generator Operator shall conduct initial training for each of its operating personnel
who can receive an oral two-party, person-to-person Operating Instruction prior to that individual operator receiving an oral
two-party, person-to-person Operating Instruction to either:” Requirement R4 is assigned a “Medium” VRF. R4 now reads:
”Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall at least once every twelve (12) calendar
months: This Requirement warrants a VRF of “Medium” because R4 is a requirement in an operations planning time frame that,
if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability to effectively
monitor and control the bulk electric system. However, a violation of this requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures. ” Requirement R5, R6 and R7 are assigned a “High” VRF. R5 now reads: ”Each
Balancing Authority, Reliability Coordinator, and Transmission Operator that issues an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding written or oral single-party to multiple-party burst Operating Instructions,
shall either:” R6 is a new requirement which reads “Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating Instruction during an Emergency, excluding
written or oral single-party to multiple-party burst Operating Instructions, shall either:” R7 is a new requirement which reads
“Each Balancing Authority, Reliability Coordinator, and Transmission Operator that issues a written or oral single-party to
multiple-party burst Operating Instruction during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction.” These Requirements warrant VRFs of “High” because failure to
use the communications protocols during an emergency could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures.
NERC Criteria - Violation Severity Levels
VRF and VSL Justifications
5
Project YYYY-##.# - Project Name
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
VRF and VSL Justifications
6
Project YYYY-##.# - Project Name
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communications protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development of documented communications protocols by entities that will
both issue and receive “Operating Instructions” that reduce the possibility of miscommunication which
could eventually lead to action or inaction harmful to the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Low,” which is consistent with NERC
guidelines for similar requirements.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R1 contains only one objective which is to document clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
only one objective, only one VRF was assigned.
Proposed VSL
Lower
Moderate
The responsible entity did not
specify the instances that
require time identification
when issuing an oral or written
Operating Instruction and the
format for that time
identification, as required in
Requirement R1, Part 1.5
The responsible entity did not
require the issuer and receiver
of an oral or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R1, Part 1.1. An
alternate language may be
used for internal operations.
OR
The responsible entity did not
specify the nomenclature for
Transmission interface
Elements and Transmission
interface Facilities when issuing
an oral or written Operating
Instruction, as required in
Requirement R1, Part 1.6.
VRF and VSL Justifications
High
The responsible entity did not
include Requirement R1, Part 1.4
in its documented communication
protocols.
Severe
The responsible entity did not
include Requirement R1, Part 1.2
in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part 1.3
in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
VRF and VSL Justifications
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols, with varied VSLs based on the severity of the potential risk to the bulk electric
system if the protocols were not used. If no communication protocols were addressed at all then the VSL
is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R1.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
VRF and VSL Justifications
Non CIP
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM-002-4, R2
Proposed VRF
Low
NERC VRF Discussion
R2 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 establishes that entities who issue and receive Operating Instructions shall conduct initial training with
their operating personnel to ensure that all applicable operators will be trained on their documented
communication protocols established in Requirement R1. This training reduces the possibility of a
miscommunication, which could eventually lead to action or inaction harmful to the reliability of the Bulk
Electric System, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
Only one VRF is assigned for this requirement.
FERC VRF G2 Discussion
VRF and VSL Justifications
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 3- Consistency among Reliability Standards:
This requirement establishes that each Balancing Authority, Reliability Coordinator and Transmission
Operator conduct initial training with each of its operating personnel responsible for the Real-time
operation of the BES on documented communication protocols to reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of the bulk
electric system. This VRF is consistent with other training requirements within the body of NERC
Reliability Standards, including CIP-004-5.1 Requirements R1 and R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
Violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Low,” which is consistent with NERC guidelines for similar
requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R2 contains only one objective which is to conduct initial training for each of its
operating personnel responsible for the Real-time operation of the BES. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
An individual operator responsible
for the Real-time operation of the
interconnected Bulk Electric
System at the responsible entity
issued an Operating Instruction,
prior to being trained on the
Severe
An individual operator responsible
for the Real-time operation of the
interconnected Bulk Electric
System at the responsible entity
issued an Operating Instruction
during an Emergency prior to
14
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
documented communications
protocols developed in
Requirement R1.
VRF and VSL Justifications
being trained on the documented
communications protocols
developed in Requirement R1.
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs. These VSLs were determined based on the
potential consequences of an operator issuing an Operating Instruction without having first received
training on the communication protocols. An operator who is not trained on the communication
protocols could miscommunicate an Operating Instruction, which could put the BES in an undesirable
state. This warrants a High VSL. An operator who is not trained on the communication protocols could
miscommunicate an Operating Instruction during an Emergency, which could directly put the BES in an
undesirable state. This warrants a Severe VSL.
Since training requirements were not in prior versions of COM-002, the introduction of this training
requirement will not have the unintended consequence of lowering the current level of compliance.
VRF and VSL Justifications
16
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment is not R2 binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R3.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
VRF and VSL Justifications
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 1- Consistency w/ Blackout Report:
R3 establishes that entities who only receive Operating Instructions shall conduct initial training with their
operating personnel to ensure that all applicable operators will be trained in three part communication.
This training reduces the possibility of a miscommunication, which could eventually lead to action or
inaction harmful to the reliability of the Bulk Electric System, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement establishes that Distribution Providers and Generator Operators conduct initial training
with each of its operating personnel responsible for the Real-time operation of the BES on three part
communication to reduce the possibility of miscommunication which could eventually lead to action or
inaction harmful to the reliability of the bulk electric system. This VRF is consistent with other training
requirements within the body of NERC Reliability Standards, including CIP-004-5.1 Requirements R1 and
R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to conduct initial training for individual operators on three part communication could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively monitor
and control the bulk electric system. However, violation of the requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures. The VRF for this requirement is “Low,” which
is consistent with NERC guidelines for similar requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R3 contains only one objective which to conduct initial training with individual
system operators on three part communication. Since the requirement has only one objective, only one
VRF was assigned.
19
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
An individual operator at the
responsible entity received an
Operating Instruction prior to
being trained.
Severe
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being trained.
20
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs. These VSLs were determined based on the
potential consequences of an operator receiving an Operating Instruction without having first received
training on the communication protocols. An operator who is not trained on three part communication
could miscommunicate an Operating Instruction, which could put the BES in an undesirable state. This
warrants a High VSL. An operator who is not trained on three part communication could miscommunicate
an Operating Instruction during an Emergency, which could directly put the BES in an undesirable state.
This warrants a Severe VSL.
Since training requirements were not in prior versions of COM-002, the introduction of this training
requirement will not have the unintended consequence of lowering the current level of compliance.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
VRF and VSL Justifications
Guideline 2a:
The VSL assignment for R3 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
21
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
VRF and VSL Justifications
Non CIP
22
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement in an Operations planning requirement time frame that, if violated, could directly
affect the ability to effectively monitor and control the bulk electric system. However, a violation of this
requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
This requirement establishes that responsible entities from R1 to periodically assess their operator’s
adherence to the entity’s documented communication protocols and provide feedback to those operators.
It also requires entities to assess the effectiveness of these protocols and modify them where necessary.
The requirement addresses Recommendation 26 of the Blackout Report. The VRF for this requirement is
“Medium,” which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
FERC VRF G2 Discussion
VRF and VSL Justifications
23
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 3- Consistency among Reliability Standards:
This requirement calls for responsible entities from R1 to periodically assess their operator’s adherence to
the entity’s documented communication protocols and provide feedback to those operators. It also
requires entities to assess the effectiveness of these protocols and modify them where necessary. This
VRF is consistent with similar requirements within the body of NERC Reliability Standards, including PER005-1 Requirements R1 and R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
R4 is a requirement in an Operations planning requirement time frame that, if violated, could directly
affect the ability to effectively monitor and control the bulk electric system. However, a violation of this
requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R4 contains only one objective which is to implement clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
only one objective, only one VRF was assigned.
Proposed VSL
Lower
The responsible entity assessed
adherence to the documented
communications protocols in
Requirements R1 by its
operating personnel that issue
and receive Operating
Instructions and provided
VRF and VSL Justifications
Moderate
The responsible entity assessed
adherence to the documented
communications protocols in
Requirement R1 by its
operating personnel that issue
and receive Operating
Instructions, but did not
High
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating Instructions
OR
Severe
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating Instructions
AND
24
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
feedback to those operating
personnel and took corrective
action, as appropriate
AND
The responsible entity assessed
the effectiveness of its
documented communications
protocols in Requirement R1 for
its operating personnel that
issue and receive Operating
Instructions and modified its
documented communication
protocols, as necessary
AND
The responsible entity
exceeded twelve (12) calendar
months between assessments.
VRF and VSL Justifications
provide feedback to those
operating personnel
OR
The responsible entity assessed
adherence to the documented
communications protocols in
Requirements R1 by its
operating personnel that issue
and receive Operating
Instructions and provided
feedback to those operating
personnel but did not take
corrective action, as
appropriate
OR
The responsible entity assessed
the effectiveness of its
documented communications
protocols in Requirement R1
for its operating personnel that
issue and receive Operating
Instructions, but did not modify
its documented communication
protocols, as necessary.
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for its
operating personnel that issue and
receive Operating Instructions.
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for its
operating personnel that issue and
receive Operating Instructions.
25
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
VRF and VSL Justifications
26
Project YYYY-##.# - Project Name
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed four VSLs to establish the severity of an entity not
assessing their operator’s adherence to the entity’s communications protocols and/or not assessing the
effectiveness of those protocols at least once every 12 calendar months. If an entity evaluated the
documented communications protocols developed in Requirement R1, but exceeded twelve (12) calendar
months between evaluations then it is a “Low” VSL, since the performance or product measured has
significant value as it almost meets the full intent of the requirement.
If an entity assessed adherence to the documented communications protocols in Requirements R1 by its
operating personnel that issue and receive Operating Instructions but did not provide feedback to those
operating personnel it is a “Medium” VSL. If an entity assessed adherence to the communications
protocols by its operating personnel and provided feedback to those personnel but did not take corrective
action, as appropriate, it is also a “Medium” VSL. If an entity assessed the effectiveness of its protocols for
its operating personnel but did not modify its documented communication protocols, as necessary, it is
also a “Medium” VSL. The value of “Medium” is justified based one significant element (or a moderate
percentage) of the required performance is missing but the performance or product measured still has
significant value in meeting the intent of the requirement.
If an entity did not assess adherence to the documented communications protocols in Requirements R1 by
its operating personnel then it is a “High” VSL. If an entity did not assess the effectiveness of its
documented communications protocols in Requirements R1 for its operating personnel it is a “High” VSL.
The value of “High” is justified because the entity is missing more than one significant element (or is
missing a high percentage) of the required performance.
If an entity did not assess adherence to the documented communications protocols by its operating
personnel and it did not assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel, then it is a “Severe” VSL. The value of “Severe” is justified
because the performance measured does not meet the intent of the requirement.
VRF and VSL Justifications
27
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
VRF and VSL Justifications
28
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R4 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
29
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R5
Proposed VRF
High
NERC VRF Discussion
R5 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
VRF and VSL Justifications
30
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 1- Consistency w/ Blackout Report:
R5 requires entities who issue an Operating Instruction during an Emergency to use three part
communication or take an alternative action if the receiver does not respond. The requirement addresses
Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which is consistent
with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement mandates the use of three part communication for entities that issue Operating
Instructions during an Emergency in order to reduce the possibility of miscommunication. A
miscommunication could lead to action or inaction harmful to the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
R5 is a requirement in an Operations Planning time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R5 contains only one objective which is for entities that issue Operating
Instructions to use three part communication or take an alternative action if the receiver does not
respond to reduce the possibility of miscommunication which could lead to action or inaction harmful to
the reliability of the bulk electric system. Since the requirement has only one objective, only one VRF was
assigned.
31
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
Proposed VSL
Lower
N/A
Moderate
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
•
Confirmed the receiver’s
response if the repeated
information was correct
(in accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
VRF and VSL Justifications
Took an alternative action
if a response was not
received or if the
Operating Instruction was
not understood by the
receiver.
High
N/A
Severe
The responsible entity that issued
an Operating Instruction during an
Emergency did not take one of the
following actions:
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect or
if requested by the receiver.
•
Took an alternative action if a
response was not received or
if the Operating Instruction
was not understood by the
receiver.
AND
32
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
VRF and VSL Justifications
33
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure to use three part
communication when issuing an Operating Instruction during an Emergency.
If an entity, when issuing an Operating Instruction during an Emergency, did not use three part
communication or take an alternative action if the receiver does not respond, yet instability, uncontrolled
separation, or cascading failures did not occur as a result, the entity violated the Requirement with a
“Medium” VSL. The value of “Medium” is justified based one significant element (or a moderate
percentage) of the required performance is missing but the performance or product measured still has
significant value in meeting the intent of the requirement, which is to avoid action or inaction that is
harmful to the reliability of the Bulk Electric System.
If an entity, when issuing an Operating Instruction during an Emergency, did not use three part
communication or take an alternative action if the receiver does not respond, and instability, uncontrolled
separation, or cascading failures occurred as a result, the entity violated the Requirement with a “Severe”
VSL. The value of “Severe” is justified because the performance outcome does not meet the intent of the
requirement.
VRF and VSL Justifications
34
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R5 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
35
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R6
Proposed VRF
High
NERC VRF Discussion
R6 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
VRF and VSL Justifications
36
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R6
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 1- Consistency w/ Blackout Report:
R6 requires entities who receive an Operating Instruction during an Emergency to repeat, not necessarily
verbatim, the Operating Instruction and receive confirmation from the issuer that the response was
correct, or request that the issuer reissue the Operating Instruction. The requirement addresses
Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which is consistent
with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement mandates the use of three part communication for entities that receive Operating
Instructions during an Emergency in order to reduce the possibility of miscommunication. A
miscommunication could lead to action or inaction harmful to the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
R6 is a requirement in an Operations Planning time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R6 contains only one objective which is for entities that receive Operating
Instructions during an Emergency to repeat, not necessarily verbatim, the Operating Instruction in order
to reduce the possibility of miscommunication which could lead to action or inaction harmful to the
reliability of the bulk electric system. Since the requirement has only one objective, only one VRF was
assigned.
37
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R6
Proposed VSL
Lower
N/A
Moderate
The responsible entity did not
repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the issuer
that the response was correct,
or request that the issuer
reissue the Operating
Instruction when receiving an
Operating Instruction.
High
N/A
Severe
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
VRF and VSL Justifications
38
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure of the recipient of an
Operating Instruction to use three part communication after receiving an Operating Instruction during an
Emergency.
If an entity, when receiving an Operating Instruction during an Emergency, did not repeat, not necessarily
verbatim, the Operating Instruction during an Emergency and receive confirmation from the issuer that
the response was correct, or request that the issuer reissue the Operating Instruction when receiving an
Operating Instruction, yet instability, uncontrolled separation, or cascading failures did not occur as a
result, the entity violated the Requirement with a “Medium” VSL. The value of “Medium” is justified
based one significant element (or a moderate percentage) of the required performance is missing but the
performance or product measured still has significant value in meeting the intent of the requirement,
which is to avoid action or inaction that is harmful to the reliability of the Bulk Electric System.
If an entity, when receiving an Operating Instruction during an Emergency, did not repeat, not necessarily
verbatim, the Operating Instruction during an Emergency and receive confirmation from the issuer that
the response was correct, or request that the issuer reissue the Operating Instruction when receiving an
Operating Instruction, and instability, uncontrolled separation, or cascading failures occurred as a result,
the entity violated the Requirement with a “Severe” VSL. The value of “Severe” is justified because the
performance outcome does not meet the intent of the requirement.
VRF and VSL Justifications
39
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R6 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
40
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R7
Proposed VRF
High
NERC VRF Discussion
R7 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
VRF and VSL Justifications
41
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 1- Consistency w/ Blackout Report:
R7 requires entities that issue a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency to confirm or verify that the Operating Instruction was received by at least one
receiver. The requirement addresses Recommendation 26 of the Blackout Report. The VRF for this
requirement is “High,” which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement mandates entities that issue a written or oral single-party to multiple-party burst
Operating Instruction during an Emergency to confirm or verify that the Operating Instruction was
received by at least one receiver . A miscommunication could lead to action or inaction harmful to the
reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
R7 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R7 contains only one objective which requires entities that issue a written or
oral single-party to multiple-party burst Operating Instruction during an Emergency confirm or verify that
the Operating Instruction was received by at least one receiver of the Operating Instruction. Since the
requirement has only one objective, only one VRF was assigned.
42
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
Proposed VSL
Lower
N/A
Moderate
The responsible entity that that N/A
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction.
High
Severe
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
VRF and VSL Justifications
43
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure of the issuer of a written or
oral single-party to multiple-party burst Operating Instruction during an Emergency to confirm or verify
that the Operating Instruction was received by at least one receiver.
If an entity, when issuing a written or oral single-party to multiple-party burst Operating Instruction during
an Emergency, did not confirm or verify that the Operating Instruction was received by at least one
receiver, yet instability, uncontrolled separation, or cascading failures did not occur as a result, the entity
violated the Requirement with a “Medium” VSL. The value of “Medium” is justified based one significant
element (or a moderate percentage) of the required performance is missing but the performance or
product measured still has significant value in meeting the intent of the requirement, which is to avoid
action or inaction that is harmful to the reliability of the Bulk Electric System.
If an entity, when issuing a written or oral single-party to multiple-party burst Operating Instruction during
an Emergency, did not confirm or verify that the Operating Instruction was received by at least one
receiver, and instability, uncontrolled separation, or cascading failures occurred as a result, the entity
violated the Requirement with a “Severe” VSL. The value of “Severe” is justified because the
performance outcome does not meet the intent of the requirement.
VRF and VSL Justifications
44
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R7 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
VRF and VSL Justifications
45
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
46
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
for their interdependence
VRF and VSL Justifications
47
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit M
Summary of Development History and Complete Record of Development COM-001-2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Summary of Development History
Project 2006-06 – Reliability Coordination
The development record for proposed Reliability Standard COM-001-2 is summarized
below.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give
“due weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is
derived from the reliability coordination standard drafting team (“SDT”). For this project, the
standard drafting team consisted of industry experts, all with a diverse set of experiences. A
roster of the team members is included in Exhibit P.
II.
Standard Development History
A. Standard Authorization Request Development
Project 2006-06 – Reliability Coordination was initiated on December 18, 2006 as a SAR
for revisions to existing standards. The SAR was posted for a 30-day comment period from
January 15, 2007 to February 14, 2007. NERC received 11 sets of comments from more than 31
different individuals from more than 15 companies representing 9 of the 10 industry segments.
Most commenters disagreed with the broad scope of the SAR since it included revisions to 27
standards. In response to the comments, NERC revised the purpose statement of the SAR and
reduced the number of standards considered for revision from 27 to10, narrowing the scope of
the project.
A second draft of the SAR was posted for a comment period from March 19, 2007 to
April 17, 2007. NERC received 19 sets of comments from 52 different individuals from
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2012).
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
approximately 40 companies in 8 of the 10 industry segments. In response to comments, NERC
corrected references of “FERC NOPR” to “Order No. 693” and made small changes to the
detailed and brief description of proposed changes. The SAR was approved by the Standards
Committee and moved forward into development.
B. First Posting – Comment Period
COM-001-2 was first posted for a 45-day comment period from August 5, 2008 to
September 16, 2008. NERC received 29 sets of comments from more than 70 different
individuals, including 50 companies and representing 8 of the 10 industry segments. 2 In
response to comments, the SDT made the following changes to the draft COM-001-2 standard:
•
Replaced “telecommunications facilities” with “interpersonal communications capabilities”
to better reflect the intent of the SDT.
•
Added the Transmission Service Provider (TSP), Load-serving Entity (LSE), and
Purchasing-Selling Entity (PSE) to the list of entities in Requirement R3 that must use
English Language for inter-entity communications.
•
Added a time requirement to Requirement R2.
•
Removed informational sentence from end of Requirement R3.
•
Reworded the violation severity levels (VSLs) to match changes in the Requirements.
•
Made other general language improvements to the Requirements and Measures.
C. Second Posting – Comment Period
2
COM-001-2 was posted along with six IRO (Interconnection Reliability Operations and Coordination) Reliability
Standards that will be filed in a separate petition.
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Second draft of the COM-001-2 standard was posted again for a 30-day public comment period
from July 10, 2009 to August 9, 2009. NERC received 31 sets of comments from more than 87
different individuals from over 62 companies in 8 of the 10 industry segments. The SDT made
the following changes to COM-001-2:
•
Proposed definitions for “Interpersonal Communication” and “Alternative Interpersonal
Communication.
•
Revised the wording of Requirement R2 to add clarity and revised Requirement R3 to
include the phrase “unless dictated by law…” to address legal requirements in some areas.
•
Removed the mitigation plan from Requirement R1 and Measure M1.
•
Added more VSLs for Requirement R2.
•
Removed Distribution Provider and Generator Operator from the Data Retention section of
Requirement R1.
D. Third Posting – Comment Period
The draft of the Reliability Coordination standard was posted for a third comment period
from January 4, 2010 to February 18, 2010. There were 42 sets of comments from more than
150 different individuals from 50 companies representing all 10 of NERC’s industry segments.
In response to comments, the SDT revised the definitions “Interpersonal Communication” and
“Alternative Interpersonal Communication.” The SDT also extensively revised Requirement R1
(now R9), to more specifically delineate Interpersonal and Alternative Interpersonal
Communication in tandem with the revisions of the definitions, and to specify the applicable
entity responsibility. The VRF for this Requirement was changed to “Medium.”
E. Fourth Posting – Formal Comment Period Initial Ballot
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
A fourth draft of the standard was posted for a formal comment period from January 18,
2011 to March 7, 2011, with an initial ballot held from February 25, 2011 to March 7, 2011. All
of the Reliability Coordination standards in Project 2006-06 were balloted together, and the
standards received a quorum of 87.10% and an approval of 49.54%. During the formal comment
period, 41 sets of comments were received from 168 different individuals from 112 companies
representing 9 of the 10 industry segments. In response to comments, the SDT made the
following changes to the standards:
•
Addressed the applicability of the standards and implementation plans by aligning COM001-2 to include the same entities and by removing LSE, PSE and TSP from the COM
standards.
•
Removed the phrase "to exchange Interconnection and operating information" in
Requirements R1 through R8 to clarify that the intent of the capability is NOT for the
exchange of data.
•
Added a new Requirement R11 to COM-001 for clarity regarding responsibilities of the
Distribution Provider and the Generator Operator when either entity experiences a failure of
its Interpersonal Communication capability.
•
Removed PSE and LSE from the COM-001-2 implementation plan.
As a result of the revisions, the SDT moved COM-001-2 to a successive ballot.
F. Fifth Posting – Comment Period, Successive Ballot, and Non-Binding Poll
Fifth draft of the COM-001-2 standard was posted for a comment period and non-binding
poll of the VRFs and VSLs from January 9, 2012 to February 9, 2012, with a successive ballot
and non-binding poll held from January 30, 2012 to February 9, 2012. COM-001-2 received a
quorum of 81.82% and an approval of 54.64% with a 71.35% approval for the VRFs and VSLs.
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The SDT received 62 sets of comments from 170 different individuals from approximately 106
companies representing 9 of 10 industry segments. In response to comments, the SDT made the
following changes to COM-001-2:
•
Removed “for the exchange of Interconnection and operating information” from the purpose
statement.
•
Made effective date language consistent with the current Standard Drafting Guidelines.
•
Added a part to Requirements R3 and R4 to address synchronous and asynchronous
connections.
•
Changed wording in Requirement R11 from “Mutually agreeable time” to “mutually
agreeable action.”
•
Made conforming word changes and capitalizations and fixed typos.
•
Made conforming changes to VSLs.
G. Sixth Posting – Comment Period, Successive Ballot and Non-binding Poll,
and Recirculation Ballot and Non-Binding Poll
In the sixth posting, COM-001-2 was posted for a comment period and non-binding poll
of the VRFs and VSLs from June 7, 2012 to July 6, 2012, with a successive ballot and nonbinding poll of the VRFs and VSLs. COM-001-2 received a 75.37% quorum, and an approval of
72.16%, with a 73.71% approval for the VRFs and VSLs. The SDT received 41 sets of
comments from 136 different individuals from 90 companies representing 9 of the 10 industry
segments. Slight wording changes were made to the COM-001-2 Requirements and Measures,
but none of the changes were substantive.
H. Seventh Posting – Recirculation Ballot
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For the seventh and final posting, COM-001-2 was posted for a recirculation ballot from
September 6, 2012 to September 17, 2012. COM-001-2 received industry approval with a
quorum of 80.35% and an approval of 75.01%.
I. Board of Trustees Approval
The final drafts of the COM-001-2 and COM-002-3 standards were presented to NERC’s
Board of Trustees for approval on November 7, 2012. The Board of Trustees approved the
standards, and NERC staff recommended that they be filed with applicable regulatory
authorities.
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project 2006-06 Reliability Coordination
Related Files
Status:
The Board of Trustees (BOT) adopted the IRO-002, IRO-005, and IRO-014 standards at their August 4, 2011 meeting. The standard IRO-001-3 was adopted by the BOT at their August 16, 2012 meeting. Standards
COM-001-2 and COM-002-3 were BOT adopted on November 7, 2012. IRO-002-3, IRO-005-4, and IRO-014-2 were filed with applicable regulatory authorities for approval on April 16, 2013. NERC staff is
preparing the filing for COM-001-2 and COM-002-3.
Purpose/Industry Need:
To ensure that the reliability-related requirements applicable to the Reliability Coordinator are clear, measurable, unique and enforceable; and to ensure that this set of requirements is sufficient to maintain reliability of
the Bulk Electric System.
Documents to be submitted for the FERC Filing of standards for Project 2006-06 - Reliability Coordination - IRO-002-3, IRO-005-4, IRO-014-2 (April 16, 2013)
Final Exhibit
DRAFT
Draft 7
COM-001-2
Clean (82) | Redline to Last Posting (83)| Redline to
Last Approved (84)
Implementation Plan and Mapping Document
Clean (85)| Redline to Last Posting (86)
ACTION
DATES
RESULTS
Recirculation Ballot
Info>> (89)
09/06/12 - 09/17/12
(closed)
Summary>> (90)
Ballot Results>> (91)
Vote>>
VRF/VSL Justification
Clean (87) | Redline to Last Posting (88)
Draft 6
COM-001-2
Clean (65) | Redline to last posting (66)
Implementation Plan and Mapping Document
Clean (67)| Redline to last posting (68)
COM-002-3
Clean | Redline to last posting | Redline to last
Recirculation Ballots
and Non-binding Polls:
COM-002-3
IRO-001-3
Summary>> (77)
Updated
06/27/12 - 07/06/12
(closed)
Ballot Results:
COM-002-3
Ballot Extension>> (73)
IRO-001-3
Updated Info>> (74)
Non-binding Poll
CONSIDERATION OF
COMMENTS
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
approved
Results:
Info>> (75)
Implementation Plan and Mapping Document
Clean | Redline to last posting
COM-002-3
Vote>>
IRO-001-3
IRO-001-3
Clean | Redline to last posting
Implementation Plan and Mapping Document
Clean | Redline to last posting
Supporting Materials:
Comment Form (Word) (69)
Successive Ballot and
Non-binding Poll:
Ballot Results:
COM-001-2 (78)
COM-001-2
06/27/12 - 07/11/12
(closed)
Info>> (76)
Non-binding Poll
Results:
Vote>>
COM-001-2 (79)
COM-001-1.1 (70)
Consideration of
Comments>> (81)
COM-002-2
VRF/VSL Justification for COM-001-1
Clean (71) | Redline (72)
VRF/VSL Justification for COM-002-3
Clean | Redline
Comment Period
Submit Comments>>
06/07/12 - 07/06/12
(closed)
Comments Received>>
(80)
VRF/VSL Justification for IRO-001-3
Clean | Redline
Draft 5
COM-001-2
Clean (50)| Redline to last posting (51)
Implementation Plan and Mapping Document
Clean (52)| Implementation Plan Redline to last
posting (53) |Mapping Document Redline to last
posting (54)
Extension>> (58)
Updated Info>> (59)
Info>> (60)
IRO-001-3
Clean | Redline to last posting | Redline to last
approved
01/30/12 - 02/09/12
(closed)
Vote>>
COM-002-3
Clean | Redline to last posting
Implementation Plan and Mapping Document
Clean | Implementation Plan Redline to last
posting |Mapping Document Redline to last posting
Full Records:
IRO-001-3
COM-001-2 (61)
COM-002-3
Successive Ballots and
Non-Binding Polls
Comment Period
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IRO-001-3
COM-001-2 (62)
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Comments Received>>
(63)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan and Mapping Document
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Draft 4 Reliability Coordination Standards
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IRO-001-2
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IRO-016-1
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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Draft 3 Reliability Coordination Standards
COM-001-2
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COM-002-3
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IRO-014-2
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Draft 2 Reliability Coordination Standards
COM-001-2
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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Reliability Coordination Standards
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COM-001-2
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Draft SAR Version 1
Reliability Coordination Standards
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(4)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Authorization Request Form
Title of Proposed Standard
Reliability Coordination (Project 2006-06)
Request Date
December 18, 2006
SAR Requestor Information
Name
Ellis Rankin
Primary Contact
Ellis Rankin
Telephone
214-743-6828
Fax
972-263-6710
E-mail
[email protected]
SAR Type (Check a box for each one
that applies.)
New Standard
Revision to existing Standards – see
list below
Withdrawal of existing Standard
Urgent Action
Purpose
The purpose of this set of standards is to ensure that the reliability coordinator has
processes, procedures, plans, and can use their tools and authorities to support real-time
operating reliability within its own reliability area and between reliability coordinator areas in
support of reliability of the interconnected bulk power systems.
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination – Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-003 — Reliability Coordination – Wide Area View
IRO-004 — Reliability Coordination – Operations Planning
IRO-005 — Reliability Coordination – Current Day Operations
IRO-007 — Monitoring the Wide Area
IRO-008 — Reliability Coordinator Analyses and Assessments
IRO-009 — Reliability Coordinator Actions to Operate Within IROLs
IRO-010 — Reliability Coordinator Data Specification and Collection
IRO-011 — Providing Data to the Reliability Coordinator
IRO-012 — Procedures, Processes or Plans for Preventing and Mitigating IROLs
IRO-013 — Reliability Coordinator Directives Relative to IROLs
IRO-014 — Procedures to Support Coordination between Reliability Coordinators
IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
ORG-020 — Reliability Coordinator Certification - Certification
ORG-021 — Reliability Coordinator Certification - Agreements
ORG-022 — Reliability Coordinator Certification - Personnel
ORG-023 — Reliability Coordinator Certification - Data Acquisition and Monitoring
ORG-024 — Reliability Coordinator Certification – System Analysis
ORG-025 — Reliability Coordinator Certification – Emergency Operations
ORG-026 — Reliability Coordinator Certification – Loss of Control Center Functionality
ORG-027 — Reliability Coordinator Certification – Restoration
SAR-1
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Standards Authorization Request Form
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
Several of the standards in this set are Version 0 standards. As the electric reliability
organization begins enforcing compliance with reliability standards under Section 215 of the
Federal Power Act in the United States and applicable statutes and regulations in Canada,
the industry needs a set of clear, measurable, and enforceable reliability standards. The
Version 0 standards, while a good foundation, were translated from historical operating and
planning policies and guides that were appropriate in an era of voluntary compliance. The
Version 0 standards and recent updates were put in place as a temporary starting point to
stand up the electric reliability organization and begin enforcement of mandatory standards.
However, it is important to update the standards in a timely manner, incorporating
improvements to make the standards more suitable for enforcement and to capture prior
recommendations that were deferred during the Version 0 translation.
Industry Need
1. Provide an adequate level of reliability for the North American bulk power systems — the
standards are complete and the requirements are set at an appropriate level to ensure
reliability.
2. Ensure they are enforceable as mandatory reliability standards with financial penalties —
the applicability to bulk power system owners, operators, and users, and as appropriate
particular classes of facilities, is clearly defined; the purpose, requirements, and
measures are results-focused and unambiguous; the consequences of violating the
requirements are clear.
3. Consider comments received during the initial development of this set of standards and
other comments received from ERO regulatory authorities and stakeholders (Attachment
1)
4. Bring the standards into conformance with the latest version of the Reliability Standards
Development Procedure and the ERO Rules of Procedure. (Attachment 2)
5. Satisfy the standards procedure requirement for five-year review of the standards.
Brief Description
The drafting team will review all of the requirements in this set of standards and eliminate
all of the requirements that are redundant. There are redundancies between requirements
in the IRO-sequence of standards and also redundancies between requirements in the IROsequence of standards and the ORG-sequence of standards, and redundancies with PER004, COM-001, COM-002, and PRC-001. Note that there will be a new standard to address
communication protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
The drafting team also needs to review requirements and ensure that the distinctions
between the functional entity and the real-time system operator are clear and distinct. The
requirements should be written for the functional entity.
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission operator.”
The drafting team needs to verify that requirements exempt the real time-operator from
SAR-2
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Standards Authorization Request Form
liability when making a good faith effort at preserving reliability.
A challenge has been to require that entities have ‘facilities’ in place and available to the
real-time system operators. These facilities are reviewed during certification, and unless
there is a specific requirement to review these facilities, they may not be reviewed after the
initial certification. To eliminate redundancy between the ‘certification’ standards and the
standards that are aimed more at real-time operations, the certification standards could be
phrased to clarify that entities are required to ‘have and maintain’ the specified facilities.
This would enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary, making periodic
checks of the facilities that are infrequently would motivate entities to maintain these
facilities, e.g., “Shall have a back up power supply for critical operations, and shall maintain
and test at least once per year.”
The results of the Operating Committee study on operator situational awareness tools
should be used to verify that the requirements in the certification standards will meet
reliability needs.
This project also needs to be coordinated with the project for developing Transmission
Operator and Balancing Authority standards (2007-06).
IRO-001 has some ‘fill-in-the-blank’ components to eliminate.
The development may include other improvements to the standards deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing high
quality, enforceable and technically sufficient bulk power system reliability standards.
SAR-3
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
Reliability
Coordinator
The entity that is the highest level of authority who is responsible for the
reliable operation of the Bulk Electric System, has the Wide Area view of
the Bulk Electric System, and has the operating tools, processes and
procedures, including the authority to prevent or mitigate emergency
operating situations in both next-day analysis and real-time operations.
The Reliability Coordinator has the purview that is broad enough to
enable the calculation of Interconnection Reliability Operating Limits,
which may be based on the operating parameters of transmission
systems beyond any Transmission Operator’s vision.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within its metered boundary and supports
system frequency in real time.
Interchange
Authority
Authorizes valid and balanced Interchange Schedules.
Planning
Authority
Plans the Bulk Electric System.
Resource
Planner
Develops a long-term (>one year) plan for the resource adequacy of
specific loads within a Planning Authority area.
Transmission
Planner
Develops a long-term (>one year) plan for the reliability of transmission
systems within its portion of the Planning Authority area.
Transmission
Service
Provider
Provides transmission services to qualified market participants under
applicable transmission service agreements
Transmission
Owner
Owns transmission facilities.
Transmission
Operator
Operates and maintains the transmission facilities, and executes
switching orders.
Distribution
Provider
Provides and operates the “wires” between the transmission system and
the customer.
Generator
Owner
Owns and maintains generation unit(s).
Generator
Operator
Operates generation unit(s) and performs the functions of supplying
energy and Interconnected Operations Services.
PurchasingSelling Entity
The function of purchasing or selling energy, capacity, and all necessary
Interconnected Operations Services as required.
SAR-4
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Standards Authorization Request Form
Market
Operator
Integrates energy, capacity, balancing, and transmission resources to
achieve an economic, reliability-constrained dispatch.
Load-Serving
Entity
Secures energy and transmission (and related generation services) to
serve the end user.
SAR-5
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Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR-6
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Standards Authorization Request Form
Related Standards – Listed under description
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR-7
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
The drafting team will assist stakeholders in considering these
comments in determining what changes to make to the standards:
COM-001-0
Telecommunications
FERC NOPR
o Include Measures and Levels of Non-Compliance;
o Include generator operators and distribution provider as applicable entities; and
o Include requirements for communication facilities for use during emergency
situations.
FERC Staff Report
o Lacks adequacy, redundancy and routing requirements
o Generation owners missing
o Expect new standard in November
V0
o
o
o
Industry Comments
Redundant with Policy 5A, R1
Many players missing
Apply R1 to all but smallest entities
Violation Risk Factor Drafting Team Comments
o R6 – administrative requirement
COM-002-1
Communications and Coordination
FERC NOPR
o Include Measures and Levels of Non-Compliance;
o Include a Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area views of transmission operators or balancing
authorities;
o Include distribution providers as applicable entities; and
o Require tightened communications protocols, especially for communications during
alerts and emergencies.
FERC Staff Report
o Missing requirement for approval of actions
o Lack of compliance and measures
o Expect November update
V0
o
o
o
o
Industry Comments
Voice with generators not required
R1 – include reliability authority
R2 – include sabotage and security
R4 – clarify repeat back requirement with regard to emergency
IRO-001-0
Reliability Coordination – Responsibilities and Authorities
FERC NOPR
o Reflect the process set forth in the NERC Rules of Procedures; and
o Eliminate the regional reliability organization as an applicable entity.
FERC Staff Report
o RC not explicitly mentioned in Purpose
Regional Fill-in-the-Blank Team Comments
o Remove ", sub-region, or interregional coordinating group" from R1
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
o Consider removing "Standards of conduct are necessary to ensure the Reliability
Coordinator does not act in a manner that favors one market participant over
another." from the Purpose section of the standard.
V0 Industry Comments
o Inability to perform needs to be communicated
o What is meant by ‘interest of other entity’?
Violation Risk Factor Drafting Team Comments
o R6 - Since the RC must be NERC certified, it stands to reason that anyone
performing RC tasks should be certified. However, since the RC still retains the
accountability for actions, and requirement 4 handles the agreements, this
requirement is a medium risk.
IRO-002-0
Reliability Coordination – Facilities
FERC NOPR
o Include Measures and Levels of Non-Compliance and
o Modify Requirement R7 to explicitly require a minimum set of tools for the reliability
coordinator.
FERC Staff Report
o Lack of Measures & Compliance
o Expect new standard in November
V0
o
o
o
Industry Comments
R5 – define synchronized information system
R7 – define ‘adequate’ tools and ‘wide-area’
Words such as ‘easily understood’ and ‘particular emphasis’ need to be tightened
IRO-005-1
FERC NOPR
Reliability Coordination – Current Day Operations
o
Include Measures and Levels of Non-Compliance. We propose that the Measures and
Levels of Non-Compliance specific to IROL violations should be commensurate with
the magnitude, duration, frequency and causes of the violation.
o
Further, as discussed above, we propose that the ERO conduct a survey on IROL
practices and experiences.
o
The Commission may propose further modifications to IRO-005-1 based on the
survey results.
FERC Staff Report
o Concern with timing of critical outage during initial correction period
o Ambiguous with respect to IROL limits
o Lack of Measures & Compliance
Regional Fill-in-the-Blank Team Comments
o R14 has regional reference
V0 Industry Comments
o R10, 11 & 12 – RA not empowered to do this
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
IRO-014-1
Procedures, Processes, or Plans to Support Coordination Between
Reliability Coordinators
FERC NOPR
o
No changes identified.
IRO-015-1
Notifications and Information Exchange Between Reliability Coordinators
FERC NOPR
o
No changes identified.
IRO-016-1
Coordination of Real-Time Activities Between Reliability Coordinators
FERC NOPR
o No changes identified.
Violation Risk Factors Drafting Team Comments
o R1.2.1 & R2 – ambiguous
PER-004-0
Reliability Coordination – Staffing
FERC NOPR
o Include formal training requirements for reliability coordinators similar to those
addressed under the personnel training Reliability Standard PER-002-0;
o Include requirements pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0; and
o Include Levels of Non-Compliance and Measures that address staffing requirements
and the requirement for five days of emergency training.
FERC Staff Report
o Min. expectations and # of hours per year missing
o Blackout Report items not addressed
o Formal program not specified
o Measures & Compliance missing
V0 Industry Comments
o Calendar year timing increment
o Other training needs to be defined
PRC-001-0
System Protection Coordination
FERC NOPR
o Include Measures and Levels of Non-Compliance;
o Include a requirement that relevant transmission operators and generator operators
must be informed immediately upon the detection of failures in relays or protection
system elements on the Bulk-Power System that would threaten reliable operation,
so that these entities can carry out the appropriate corrective control actions
consistent with those used in mitigating IROL violations; and
o Clarify that, after being informed of failures in relays or protection system elements
on the Bulk-Power System, transmission operators or generator operators shall carry
out corrective control actions, i.e., returning the system to a stable state that
respects system requirements as soon as possible and no longer than 30 minutes.
FERC Staff Report
o Max. time period for corrective actions missing
o Expect new standard in November
V0 Industry Comments
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
o Effects on reliability may not be known
o Consistent terminology as to neighbor vs. affected
o Not all criteria moved over from policies
The following standards have been proposed for retirement because they will be displaced
by IRO-007 and IRO-008 but are included here in the event their retirement is not
approved:
IRO-003-1 — Reliability Coordination – Wide-Area View
FERC NOPR
o Include Measures and Levels of Non-Compliance; and
o Include criteria to define the term “critical facilities” in a reliability
coordinator’s area and its adjacent systems.
FERC Staff Report
o Need to define critical facilities
o Lack of Measures & Compliance
o Expect new standard in November
IRO-004-1 — Reliability Coordination – Operations Planning
FERC NOPR
o Require the next-day analysis to identify effective control actions that can be
implemented within 30 minutes during contingency conditions.
FERC Staff Report
o No system assessment required
V0 Industry Comments
o Change ‘particular attention to’ to ‘to monitor’
The following standards are under development and have not yet been approved, so there
are no FERC comments or stakeholder comments on a ‘finished’ standard. These standards
will be reviewed and may be modified as needed to meet the goals identified in the purpose
statement of this SAR:
IRO-007 — Monitoring the Wide Area
IRO-008 — Reliability Coordinator Operational Analyses and Real-Time Assessments
IRO-009 — Reliability Coordinator Actions to Operate Within IROLs
IRO-010 — Reliability Coordinator Data Specification and Collection
IRO-012 — Reliability Coordinator Processes, Procedures, or Plans for Preventing and
Mitigating Reliability Operating Limits
ORG-020
ORG-021
ORG-022
ORG-023
ORG-024
ORG-025
ORG-026
ORG-027
—
—
—
—
—
—
—
—
Reliability
Reliability
Reliability
Reliability
Reliability
Reliability
Reliability
Reliability
Coordinator
Coordinator
Coordinator
Coordinator
Coordinator
Coordinator
Coordinator
Coordinator
Certification
Certification
Certification
Certification
Certification
Certification
Certification
Certification
4
- Certification
- Agreements
- Personnel
- Data Acquisition and Monitoring
– System Analysis
– Emergency Operations
– Loss of Control Center Functionality
– Restoration
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
SAR for Project 2006-06 Reliability Coordination – Attachment 2
The drafting team will reference these guidelines in determining what changes to
make to the standards to bring them into conformance with the Reliability
Standards Development Procedure Manual, Version 6 and the ERO Rules of
Procedure:
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities
responsible for complying with the reliability standard, with any specific additions or
exceptions noted? Where multiple functional classes are identified is there a clear
line of responsibility for each requirement identifying the functional class and entity
to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is
ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard,
such as the entire North American bulk power system, an interconnection, or within
a regional entity area? If no geographic limitations are identified, the default is that
the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the
standard based on electric facility characteristics, such as generators with a
nameplate rating of 20 MW or greater, or transmission facilities energized at 200 kV
or greater or some other criteria? If no functional entity limitations are identified,
the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how
the standard contributes to the reliability of the bulk power system? Each purpose
statement should include a value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if
achieved by the applicable entities, will provide for a reliable bulk power system,
consistent with good utility practices and the public interest?
Does each requirement identify who shall do what under what conditions and to
what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a
third party with knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used
to objectively evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics
provided within the requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Is this reliability standard based upon sound engineering and operating judgment,
analysis, or experience, as determined by expert practitioners in that particular
field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend
on external information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO
and regional entity compliance documents, are the consequences of violating a
standard clearly known to the responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can
responsible entities, using reasonable judgment and in keeping with good utility
practices, arrive at a consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically
implemented by the assigned responsible entities within the specified effective date
and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include
facilities for communication, agreements with other entities, etc.) should be
located in the standards for certification. The certification requirements should
indicate that entities have a responsibility to ‘maintain’ their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms
and definitions that are approved through the NERC reliability standards
development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in
Reliability Standards, then the term must be capitalized when it is used in the
standard. New terms should not be added unless they have a ‘unique’ definition
when used in a NERC reliability standard. Common terms that could be found in a
college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need
to be added to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or
could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures;
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
or a requirement in a planning time frame that, if violated, could, under
emergency, abnormal, or restorative conditions anticipated by the
preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk
electric system at an unacceptable risk of instability, separation, or cascading
failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. However, violation of a medium risk
requirement is unlikely to lead to bulk electric system instability, separation,
or cascading failures;
or a requirement in a planning time frame that, if violated, could, under
emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of
the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. A requirement that is
administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. A planning requirement that is
administrative in nature.
Mitigation Time Horizon
The drafting team should also indicate the time horizon available for mitigating a
violation to the requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to
and including seasonal.
•
Same-day Operations — routine actions required within the timeframe of a
day, but not real-time.
•
Real-time Operations — actions required within one hour or less to
preserve the reliability of the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time
operations.
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be
applied for the requirements within a standard. (‘Violation severity levels’ replace
existing ‘levels of non-compliance.’) The violation severity levels may be applied
for each requirement or combined to cover multiple requirements, as long as it is
clear which requirements are included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible
entity is mostly compliant with and meets the intent of the requirement but
is deficient with respect to one or more minor details. Equivalent score: 95%
to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The
responsible entity is mostly compliant with and meets the intent of the
requirement but is deficient with respect to one or more significant elements.
Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only
partially achieved the reliability objective of the requirement and is missing
one or more significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed
to meet the reliability objective of the requirement. Equivalent score: less
than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Electric Reliability
Organization’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements
that assign one entity responsibility for developing some performance
measures without requiring that the performance measures be included in
the body of a standard – then require another entity to comply with those
requirements.
Every reliability objective can be met, at least at a threshold level, by a
North American standard. If we need regions to develop regional standards,
such as in under-frequency load shedding, we can always write a uniform
North American standard for the applicable functional entities as a means of
encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any
requirements currently assigned to the RRO should be re-assigned to the
applicable functional entity.
4
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant –
must include time to file with regulatory authorities and provide notice to
responsible entities of the obligation to comply. If the standard is to be
actively monitored, time for the Compliance Monitoring and Enforcement
Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be
provided in the implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full
name and number of the standard under the section called, ‘Associated
Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the
responsibilities and tasks assigned to functional entities as provided in pages
13 through 53 of the draft Functional Model Version 3.
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Maureen E. Long
Standards Process Manager
January 15, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for SAR to Modify Vegetation Management, SAR
for Reliability Coordination and SAR and Standard to Modify Facility Ratings Standards
The Standards Committee (SC) announces the following standards actions:
SAR to Modify the Vegetation Management Standard FAC-003-1 Posted for 30-day
Comment Period January 15–February 14, 2007
The SAR for Project 2007-07 proposes modifying the Vegetation Management standard FAC-003-1 to
address concerns raised by FERC and stakeholders and to bring the standard into conformance with the
ERO Rules of Procedure and the latest version of the Reliability Standards Development Procedure.
Please use the comment form to provide comments on this SAR.
SAR to Modify the Reliability Coordinator Standards Posted for 30-day Comment Period
January 15–February 14, 2007
The SAR for Project 2006-06 proposes retiring, modifying, or adding to existing requirements for the
reliability coordinator to ensure that the complete set of requirements addresses all the processes,
procedures, plans, tools, and authorities the reliability coordinator needs to support the reliable operation
of the interconnected bulk power systems. This project involves addressing concerns raised by FERC and
stakeholders and also involves bringing the set of standards into conformance with the ERO Rules of
Procedure and the latest version of the Reliability Standards Development Procedure. Please use the
comment form to provide comments on this SAR.
SAR and Standard to Modify the Facility Ratings Standards Posted for 45-day Comment
Period January 15–February 28, 2007
The SAR for Project 2006-09 proposes modifying two Facility Ratings standards, FAC-008-1 and FAC009-1, to address concerns raised by FERC and stakeholders and to bring the standard into conformance
with the ERO Rules of Procedure and the latest version of the Reliability Standards Development
Procedure. Because there were relatively few technical changes recommended for this set of standards,
the revised standard, which combines FAC-008-1 and FAC-009-1, is posted for comment along with an
implementation plan. Please use the comment form to provide comments on this SAR, standard and
implementation plan.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. If you have any questions, please
contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian Thumm
Organization: ITC Transmission
Telephone:
248.374.7846
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments: Yes, there is a reliability need to revise the Standards identified in this
SAR. Not all of the revisions described, however, are reliability related and in fact
should not be included in the standards (e.g., exempting an operator from liability).
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The Standard Drafting Team should not be given lattitude to "include other
improvements to the standards deemed appropriate by the drafting team." The
purpose of the SAR is to identify the changes contemplated by the need for the
Standard Revision. If there are changes that the SAR requestor would like to make to
the Standard, they should be spelled out in the SAR. If the SAR requestor does not
really know the changes that should be made to the standard, then the SAR should be
withdrawn until the need for a SAR can be adequately justified.
The remainder of the SAR is very broad; perhaps too broad. The requestor should
consider reducing the scope of the SAR to make specific changes to the standards,
rather than try to consolidate all of the Standards in one swift stroke.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Uncertain to say what they would be at this point.
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
IRC Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
SPP
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Calimano
NYISO
NPCC
2
Alicia Daughtery
PJM
RFC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Anita Lee
AESO
WECC
2
Steve Myers
ERCOT
ERCOT
2
Bill Phillips
MISO
RFC
2
SERC
MRO
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments: The IRC agrees with the objective but does not agree with the process.
We agree there is a general need to clean up the standards and where appropriate
consolidate the standards. However, this SAR covers too large a swath of standards,
and as a consequence the resulting standard has the potential of being too large for
reasoned comments.
The SRC believes that the wide perspective proposed by this SAR could compromise the
internal consistency within individual standards. Subject Matter experts created
interrelated requirements in given areas. This SAR proposes to impose a vertically
integrated prospective, linking standards in widely dispersed areas of operational
expertise. While a review of the vertical integration is useful and in places needed, it is
recommended that the results of the review should themselves be sent as
recommended SARs for industry consideration by the SMEs for the individual standards,
and not as a proposed ad hoc standard. Grouping them as proposed in the SAR may
result in unintended disconnects within the other standards, and in the worst case
result in an ongoing series of iterative SARs.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We do agree the standards should be consolidated and redundancies
eliminated where appropriate.
However, it is not appropriate to include standards in this SAR that have not yet been
approved. For example, it is not necessary to expand on the requirement to have
faclities in place by adding a testing requirement. If an entity is required to have
facilities in place and they are not maintained and available, they do not meet the
requirement.
The "boiler plate" language that this "development may include other improvements
deemed appropriate by the drafting team" is too vague and essentially opens the scope
to include anything the drafting team wants to do with the standard. This is not
appropriate. The scope should be specific and the drafting team should only focus on
those specifics.
The SRC supports the approach of prioritizing and revising individual standards to
include FERC's comments as part of the consideration process. Only a few standards
should be revised at a time to make the process more manageable.
Page 5 of 6
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 6 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
David Kiguel
Organization: Hydro One Networks Inc.
Telephone:
416-345-5313
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Please see our answer to question No. 3.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: This project involves the revision of 27 NERC Standards, not a small task
by any measure. The extent of the proposed work and the necessary expertise is
beyond what can be found in one single SAR team and drafting team.
We respectfuly submit that the project be divided into as many SARs and teams as
necessary with the work directed and monitored by the Standards Committee.
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest ISO Stakeholders Standards Collaboration Participants
Lead Contact:
Jason Marshall
Contact Organization:
Midwest ISO
Contact Segment:
2
Contact Telephone:
317-249-5494
Contact E-mail:
[email protected]
Additional Member Name
Jim Cyrulewski
Additional Member
Organization
JDRJC Associates
Region*
RFC
Segment*
8
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments: We agree there is a general need to consolidate where necessary and clean
up the standards. However, this SAR covers too large a swath of standards. It very
confusing what the overall goal is. Additionally, we are concerned that the range of
expertise required by this SAR will result in a drafting team that is too large and will
result in little to no progress unless the drafting team is subdivided. If the drafting
team is subdivided, then this SAR should be subdivided into other SARs.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We do agree the standards should be consolidated and redundancies
eliminated where appropriate. However, it is not appropriate to include standards in
this SAR that have not yet been approved.
It is not necessary to expand on the requirement to have faclities in place by adding a
testing requirement. If an entity is required to have facilities in place and they are not
maintained and available, they do not meet he requirement of having facilities in place.
The "boiler plate" language that this "development may include other improvements
deemed appropriate by the drafting team is too vague and essentially opens the scope
to include anything the drafting team wants to do with the standard. This is not
appropriate. The scope should be specific and the drafting team should only focus on
those specifics.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Because of the overbroad nature of this SAR, the answer is likely yes.
However, it is nearly impossible to determine all the additional required changes
without missing important items. This SAR needs to be broken down to address
individual standards.
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments: ISO New England supports the objective but does not agree with the
process.
We agree there is a general need to clean up the standards and where appropriate
consolidate the standards. However, this SAR covers too large a swath of standards,
and as a consequence the resulting standard has the potential of being too large for
reasoned comments.
We are concerned that the wide perspective proposed by this SAR could compromise
the internal consistency within individual standards. Subject Matter Experts created
interrelated requirements in given areas. This SAR proposes to impose a vertically
integrated prospective, linking standards in widely dispersed areas of operational
expertise. While a review of the vertical integration is useful and in places needed, it is
recommended that the results of the review should themselves be sent as
recommended SARs for industry consideration by the SMEs for the individual standards,
and not as a proposed ad hoc standard. Grouping them as proposed in the SAR may
result in unintended disconnects within the other standards, and in the worst case
result in an ongoing series of iterative SARs.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We do agree the standards should be consolidated and redundancies
eliminated where appropriate.
However, it is not appropriate to include standards in this SAR that have not yet been
approved. For example, it is not necessary to expand on the requirement to have
faclities in place by adding a testing requirement. If an entity is required to have
facilities in place and they are not maintained and available, they do not meet the
requirement.
The "boiler plate" language that this "development may include other improvements
deemed appropriate by the drafting team" is too vague and essentially opens the scope
to include anything the drafting team wants to do with the standard. This is not
appropriate. The scope should be specific and the drafting team should only focus on
those specifics.
ISO New England supports the approach of prioritizing and revising individual standards
to include FERC's comments as part of the consideration process. We also support the
Page 5 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
consideration of non-FERC industry comments submitted previously in the commenting
process where the requirements were not available for commenting.
Only a few standards should be revised at a time to make the process more
manageable.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 6 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Gentry
Organization: Salt River Project
Telephone:
602-236-6408
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
WECC Reliability Coordination Comments Work Group
Lead Contact:
Nancy Bellows
Contact Organization:
WACM
Contact Segment:
10
Contact Telephone:
970-461-7246
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Jack Bernhardson
PNSC
WECC
10
Bob Johnson
PSC
WECC
10
Frank McElvain
RDRC
WECC
10
Greg Tillitson
CMRC
WECC
10
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: We believe that the drafting needs to verify that requirements exempt the
reliability coordinator real-time supervision, as well as the real-time operator from
liability when making a good faith effort at preserving reliability.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
The WECC RCCWG believes that the FERC Staff Report suggestion that COM-001
"generation owners missing" should not translate to addition of generation owners in
the applicabliity. "Generator Operator" is an applicable entity, but not "Generator
Owner".
The WECC RCCWG believes the Reliability Coordination SAR should address those V0
comments on requirements, when those specific are no longer part of the standard
referenced in the V0 comments identified in Attachment 1 of the SAR if those
comments were not previously addressed. One example: posted "V0 Industry
Comments" suggest inclusion of sabotage and security in R2 of COM-002. That
comment is no longer applicable to COM-002 R2 - the standard requirements have
changed. That said, the comment intent should not be lost.
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Public Service Commission of South Carolina
Lead Contact:
Phil Riley
Contact Organization:
Public Service Commission of South Carolina
Contact Segment:
9
Contact Telephone:
803-896-5154
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mignon L. Clyburn
Public Service Commission of SC
SERC
9
Elizabeth B. Fleming
Public Service Commission of SC
SERC
9
G. O'Neal Hamilton
Public Service Commission of SC
SERC
9
John E. Howard
Public Service Commission of SC
SERC
9
Randy Mitchell
Public Service Commission of SC
SERC
9
C. Robert Moseley
Public Service Commission of SC
SERC
9
David A. Wright
Public Service Commission of SC
SERC
9
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro Québec TransÉnergie
Telephone:
514 289-2211; X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: Please see our answer to question No. 3.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: This project involves the revision of 27 NERC Standards, not a small task
by any measure. The extent of the proposed work and the necessary expertise is
beyond what can be found in one single SAR team and drafting team.
We respectfuly submit that the project be divided into as many SARs and teams as
necessary with the work directed and monitored by the Standards Committee.
Also, coordination with the Standards in development IRO-007-1 to IRO-010-1 that are
also the object of a separate revision and commentary period should be taken care of.
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments: The IESO agrees with the objective but does not agree with the process.
There is a general need to clean up the standards and where appropriate consolidate
the standards. However, this SAR covers too large a swath of standards, and as a
consequence the resulting standard has the potential of being too large for reasoned
comments.
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments:
We agree with the intent to fill in the gaps and eliminate duplications among standards,
and applaud the SDT for taking on this huge and challenging task. We are concerned,
however, that the scope itself is too wide but yet not wide enough. Some of the listed
standards are still being commented on, for example: IROL-007 to IRO-010, while
some others had been commented on but are now in a dormant state, for example: the
organization certification standards. These standards are not yet approved, and hence
are subject to change and become moving targets for this holistic review task.
The scope description does not suggest an approach to deal with ongoing changes to
the standards identified. We are concerned that the wide scope and the massive task
may not ensure that a one time change will cover all affected standards - those
approved and those under development.
We suggest the SDT compare this approach to an alternative approach which is to
revise a few standards at a time, on a priority basis and considering FERC's views on
the status of the standards, thereby limiting the corresponding changes within a more
manageable scope. Overtime, when all standards have gone through revisions, all
corresponding changes will be duly made.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 5 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
There are likely additional standard revisions beyond those identified, but we find it's
almost impossible to pre-determine which other standards will be affected as a result of
changes to those identified in this SAR.
For example, changes currently proposed for IRO-007 to IRO-010 will precipitate
corresponding changes to other affected standards, e.g. TOP-003, TOP-005, etc.
However, we are unable to provide any specific list of standards that will require
corresponding changes not knowing what changes will be made to the standards listed
in the SAR.
Given the above, it should not be taken for granted that the list is exhaustive in terms
of revisions required.
Page 6 of 6
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jason Shaver
Organization: American Transmission Co.
Telephone:
262 506 6885
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: ATC agrees with the spirit of the SAR but believes that more details should
be provided.
Identify which of the redundant requirements will be deleted.
Lastly ATC does not understand how a SDT can tackle the ORG -020 – 027 when these
standards have not been approved by the board. In other words how can the SDT
move forward on the scope when eight of the standards are still in being worked on?
To approve the scope of the SAR references to ORG-020 – 027 should be deleted and
considered out of bounds for the SDT.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on 1st Posting of Reliability Coordination SAR
The Reliability Coordination SAR Requesters thank all commenters who submitted comments
on Draft 1 of the Reliability Coordination SAR. This SAR was posted for a 30- day public
comment period from January 15 through February 14, 2007. The requesters asked
stakeholders to provide feedback on the standard through a special standard Comment Form.
There were 11 sets of comments, including comments from more than 31 different people from
more than 15 companies representing 9 of the 10 Industry Segments as shown in the table on
the following pages.
While most stakeholders agreed with the reliability-related need to modify the standards
addressed by this SAR, most stakeholders disagreed with the proposed scope of the original
SAR and the drafting team made the following revisions to reduce the scope:
-
Revised the purpose statement to more narrowly focus on the reliability-related
purpose of revising the set of standards addressed by the SAR
-
Removed the standards that were listed in the original SAR that are still under
development, including the certification standards (ORG-020-1 through ORG-0271), the Version 1 IROL Standards that are still under development (IRO-007-1
through IRO-013-1) and the standards that are identified in the Version 1 IROL
Implementation Plan as proposed for retirement when the Version 1 IROL Standards
become effective (IRO-003-1, IRO-004-1).
-
Removed the paragraph that referenced facilities.
-
Removed the paragraph that would have allowed the standard drafting team to
make ‘any’ additions to requirements as long as those additions met stakeholder
approval.
-
Added more specificity to the drafting team’s approach to modifying the set of
standards identified in the SAR.
Based on the comments received, the drafting team is posting the revised SAR for another
comment period.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Reliability-Coordination_Project_2006-6.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Page 1 of 13
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Consideration of Comments on 1st Posting of Reliability Coordination SAR
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
1.
Jason Shaver
American Transmission Co.
9
2.
David Kiguel
Hydro One Networks, Inc.
9
3.
Roger Champagne
Hydro Québec TransÉnergie
9
4.
Ron Falsetti
Independent Electricity System
Operator
9
5.
Kathleen Goodman
ISO New England
9
6.
Charles Yeung (SPP)
ISO/RTO Council
9
7.
Mike Calimano (NYISO)
ISO/RTO Council
9
8.
Alicia Daughtery (PJM)
ISO/RTO Council
9
9.
Ron Falsetti (IESO)
ISO/RTO Council
9
10.
Matt Goldberg (ISONE)
ISO/RTO Council
9
11.
Brent Kingsford (CAISO)
ISO/RTO Council
9
12.
Anita Lee (AESO)
ISO/RTO Council
9
13.
Steve Myers (ERCOT)
ISO/RTO Council
9
14.
Bill Phillips (MISO)
ISO/RTO Council
15.
Brian Thumm
ITC Transmission
16.
Jim Cyrulewski
JDRJC Associates
17.
Jason Marshall
Midwest ISO Stakeholders
Standards Collaboration Participants
18.
Phil Riley
PSC of South Carolina
9
19.
Mignon L. Clyburn
PSC of South Carolina
9
20.
Elizabeth B. Fleming
PSC of South Carolina
9
21.
G. O'Neal Hamilton
PSC of South Carolina
9
22.
John E. Howard
PSC of South Carolina
9
23.
Randy Mitchell
PSC of South Carolina
9
24.
C. Robert Moseley
PSC of South Carolina
9
25.
David A. Wright
PSC of South Carolina
9
26.
Mike Gentry
Salt River Project
27.
Nancy Bellows (WACM)
WECC Reliability Coordination
Comments Work Group
9
28.
Jack Bernhardsen
(PNSC)
WECC Reliability Coordination
Comments Work Group
9
29.
Bob Johnson (PSC)
WECC Reliability Coordination
Comments Work Group
9
30.
Frank McElvain (RDRC)
WECC Reliability Coordination
Comments Work Group
9
31.
Greg Tillitson (CMRC)
WECC Reliability Coordination
Comments Work Group
9
9
9
9
9
9
Page 2 of 13
9
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Consideration of Comments on 1st Posting of Reliability Coordination SAR
Index to Questions, Comments, and Responses
1.
Do you agree that there is a reliability-related need for the proposed revisions to this set
of standards? If not, please explain in the comment area. ...................................... 4
2.
Do you agree with the scope of the SAR? If not, please explain in the comment area. 6
3.
Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project? ..........................................................11
Page 3 of 13
1. Do you agree that there is a reliability-related need for the proposed revisions to this set of
standards? If not, please explain in the comment area.
Summary Consideration: Most commenters indicated that they do believe that there is a reliability-related need for the
proposed revisions to the standards.
Question #1
Commenter
ISO/RTO Council
ISO New England
Yes
No
;
;
Comment
The IRC and ISO-NE agrees with the objective but does not agree with the process.
We agree there is a general need to clean up the standards and where appropriate
consolidate the standards. However, this SAR covers too large a swath of standards, and
as a consequence the resulting standard has the potential of being too large for reasoned
comments.
The SRC believes that the wide perspective proposed by this SAR could compromise the
internal consistency within individual standards. Subject Matter experts created
interrelated requirements in given areas. This SAR proposes to impose a vertically
integrated prospective, linking standards in widely dispersed areas of operational
expertise. While a review of the vertical integration is useful and in places needed, it is
recommended that the results of the review should themselves be sent as recommended
SARs for industry consideration by the SMEs for the individual standards, and not as a
proposed ad hoc standard. Grouping them as proposed in the SAR may result in
unintended disconnects within the other standards, and in the worst case result in an
ongoing series of iterative SARs.
Response:
The intent is not to develop a single standard from the list of standards.
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting team
asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be addressed
by the IROL SDT and to eliminate the list of proposed certification standards.
Midwest ISO
agree there is a general need to consolidate where necessary and clean up the
; ; We
Stakeholders
standards. However, this SAR covers too large a swath of standards. It very confusing
Standards
what the overall goal is. Additionally, we are concerned that the range of expertise
Collaboration
required by this SAR will result in a drafting team that is too large and will result in little
Participants
to no progress unless the drafting team is subdivided. If the drafting team is subdivided,
Page 4 of 13
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #1
Commenter
Comment
then this SAR should be subdivided into other SARs.
Response: The SAR was revised to more clearly define the scope of work.
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting team
asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be addressed
by the IROL SDT and to eliminate the list of proposed certification standards.
The IESO agrees with the objective but does not agree with the process.
Independent
; ; There
is a general need to clean up the standards and where appropriate consolidate the
Electricity System
standards.
However, this SAR covers too large a swath of standards, and as a
Operator
consequence the resulting standard has the potential of being too large for reasoned
comments.
Response: The SAR was revised to more clearly define the scope of work.
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting team
asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be addressed
by the IROL SDT and to eliminate the list of proposed certification standards.
ITC Transmission
Yes, there is a reliability need to revise the Standards identified in this SAR. Not all of
;
the revisions described, however, are reliability related and in fact should not be included
in the standards (e.g., exempting an operator from liability).
Response: The SAR was revised to omit the reference to the liability exemption.
American
;
Transmission Co.
Hydro One Networks, ;
Inc.
Hydro Québec
TransÉnergie
Salt River Project
;
WECC Reliability
Coordination
Comments Work
Group
PSC of South
Carolina
Yes
No
;
;
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Summary Consideration: Most commenters disagreed with the scope of the original SAR and the drafting team made major
modifications to reduce the scope of the SAR to only include standards that are already approved and to identify more
specifically the range of changes contemplated to the standards that remain in the revised SAR.
Question #2
Commenter
Yes
No
Comment
Hydro One Networks,
Please
see
our
answer
to
question
No.
3.
;
Inc.
Hydro Québec
TransÉnergie
Response: Please see the response to question 3.
ITC
Standard Drafting Team should not be given lattitude to "include other
; The
improvements to the standards deemed appropriate by the drafting team." The
purpose of the SAR is to identify the changes contemplated by the need for the
Standard Revision. If there are changes that the SAR requestor would like to make
to the Standard, they should be spelled out in the SAR. If the SAR requestor does
not really know the changes that should be made to the standard, then the SAR
should be withdrawn until the need for a SAR can be adequately justified.
The remainder of the SAR is very broad; perhaps too broad. The requestor should
consider reducing the scope of the SAR to make specific changes to the standards,
rather than try to consolidate all of the Standards in one swift stroke.
Response: The intent is not to develop a single standard from the list of standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be
addressed by the IROL SDT and to eliminate the list of proposed certification standards.
The intent of the original SAR was to give the Standard Drafting Team enough latitude to address requirements that fall
within a list of performance requirements. Looking to the future, the Standard Drafting Team cannot expand on the scope of
its SAR but may develop a set of requirements that is smaller than the scope of the SAR. Based on stakeholder comments,
the scope has been revised and is more clearly and more narrowly defined.
ISO/RTO Council
We do agree the standards should be consolidated and redundancies eliminated
;
ISO New England
where appropriate.
However, it is not appropriate to include standards in this SAR that have not yet
been approved. For example, it is not necessary to expand on the requirement to
have facilities in place by adding a testing requirement. If an entity is required to
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #2
Commenter
Yes
No
Comment
have facilities in place and they are not maintained and available, they do not meet
the requirement.
The "boiler plate" language that this "development may include other improvements
deemed appropriate by the drafting team" is too vague and essentially opens the
scope to include anything the drafting team wants to do with the standard. This is
not appropriate. The scope should be specific and the drafting team should only
focus on those specifics.
The SRC supports the approach of prioritizing and revising individual standards to
FERC's comments as part of the consideration process. Only a few standards should
be revised at a time to make the process more manageable.
Response: The SAR was revised to omit all of the standards that were listed in the original SAR but weren’t approved (draft
IROL Standards and the draft Certification Standards).
The SAR was revised to omit the paragraph that referenced facilities. Note that there is a new performance objective in the
revised SAR that indicates the resultant standards will have requirements to address the RC’s facility capabilities.
The intent of the original SAR was to give the Standard Drafting Team enough latitude to address requirements that fall
within a list of performance requirements. Looking to the future, the Standard Drafting Team cannot expand on the scope of
its SAR but may develop a set of requirements that is smaller than the scope of the SAR. Based on stakeholder comments,
the scope has been revised and is more clearly and more narrowly defined. The drafting team revised the SAR to omit the
‘boiler plate’ language.
The intent is not to develop a single standard from the list of standards.
The SAR DT can recommend that the standards be revised in a specific sequence but the final determination of which
standards are revised or developed first is a decision that belongs to the Standards Committee.
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting
team asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
Midwest ISO
Stakeholders
Standards
Collaboration
Participants
;
We do agree the standards should be consolidated and redundancies eliminated
where appropriate. However, it is not appropriate to include standards in this SAR
that have not yet been approved.
It is not necessary to expand on the requirement to have facilities in place by
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #2
Commenter
Yes
No
Comment
adding a testing requirement. If an entity is required to have facilities in place and
they are not maintained and available, they do not meet he requirement of having
facilities in place.
The "boiler plate" language that this "development may include other improvements
deemed appropriate by the drafting team is too vague and essentially opens the
scope to include anything the drafting team wants to do with the standard. This is
not appropriate. The scope should be specific and the drafting team should only
focus on those specifics.
Response: The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already
be addressed by the IROL SDT and to eliminate the list of proposed certification standards.
The SAR was revised to omit the paragraph that referenced facilities. Note that there is a new performance objective in the
revised SAR that indicates the resultant standards will have requirements to address the RC’s facility capabilities.
The intent of the original SAR was to give the Standard Drafting Team enough latitude to address requirements that fall
within a list of performance requirements. Looking to the future, the Standard Drafting Team cannot expand on the scope of
its SAR but may develop a set of requirements that is smaller than the scope of the SAR. Based on stakeholder comments,
the scope has been revised and is more clearly and more narrowly defined. The drafting team revised the SAR to omit the
‘boiler plate’ language.
American
Transmission Co.
;
ATC agrees with the spirit of the SAR but believes that more details should be
provided.
Identify which of the redundant requirements will be deleted.
Lastly ATC does not understand how a SDT can tackle the ORG -020 – 027 when
these standards have not been approved by the board. In other words how can the
SDT move forward on the scope when eight of the standards are still in being
worked on? To approve the scope of the SAR references to ORG-020 – 027 should
be deleted and considered out of bounds for the SDT.
Response: The SAR drafting team will let the standard drafting team determine what requirements will be deleted.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be
addressed by the IROL SDT and to eliminate the list of proposed certification standards.
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #2
Commenter
Independent
Electricity System
Operator
Yes
;
No
;
Comment
We agree with the intent to fill in the gaps and eliminate duplications among
standards, and applaud the SDT for taking on this huge and challenging task. We
are concerned, however, that the scope itself is too wide but yet not wide enough.
Some of the listed standards are still being commented on, for example: IROL-007
to IRO-010, while some others had been commented on but are now in a dormant
state, for example: the organization certification standards. These standards are not
yet approved, and hence are subject to change and become moving targets for this
holistic review task.
The scope description does not suggest an approach to deal with ongoing changes
to the standards identified. We are concerned that the wide scope and the massive
task may not ensure that a one time change will cover all affected standards - those
approved and those under development.
We suggest the SDT compare this approach to an alternative approach which is to
revise a few standards at a time, on a priority basis and considering FERC's views
on the status of the standards, thereby limiting the corresponding changes within a
more manageable scope. Overtime, when all standards have gone through
revisions, all corresponding changes will be duly made.
Response: The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already
be addressed by the IROL SDT and to eliminate the list of proposed certification standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be
addressed by the IROL SDT and to eliminate the list of proposed certification standards. The SAR was modified to state that
the standard drafting team will work with stakeholders to:
Eliminate redundancy in the requirements.
Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC to certification.
- Fill identified gaps in the requirements for Reliability Coordination
-
The intent is not to develop a single standard from the list of standards. The SAR DT can recommend that the standards be
revised in a specific sequence but the final determination of which standards are revised or developed first is a decision that
belongs to the Standards Committee.
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #2
Commenter
Yes
No
Comment
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting
team asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
We believe that the drafting needs to verify that requirements exempt the reliability
WECC Reliability
;
coordinator real-time supervision, as well as the real-time operator from liability
Coordination
when making a good faith effort at preserving reliability.
Comments Work
Group
Response: The drafting team removed the reference to liability from the SAR.
Salt River Project
;
PSC of South
Carolina
;
Page 10 of 13
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
3. Are there additional revisions, beyond those identified in the SAR that should be addressed within the scope of
this project?
Question #3
Commenter
ITC Transmission
Hydro One Networks,
Inc.
Hydro Québec
TransÉnergie
Yes
;
No
Comment
Uncertain to say what they would be at this point.
This project involves the revision of 27 NERC Standards, not a small task by any
measure. The extent of the proposed work and the necessary expertise is beyond what
can be found in one single SAR team and drafting team.
We respectfuly submit that the project be divided into as many SARs and teams as
necessary with the work directed and monitored by the Standards Committee.
Response: The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already
be addressed by the IROL SDT and to eliminate the list of proposed certification standards.
The Standards Committee may assign more than one drafting team to develop the standards and when the SAR drafting team
asks the Standards Committee for authorization to move the SAR forward to standard drafting, the drafting team may
recommend that more than one SDT be assigned to draft the standards.
Independent
There are likely additional standard revisions beyond those identified, but we find it's
;
Electricity System
almost impossible to pre-determine which other standards will be affected as a result of
Operator
changes to those identified in this SAR.
For example, changes currently proposed for IRO-007 to IRO-010 will precipitate
corresponding changes to other affected standards, e.g. TOP-003, TOP-005, etc.
However, we are unable to provide any specific list of standards that will require
corresponding changes not knowing what changes will be made to the standards listed
in the SAR.
Given the above, it should not be taken for granted that the list is exhaustive in terms
of revisions required.
Response: The intent of the original SAR was to give the Standard Drafting Team enough latitude to address requirements
that fall within a list of performance requirements. Looking to the future, the Standard Drafting Team cannot expand on the
scope of its SAR but may develop a set of requirements that is smaller than the scope of the SAR.
Based on stakeholder comments, the SAR DT eliminated the paragraph that would have allowed the Standard Drafting Team
to expand the scope of activities to address new issues that may come up after the SAR is finalized. If new ideas are
identified during standard drafting, the standard drafting team will need to revise its SAR or develop a new SAR to address
those additional ideas.
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #3
Commenter
WECC Reliability
Coordination
Comments Work
Group
Yes
;
No
;
Comment
The WECC RCCWG believes that the FERC Staff Report suggestion that COM-001
"generation owners missing" should not translate to addition of generation owners in the
applicability. "Generator Operator" is an applicable entity, but not "Generator Owner".
The WECC RCCWG believes the Reliability Coordination SAR should address those V0
comments on requirements, when those specific are no longer part of the standard
referenced in the V0 comments identified in Attachment 1 of the SAR if those comments
were not previously addressed. One example: posted "V0 Industry Comments" suggest
inclusion of sabotage and security in R2 of COM-002. That comment is no longer
applicable to COM-002 R2 - the standard requirements have changed. That said, the
comment intent should not be lost
Response: The FERC comments are ‘issues to consider’ but are not directives for changes to the standards.
The SAR was revised and any outdated V0 comments (or other organization or committee comments) comments have been
removed.
Midwest ISO
of the overbroad nature of this SAR, the answer is likely yes. However, it is
; ; Because
Stakeholders
nearly impossible to determine all the additional required changes without missing
Standards
important items. This SAR needs to be broken down to address individual standards.
Collaboration
Participants
Response: The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already
be addressed by the IROL SDT and to eliminate the list of proposed certification standards.
The list of standards included in the scope of this SAR has been reduced to eliminate standards that will already be addressed
by the IROL SDT and to eliminate the list of proposed certification standards. The SAR was modified to state that the
standard drafting team will work with stakeholders to:
Eliminate redundancy in the requirements.
Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC to certification.
- Fill identified gaps in the requirements for Reliability Coordination
-
ISO/RTO Council
ISO New England
American
Transmission Co.
;
;
Page 12 of 13
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
Question #3
Commenter
Salt River Project
PSC of South
Carolina
Yes
No
Comment
;
;
Page 13 of 13
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Consideration of Comments on 1st Draft of the Reliability Coordination SAR
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Authorization Request Form
Title of Proposed Standard
Reliability Coordination (Project 2006-06)
Request Date
December 18, 2006
SAR Type (Check a box for each one
that applies.)
SAR Requestor Information
Name
Ellis Rankin
Primary Contact
New Standard
Ellis Rankin
Revision to existing Standards –
see list below
COM-001 — Telecommunications
COM-002 — Communications and
Coordination
IRO-001 — Reliability Coordination –
Responsibilities and Authorities
IRO-002 — Reliability Coordination –
Facilities
IRO-005 — Reliability Coordination –
Current Day Operations
IRO-014 — Procedures to Support
Coordination between Reliability
Coordinators
IRO-015 — Notifications and Information
Exchange Between Reliability
Coordinators
IRO-016 — Coordination of Real-time
Activities between Reliability
Coordinators
PER-004 — Reliability Coordination –
Staffing
PRC-001 — System Protection
Coordination
Telephone
Fax
214-743-6828
972-263-6710
Withdrawal of existing Standard
E-mail
[email protected]
Urgent Action
Some requirements in the above
standards
Purpose
To ensure that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable; and to ensure that this set of requirements is sufficient to maintiain
reliability of the Bulk Electric System.
SAR-1
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Standards Authorization Request Form
Brief Description
Most of the requirements in this set of standards were translated from Operating Policies as part of the
Version 0 process. There have been suggestions for improving these requirements, and the drafting
team will consider comments submitted by stakeholders, drafting teams and FERC in determining what
changes should be proposed to stakeholders.
The drafting team will review all of the requirements in this set of standards and make a determination,
with stakeholders, on whether to:
- Modify the requirement to improve its quality
- Move the requirement (into another SAR or Standard or to the certification process or
standards)
- Eliminate the requirement (either because it is redundant or because it doesn’t support bulk
power system reliability).
Detailed Description
The drafting team will review all of the requirements in the following set of standards:
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination – Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current Day Operations
IRO-014 — Procedures to Support Coordination between Reliability Coordinators
IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
For each existing requirement, the drafting team will work with stakeholders and:
- Eliminate redundancy in the requirements.
- Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC
to certification.
The standard drafting team will also:
Coordinate with the drafting teams working on the SAR and standards for Transmission
Operator and Balancing Authority standards (Project 2007-06).
Consider comments received during the initial development of this set of standards and other
comments received from ERO regulatory authorities and stakeholders (Attachment 1)
Bring the standards into conformance with the latest version of the Reliability Standards
Development Procedure and the ERO Rules of Procedure. (Attachment 2)
This review of the set of identified standards will satisfy the standards procedure requirement to review
each approved standard at least once every five years.
SAR-2
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports system frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and related reliability-related
services) to serve the end-use customer.
SAR-3
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Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
SAR-4
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Standards Authorization Request Form
Related Standards – Listed under description
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
Explanation
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
SAR-5
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
The drafting team will assist stakeholders in considering these comments in
determining what changes to make to the standards:
COM-001-0
Telecommunications
FERC NOPR
o Include generator operators and distribution provider as applicable entities; and
o Include requirements for communication facilities for use during emergency
situations.
V0 Industry Comments
o Many players missing
o Apply R1 to all but smallest entities
Violation Risk Factor Drafting Team Comments
o R6 – administrative requirement
COM-002-1
Communications and Coordination
FERC NOPR
o Include a Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area views of transmission operators or balancing
authorities;
o Include distribution providers as applicable entities; and
o Require tightened communications protocols, especially for communications during
alerts and emergencies.
V0
o
o
o
o
Industry Comments
Voice with generators not required
R1 – include reliability authority
R2 – include sabotage and security
R4 – clarify repeat back requirement with regard to emergency
IRO-001-0
Reliability Coordination – Responsibilities and Authorities
FERC NOPR
o Reflect the process set forth in the NERC Rules of Procedures; and
o Eliminate the regional reliability organization as an applicable entity.
Regional Fill-in-the-Blank Team Comments
o Remove ", sub-region, or interregional coordinating group" from R1
o Consider removing "Standards of conduct are necessary to ensure the Reliability
Coordinator does not act in a manner that favors one market participant over
another." from the Purpose section of the standard.
V0 Industry Comments
o Inability to perform needs to be communicated
o What is meant by ‘interest of other entity’?
Violation Risk Factor Drafting Team Comments
o R6 - Since the RC must be NERC certified, it stands to reason that anyone
performing RC tasks should be certified. However, since the RC still retains the
accountability for actions, and requirement 4 handles the agreements, this
requirement is a medium risk.
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
IRO-002-0
Reliability Coordination – Facilities
FERC NOPR
o Modify Requirement R7 to explicitly require a minimum set of tools for the reliability
coordinator.
V0
o
o
o
Industry Comments
R5 – define synchronized information system
R7 – define ‘adequate’ tools and ‘wide-area’
Words such as ‘easily understood’ and ‘particular emphasis’ need to be tightened
IRO-005-1
FERC NOPR
Reliability Coordination – Current Day Operations
o
Propose that the ERO conduct a survey on IROL practices and experiences.
o
The Commission may propose further modifications to IRO-005-1 based on the
survey results.
V0 Industry Comments
o R10, 11 & 12 – RA not empowered to do this
IRO-016-1
Coordination of Real-Time Activities Between Reliability Coordinators
Violation Risk Factors Drafting Team Comments
o R1.2.1 & R2 – ambiguous
PER-004-0
Reliability Coordination – Staffing
FERC NOPR
o Include formal training requirements for reliability coordinators similar to those
addressed under the personnel training Reliability Standard PER-002-0;
o Include requirements pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0; and
V0 Industry Comments
o Calendar year timing increment
o Other training needs to be defined
PRC-001-0
System Protection Coordination
FERC NOPR
o Include a requirement that relevant transmission operators and generator operators
must be informed immediately upon the detection of failures in relays or protection
system elements on the Bulk-Power System that would threaten reliable operation,
so that these entities can carry out the appropriate corrective control actions
consistent with those used in mitigating IROL violations; and
o Clarify that, after being informed of failures in relays or protection system elements
on the Bulk-Power System, transmission operators or generator operators shall carry
out corrective control actions, i.e., returning the system to a stable state that
respects system requirements as soon as possible and no longer than 30 minutes.
V0
o
o
o
Industry Comments
Effects on reliability may not be known
Consistent terminology as to neighbor vs. affected
Not all criteria moved over from policies
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
The drafting team will reference these guidelines in determining what changes to
make to the standards to bring them into conformance with the Reliability
Standards Development Procedure Manual, Version 6 and the ERO Rules of
Procedure:
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for
complying with the reliability standard, with any specific additions or exceptions noted? Where
multiple functional classes are identified is there a clear line of responsibility for each
requirement identifying the functional class and entity to be held accountable for compliance?
Does the requirement allow overlapping responsibilities between Registered Entities possibly
creating confusion for who is ultimately accountable for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the
entire North American bulk power system, an interconnection, or within a regional entity area?
If no geographic limitations are identified, the default is that the standard applies throughout
North America.
Does this reliability standard identify any limitations on the applicability of the standard based
on electric facility characteristics, such as generators with a nameplate rating of 20 MW or
greater, or transmission facilities energized at 200 kV or greater or some other criteria? If no
functional entity limitations are identified, the default is that the standard applies to all identified
functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a
value statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by
the applicable entities, will provide for a reliable bulk power system, consistent with good utility
practices and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively
evaluate compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Is this reliability standard based upon sound engineering and operating judgment, analysis, or
experience, as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional
entity compliance documents, are the consequences of violating a standard clearly known to the
responsible entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible
entities, using reasonable judgment and in keeping with good utility practices, arrive at a
consistent interpretation of the required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the
assigned responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for
certification. The certification requirements should indicate that entities have a responsibility to
‘maintain’ their capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions
that are approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability
Standards, then the term must be capitalized when it is used in the standard. New terms should
not be added unless they have a ‘unique’ definition when used in a NERC reliability standard.
Common terms that could be found in a college dictionary should not be defined and added to
the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added
to the guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly cause or
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor, control, or restore the bulk electric system. However, violation of a
medium risk requirement is unlikely, under emergency, abnormal, or restoration
conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system,
or the ability to effectively monitor, control, or restore the bulk electric system. A
planning requirement that is administrative in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and
including seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not
real-time.
•
Real-time Operations — actions required within one hour or less to preserve the
reliability of the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of noncompliance.’) The violation severity levels must be applied for each requirement and may be
combined to cover multiple requirements, as long as it is clear which requirements are included
and that all requirements are included.
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one
or more minor details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is
mostly compliant with and meets the intent of the requirement but is deficient with
respect to one or more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially
achieved the reliability objective of the requirement and is missing one or more
significant elements. Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the
reliability objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
4
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
5
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Maureen E. Long
Standards Process Manager
March 19, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for SAR for Reliability Coordination, SAR for
Operating Personnel Communications Protocols, and Relay Loadability Standard
The Standards Committee (SC) announces the following standards actions:
SAR to Modify the Reliability Coordinator Standards (March 19–April 17, 2007)
The Reliability Coordination SAR drafting team posted the second draft of its SAR for Project
2006-06 for a 30-day comment period from March 19 through April 17, 2007.
The SAR proposes retiring, modifying or moving to other standards the Reliability Coordinator
requirements contained within a set of ten already approved standards. The purpose of making
these modifications is to ensure that the remaining requirements are clear, measurable, unique
and enforceable; and to ensure that this set of requirements is sufficient to maintain reliability of
the Bulk Electric System. This project also involves addressing concerns raised by FERC and
stakeholders and involves bringing the set of standards into conformance with the ERO Rules of
Procedure and the latest version of the Reliability Standards Development Procedure. Please use
the comment form to provide comments on this SAR.
SAR for Project 2007-02 Operating Personnel Communications Protocols (March 19–April
17, 2007)
The Operating Personnel Communications Protocols SAR for Project 2007-02 is posted for a 30day comment period from March 19 through April 17, 2007.
This SAR calls for the development of communications protocols for use by real-time system
operators to improve situational awareness and shorten response time. The need for improved
real-time communications protocols was identified during the investigation of the August 2003
Blackout. Please use the comment form to provide comments on this SAR.
Transmission Relay Loadability Standard (March 19–April 17, 2007)
The Transmission Relay Loadability drafting team posted the third draft of its standard for a 30day comment period from March 19 through April 17, 2007. The drafting team is seeking
comments on a change in the requirements that assigns responsibility for identifying certain
critical facilities to the planning coordinator, in support of the latest approved version of the
Functional Model.
The standard codifies the relay loadability criteria embodied in the NERC Recommendation 8a,
Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S.–
Canada Power System Outage Task Force Recommendation 21A, Make More Effective and
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
REGISTERED BALLOT BODY
March 19, 2007
Page Two
Wider Use of System Protection Measures. Please use the comment form to provide comments
on this standard.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: However, this is a large scope (a large amount of work) for the standard
drafting team. Wherever possible, it is recommented that the drafting team list and
explain the criteria it is using so that it may be easier to achieve stakeholder consensus
where many related changes are made. With such a large scope the drafting team
should consider carefully how the changes are balloted so ballots don't fail because
statkeholders object to a minor subset of issues in a particular ballot.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Standards Collaboration Group
Lead Contact:
Terry Bilke
Contact Organization:
Midwest ISO
Contact Segment:
2
Contact Telephone:
317-249-5463
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
David Lemmons
Xcel Energy
MRO
6
Jim Cyrulewski
JDRJC Associates
RFC
8
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: We agree with improving the quality of the requirements, removing
redundancies and those things that do not contribute to reliability.
It isn’t clear what stakeholders will be involved to improve these standards. Is it the
ballot body as a whole or some other forum? Since there is no drafting team roster, we
are not sure who is working on this project and who are the stakeholders suggesting
the changes to requirements.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: The FERC NOPR should not be used to change the standards. Items in the
final order should be given due consideration.
Several of V0 comments items are not clear. They are primarily bullet notes with no
context. Is there additional information about these comments somewhere?
Page 4 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments: We disagree with the assignment of Violation Severity Levels (VSL). The
drafting team should assess the likely bounds of performance and the VSLs should be
divided into four relatively equal portions. Yes/No requirements should not arbitrarily
be counted as Severe violations. The proposed VSL breakdown in the SAR is not part
of the Sanctions Guidelines and the proposed process has not been vetted in the
industry.
Page 5 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization
Lead Contact:
Terry Bilke
Contact Organization:
MRO for Group (Midwest ISO for Lead)
Contact Segment:
2
Contact Telephone:
317-249-5463
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Neal Balu
WPSR
MRO
10
Joe Knight
GRE
MRO
10
Al Boesch
NPPD
MRO
10
Robert Coish, Chair
MHEB
MRO
10
Carol Gerou
MP
MRO
10
Ken Goldsmith
ALT
MRO
10
Todd Gosnell
OPPD
MRO
10
Jim Haigh
WAPA
MRO
10
Pam Oreschnik
XEL
MRO
10
Dave Rudolph
BEPC
MRO
10
Eric Ruskamp
LES
MRO
10
Mike Brytowski, Secretary
MRO
MRO
10
27 Additional MRO Members
Not Named Above
MRO
10
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments: We agree with excluding standards still under development.
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: We agree with improving the quality of the requirements, removing
redundancies and those things that do not contribute to reliability. We do not see a
listing of the drafting team members and it is unclear what stakeholders will be
involved to improve these standards.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: The FERC NOPR should not be used to change the standards. Items in the
final order should be considered.
Several of V0 comments items are not clear. It would help if these fill comments were
posted somewhere for reference.
We disagree with the assignment of Violation Severity Levels (VSL). VSLs should not
be skewed to inflate the sanctions associated with a requirement. The drafting team
should assess the likely bounds of performance and the VSLs should be divided into
four relatively equal portions. The proposed breakdown in the SAR is not part of the
Sanctions Guidelines and has not be vetted in the industry.
Page 4 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC CP9 Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
Northeast Power Coordinating Council
Contact Segment:
10
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Ron Falsetti
The IESO, Ontario
NPCC
2
Roger Champagne
TransEnergie HydroQuebec
NPCC
1
Randy Macdonald
New Brunswick System
Operator
NPCC
2
Herb Schrayshuen
National Grid US
NPCC
1
Al Adamson
New York State Reliability
Council
NPCC
10
Kathleen Goodman
ISO-New England
NPCC
2
David Kiguel
Hydro One Networks
NPCC
1
William Shemley
ISO-New England
NPCC
2
Murale Gopinathan
Northeast Utilities
NPCC
1
Michael Schiavone
National Grid US
NPCC
1
Greg Campoli
New York ISO
NPCC
2
Donald Nelson
MA Dept of Tel.and Energy
NPCC
9
Ed Thompson
ConEd
NPCC
1
Guy V. Zito
NPCC
NPCC
10
Michael Rinalli
National Grid US
NPCC
1
Page 2 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 3 of 6
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 4 of 6
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 5 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 6 of 6
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Calimano
Organization: New York Independent System Operator
Telephone:
518-356-6129
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Please use this form to submit comments on the Reliability Coordination SAR. Comments
must be submitted by February 14, 2007. You may submit the completed form by email to [email protected] with the words “Reliability Coordination” in the subject line. If
you have questions, please contact Maureen Long at [email protected] or by
telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Mike Gentry
Organization: Salt River Project
Telephone:
602-236-6408
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review the set of standards that includes reliability
coordinator requirements with the intent of eliminating duplicate requirements and
upgrading and reorganizing the requirements to ensure that there are requirements that
address the reliability coordinator’s processes, procedures, plans, tools, and authorities to
support real-time operating reliability within its own reliability area and between reliability
coordinator areas in support of reliability of the interconnected bulk power systems.
The scope of the SAR includes the following:
-
The drafting team will review all of the requirements in this set of standards and
eliminate all of the requirements that are redundant. There are redundancies
between requirements in the IRO-sequence of standards and also redundancies
between requirements in the IRO-sequence of standards and the ORG-sequence
of standards, and redundancies with PER-004, COM-001, COM-002, and PRC001. Note that there will be a new standard to address communication
protocols (Project 2007-02) and requirements for real-time communication
protocols need to be transferred to that new standard.
-
The drafting team also needs to review requirements and ensure that the
distinctions between the functional entity and the real-time system operator are
clear and distinct. The requirements should be written for the functional entity.
-
The drafting team also needs to clarify the responsibilities and authorities in the
requirements when comparing the “reliability coordinator” and the “transmission
operator.”
-
The drafting team needs to verify that requirements exempt the real timeoperator from liability when making a good faith effort at preserving reliability.
-
The drafting team needs to address the reliability coordinator’s facilities. A
challenge has been to require that entities have “facilities” in place and available
to the real-time system operators. These facilities are reviewed during
certification, and unless there is a specific requirement to review these facilities,
they may not be reviewed after the initial certification. To eliminate redundancy
between the “certification” standards and the standards that are aimed more at
real-time operations, the certification standards could be phrased to clarify that
entities are required to “have and maintain” the specified facilities. This would
enable the compliance monitor to check facilities on a periodic basis. While
checking the facilities that are used on a daily basis may not be necessary,
making periodic checks of the facilities that are infrequently would motivate
entities to maintain these facilities, e.g., “Shall have a back-up power supply for
critical operations, and shall maintain and test at least once per year.”
-
The results of the Operating Committee’s study on operator situational
awareness tools should be used to verify that the requirements in the
certification standards will meet reliability needs.
-
This project also needs to be coordinated with the project for developing
transmission operator and balancing authority standards (2007-06).
-
IRO-001 has some “fill-in-the-blank” components to eliminate.
Page 3 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
-
The development may include other improvements to the standards deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent
with establishing high quality, enforceable and technically sufficient bulk power
system reliability standards.
Page 4 of 5
January 15, 2007
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Comment Form — 1st Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree that there is a reliability-related need to for the proposed revisions to this
set of standards? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the scope of the SAR? If not, please explain in the comment area.
Yes
No
Comments: The FERC NOPR and FERC Staff comments under Standard PRC-001-0,
System Protection Coordination, do not apply to Reliability Coordination. In fact, the
current Standard, PRC-001-1, does not apply to Reliability Coordinators.This Standard
should be removed from the scope of this SAR.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
Page 5 of 5
January 15, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
WECC Reliability Coordination Comments Work Group
Lead Contact:
Nancy Bellows
Contact Organization:
WECC
Contact Segment:
10
Contact Telephone:
970-461-7246
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Gentry
SRP
WECC
10
Robert Johnson
Xcel - PSC
WECC
10
Frank McElvain
RDRC
WECC
10
Greg Tillitson
CMRC
WECC
10
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: The WECC RCCWG agrees with the overall approach. That said, there is
currently another SAR in process that addresses communications protocols and paths.
The referenced SAR, "Operating Personnel Communications Protocols" is also meant to
address FERC comments relative to communications protocols. Having two separate
SARs that address the same comment seems redundant.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Page 4 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments: The WECC RCCWG believes that revision to each existing Standard, as a
result of this SAR, should be individually balloted, instead of grouped together in one
ballot on the entire group of changes.
Page 5 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jeff Hackman
Organization: Ameren Services
Telephone:
314.554.2839
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: We agree with improving the quality of the requirements, removing
redundancies and those things that do not contribute to reliability.
It isn’t clear what stakeholders will be involved to improve these standards. Is it the
ballot body as a whole or some other forum? Since there is no drafting team roster, we
are not sure who is working on this project and who are the stakeholders suggesting
the changes to requirements.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: The FERC NOPR should not be used to change the standards. Items in the
final order should be given due consideration.
Several of V0 comments items are not clear. They are primarily bullet notes with no
context. Is there additional information about these comments somewhere?
Page 4 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments: We disagree with the assignment of Violation Severity Levels (VSL). The
drafting team should assess the likely bounds of performance and the VSLs should be
divided into four relatively equal portions. Yes/No requirements should not arbitrarily
be counted as Severe violations. The proposed VSL breakdown in the SAR is not part
of the Sanctions Guidelines and the proposed process has not been vetted in the
industry.
To the extent that requirements are modified or moved, care should be taken to make
sure that the two-way exchange of information between RC and TOP and RC and BA
should be preserved.
Page 5 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jason Shaver
Organization: American Transmission Company
Telephone:
262 506 6885
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 6
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 6
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 6
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: The SAR needs to be further refined to identify those specific requirements
that will be:
1) Reviewed as being duplicative
2) Considered being relocated
3) Considered being eliminated
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Page 4 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
Yes
No
Comments: The SAR identified standards IRO-014 and IRO-015 on its first page but
does not address these standards in Attachment 1. The SAR needs to be updated to
either acknowledge that these two standards will not be changed or identify what needs
to be corrected.
Attachment 1:
COM-001-0
NERC has a current effort to address communication facilities in standard EOP-008.
This group needs to be aware of that effort and should insure that any change to COM001 does not counter that effort of EOP-008.
How will this effort differ from the other NERC effort?
COM-002-1
NERC has a current effort to address communication protocol in emergencies with
“Operating Personnel Communications Protocols.” Similar to our previous comment
this group needs to be aware of that effort and should insure that any change to COM002 does not counter that groups efforts.
How will this effort differ from the other NERC effort?
IRO-001-0
Please provide additional information on the following bullet point:
“Reflect the process set forth in the NERC Rules of Procedures”
What specific sections of NERC Rules of Procedure will be reflected in IRO-001-0?
IRO-005-1
The first bullet point does not seem to fall within the goal of this SAR.
“Propose that the ERO conduct a survey of IROL practices and experiences.”
This effort does not need to go through NERC Reliability Standards Development
Process to be performed. NERC could take up this effort at any time and it will slow
down this process if it is going to be included in this SAR.
PER-004-0
NERC has another group that is looking into to these concerns.
How will this effort differ from that effort?
Page 5 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 6 of 6
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Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Susan Renne
Organization: Bonneville Power Administration
Telephone:
(360) 418-2912
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments: No comments
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: No comments
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: No comments at this time. We will comment when the standards are up
for comment.
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Comments: No comments
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments: No comments at this time. We will comment when the standards are up
for comment.
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
CJ Ingersoll
Organization: Constellation
Telephone:
713-332-2906
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments: CECD feels that given the number of standards that IRO-007-1 and IRO010-1 may impact [IRO-002-1 R2, IRO-002-1 R6, IRO-003-2, IRO-004-1 R4 and R5,
IRO-005-2 R1, TOP-003-0 R1.2, TOP-005-1 R1] CECD disagrees with removing them
from consideration. We do agree with the decision to exclude ORG-027-1.
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ed Davis
Organization: Entergy Services
Telephone:
504-576-3029
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
We argree with the reduction of standards to be included in this body of work.
However, we suggest PRC-001 should also be eliminated from this SAR.
The title of the SAR is Reliability Coordination, but the purpose is to ensure
requirements applicable to the Reliability Coordinator are clear, etc., etc. The second
part of the Purpose is to ensure that "this set of requirements" is sufficient… , referring
back to the first part of the sentence. PRC-001 does not apply to the Reliability
Coordinators and is out of place in this SAR.
PRC-001 should not be included in this SAR nor the resulting standard development
work under this SAR. First, PRC-001 does not apply to Reliability Coordinators and
there is already a significantly large amount of work related to Reliability Coordinators
under this SAR. Second, the SDT's attention should not be redirected to system
protection coordination among BAs, TOPs, and GOPs. We disagree if the intent of the
Requestor is to make PRC-001 applicable to Reliability Coordinators under this SAR; If
that is the intent we suggest it be done in a separate SAR activity.
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Dave Folk
Organization: FirstEnergy Corp.
Telephone:
330-384-4668
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments: While IRO-007-1 through IRO-010-1 are currently open for a 30-day
comment period until 4/20/07, this standards work plan effort should leave no stone
unturned in developing quality standards. Consequently, IRO-007-1 through IRO-0101 may contain requirements that are valuable and easily consolidated with the
standards under review by this SAR. In addition, they may also contain duplicative
requirements that could be consolidated as part of the review process of this SAR.
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments: Rather than using the word quality to describe the outcome, the first bullet
point above should say, "Modify the requirement to improve clarity and measureability
while removing abiguity." This way the drafting team could use a check list against
each requirement to test whether it is clear, measureable, and unambiguous.
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments: Under the detailed description in the second paragraph, the SAR should be
modified to include a line item to include "Improve clarity of, improve measureability
of, and remove abiguity from the requirements."
Page 4 of 5
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Comment Form — 2nd Posting of Reliability Coordination SAR
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments: This effort should leave no stone unturned in developing quality standards
within the expertise and domain of this effort. Therefore, every effort must be made to
ensure this round of work plan related standard revisions is as complete and all
encompassing as is humanly possible to ensure to the extent possible that this
standards process reaches a point that these standards are complete, accurate and
only minor revisions are required to maintain them going forward. Tying the hands of
the drafting team as suggested by "Several stakeholders" will only prolong the
industry's work to achieve good, high quality requirements and standards. In addition,
we should be using our resources as efficietly as possible. Allowing some latitude to
the drafting teams to find and fix issues with standards that are related to the
standards within there area of expertise and charge is a good thing to do at this point
in the standards evolution process and conducive to the efficient use of resources. As a
practicle matter this process may never end, but it should reach a point that is much
more manageable sooner rather than later.
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie
Telephone:
514 289-2211, X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
IRC Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
SPP
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Calimano
NYISO
NPCC
2
Alicia Daugherty
PJM
RFC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Anita Lee
AESO
WECC
2
Steve Myers
ERCOT
ERCOT
2
William Phillips
MISO
RFC+SERC+MRO
2
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian F Thumm
Organization: ITC Transmission
Telephone:
248-374-7846
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Please use this form to submit comments on the second draft of the Reliability
Coordination SAR. Comments must be submitted by April 17, 2007. You may submit the
completed form by e-mail to [email protected] with the words “Reliability Coordination”
in the subject line. If you have questions please contact Maureen Long at
[email protected] or by telephone at 813-468-5998.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Gammon
Organization: Kansas City Power & Light
Telephone:
816-654-1242
E-mail:
816-654-1245
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs,
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 — Regional Reliability Organizations, Regional Entities
Page 1 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one Region or Segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
Background Information
The purpose of this SAR is to review a set of standards that includes reliability coordinator
requirements with the intent of eliminating duplicate requirements and upgrading and
reorganizing the requirements.
Based on stakeholder comments, the drafting team made several significant changes to
the first draft of the SAR, including the following:
-
Reduced the number of standards addressed in this project by eliminating
consideration of standards that have not been approved, and standards
expected to be retired as part of the IROL Implementation Plan.
-
Revised the Descriptions to state more clearly the approach the standard
drafting team will take in determining what action to take with each requirement
in the set of standards. The drafting team will work with stakeholders to
determine whether to:
o Modify the requirement to improve its quality
o Move the requirement (into another SAR or Standard or to the certification
process or standards)
o Eliminate the requirement (either because it is redundant or because it
doesn’t support Bulk Electric System reliability).
-
Revised the descriptions of the ‘Reliability Functions’ to reflect the latest version
of the Functional Model (V3).
The SAR Drafting Team asks that you review the revised SAR and then answer the
questions on the following page.
Page 3 of 5
March 19, 2007
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 2nd Posting of Reliability Coordination SAR
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The drafting team reduced the scope of this SAR to eliminate review of standards that
are still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1.
Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
2. The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements:
-
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process
or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t
support Bulk Electric System reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain
in the comment area.
Yes
No
Comments:
3. Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project?
Yes
No
Comments:
4. Several stakeholders indicated that the drafting team should remove the language in
the original SAR that would have allowed the standard drafting team to add
requirements to the standards if those additions were supported by stakeholders. The
drafting team modified the SAR in support of those comments. The SAR drafting team
thinks that additional SARs can be developed in the future to address any gaps in this
set of requirements. Any new SARs generated by this effort would follow the normal
standards development process. Do you support this approach?
Yes
No
Comments:
Page 4 of 5
March 19, 2007
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Comment Form — 2nd Posting of Reliability Coordination SAR
5. If you have any other comments on this SAR that you have not already submitted
above, please provide them here.
No additional comments
Comments:
Page 5 of 5
March 19, 2007
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
The SAR to Modify Reliability Coordinator standards requesters thank all commenters who
submitted comments on Draft 1 of the SAR. This SAR was posted for a 30-day public comment
period from March 19 through April 17, 2007. The requesters asked stakeholders to provide
feedback on the SAR through a special SAR Comment Form. There were 19 sets of comments,
including comments from 52 different people from more than 40 companies representing 8 of
the 10 Industry Segments as shown in the table on the following pages.
Based on comments received, the drafting team made two changes to the SAR:
Replaced references to the FERC NOPR with references to the FERC Order 693
Added a bullet to the detailed description that says, “Improve clarity of, improve
measureability of, and remove abiguity from the requirement” and revised the bullets in
the brief description to match this language.
The drafting team is recommending that the Standards Committee authorize moving the SAR
forward to the standard drafting stage of the standards process.
In this “Consideration of Comments” document stakeholder comments have been organized so
that it is easier to see the responses associated with each question. All comments received on
the standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Reliability-Coordination_Project_2006-6.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal
is to give every comment serious consideration in this process! If you feel there has been an
error or omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060
or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process.1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
Page 1 of 18
May 1, 2007
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
2
1.
Anita Lee (G1)
AESO
2.
Ken Goldsmith (G4)
ALT
3.
Jeff Hackman
Ameren Services
4.
Jason Shaver
American Transmission Co.
5.
Dave Rudolph (G4)
BEPC
6.
Susan Renne
BPA
7.
Brent Kingsford (G1)
CAISO
8.
Greg Tillitson (G5)
CMRC
9.
Ed Thompson (G2)
ConEd
10.
CJ Ingersoll
Constellation
11.
Ed Davis
Entergy Services, Inc.
12.
Steve Myers (G1)
ERCOT
13.
David Folk
FirstEnergy Corp.
14.
Joe Knight (G4)
GRE
15.
David Kiguel (G2)
Hydro One Networks
9
16.
Roger Champagne (I) (G2)
Hydro-Québec TransÉnergie
9
17.
Ron Falsetti (I) (G1) (G2)
IESO
9
18.
Matt Goldbert (G1)
ISO-NE
9
19.
Kathleen Goodman (I) (G2)
ISO-NE
9
20.
William Shemley (G2)
ISO-NE
9
21.
Brian F. Thumm
ITC Transco
22.
Jim Cyrulewski (G3)
JDRJC Associates
23.
Michael Gammon
Kansas City Power & Light
24.
Eric Ruskamp (G4)
LES
25.
Donald Nelson (G2)
MA Dept. of Tel. and Energy
26.
Robert CoisH (I) (G4)
Manitoba Hydro
27.
William Phillips (G1)
MISO
9
28.
Terry Bilke (G3) (G4)
MISO
9
3
4
5
6
7
8
9
10
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
9
Page 2 of 18
9
9
9
May 1, 2007
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
29.
Carol Gerou (G4)
MP
9
30.
Mike Brytowski (G4)
MRO
9
31.
Randy Macdonald (G2)
NBSO
32.
Herb Schrayshuen(G2)
NGRID
9
33.
Michael Schiavone (G2)
NGRID
9
34.
Michael Rinalli (G2)
NGRID
9
35.
Guy V. Zito(G2)
NPCC
9
36.
Al Boesch (G4)
NPPC
9
37.
Murale Gopinathan (G2)
NU
38.
Mike Calimano (I) (G1)
NYISO
39.
Greg Campoli (G2)
NYISO
40.
Ralph Rufrano (G2)
NYPA
41.
Al Adamson (G2)
NYSRC
42.
Todd Gosnell (G4)
OPPD
43.
Alicia Daugherty (G1)
PJM
44.
Frank McElvain (G5)
RDRC
45.
Charles Yeung (G1)
SPP
46.
Mike Gentry (I) G5)
SRP
47.
Jim Haigh (G4)
WAPA
9
48.
Nancy Bellows (G5)
WECC
9
49.
Neal Balu (G4)
WPSR
9
50.
Robert Johnson (G5)
Xcel – PSC
9
51.
David Lemmons (G3)
Xcel Energy
52.
Pam Oreschnik (G4)
XEL
9
9
9
9
9
9
9
9
9
9
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – IRC Standards Review Committee
G2 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G3 – Midwest Standards Collaboration Group
G4 – MRO Members
G5 – WECC Reliability Coordination Comments Work Group
Page 3 of 18
May 1, 2007
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Index to Questions, Comments, and Responses
1.
The drafting team reduced the scope of this SAR to eliminate review of standards that are
still under development, including IRO-007-1 through IRO-010-1, and ORG-027-1. Do
you agree with this modification? If not, please explain in the comment area. ...............5
2.
The drafting team modified the SAR to be more exacting in describing the scope of
changes proposed for the set of standards. The revised SAR clarifies that the Standard
Drafting Team will work with stakeholders to determine what to do with each of the
existing requirements: ...........................................................................................8
3.
Are there additional revisions, beyond those identified in the SAR that should be
addressed within the scope of this project? ............................................................. 12
4.
Several stakeholders indicated that the drafting team should remove the language in the
original SAR that would have allowed the standard drafting team to add requirements to
the standards if those additions were supported by stakeholders. The drafting team
modified the SAR in support of those comments. The SAR drafting team thinks that
additional SARs can be developed in the future to address any gaps in this set of
requirements. Any new SARs generated by this effort would follow the normal standards
development process. Do you support this approach? .............................................. 14
5.
If you have any other comments on this SAR that you have not already submitted above,
please provide them here. .................................................................................... 18
Page 4 of 18
May 1, 2007
1. The drafting team reduced the scope of this SAR to eliminate review of standards that are still under development, including
IRO-007-1 through IRO-010-1, and ORG-027-1. Do you agree with this modification? If not, please explain in the
comment area.
Summary Consideration: Most stakeholders agreed with the modifications made to reduce the scope of this SAR.
Question #1
Commenter
Entergy
Yes
No
;
Comment
We agree with the reduction of standards to be included in this body of work. However,
we suggest PRC-001 should also be eliminated from this SAR.
The title of the SAR is Reliability Coordination, but the purpose is to ensure requirements
applicable to the Reliability Coordinator are clear, etc., etc. The second part of the
Purpose is to ensure that "this set of requirements" is sufficient… , referring back to the
first part of the sentence. PRC-001 does not apply to the Reliability Coordinators and is
out of place in this SAR.
PRC-001 should not be included in this SAR nor the resulting standard development work
under this SAR. First, PRC-001 does not apply to Reliability Coordinators and there is
already a significantly large amount of work related to Reliability Coordinators under this
SAR. Second, the SDT's attention should not be redirected to system protection
coordination among BAs, TOPs, and GOPs. We disagree if the intent of the Requestor is
to make PRC-001 applicable to Reliability Coordinators under this SAR; If that is the
intent we suggest it be done in a separate SAR activity.
Response: Requirement 2.2 in PRC-001 states:
If a protective relay or equipment failure reduces system reliability, the Transmission Operator shall notify its Reliability Coordinator
and affected Transmission Operators and Balancing Authorities. The Transmission Operator shall take corrective action as soon as
possible.
This is ‘incomplete’ because there is no requirement for the RC to use that information. The intent in including PRC-001 in
this SAR was to ‘complete’ this requirement. As envisioned, the new requirement may go in one of the existing RC
standards, or may go into a new standard – but because it is something for the RC to do, it seems appropriate to include the
consideration of this requirement as part of the RC SAR.
FirstEnergy
IRO-007-1 through IRO-010-1 are currently open for a 30-day comment period
; While
until 4/20/07, this standards work plan effort should leave no stone unturned in
developing quality standards. Consequently, IRO-007-1 through IRO-010-1 may contain
requirements that are valuable and easily consolidated with the standards under review
Page 5 of 18
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #1
Commenter
Yes
No
Comment
by this SAR. In addition, they may also contain duplicative requirements that could be
consolidated as part of the review process of this SAR.
Response: The Implementation Plan posted with IRO-007 through IRO-010 already calls for modification to some of the
standards included in this SAR. However, the changes identified with the implementation plan for IRO-007 through IRO-011
are limited to those changes resulting from adoption of the proposed standards. If changes are needed to IRO-007 through
IRO-010, they can be addressed with a new SAR.
Constellation
CECD feels that given the number of standards that IRO-007-1 and IRO-010-1 may
;
impact [IRO-002-1 R2, IRO-002-1 R6, IRO-003-2, IRO-004-1 R4 and R5, IRO-005-2 R1,
TOP-003-0 R1.2, TOP-005-1 R1] CECD disagrees with removing them from
consideration. We do agree with the decision to exclude ORG-027-1.
Response: Please review the Implementation Plan posted with IRO-007 through IRO-010. The proposed changes to the list
of standards you identified are limited to those changes resulting from adoption of the proposed standards. . If changes are
needed to IRO-007 through IRO-010, they can be addressed with a new SAR.
MRO
We agree with excluding standards still under development.
;
Response: Thank you for your support – most commenters agreed with omitting all standards still under development.
Ameren Services
;
ATC LLC
BPA
Hydro-Québec
TransÉnergie
IESO
IRC SRC
ISO-NE
ITC Transco
KCPL
Manitoba Hydro
Midwest SCG
NPCC CP9 RSWG
NYISO
;
;
;
;
;
;
;
;
;
;
;
;
Page 6 of 18
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #1
Commenter
SRP
WECC RCCWG
Yes
No
Comment
;
;
Page 7 of 18
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
2. The drafting team modified the SAR to be more exacting in describing the scope of changes proposed for the set of
standards. The revised SAR clarifies that the Standard Drafting Team will work with stakeholders to determine what to do
with each of the existing requirements:
−
−
−
Modify the requirement to improve its quality
Move the requirement (into another SAR or Standard or to the certification process or standards)
Eliminate the requirement (either because it is redundant or because it doesn’t support Bulk Electric System
reliability).
Do you agree with this approach to reviewing the requirements? If not, please explain in the comment area.
Summary Consideration: Most stakeholders agreed with this approach to reviewing the requirements in the standards
associated with this SAR.
Question #2
Commenter
SRP
Yes
No
Comment
The
FERC
NOPR
and
FERC
Staff
comments
under Standard PRC-001-0, System
; Protection Coordination, do not apply to Reliability
Coordination. In fact, the current
Standard, PRC-001-1, does not apply to Reliability Coordinators.This Standard should be
removed from the scope of this SAR.
Response: The FERC NOPR has now been replaced with FERC Order 693 and includes the following language regarding PRC001-1:
1449. The Commission approves Reliability Standard PRC-001-1 as mandatory and enforceable. In addition, the Commission directs
the ERO to develop modifications to PRC-001-1 through the Reliability Standards development process that:
(1) correct the references for Requirements and
(2) include a requirement that upon the detection of failures in relays or protection system elements on the Bulk-Power System that
threaten reliable operation, relevant transmission operators must be informed promptly, but within a specified period of time that is
developed in the Reliability Standards development process, whereas generator operators must also promptly inform their transmission
operators and
(3) clarifies that, after being informed of failures in relays or protection system elements that threaten reliability of the Bulk-Power
System, transmission operators must carry out corrective control actions, i.e., return a system to a stable state that respects system
requirements as soon as possible and no longer than 30 minutes after they receive notice of the failure.
The existing PRC-001-1 Requirement 2.2 states:
If a protective relay or equipment failure reduces system reliability, the Transmission Operator shall notify its Reliability Coordinator
and affected Transmission Operators and Balancing Authorities. The Transmission Operator shall take corrective action as soon as
possible.
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Question #2
Commenter
Yes No
Comment
This is ‘incomplete’ because there is no requirement for the RC to use that information. The intent in including PRC-001 in
this SAR was to ‘complete’ this requirement. As envisioned, the new requirement may go in one of the existing RC
standards, or may go into a new standard – but because it is something for the RC to do, it seems appropriate to include the
consideration of this requirement as part of the RC SAR.
Ameren Services
agree with improving the quality of the requirements, removing redundancies and
; ; We
Midwest SCG
those things that do not contribute to reliability.
It isn’t clear what stakeholders will be involved to improve these standards. Is it the
ballot body as a whole or some other forum? Since there is no drafting team roster, we
are not sure who is working on this project and who are the stakeholders suggesting the
changes to requirements.
Response: The Reliability Standards Development Procedure will be used to collect stakeholder feedback. If the Standards
Committee (SC) accepts this SAR, then the SC can either appoint the existing drafting team to work with stakeholders to
make revisions to the standards, or the SC can have the standards staff send a notice to all members of the RBB as well as
all entities who have indicated they want to receive email notices of standards actions to let everyone know that the SC is
seeking volunteers to work on a new drafting team. In either case, the drafting team will ‘propose’ revisions and post those
for comment. NERC’s standards staff will send an email notice to all members of the RBB as well as all entities who have
indicated they want to receive email notices of standards actions – the notice will tell people that some proposed revisions
have been posted for comment and will seek feedback on the proposed revisions through a comment form – the same
process as used to collect feedback on this SAR. The drafting team will use the responses to the questions on the comment
form to determine which changes are supported by stakeholders, and will continue to make modifications until the drafting
team feels that they have a set of proposed changes that meets the consensus of the stakeholders who participated in the
comment periods.
The drafting team that is working on the IROL standards submitted this Reliability Coordination SAR – the SC did not assign a
separate drafting team to address the SAR comments. The roster for this team is posted on the related files page of the
IROL standards. Here is a link to the roster: ftp://www.nerc.com/pub/sys/all_updl/standards/dt/GroupRoster_IROLSDT.pdf
MRO
agree with improving the quality of the requirements, removing redundancies and
; ; We
those things that do not contribute to reliability. We do not see a listing of the drafting
team members and it is unclear what stakeholders will be involved to improve these
standards.
Response: The Reliability Standards Development Procedure will be used to collect stakeholder feedback. If the Standards
Committee (SC) accepts this SAR, then the SC can either appoint the existing drafting team to work with stakeholders to
make revisions to the standards, or the SC can have the standards staff send a notice to all members of the RBB as well as
all entities who have indicated they want to receive email notices of standards actions to let everyone know that the SC is
seeking volunteers to work on a new drafting team. In either case, the drafting team will ‘propose’ revisions and post those
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Question #2
Commenter
Yes No
Comment
for comment. NERC’s standards staff will send an email notice to all members of the RBB as well as all entities who have
indicated they want to receive email notices of standards actions – the notice will tell people that some proposed revisions
have been posted for comment and will seek feedback on the proposed revisions through a comment form – the same
process as used to collect feedback on this SAR. The drafting team will use the responses to the questions on the comment
form to determine which changes are supported by stakeholders, and will continue to make modifications until the drafting
team feels that they have a set of proposed changes that meets the consensus of the stakeholders who participated in the
comment periods.
The drafting team that is working on the IROL standards submitted this Reliability Coordination SAR – the SC did not assign a
separate drafting team to address the SAR comments. The roster for this team is posted on the related files page of the
IROL standards. Here is a link to the roster: ftp://www.nerc.com/pub/sys/all_updl/standards/dt/GroupRoster_IROLSDT.pdf
FirstEnergy
Rather than using the word quality to describe the outcome, the first bullet point above
;
should say, "Modify the requirement to improve clarity and measureability while
removing abiguity." This way the drafting team could use a check list against each
requirement to test whether it is clear, measureable, and unambiguous.
Response: The drafting team has adopted this suggestion and modified the SAR so that the revised bullet now says:
- Modify the requirement to improve its clarity and measureability while removing abiguity
Manitoba Hydro
However, this is a large scope (a large amount of work) for the standard drafting team.
;
Wherever possible, it is recommended that the drafting team list and explain the criteria
it is using so that it may be easier to achieve stakeholder consensus where many related
changes are made. With such a large scope the drafting team should consider carefully
how the changes are balloted so ballots don't fail because stakeholders object to a minor
subset of issues in a particular ballot.
Response: Agreed.
WECC RCCWG
The WECC RCCWG agrees with the overall approach. That said, there is currently
;
another SAR in process that addresses communications protocols and paths. The
referenced SAR, "Operating Personnel Communications Protocols" is also meant to
address FERC comments relative to communications protocols. Having two separate
SARs that address the same comment seems redundant.
Response: There are a couple of standards that are in more than one ‘project’ in the Reliability Standards Work Plan 20072009. The coordinators working with the drafting teams for these projects are aware of this duplication and will ‘hand off’
requirements between one another to ensure that each requirement is addressed and that only one drafting team works on
modifying each requirement.
ATC LLC
;
BPA
;
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #2
Commenter
Constellation
Entergy
Hydro-Québec
TransÉnergie
IESO
IRC SRC
ISO-NE
ITC Transco
KCPL
NPCC CP9 RSWG
NYISO
Yes
No
Comment
;
;
;
;
;
;
;
;
;
;
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
3. Are there additional revisions, beyond those identified in the SAR that should be addressed within the scope of this project?
Summary Consideration: The drafting team made the following modifications to the SAR based on stakeholder
suggestions for additional revisions:
Replaced references to the FERC NOPR with references to the FERC Order 693
Added a bullet to the detailed description that says, “Improve clarity of, improve measureability of, and remove abiguity
from the requirement”
Question #3
Commenter
MRO
Yes
;
No
Comment
The FERC NOPR should not be used to change the standards. Items in the final order
should be considered.
Several of V0 comments items are not clear. It would help if these fill comments were
posted somewhere for reference.
We disagree with the assignment of Violation Severity Levels (VSL). VSLs should not be
skewed to inflate the sanctions associated with a requirement. The drafting team should
assess the likely bounds of performance and the VSLs should be divided into four
relatively equal portions. The proposed breakdown in the SAR is not part of the
Sanctions Guidelines and has not be vetted in the industry.
Response: Agreed. The drafting team has modified the SAR to replace the references to the NOPR with references to FERC
Order 693.
The Version 0 comments are posted on the Approved Standards web page – here is the link to that set of comments:
ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Standards_V0_Industry_Comments_20060105.pdf
The proposed breakdown in VSLs was not included in the Sanctions Guidelines – but it was supported by both the Standards
Committee and the Compliance and Certification Committee on December 14, 2006. The Stanards Committee supported
having drafting teams use the breakdown that appears in the SAR – and that breakdown was included in the Reliabilty
Standards Development Work Plan 2007-2009.
Ameren Services
The FERC NOPR should not be used to change the standards. Items in the final order
;
Midwest SCG
should be given due consideration.
Several of V0 comments items are not clear. They are primarily bullet notes with no
context. Is there additional information about these comments somewhere?
Response: Agreed. The drafting team has modified the SAR to replace the references to the NOPR with references to FERC
Order 693.
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #3
Commenter
Yes No
Comment
The Version 0 comments are posted on the Approved Standards web page – here is the link to that set of comments:
ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Standards_V0_Industry_Comments_20060105.pdf
ATC LLC
;
Constellation
;
The SAR needs to be further refined to identify those specific requirements that will be:
1) Reviewed as being duplicative
2) Considered being relocated
3) Considered being eliminated
Response: As envisioned, the standard drafting team will work with stakeholders (using the comment process) to propose
and obtain stakeholder feedback on whether each requirement should be retired, moved, enhanced, etc.
FirstEnergy
Under the detailed description in the second paragraph, the SAR should be modified to
;
include a line item to include "Improve clarity of, improve measureability of, and remove
abiguity from the requirements."
Response: The drafting team adopted your suggestion and added the proposed bullet to the detailed description of the SAR.
BPA
No comments at this time. We will comment when the standards are up for comment.
;
Entergy
Hydro-Québec
TransÉnergie
IESO
IRC SRC
ISO-NE
ITC Transco
KCPL
Manitoba Hydro
NPCC CP9 RSWG
NYISO
SRP
WECC RCCWG
;
;
;
;
;
;
;
;
;
;
;
;
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
4. Several stakeholders indicated that the drafting team should remove the language in the original SAR that would have
allowed the standard drafting team to add requirements to the standards if those additions were supported by stakeholders.
The drafting team modified the SAR in support of those comments. The SAR drafting team thinks that additional SARs can
be developed in the future to address any gaps in this set of requirements. Any new SARs generated by this effort would
follow the normal standards development process. Do you support this approach?
Summary Consideration: Stakeholders who responded to this question overwhelmingly indicated support for having firm
boundaries on what could be changed with the associated standards by removing the open-ended language from the original
SAR.
Question #4
Commenter
BPA
Yes
FirstEnergy
;
No
Comment
;
This effort should leave no stone unturned in developing quality standards within the
expertise and domain of this effort. Therefore, every effort must be made to ensure this
round of work plan related standard revisions is as complete and all encompassing as is
humanly possible to ensure to the extent possible that this standards process reaches a
point that these standards are complete, accurate and only minor revisions are required
to maintain them going forward. Tying the hands of the drafting team as suggested by
"Several stakeholders" will only prolong the industry's work to achieve good, high quality
requirements and standards. In addition, we should be using our resources as efficietly
as possible. Allowing some latitude to the drafting teams to find and fix issues with
standards that are related to the standards within there area of expertise and charge is a
good thing to do at this point in the standards evolution process and conducive to the
efficient use of resources. As a practicle matter this process may never end, but it
should reach a point that is much more manageable sooner rather than later.
Response: Stakeholders overwhelmingly indicated support for having firm boundaries on what could be changed with the
associated standards.
ATC LLC
The SAR identified standards IRO-014 and IRO-015 on its first page but does not address
;
these standards in Attachment 1. The SAR needs to be updated to either acknowledge
that these two standards will not be changed or identify what needs to be corrected.
Attachment 1:
COM-001-0
NERC has a current effort to address communication facilities in standard EOP-008. This
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #4
Commenter
Yes
No
Comment
group needs to be aware of that effort and should insure that any change to COM-001
does not counter that effort of EOP-008.
How will this effort differ from the other NERC effort?
COM-002-1
NERC has a current effort to address communication protocol in emergencies with
“Operating Personnel Communications Protocols.” Similar to our previous comment this
group needs to be aware of that effort and should insure that any change to COM-002
does not counter that groups efforts.
How will this effort differ from the other NERC effort?
IRO-001-0
Please provide additional information on the following bullet point:
“Reflect the process set forth in the NERC Rules of Procedures”
What specific sections of NERC Rules of Procedure will be reflected in IRO-001-0?
IRO-005-1
The first bullet point does not seem to fall within the goal of this SAR.
“Propose that the ERO conduct a survey of IROL practices and experiences.”
This effort does not need to go through NERC Reliability Standards Development Process
to be performed. NERC could take up this effort at any time and it will slow down this
process if it is going to be included in this SAR.
PER-004-0
NERC has another group that is looking into to these concerns.
How will this effort differ from that effort?
Response:
The two coordinate operations standards highlighted (IRO-014 and IRO-015), did not have any suggestions from FERC for
improvements, and they were not part of Version 0 so there were no suggestions for improvements to these standards from
the Version 0 process.
COM-001 and COM-002 both contain requirements that are assigned to several different functions – and both include a mix
of ‘preparedness’ requirements as well as some ‘real-time’ notification requirements as well as some requirements that may
end up being converted into a new standard for ‘communications protocols’. The intent in including the standards in multiple
projects was to ensure that each requirement was fully addressed and ended up where it belonged. The coordinators
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #4
Commenter
Yes No
Comment
supporting these projects are aware of this duplication and are working to ensure that there is a ‘hand off’ of requirements
between teams to eliminate gaps and duplication.
IRO-001
In Order 693, FERC explains what it meant by the bullet, ‘Reflect the process set forth in the NERC Rules of Procedure’:
896. In the NOPR, the Commission proposed to approve the Reliability Standard as mandatory and enforceable. In addition, as a
separate action under section 215(d)(5), the NOPR proposed to direct the ERO to develop modifications to Requirement R1 to substitute
“Regional Entity” for “regional reliability organization” and reflect NERC’s Rules of Procedure for registering, certifying and verifying
entities, including reliability coordinators.
IRO-005-1
The bullet point you’ve highlighted may or may not be addressed by the drafting team. As envisioned, the results of a survey
may prove useful in determining a need for additional modifications to the standards. Note that FERC Order 693 has replaced
the NOPR and the SAR has been updated to reflect this. The survey is still identified in Order 693 – and FERC clarified that
the intent of the survey is to determine if additional modifications to IRO-005 are necessary.
PER-004 includes a mix of preparation and real-time requirements. The intent in placing the standard in more than one
project is to ensure that each requirement is reviewed by an appropriate team, and that all requirements that are needed end
up in an appropriate standard.
Ameren Services
;
Constellation
Entergy
Hydro-Québec
TransÉnergie
IESO
IRC SRC
ISO-NE
ITC Transco
KCPL
Manitoba Hydro
;
;
;
;
;
;
;
;
;
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
Question #4
Commenter
Midwest SCG
MRO
NPCC CP9 RSWG
NYISO
WECC RCCWG
Yes
No
Comment
;
;
;
;
;
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Consideration of Comments for SAR to Modify Reliability Coordinator Standards
5. If you have any other comments on this SAR that you have not already submitted above, please provide them here.
Summary Consideration: The drafting team did not make any conforming changes to the SAR based on comments provided
in response to question 5.
Question #5
Commenter
Ameren Services
Yes
No
Comment
We disagree with the assignment of Violation Severity Levels (VSL). The drafting team
should assess the likely bounds of performance and the VSLs should be divided into four
relatively equal portions. Yes/No requirements should not arbitrarily be counted as
Severe violations. The proposed VSL breakdown in the SAR is not part of the Sanctions
Guidelines and the proposed process has not been vetted in the industry.
To the extent that requirements are modified or moved, care should be taken to make
sure that the two-way exchange of information between RC and TOP and RC and BA
should be preserved.
Response: Violation Severity Levels identify how badly you missed the intent of a requirment – not all requirements lend
themselves to 4 different VSLs. The guidelines for determining a VSL are just ‘guidelines’ – however these guidelines were
endorsed by the SC and the CCC and the SDT would need a strong reason for not using these guidelines.
Midwest SCG
We disagree with the assignment of Violation Severity Levels (VSL). The drafting team
should assess the likely bounds of performance and the VSLs should be divided into four
relatively equal portions. Yes/No requirements should not arbitrarily be counted as
Severe violations. The proposed VSL breakdown in the SAR is not part of the Sanctions
Guidelines and the proposed process has not been vetted in the industry.
Response: Violation Severity Levels identify how badly you missed the intent of a requirment – not all requirements lend
themselves to 4 different VSLs. The guidelines for determining a VSL are just ‘guidelines’ – however these guidelines were
endorsed by the SC and the CCC and the SDT would need a strong reason for not using these guidelines.
BPA
; No comments at this time. We will comment when the standards are up for comment.
Response:
WECC RCCWG
The WECC RCCWG believes that revision to each existing Standard, as a result of this
SAR, should be individually balloted, instead of grouped together in one ballot on the
entire group of changes.
Response: The SDT appointed to work on the standards will identify how to ballot the standards modified as part of this set
of standards.
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Authorization Request Form
Title of Proposed Standard
Reliability Coordination (Project 2006-06)
Request Date
December 18, 2006
Revised Date
May 1, 2007
SAR Requestor Information
Name
Ellis Rankin
Primary Contact
Ellis Rankin
SAR Type (Check a box for each one that applies.)
New Standard
Revision to existing Standards – see list below
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination –
Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current
Day Operations
IRO-014 — Procedures to Support Coordination
between Reliability Coordinators
IRO-015 — Notifications and Information
Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities
between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
Telephone
214-743-6828
Fax
972-263-6710
E-mail
[email protected]
Withdrawal of existing Standard
Some requirements in the above standards
Urgent Action
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
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Standards Authorization Request Form
Purpose
To ensure that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable; and to ensure that this set of requirements is sufficient to maintain
reliability of the Bulk Electric System.
Brief Description
Most of the requirements in this set of standards were translated from Operating Policies as part of the
Version 0 process. There have been suggestions for improving these requirements, and the drafting
team will consider comments submitted by stakeholders, drafting teams and FERC in determining what
changes should be proposed to stakeholders.
The drafting team will review all of the requirements in this set of standards and make a determination,
with stakeholders, on whether to:
- Modify the requirement to improve its clarity and measureability while removing abiguity
Move the requirement (into another SAR or Standard or to the certification process or
standards)
- Eliminate the requirement (either because it is redundant or because it doesn’t support bulk
power system reliability).
Detailed Description
The drafting team will review all of the requirements in the following set of standards:
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination – Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current Day Operations
IRO-014 — Procedures to Support Coordination between Reliability Coordinators
IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
For each existing requirement, the drafting team will work with stakeholders and:
- Eliminate redundancy in the requirements.
- Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC
to certification.
- Improve clarity of, improve measureability of, and remove abiguity from the requirement
The standard drafting team will also:
Coordinate with the drafting teams working on the SAR and standards for Transmission
Operator and Balancing Authority standards (Project 2007-06).
Consider comments received during the initial development of this set of standards and other
comments received from ERO regulatory authorities and stakeholders (Attachment 1)
Bring the standards into conformance with the latest version of the Reliability Standards
Development Procedure and the ERO Rules of Procedure. (Attachment 2)
This review of the set of identified standards will satisfy the standards procedure requirement to review
each approved standard at least once every five years.
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports system frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and related reliability-related
services) to serve the end-use customer.
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Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
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Standards Authorization Request Form
Related Standards – Listed under description
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Explanation
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
The drafting team will assist stakeholders in considering these comments in determining
what changes to make to the standards:
COM-001-0
Telecommunications
FERC Order 693
o Include generator operators and distribution provider as applicable entities and and
include requirements for their telecommunications
o Include requirements for telecommunication facilities for use during normal and
emergency conditions that reflect the roles of the applicable entities and their impact
on reliable operation
o Includes adequate flexibility for compliance with the reliability standard, adoption of
new technologies and cost-effective solutions
V0 Industry Comments
o Many players missing
o Apply R1 to all but smallest entities
Violation Risk Factor Drafting Team Comments
o R6 – administrative requirement
COM-002-1
Communications and Coordination
FERC Order 693
o Include a Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area views of transmission operators or balancing
authorities;
o Include distribution providers as applicable entities; and
o Require tightened communications protocols, especially for communications during
alerts and emergencies.
V0
o
o
o
o
Industry Comments
Voice with generators not required
R1 – include reliability authority
R2 – include sabotage and security
R4 – clarify repeat back requirement with regard to emergency
IRO-001-0
Reliability Coordination – Responsibilities and Authorities
FERC Order 693
o Reflect the process set forth in the NERC Rules of Procedures; and
o Eliminate the regional reliability organization as an applicable entity.
Regional Fill-in-the-Blank Team Comments
o Remove ", sub-region, or interregional coordinating group" from R1
o Consider removing "Standards of conduct are necessary to ensure the Reliability
Coordinator does not act in a manner that favors one market participant over
another." from the Purpose section of the standard.
V0 Industry Comments
o Inability to perform needs to be communicated
o What is meant by ‘interest of other entity’?
Violation Risk Factor Drafting Team Comments
o R6 - Since the RC must be NERC certified, it stands to reason that anyone
performing RC tasks should be certified. However, since the RC still retains the
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
accountability for actions, and requirement 4 handles the agreements, this
requirement is a medium risk.
IRO-002-0
Reliability Coordination – Facilities
FERC Order 693
o Require a minimum set of tools that should be made available to reliability
coordinators.
V0
o
o
o
Industry Comments
R5 – define synchronized information system
R7 – define ‘adequate’ tools and ‘wide-area’
Words such as ‘easily understood’ and ‘particular emphasis’ need to be tightened
IRO-005-1
Reliability Coordination – Current Day Operations
FERC Order 693
o
Measures and Levels of Non-Compliance specific to IROL violations must be
commensurate with the magnitude, duration, frequency and causes of the violations
and whether these occur during normal or contingency conditions.
o
Conduct a survey on IROL practices and experiences; the Commission may propose
further modifications to IRO-005-1 based on the survey results.
V0 Industry Comments
o R10, 11 & 12 – RA not empowered to do this
IRO-016-1
Coordination of Real-Time Activities Between Reliability Coordinators
Violation Risk Factors Drafting Team Comments
o R1.2.1 & R2 – ambiguous
PER-004-0
Reliability Coordination – Staffing
FERC Order 693
o Include formal training requirements for reliability coordinators similar to those
addressed under the personnel training Reliability Standard PER-002-0;
o Include requirements pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0
o Consider the suggestions of FirstEnergy and Xcel:
1413. FirstEnergy seeks revisions to the terms “shall have a comprehensive
understanding” and “shall have extensive knowledge.” It states that it will be difficult
for entities to demonstrate compliance with these terms. In addition, FirstEnergy
suggests that the reliability coordinator staffing requirements should be located in
the IRO Reliability Standards.
1414. Xcel states that emergency training requirements should be expressed in hour
increments rather than days to allow for flexibility in scheduling training and
coordinating with rotating shift schedules.
V0 Industry Comments
o Calendar year timing increment
o Other training needs to be defined
PRC-001-0
System Protection Coordination
FERC Order 693
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
o Correct the references for Requirements
o Include a requirement that upon the detection of failures in relays or protection
system elements on the Bulk-Power System that threaten reliable operation,
relevant transmission operators must be informed promptly, but within a specified
period of time whereas generator operators must also promptly inform their
transmission operators
o Clarify that, after being informed of failures in relays or protection system elements
that threaten reliability of the Bulk-Power System, transmission operators must carry
out corrective control actions, i.e., return the system to a stable state that respects
system requirements as soon as possible and no longer than 30 minutes after they
receive notice of the failure
V0
o
o
o
Industry Comments
Effects on reliability may not be known
Consistent terminology as to neighbor vs. affected
Not all criteria moved over from policies
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
The drafting team will reference these guidelines in determining what changes to
make to the standards to bring them into conformance with the Reliability
Standards Development Procedure Manual, Version 6 and the ERO Rules of
Procedure:
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels must be applied for each requirement and may be combined to cover
multiple requirements, as long as it is clear which requirements are included and that all requirements are
included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan. The effective date should be linked to the NERC BOT adoption date.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
4
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Standard Authorization Request Form
Title of Proposed Standard
Reliability Coordination (Project 2006-06)
Request Date
December 18, 2006
Revised Date
May 1, 2007
SAR Requestor Information
Name
Ellis Rankin
Primary Contact
Ellis Rankin
SAR Type (Check a box for each one that applies.)
New Standard
Revision to existing Standards – see list below
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination –
Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current
Day Operations
IRO-014 — Procedures to Support Coordination
between Reliability Coordinators
IRO-015 — Notifications and Information
Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities
between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
Telephone
214-743-6828
Fax
972-263-6710
E-mail
[email protected]
Withdrawal of existing Standard
Some requirements in the above standards
Urgent Action
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Authorization Request Form
Purpose
To ensure that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable; and to ensure that this set of requirements is sufficient to maintain
reliability of the Bulk Electric System.
Brief Description
Most of the requirements in this set of standards were translated from Operating Policies as part of the
Version 0 process. There have been suggestions for improving these requirements, and the drafting
team will consider comments submitted by stakeholders, drafting teams and FERC in determining what
changes should be proposed to stakeholders.
The drafting team will review all of the requirements in this set of standards and make a determination,
with stakeholders, on whether to:
- Modify the requirement to improve its clarity and measureability while removing abiguity
Move the requirement (into another SAR or Standard or to the certification process or
standards)
- Eliminate the requirement (either because it is redundant or because it doesn’t support bulk
power system reliability).
Detailed Description
The drafting team will review all of the requirements in the following set of standards:
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination – Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current Day Operations
IRO-014 — Procedures to Support Coordination between Reliability Coordinators
IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
For each existing requirement, the drafting team will work with stakeholders and:
- Eliminate redundancy in the requirements.
- Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC
to certification.
- Improve clarity of, improve measureability of, and remove abiguity from the requirement
The standard drafting team will also:
Coordinate with the drafting teams working on the SAR and standards for Transmission
Operator and Balancing Authority standards (Project 2007-06).
Consider comments received during the initial development of this set of standards and other
comments received from ERO regulatory authorities and stakeholders (Attachment 1)
Bring the standards into conformance with the latest version of the Reliability Standards
Development Procedure and the ERO Rules of Procedure. (Attachment 2)
This review of the set of identified standards will satisfy the standards procedure requirement to review
each approved standard at least once every five years.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports system frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and related reliability-related
services) to serve the end-use customer.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Authorization Request Form
Related Standards – Listed under description
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Explanation
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
The drafting team will assist stakeholders in considering these comments in determining
what changes to make to the standards:
COM-001-0
Telecommunications
FERC Order 693
o Include generator operators and distribution provider as applicable entities and and
include requirements for their telecommunications
o Include requirements for telecommunication facilities for use during normal and
emergency conditions that reflect the roles of the applicable entities and their impact
on reliable operation
o Includes adequate flexibility for compliance with the reliability standard, adoption of
new technologies and cost-effective solutions
V0 Industry Comments
o Many players missing
o Apply R1 to all but smallest entities
Violation Risk Factor Drafting Team Comments
o R6 – administrative requirement
COM-002-1
Communications and Coordination
FERC Order 693
o Include a Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area views of transmission operators or balancing
authorities;
o Include distribution providers as applicable entities; and
o Require tightened communications protocols, especially for communications during
alerts and emergencies.
V0
o
o
o
o
Industry Comments
Voice with generators not required
R1 – include reliability authority
R2 – include sabotage and security
R4 – clarify repeat back requirement with regard to emergency
IRO-001-0
Reliability Coordination – Responsibilities and Authorities
FERC Order 693
o Reflect the process set forth in the NERC Rules of Procedures; and
o Eliminate the regional reliability organization as an applicable entity.
Regional Fill-in-the-Blank Team Comments
o Remove ", sub-region, or interregional coordinating group" from R1
o Consider removing "Standards of conduct are necessary to ensure the Reliability
Coordinator does not act in a manner that favors one market participant over
another." from the Purpose section of the standard.
V0 Industry Comments
o Inability to perform needs to be communicated
o What is meant by ‘interest of other entity’?
Violation Risk Factor Drafting Team Comments
o R6 - Since the RC must be NERC certified, it stands to reason that anyone
performing RC tasks should be certified. However, since the RC still retains the
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
accountability for actions, and requirement 4 handles the agreements, this
requirement is a medium risk.
IRO-002-0
Reliability Coordination – Facilities
FERC Order 693
o Require a minimum set of tools that should be made available to reliability
coordinators.
V0
o
o
o
Industry Comments
R5 – define synchronized information system
R7 – define ‘adequate’ tools and ‘wide-area’
Words such as ‘easily understood’ and ‘particular emphasis’ need to be tightened
IRO-005-1
Reliability Coordination – Current Day Operations
FERC Order 693
o
Measures and Levels of Non-Compliance specific to IROL violations must be
commensurate with the magnitude, duration, frequency and causes of the violations
and whether these occur during normal or contingency conditions.
o
Conduct a survey on IROL practices and experiences; the Commission may propose
further modifications to IRO-005-1 based on the survey results.
V0 Industry Comments
o R10, 11 & 12 – RA not empowered to do this
IRO-016-1
Coordination of Real-Time Activities Between Reliability Coordinators
Violation Risk Factors Drafting Team Comments
o R1.2.1 & R2 – ambiguous
PER-004-0
Reliability Coordination – Staffing
FERC Order 693
o Include formal training requirements for reliability coordinators similar to those
addressed under the personnel training Reliability Standard PER-002-0;
o Include requirements pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0
o Consider the suggestions of FirstEnergy and Xcel:
1413. FirstEnergy seeks revisions to the terms “shall have a comprehensive
understanding” and “shall have extensive knowledge.” It states that it will be difficult
for entities to demonstrate compliance with these terms. In addition, FirstEnergy
suggests that the reliability coordinator staffing requirements should be located in
the IRO Reliability Standards.
1414. Xcel states that emergency training requirements should be expressed in hour
increments rather than days to allow for flexibility in scheduling training and
coordinating with rotating shift schedules.
V0 Industry Comments
o Calendar year timing increment
o Other training needs to be defined
PRC-001-0
System Protection Coordination
FERC Order 693
2
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o Correct the references for Requirements
o Include a requirement that upon the detection of failures in relays or protection
system elements on the Bulk-Power System that threaten reliable operation,
relevant transmission operators must be informed promptly, but within a specified
period of time whereas generator operators must also promptly inform their
transmission operators
o Clarify that, after being informed of failures in relays or protection system elements
that threaten reliability of the Bulk-Power System, transmission operators must carry
out corrective control actions, i.e., return the system to a stable state that respects
system requirements as soon as possible and no longer than 30 minutes after they
receive notice of the failure
V0
o
o
o
Industry Comments
Effects on reliability may not be known
Consistent terminology as to neighbor vs. affected
Not all criteria moved over from policies
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
The drafting team will reference these guidelines in determining what changes to
make to the standards to bring them into conformance with the Reliability
Standards Development Procedure Manual, Version 6 and the ERO Rules of
Procedure:
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels must be applied for each requirement and may be combined to cover
multiple requirements, as long as it is clear which requirements are included and that all requirements are
included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan. The effective date should be linked to the NERC BOT adoption date.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
4
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Standard Authorization Request Form
Title of Proposed Standard
Reliability Coordination (Project 2006-06)
Request Date
December 18, 2006
Revised Date
May 1, 2007
SAR Requestor Information
Name
Ellis Rankin
Primary Contact
Ellis Rankin
SAR Type (Check a box for each one that applies.)
New Standard
Revision to existing Standards – see list below
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination –
Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current
Day Operations
IRO-014 — Procedures to Support Coordination
between Reliability Coordinators
IRO-015 — Notifications and Information
Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities
between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
Telephone
214-743-6828
Fax
972-263-6710
E-mail
[email protected]
Withdrawal of existing Standard
Some requirements in the above standards
Urgent Action
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Authorization Request Form
Purpose
To ensure that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable; and to ensure that this set of requirements is sufficient to maintain
reliability of the Bulk Electric System.
Brief Description
Most of the requirements in this set of standards were translated from Operating Policies as part of the
Version 0 process. There have been suggestions for improving these requirements, and the drafting
team will consider comments submitted by stakeholders, drafting teams and FERC in determining what
changes should be proposed to stakeholders.
The drafting team will review all of the requirements in this set of standards and make a determination,
with stakeholders, on whether to:
- Modify the requirement to improve its clarity and measureability while removing abiguity
- Move the requirement (into another SAR or Standard or to the certification process or
standards)
- Eliminate the requirement (either because it is redundant or because it doesn’t support bulk
power system reliability).
Detailed Description
The drafting team will review all of the requirements in the following set of standards:
COM-001 — Telecommunications
COM-002 — Communications and Coordination
IRO-001 — Reliability Coordination – Responsibilities and Authorities
IRO-002 — Reliability Coordination – Facilities
IRO-005 — Reliability Coordination – Current Day Operations
IRO-014 — Procedures to Support Coordination between Reliability Coordinators
IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
PER-004 — Reliability Coordination – Staffing
PRC-001 — System Protection Coordination
For each existing requirement, the drafting team will work with stakeholders and:
- Eliminate redundancy in the requirements.
- Identify requirements that should be moved into other SARs
- Eliminate requirements that do not support bulk power system reliability
- Transfer requirements that need to be in place before an entity begins operation as an RC
to certification.
- Improve clarity of, improve measureability of, and remove abiguity from the requirement
The standard drafting team will also:
Coordinate with the drafting teams working on the SAR and standards for Transmission
Operator and Balancing Authority standards (Project 2007-06).
Consider comments received during the initial development of this set of standards and other
comments received from ERO regulatory authorities and stakeholders (Attachment 1)
Bring the standards into conformance with the latest version of the Reliability Standards
Development Procedure and the ERO Rules of Procedure. (Attachment 2)
This review of the set of identified standards will satisfy the standards procedure requirement to review
each approved standard at least once every five years.
Deleted: quality ¶
Formatted: Bullets and Numbering
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports system frequency in real time.
Interchange
Authority
Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator
Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator Area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.
Transmission
Service
Provider
Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related
services as required.
Market
Operator
Interface point for reliability functions with commercial functions.
Load-Serving
Entity
Secures energy and transmission service (and related reliability-related
services) to serve the end-use customer.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk electric systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk electric systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk electric
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk electric
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk electric systems.
6. Personnel responsible for planning and operating interconnected bulk electric
systems shall be trained, qualified, and have the responsibility and authority to
implement actions.
7. The security of the interconnected bulk electric systems shall be assessed,
monitored and maintained on a wide area basis.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. The planning and operation of bulk electric systems shall recognize that reliability is an
essential requirement of a robust North American economy. Yes
2. An Organization Standard shall not give any market participant an unfair competitive
advantage.Yes
3. An Organization Standard shall neither mandate nor prohibit any specific market structure.
Yes
4. An Organization Standard shall not preclude market solutions to achieving compliance with
that Standard. Yes
5. An Organization Standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Authorization Request Form
Related Standards – Listed under description
Standard No.
Explanation
Related SARs
SAR ID
Explanation
Regional Differences
Region
ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC
Explanation
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
The drafting team will assist stakeholders in considering these comments in determining
what changes to make to the standards:
COM-001-0
Telecommunications
FERC Order 693
o Include generator operators and distribution provider as applicable entities and and
include requirements for their telecommunications
o Include requirements for telecommunication facilities for use during normal and
emergency conditions that reflect the roles of the applicable entities and their impact
on reliable operation
o Includes adequate flexibility for compliance with the reliability standard, adoption of
new technologies and cost-effective solutions
Deleted: FERC NOPR
Deleted: situations.
V0 Industry Comments
o Many players missing
o Apply R1 to all but smallest entities
Violation Risk Factor Drafting Team Comments
o R6 – administrative requirement
COM-002-1
Communications and Coordination
FERC Order 693
o Include a Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area views of transmission operators or balancing
authorities;
o Include distribution providers as applicable entities; and
o Require tightened communications protocols, especially for communications during
alerts and emergencies.
V0
o
o
o
o
Deleted: NOPR
Industry Comments
Voice with generators not required
R1 – include reliability authority
R2 – include sabotage and security
R4 – clarify repeat back requirement with regard to emergency
IRO-001-0
Reliability Coordination – Responsibilities and Authorities
FERC Order 693
o Reflect the process set forth in the NERC Rules of Procedures; and
o Eliminate the regional reliability organization as an applicable entity.
Regional Fill-in-the-Blank Team Comments
o Remove ", sub-region, or interregional coordinating group" from R1
o Consider removing "Standards of conduct are necessary to ensure the Reliability
Coordinator does not act in a manner that favors one market participant over
another." from the Purpose section of the standard.
V0 Industry Comments
o Inability to perform needs to be communicated
o What is meant by ‘interest of other entity’?
Violation Risk Factor Drafting Team Comments
o R6 - Since the RC must be NERC certified, it stands to reason that anyone
performing RC tasks should be certified. However, since the RC still retains the
1
Deleted: NOPR
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
accountability for actions, and requirement 4 handles the agreements, this
requirement is a medium risk.
IRO-002-0
Reliability Coordination – Facilities
FERC Order 693
o Require a minimum set of tools that should be made available to reliability
coordinators.
V0
o
o
o
Industry Comments
R5 – define synchronized information system
R7 – define ‘adequate’ tools and ‘wide-area’
Words such as ‘easily understood’ and ‘particular emphasis’ need to be tightened
IRO-005-1
Reliability Coordination – Current Day Operations
FERC Order 693
Deleted: NOPR
Deleted: Modify Requirement R7
to explicitly
Deleted: r
Deleted: for the
Deleted: NOPR
o
Measures and Levels of Non-Compliance specific to IROL violations must be
commensurate with the magnitude, duration, frequency and causes of the violations
and whether these occur during normal or contingency conditions.
Formatted: Bullets and Numbering
o
Conduct a survey on IROL practices and experiences; the Commission may propose
further modifications to IRO-005-1 based on the survey results.
Deleted: Propose that the ERO c
V0 Industry Comments
o R10, 11 & 12 – RA not empowered to do this
IRO-016-1
Deleted: . ¶
Formatted: Font: Verdana, 10 pt
Deleted: T
Coordination of Real-Time Activities Between Reliability Coordinators
Violation Risk Factors Drafting Team Comments
o R1.2.1 & R2 – ambiguous
PER-004-0
Reliability Coordination – Staffing
FERC Order 693
o Include formal training requirements for reliability coordinators similar to those
addressed under the personnel training Reliability Standard PER-002-0;
o Include requirements pertaining to personnel credentials for reliability coordinators
similar to those in PER-003-0
o Consider the suggestions of FirstEnergy and Xcel:
1413. FirstEnergy seeks revisions to the terms “shall have a comprehensive
understanding” and “shall have extensive knowledge.” It states that it will be difficult
for entities to demonstrate compliance with these terms. In addition, FirstEnergy
suggests that the reliability coordinator staffing requirements should be located in
the IRO Reliability Standards.
1414. Xcel states that emergency training requirements should be expressed in hour
increments rather than days to allow for flexibility in scheduling training and
coordinating with rotating shift schedules.
Deleted: NOPR
Deleted: ; and
Formatted: Bullets and Numbering
Deleted:
Formatted: Indent: Left: 36 pt
V0 Industry Comments
o Calendar year timing increment
o Other training needs to be defined
PRC-001-0
System Protection Coordination
FERC Order 693
2
Deleted: NOPR
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SAR for Project 2006-06 Reliability Coordination – Attachment 1
o Correct the references for Requirements
o Include a requirement that upon the detection of failures in relays or protection
system elements on the Bulk-Power System that threaten reliable operation,
relevant transmission operators must be informed promptly, but within a specified
period of time whereas generator operators must also promptly inform their
transmission operators
o Clarify that, after being informed of failures in relays or protection system elements
that threaten reliability of the Bulk-Power System, transmission operators must carry
out corrective control actions, i.e., return the system to a stable state that respects
system requirements as soon as possible and no longer than 30 minutes after they
receive notice of the failure
V0
o
o
o
Industry Comments
Effects on reliability may not be known
Consistent terminology as to neighbor vs. affected
Not all criteria moved over from policies
Formatted: Bullets and Numbering
Deleted: relevant transmission
operators and generator
operators must be informed
immediately
Deleted: would
Deleted: <#>so that these
entities can carry out the
appropriate corrective control
actions consistent with those
used in mitigating IROL
violations; and ¶
Deleted: on
Deleted: or generator operators
shall
Deleted: ing
Deleted: .
Deleted: ¶
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
The drafting team will reference these guidelines in determining what changes to
make to the standards to bring them into conformance with the Reliability
Standards Development Procedure Manual, Version 6 and the ERO Rules of
Procedure:
Standard Review Guidelines
Applicability
Does this reliability standard clearly identify the functional classes of entities responsible for complying
with the reliability standard, with any specific additions or exceptions noted? Where multiple functional
classes are identified is there a clear line of responsibility for each requirement identifying the functional
class and entity to be held accountable for compliance? Does the requirement allow overlapping
responsibilities between Registered Entities possibly creating confusion for who is ultimately accountable
for compliance?
Does this reliability standard identify the geographic applicability of the standard, such as the entire North
American bulk power system, an interconnection, or within a regional entity area? If no geographic
limitations are identified, the default is that the standard applies throughout North America.
Does this reliability standard identify any limitations on the applicability of the standard based on electric
facility characteristics, such as generators with a nameplate rating of 20 MW or greater, or transmission
facilities energized at 200 kV or greater or some other criteria? If no functional entity limitations are
identified, the default is that the standard applies to all identified functional entities.
Purpose
Does this reliability standard have a clear statement of purpose that describes how the standard
contributes to the reliability of the bulk power system? Each purpose statement should include a value
statement.
Performance Requirements
Does this reliability standard state one or more performance requirements, which if achieved by the
applicable entities, will provide for a reliable bulk power system, consistent with good utility practices
and the public interest?
Does each requirement identify who shall do what under what conditions and to what outcome?
Measurability
Is each performance requirement stated so as to be objectively measurable by a third party with
knowledge or expertise in the area addressed by that requirement?
Does each performance requirement have one or more associated measures used to objectively evaluate
compliance with the requirement?
If performance results can be practically measured quantitatively, are metrics provided within the
requirement to indicate satisfactory performance?
Technical Basis in Engineering and Operations
Is this reliability standard based upon sound engineering and operating judgment, analysis, or experience,
as determined by expert practitioners in that particular field?
Completeness
Is this reliability standard complete and self-contained? Does the standard depend on external
information to determine the required level of performance?
1
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Consequences for Noncompliance
In combination with guidelines for penalties and sanctions, as well as other ERO and regional entity
compliance documents, are the consequences of violating a standard clearly known to the responsible
entities?
Clear Language
Is the reliability standard stated using clear and unambiguous language? Can responsible entities, using
reasonable judgment and in keeping with good utility practices, arrive at a consistent interpretation of the
required performance?
Practicality
Does this reliability standard establish requirements that can be practically implemented by the assigned
responsible entities within the specified effective date and thereafter?
Capability Requirements versus Performance Requirements
In general, requirements for entities to have ‘capabilities’ (this would include facilities for
communication, agreements with other entities, etc.) should be located in the standards for certification.
The certification requirements should indicate that entities have a responsibility to ‘maintain’ their
capabilities.
Consistent Terminology
To the extent possible, does this reliability standard use a set of standard terms and definitions that are
approved through the NERC reliability standards development process?
If the standard uses terms that are included in the NERC Glossary of Terms Used in Reliability Standards,
then the term must be capitalized when it is used in the standard. New terms should not be added unless
they have a ‘unique’ definition when used in a NERC reliability standard. Common terms that could be
found in a college dictionary should not be defined and added to the NERC Glossary.
Are the verbs on the ‘verb list’ from the DT Guidelines? If not – do new verbs need to be added to the
guidelines or could you use one of the verbs from the verb list?
Violation Risk Factors (Risk Factor)
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly cause or contribute to bulk electric
system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures, or could hinder
restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures;
or a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor, control, or
2
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
restore the bulk electric system. However, violation of a medium risk requirement is unlikely,
under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to
bulk electric system instability, separation, or cascading failures, nor to hinder restoration to a
normal condition.
Lower Risk Requirement
A requirement that, if violated, would not be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. A requirement that is administrative in nature;
or a requirement in a planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively
monitor, control, or restore the bulk electric system. A planning requirement that is administrative
in nature.
Time Horizon
The drafting team should also indicate the time horizon available for mitigating a violation to the
requirement using the following definitions:
•
Long-term Planning — a planning horizon of one year or longer.
•
Operations Planning — operating and resource plans from day-ahead up to and including
seasonal.
•
Same-day Operations — routine actions required within the timeframe of a day, but not realtime.
•
Real-time Operations — actions required within one hour or less to preserve the reliability of
the bulk electric system.
•
Operations Assessment — follow-up evaluations and reporting of real time operations.
Violation Severity Levels
The drafting team should indicate a set of violation severity levels that can be applied for the
requirements within a standard. (‘Violation severity levels’ replace existing ‘levels of non-compliance.’)
The violation severity levels must be applied for each requirement and may be combined to cover
multiple requirements, as long as it is clear which requirements are included and that all requirements are
included.
The violation severity levels should be based on the following definitions:
•
Lower: mostly compliant with minor exceptions — The responsible entity is mostly compliant
with and meets the intent of the requirement but is deficient with respect to one or more minor
details. Equivalent score: 95% to 99% compliant.
•
Moderate: mostly compliant with significant exceptions — The responsible entity is mostly
compliant with and meets the intent of the requirement but is deficient with respect to one or
more significant elements. Equivalent score: 85% to 94% compliant.
•
High: marginal performance or results — The responsible entity has only partially achieved
the reliability objective of the requirement and is missing one or more significant elements.
Equivalent score: 70% to 84% compliant.
•
Severe: poor performance or results — The responsible entity has failed to meet the reliability
objective of the requirement. Equivalent score: less than 70% compliant.
Compliance Monitor
3
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SAR for Project 2006-06 Reliability Coordination – Attachment 2
Replace, ‘Regional Reliability Organization’ with ‘Regional Entity’
Fill-in-the-blank Requirements
Do not include any ‘fill-in-the-blank’ requirements. These are requirements that assign one
entity responsibility for developing some performance measures without requiring that the
performance measures be included in the body of a standard – then require another entity to
comply with those requirements.
Every reliability objective can be met, at least at a threshold level, by a North American
standard. If we need regions to develop regional standards, such as in under-frequency load
shedding, we can always write a uniform North American standard for the applicable functional
entities as a means of encouraging development of the regional standards.
Requirements for Regional Reliability Organization
Do not write any requirements for the Regional Reliability Organization. Any requirements
currently assigned to the RRO should be re-assigned to the applicable functional entity.
Effective Dates
Must be 1st day of 1st quarter after entities are expected to be compliant – must include time to
file with regulatory authorities and provide notice to responsible entities of the obligation to
comply. If the standard is to be actively monitored, time for the Compliance Monitoring and
Enforcement Program to develop reporting instructions and modify the Compliance Data
Management System(s) both at NERC and Regional Entities must be provided in the
implementation plan. The effective date should be linked to the NERC BOT adoption date.
Associated Documents
If there are standards that are referenced within a standard, list the full name and number of the
standard under the section called, ‘Associated Documents’.
Functional Model Version 3
Review the requirements against the latest descriptions of the responsibilities and tasks assigned
to functional entities as provided in pages 13 through 53 of the draft Functional Model Version
3.
4
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Maureen E. Long
Standards Process Manager
May 11, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement
Nomination Periods Open for Two Drafting Teams
The Standards Committee (SC) announces the following standards actions:
Nominations for Project 2006-06 Reliability Coordination Standard Drafting Team (May
14–25, 2007)
The Standards Committee authorized moving the SAR for Reliability Coordination forward to standard
drafting and is seeking industry experts to serve on the Reliability Coordination Standard Drafting
Team. This drafting team will work on modifications to the following standards:
- COM-001 — Telecommunications
- COM-002 — Communications and Coordination
- IRO-001 — Reliability Coordination – Responsibilities and Authorities
- IRO-002 — Reliability Coordination – Facilities
- IRO-005 — Reliability Coordination – Current Day Operations
- IRO-014 — Procedures to Support Coordination between Reliability Coordinators
- IRO-015 — Notifications and Information Exchange Between Reliability Coordinators
- IRO-016 — Coordination of Real-time Activities between Reliability Coordinators
- PER-004 — Reliability Coordination – Staffing
- PRC-001 — System Protection Coordination
If you are interested in serving on this standard drafting team, please complete this nomination form and
return it to [email protected] by May 25, 2007 with “RC SDT Nomination” in the subject line.
Nominations for Project 2007-18 Reliability-based Control SAR Drafting Team (May 14–
25, 2007)
The Standards Committee authorized posting the SAR for Reliability-based Control and is seeking
industry experts to serve on the Reliability-based Control SAR Drafting Team. This SAR proposes to
develop requirements to achieve the following objectives:
- To maintain Interconnection frequency within predefined frequency limits under all conditions
(i.e., normal and abnormal), to prevent frequency-related instability; unplanned tripping of load
or generation; or uncontrolled separation or Cascading outages that adversely impact the
reliability of the Interconnection. (Work brought into this SAR from BAL-007 though BAL011.)
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
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REGISTERED BALLOT BODY
May 11, 2007
Page Two
- To support elimination of SOL/IROL violations caused by excessive (as determined by this
standard) Area Control Error (“ACE”). (Could be a separate and individually balloted Standard.)
- To prevent Interconnection frequency excursions of short-duration attributed to the ramping of
on and off-peak Interchange Transactions. (Could be a separate and individually balloted
Standard.)
- To support timely transmission congestion relief by requiring corrective load/generation
management within a defined timeframe when ACE is impacted by the curtailment of
Interchange Transactions under transmission loading relief procedures. (Could be a separate and
individually balloted Standard.)
- To address the directives of FERC Order 693.
If you are interested in serving on this SAR drafting team, please complete this nomination form and
return it to [email protected] by May 25, 2007 with “RB Control SARDT Nomination” in the subject
line.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. If you have any questions, please
contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
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Standard COM-001-2 — Telecommunications
A. Introduction
1.
Title:
Telecommunications
2.
Number:
COM-001-2
3.
Purpose: Each Reliability Coordinator, Transmission Operator and Balancing
Authority needs adequate and reliable telecommunications facilities internally and with
others for the exchange of Interconnection and operating information necessary to
maintain reliability.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
5.
Effective Date:
TBD
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
operationally test, on a quarterly basis at a minimum, alternative telecommunications
facilities to ensure the availability of their use when normal telecommunications
facilities fail. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
R2.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities of the failure of its normal telecommunications facilities, and
shall verify that alternate means of telecommunications are functional. [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
R3.
Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator,
Balancing Authority, Generator Operator and Distribution Provider shall use English as
the language for all inter-entity Bulk Electric System (BES) reliability communications
between and among operating personnel responsible for the real-time generation
control and operation of the interconnected BES. Transmission Operators and
Balancing Authorities may use an alternate language for internal operations. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]
R4.
Each Distribution Provider and Generation Operator shall have telecommunications
facilities with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information. [Violation Risk Factor: High][Time
Horizon: Real-time Operations and Operations Planning]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
provide evidence that it operationally tested, on a quarterly basis at a minimum,
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Standard COM-001-2 — Telecommunications
alternative telecommunications facilities to ensure the availability of their use when
normal telecommunications facilities fail.
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
provide evidence that it notified impacted entities of failure of their normal
telecommunications facilities, and verified the alternate means of telecommunications
were functional.
M3. The Reliability Coordinator, Transmission Operator or Balancing Authority shall have
and provide upon request evidence that could include, but is not limited to operator
logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent, that will be used to determine that personnel used English as the language
for all inter-entity BES reliability communications between and among operating
personnel responsible for the real-time generation control and operation of the
interconnected BES.
M4. Each Distribution Provider and Generation Operator has telecommunications facilities
with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
- Spot Checking
- Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator and Balancing Authority shall
keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of
time as part of an investigation:
For the Measures, each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall each keep the most recent three months of historical
data (evidence).
If a Reliability Coordinator, Transmission Operator and Balancing Authority is
found non-compliant it shall keep information related to the noncompliance until
found compliant.
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Standard COM-001-2 — Telecommunications
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
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Standard COM-001-2 — Telecommunications
2.
Violation Severity Levels
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last quarter.
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last 2 quarters.
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last 3 quarters.
The Reliability
Coordinator, Transmission
Operator, or Balancing
Authority failed to
operationally test within the
last 4 quarters.
R2
The Reliability
Coordinator,
Transmission Operator or
Balancing Authority
notified all impacted
entities of the failure of
their normal
telecommunications
facilities, but failed to
verify the alternate means
of telecommunications
are functional.
The Reliability
Coordinator,
Transmission Operator or
Balancing Authority
notified some, but not all,
impacted entities of the
failure of their normal
telecommunications
facilities, and failed to
verify the alternate means
of telecommunications
are functional.
N/A
The Reliability
Coordinator, Transmission
Operator or Balancing
Authority failed to notify
any impacted entities of the
failure of their normal
telecommunications
facilities, and failed verify
the alternate means of
telecommunications are
functional.
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Standard COM-001-2 — Telecommunications
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3
N/A
N/A
N/A
The responsible entity
failed to provide evidence
of concurrence to use a
language other than
English for all
communications between
and among operating
personnel responsible for
the real-time generation
control and operation of
the interconnected Bulk
Electric System.
R4
N/A
N/A
N/A
The Distribution Provider
or Generation Operator
failed to have
telecommunications
facilities with its
Transmission Operator
and Balancing Authority
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E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RCSDT
Revised
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Standard COM-001-2 — Telecommunications
A. Introduction
1.
Title:
Telecommunications
2.
Number:
COM-001-21
3.
Purpose: Each Reliability Coordinator, Transmission Operator and Balancing
Authority needs adequate and reliable telecommunications facilities internally and with
others for the exchange of Interconnection and operating information necessary to
maintain reliability.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
4.4. NERCNet User Organizations.
5.
Effective Date:
TBDJanuary 1, 2007
B. Requirements
R1.Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall
provide adequate and reliable
telecommunications facilities for the
exchange of Interconnection and operating
information:
R2.
The RC SDT contends that COM-001-1, R1
and its subrequirements are low level
facilitating requirements that are more
appropriately and inherently monitored under
various higher-level performance-based
reliability requirements for each entity
throughout the body of standards. (See
Implementation Plan for examples.)
R1.1.
Internally.
R1.2.
Between the Reliability
Coordinator and its Transmission Operators and Balancing Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
operationally test, on a quarterly basis at a minimum, alternative manage, alarm, test
and/or actively monitor vital telecommunications facilities to ensure the availability of
their use when normal telecommunications facilities fail. Special attention shall be
given to emergency telecommunications facilities and equipment not used for routine
communications. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
R1.
R2.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities of the failure of its normal telecommunications facilities, and
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Standard COM-001-2 — Telecommunications
shall verify that alternate means of telecommunications are functional. provide a
means to coordinate telecommunications among their respective areas. This
coordination shall include the ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
R3.
Unless agreed to otherwise, each Reliability
Requirement R3 is being incorporated
Coordinator, Transmission Operator, and
into COM-003-1 by the Operations
Personnel Communications Protocols
Balancing Authority, Generator Operator and
SDT (Project 2007-02). It will be
Distribution Provider shall use English as the
retired from this standard upon
language for all inter-entity Bulk Electric
approval of COM-003-1.
System (BES) reliability communications
between and among operating personnel
responsible for the real-time generation control and operation of the interconnected
Bulk Electric SystemBES. Transmission Operators and Balancing Authorities may use
an alternate language for internal operations. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
R4.
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities.
R5.
Each NERCNet User Organization shall adhere
to the requirements in Attachment 1-COM-001,
“NERCNet Security Policy.”
R4.
Each Distribution Provider and Generation
Operator shall have telecommunications
facilities with its Transmission Operator and
Balancing Authority for the exchange of
Interconnection and operating information.
[Violation Risk Factor: High][Time Horizon:
Real-time Operations and Operations
Planning]
The RC SDT is recommending that R4
be retired as it is redundant with EOP008-0.
The RC SDT is recommending that R5
be retired. This is an ERO procedural
issue and should not be in a reliability
standard. It should be retired and
included in the NERC Rules of
Procedure.
The new R4 was written to meet a
FERC Directive from Order 693.
C. Measures
M1.Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have
and provide upon request evidence that could include, but is not limited to
communication facility test-procedure documents, records of testing, and maintenance
records for communication facilities or equivalent that will be used to confirm that it
manages, alarms, tests and/or actively monitors vital telecommunications facilities.
(Requirement 2 part 1)
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
provide evidence that it operationally tested, on a quarterly basis at a minimum,
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Standard COM-001-2 — Telecommunications
alternative telecommunications facilities to ensure the availability of their use when
normal telecommunications facilities fail.
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
provide evidence that it notified impacted entities of failure of their normal
telecommunications facilities, and verified the alternate means of telecommunications
were functional.
M3. The Reliability Coordinator, Transmission Operator or Balancing Authority shall have
and provide upon request evidence that could include, but is not limited to operator
logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent, that will be used to determine that personnel used English as the language
for all inter-entity BES reliability communications between and among operating
personnel responsible for the real-time generation control and operation of the
interconnected BEScompliance to Requirement 4.
M3. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
have and provide upon request its current operating instructions and procedures, either
electronic or hard copy that will be used to confirm that it meets Requirement 5.
M4. The NERCnet User Organization shall have and provide upon request evidence that
could include, but is not limited to documented procedures, operator logs, voice
recordings or transcripts of voice recordings, electronic communications, etc that will
be used to determine if it adhered to the (User Accountability and Compliance)
requirements in Attachment 1-COM-001. (Requirement 6)
M4. Each Distribution Provider and Generation Operator has telecommunications facilities
with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional
EntityReliability Organizations
Regional Reliability Organizations shall be responsible for compliance
monitoring of all other entities
1.2. Compliance Monitoring and Enforcement ProcessesReset Time Frame
Compliance Audits
Self-Certifications
One or more of the following methods will be used to assess compliance:
- Self-certification (Conducted annually with submission according to
schedule.)
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Standard COM-001-2 — Telecommunications
- Spot CheckingCheck Audits (Conducted anytime with up to 30 days notice
given to prepare.)
- Compliance ViolationPeriodic Audit (Conducted once every three years
according to schedule.)
- Triggered Investigations (Notification of an investigation must be made
within 60 days of an event or complaint of noncompliance. The entity will
have up to 30 calendar days to prepare for the investigation. An entity may
request an extension of the preparation period and the extension will be
considered by the Compliance Monitor on a case-by-case basis.)
Self-Reporting
Complaints
The Performance-Reset Period shall be 12 months from the last finding of noncompliance.
1.3. Data Retention
TheFor Measure 1 each Reliability Coordinator, Transmission Operator and,
Balancing Authority shall keep data or evidence to show of compliance as identified
below unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation:
For the Measures,previous two calendar years plus the current year.
For Measure 2 each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall each keep the most recent three months90 days of
historical data (evidence).
If aFor Measure 3, each Reliability Coordinator, Transmission Operator and ,
Balancing Authority shall have its current operating instructions and procedures
to confirm that it meets Requirement 5.
For Measure 4, each Reliability Coordinator, Transmission Operator, Balancing
Authority and NERCnet User Organization shall keep 90 days of historical data
(evidence).
If an entity is found non-compliant it the entity shall keep information related to
the noncompliance until found compliant. or for two years plus the current year,
whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity
being investigated for one year from the date that the investigation is closed, as
determined by the Compliance Monitor.
The Compliance Enforcement AuthorityMonitor shall keep the last periodic audit
recordsreport and all requested and submitted subsequent auditcompliance
records.
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Standard COM-001-2 — Telecommunications
1.4. Additional Compliance Information
None
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5
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Standard COM-001-2 — Telecommunications
2.
Violation Severity Levels
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last quarter.
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last 2 quarters.
The Reliability
Coordinator,
Transmission Operator, or
Balancing Authority
failed to operationally test
within the last 3 quarters.
The Reliability
Coordinator, Transmission
Operator, or Balancing
Authority failed to
operationally test within the
last 4 quarters.
R2
The Reliability
Coordinator,
Transmission Operator or
Balancing Authority
notified all impacted
entities of the failure of
their normal
telecommunications
facilities, but failed to
verify the alternate means
of telecommunications
are functional.
The Reliability
Coordinator,
Transmission Operator or
Balancing Authority
notified some, but not all,
impacted entities of the
failure of their normal
telecommunications
facilities, and failed to
verify the alternate means
of telecommunications
are functional.
N/A
The Reliability
Coordinator, Transmission
Operator or Balancing
Authority failed to notify
any impacted entities of the
failure of their normal
telecommunications
facilities, and failed verify
the alternate means of
telecommunications are
functional.
Draft 1: July 30, 2008
6
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Standard COM-001-2 — Telecommunications
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3
N/A
N/A
N/A
The responsible entity
failed to provide evidence
of concurrence to use a
language other than
English for all
communications between
and among operating
personnel responsible for
the real-time generation
control and operation of
the interconnected Bulk
Electric System.
R4
N/A
N/A
N/A
The Distribution Provider
or Generation Operator
failed to have
telecommunications
facilities with its
Transmission Operator
and Balancing Authority
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Standard COM-001-1 — Telecommunications
Attachment 1-COM-001— NERCnet Security Policy
Levels of Non-Compliance for Transmission Operator, Balancing Authority or
Reliability Coordinator
2.
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability
Coordinator used a language other then English without agreement as
specified in R4.
2.3.2
There are no written operating instructions and procedures to enable
continued operation of the system during the loss of telecommunication
facilities as specified in R5.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed
or alarmed as specified in R2.
Levels of Non-Compliance — NERCnet User Organization
3.
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001,
NERCnet Security Policy.
E. Regional Differences
None identified.
F. Associated Documents
None Identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
Errata
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Standard COM-001-1 — Telecommunications
between “facilities” and “the exchange.”
2
TBD
Revised per SAR for Project 2006-06,
RCSDT
Revised
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Standard COM-001-1 — Telecommunications
Attachment 1-COM-001— NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum
requirements for the protection of information assets, computer systems and facilities of NERC
and other users of the NERC frame relay network known as “NERCnet.” The goal of this policy
is to prevent misuse and loss of assets.
For the purpose of this document, information assets shall be defined as processed or
unprocessed data using the NERCnet Telecommunications Facilities including network
documentation. This policy shall also apply as appropriate to employees and agents of other
corporations or organizations that may be directly or indirectly granted access to information
associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•To ensure that NERCnet information assets are adequately protected on a cost-effective basis
and to a level that allows NERC to fulfill its mission.
•To establish connectivity guidelines for a minimum level of security for the network.
•To provide a mandate to all Users of NERCnet to properly handle and protect the information
that they have access to in order for NERC to be able to properly conduct its business and
provide services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to
facilitate effective operation of its business and fulfillment of its mission. NERC also recognizes
the value of the information maintained and provided to its members and others authorized to
have access to NERCnet. It is, therefore, essential that this data, information, and computer
systems, and the manual and technical infrastructure that supports it, are secure from destruction,
corruption, unauthorized access, and accidental or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of
NERCnet resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network
are considered users of NERCnet resources. To be granted access, users shall complete a User
Application Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•Use NERCnet facilities for NERC-authorized business purposes only.
•Comply with the NERCnet security policies, standards, and guidelines, as well as any
procedures specified by the data owner.
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Standard COM-001-1 — Telecommunications
•Prevent unauthorized disclosure of the data.
•Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
•Protect the confidentiality of all user IDs and passwords.
•Maintain the data they own.
•Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
•Authorize users within their organizations to access NERCnet data and applications.
•Advise staff on NERCnet Security Policy.
•Ensure that all NERCnet users understand their obligation to protect these assets.
•Conduct self-assessments for compliance.
•
User Accountability and Compliance
•
All users of NERCnet shall be familiar and ensure compliance with the policies in this
document.
•
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
•Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
•
Involves the use of data for illicit purposes, which may include violation of any law,
regulation or reporting requirement of any law enforcement or government body.
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Implementation Plan for COM-001-2
Telecommunications
Prerequisite Approvals
• IRO-002-2
• IRO-005-3
Conforming Changes to Requirements in Already Approved Standards
•
None
Revision Summary
• The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
To be determined.
July 30, 2008
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Implementation Plan for COM-001-2
Telecommunications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
R1.4.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT contends that COM-001-1, R1 and its subrequirements are low
level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability
requirements for each entity throughout the body of standards. Examples
include:
IRO-001-1, R3 requires adequate telecommunication for the Reliability
Coordinator to direct actions of multiple entities, including TOPs and BAs.
TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to
the RC.
TOP-001-1, R3 requires adequate telecommunications facilities for the TOP,
BA, and GOP to be able to receive directives from the RC.
TOP-006-1, R1 requires adequate telecommunications for the GOP to inform
the BA and TOP of resources. The BA and TOP will then inform the RC,
other TOP and BAs of all transmission and generation available for use.
The retirement of this requirement also facilitates one of the FERC Order 693
directives for COM-001-1 to “includes adequate flexibility for compliance with
the Reliability Standard, adoption of new technologies and cost-effective
solutions”.
Notes: Based on the above information, the RC SDT recommends retiring R1 and its subrequirements.
July 30, 2008
2
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Implementation Plan for COM-001-2
Telecommunications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R1. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall operationally test, on a quarterly basis at a
minimum, alternative telecommunications facilities to ensure the
availability of their use when normal telecommunications facilities
fail. manage, alarm, test and/or actively monitor vital
telecommunications facilities. Special attention shall be given to
emergency telecommunications facilities and equipment not used for
routine communications. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
Notes: The RC SDT contends that the first sentence of COM-001-1, R2 is a low level facilitating requirements that is more appropriately and
inherently monitored under various higher level performance-based reliability requirements for each entity throughout the body of standards as
described in R1 above. We propose revising R2 as shown above.
July 30, 2008
3
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Implementation Plan for COM-001-2
Telecommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
COM-001-2
R3.
R2. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities of failure of
their normal telecommunications facilities, and verify the
alternate means of telecommunications are functional. provide
a means to coordinate telecommunications among their
respective areas. This coordination shall include the ability to
investigate and recommend solutions to telecommunications
problems within the area and with other areas. [Violation Risk
Factor: Medium Lower][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
July 30, 2008
4
Already Approved Standard
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2
R3. Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority, Generator
Operator and Distribution Provider shall use English as the
language for all inter-entity Bulk Electric System reliability
communications between and among operating personnel
responsible for the real-time generation control and
operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use
an alternate language for internal operations. [Violation
Risk Factor: Medium] [Time Horizon: Real-time
Operations]
Notes: COM-001 Requirement R3 is being incorporated into COM-003-1 by the Operations Personnel Communications Protocols SDT (Project
2007-02). It will be retired from this standard upon approval of COM-003-1.
July 30, 2008
5
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Implementation Plan for COM-001-2
Telecommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
Telecommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
July 30, 2008
6
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Implementation Plan for COM-001-2
Telecommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the requirements
in Attachment 1-COM-001, “NERCNet Security Policy.” [Violation
Risk Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-2
R4. Each Distribution Provider and Generation Operator
shall have telecommunications facilities with its
Transmission Operator and Balancing Authority for the
exchange of Interconnection and operating information.
[Violation Risk Factor: High][Time Horizon: Real-time
Operations and Operations Planning]
Notes: This is a new requirement based on the following FERC Order 693 directive:
“expands the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities”
July 30, 2008
7
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
X
X
Interchange
Authority
Transmission
Operator
X
Transmission
Owner
Generator
Owner
Generator
Operator
Distribution
Provider
X
X
Telecommunications
July 30, 2008
8
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Implementation Plan for COM-001-2
Telecommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Background and Questions
for Reliability Coordination — Project 2006-06
Comments must be submitted by September 16, 2008. If you have questions please contact Stephen Crutchfield at
[email protected] or by telephone at 609-651-9455.
Background Information:
The Reliability Coordination Standards Drafting Team was tasked with ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique and enforceable; and to ensure
that this set of requirements is sufficient to maintain reliability of the Bulk Electric System. The SAR also called for
revisions to the group of Standards based on FERC Order 693.
During the course of the project, the NERC Standard Staff revised the Reliability Standards Work Plan and noted
several areas of overlapping scope between certain projects. The original SAR for Project 2006-6 called for revisions
to PER-004 (Reliability Coordination – Staffing) and PRC-001 (System Protection Coordination). Based on the scope
overlap of the teams involved, it was determined that PER-004 would best be served by moving all of the proposed
scope to Project 2006-1, System Personnel Training. Similarly, it was determined that PER-004 would best be
served by moving all of the proposed scope to Project 2007-6, System Protection.
The RC SDT has Standards that are impacted by the work of the IROL Standards Drafting Team and the standards
that they have developed and the modifications they’ve proposed to some of the IRO standards. The RC SDT is
recommending further revisions to the IRO standards and coordinated these changes with the IROL SDT. We have
noted revisions made to the standards by the IROL SDT in our documents.
A summary of the proposed revisions to the Standards remaining in Project 2006-06 is:
COM-001-2
The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), align with
NERC’s Rules of Procedure and to address issues in FERC Order 693.
COM-002-3
The RC SDT proposes retiring this standard. The RC SDT contends that COM-002-2, R1 and its
subrequirements are low level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability requirements for each entity
throughout the body of standards. The Operations Communications Protocols SDT is addressing R2.
They plan to modify the requirement and place the modified requirement in a new standard, COM-003-1.
Requirement 2 will remain in place until COM-003-1 is approved.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — Reliability Coordination Project 2006-06
IRO-001-2
The RC SDT revised the standard and is proposing retiring several requirements (R1, R2, R4, R5, R6, R7
and R10). Changes were made to eliminate redundancies between standards (existing and proposed),
align with NERC’s Rules of Procedure and to address issues in FERC Order 693.
IRO-002-2
The RC SDT revised the standard and is proposing retiring several requirements (R1, R3, R4, R5, R6, R7
and R8). Changes were made to eliminate redundancies between standards (existing and proposed), to
align with NERC’s Rules of Procedure and to address issues in FERC Order 693.
IRO-005-2
Many of the requirements in this standard will be retired under the IROL SDT work plan. The RC SDT
proposes retiring other requirements and moving R6 and R15 to IRO-001-2. This will retire or move all
requirements in this standard. The RC SDT proposes retiring the standard.
IRO-014-2
The RC SDT revised the standard and is proposing retiring two requirements (R3 and R4). New
requirements were brought into this standard from IRO-015-1 (R1-R3) and IRO-016-1 (R1 and its sub
requirements). Changes were made to eliminate redundancies between standards (existing and
proposed), eliminate administrative items, align with NERC’s Rules of Procedure and to address issues in
FERC Order 693.
IRO-015-2
The RC SDT recommends retiring Standard IRO-015 and moving all requirements to IRO-014-2.
IRO-016-2
The RC SDT recommends retiring this Standard. The requirements listed in R1 and its sub-requirements
were incorporated into IRO-014-2 as new requirements. The RC SDT recommends retiring R2 because it
is a measure of performance of R1.
The Reliability Coordination Drafting Team would like to receive industry comments on the Requirements, Measures
and Violation Severity Levels of this group of standards. Accordingly, we request that you submit your comments
electronically by September 16, 2008.
Page 2 of 5
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Comment Form — Reliability Coordination Project 2006-06
1.
Do you agree with the revisions to the Requirements in COM-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
2.
Do you agree with the revisions to the Measures in COM-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
3.
Do you agree with the Violation Severity Levels proposed in COM-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
4.
Do you agree with the revisions to the Requirements in COM-002-3 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
5.
Do you agree with the revisions to the Measures in COM-002-3 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
6.
Do you agree with the Violation Severity Levels proposed in COM-002-3 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
7.
Do you agree with the revisions to the Requirements in IRO-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
8.
Do you agree with the revisions to the Measures in IRO-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
Page 3 of 5
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Comment Form — Reliability Coordination Project 2006-06
No
Comments:
9.
Do you agree with the Violation Severity Levels proposed in IRO-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
10. Do you agree with the revisions to the Requirements in IRO-002-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
11. Do you agree with the revisions to the Measures in IRO-002-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
12. Do you agree with the Violation Severity Levels proposed in IRO-002-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
13. Do you agree with the revisions to IRO-005-1 as shown in the posted Standard and Implementation Plan? The
RC SDT is recommending retiring or moving all of the requirements and retiring this standard. If not, please
explain in the comment area.
Yes
No
Comments:
14. Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
15. Do you agree with the revisions to the Measures in IRO-014-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
Page 4 of 5
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Comment Form — Reliability Coordination Project 2006-06
16. Do you agree with the Violation Severity Levels proposed in IRO-014-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
17. Do you agree with the RC SDT recommendation to retire IRO-015-2 and move the requirements into IRO-014-2?
If not, please explain in the comment area.
Yes
No
Comments:
18. Do you agree with the revisions to IRO-016-2 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Yes
No
Comments:
19.
If you have any other comments, not expressed in questions above, on this set of revisions, please
provide your comments here.
Comments:
Page 5 of 5
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Individual or group. (29 Responses)
Name (17 Responses)
Organization (17 Responses)
Group Name (12 Responses)
Lead Contact (12 Responses)
Contact Organization (12 Responses)
Question 1 (25 Responses)
Question 1 Comments (29 Responses)
Question 2 (25 Responses)
Question 2 Comments (29 Responses)
Question 3 (21 Responses)
Question 3 Comments (29 Responses)
Question 4 (22 Responses)
Question 4 Comments (29 Responses)
Question 5 (21 Responses)
Question 5 Comments (29 Responses)
Question 6 (20 Responses)
Question 6 Comments (29 Responses)
Question 7 (23 Responses)
Question 7 Comments (29 Responses)
Question 8 (21 Responses)
Question 8 Comments (29 Responses)
Question 9 (21 Responses)
Question 9 Comments (29 Responses)
Question 10 (20 Responses)
Question 10 Comments (29 Responses)
Question 11 (19 Responses)
Question 11 Comments (29 Responses)
Question 12 (19 Responses)
Question 12 Comments (29 Responses)
Question 13 (21 Responses)
Question 13 Comments (29 Responses)
Question 14 (20 Responses)
Question 14 Comments (29 Responses)
Question 15 (19 Responses)
Question 15 Comments (29 Responses)
Question 16 (19 Responses)
Question 16 Comments (29 Responses)
Question 17 (20 Responses)
Question 17 Comments (29 Responses)
Question 18 (20 Responses)
Question 18 Comments (29 Responses)
Question 19 (29 Responses)
Individual
Kris Manchur
Manitoba Hydro
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
No
I do not agree with the way IRO-001-2 R1 is written. In the present form the requirement may
infer that directing action is not an action. It may also infer that the RC is only required to do
'"act "or "direct actions" but not both. The way it is written also leads to problems with the
VSLs. Perhaps R1 can be edited along the lines of: R1. The Reliability Coordinator shall act to
prevent or mitigate the magnitude or duration of events that result in Adverse Reliability
Impacts. When required, the actions initiated by the Reliability Coordinator will inlude, but is
not limited to, directing the actions to be taken by Transmission Operators, Balancing
Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities,
Distribution Providers and Purchasing-Selling Entities within its Reliability Coordinator Area.
I agree with the other Requirements in IRO-001-2 with the exception of the "High" Violation
Risk Factor assigned to IRO-001-2 requirement R5. This should be a "Medium" VRF at the
most. If the emergency has been mitigated, and the entities are not aware, they will still be
operating to restrictions which means the grid is operating well within limits. Not notifying the
entities that the problem has been mitigated may have some financial implications but it should
not place the grid at risk.
Yes
No
IRO-001-2 R1 VSLs: You can not split "shall act" and "or direct actions" into separate VSLs.
They are one and same. If the RC directs action then they have acted. If the RC failed to direct
action or have failed to other wise act then they have failed to act appropriately. Perhaps the
VSLs can be drafted along the lines of the following: IRO-001-2 R1 High VSL… The
Reliability Coordinator's action was incomplete in that it failed to demonstrate a specific action
to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts. IRO-001-2 R1
Severe VSL… The Reliability Coordinator failed to act to prevent or mitigate the magnitude or
duration of Adverse Reliability Impacts. IRO-001-2 R2 VSLs: (1) Entities may be justified in
an intentional delay in respnding to an RC directive. A justified intential delay may due be
equipment problems, a generators ramp rate or system voltage adjustments prior to large
system reconfiguration or large transmission loading changes. (2) An entity cannot be faulted
for not following an RC directive because to it would violate safety, equipment, regulatory or
statutory requirements. Perhaps the VSLs can be drafted along the lines of the following:
Moderate VSL… should be deleted. High VSL… The responsible enity followed the
Reliability Coordinators directive but with an unjustified delay. Severe VSL… no edits
required. IRO-001-2 R5 VSLs: Perhaps the VSLs can be drafted along the lines of the
following to reflect to what degree the RC missed the mark: Lower VSL…The Reliability
Coordinator failed to notify <25% of its impacted Transmission Operators and Balancing
Authorities when the transmission system problem had been mitigated. Moderate VSL… The
Reliability Coordinator failed to notify >24% but <50% of its impacted Transmission
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Operators and Balancing Authorities when the transmission system problem had been
mitigated. High VSL…The Reliability Coordinator failed to notify >49% but <75% of its
impacted Transmission Operators and Balancing Authorities when the transmission system
problem had been mitigated. Severe VSL… The Reliability Coordinator failed to notify >74%
of its impacted Transmission Operators and Balancing Authorities when the transmission
system problem had been mitigated.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
NPCC
Guy Zito
NPCC
No
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between
entities (RC, TOP, BA, GOP, DP) to use a language other than English in their
communications. In M3, that option is not presented. M3 should reflect what is written in R3.
No
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between
entities (RC, TOP, BA, GOP, DP) to use a language other than English in their
communications. In M3, that option is not presented. M3 should reflect what is written in R3.
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Jeffrey V Hackman
Ameren
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes and No
While we agree that most of the requirements are redundancies that properly belong elsewhere,
we are concerned that Requirement 4 and Requirement 8 are not properly represented
elsewhere and should not be retired until they re-surface in another standard explicitly. We
believe it is still very important for an RC to monitor their respective BAs reserves and CPS
performance. Likewise in R8, while the frequency monitoring is a BA function, we think that it
is important enough to also be included as an RC function explictly.
Yes
Yes
Yes
Yes
Yes
Individual
Dan Rochester
Independent Electricity System Operator - Ontario
Yes
No
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
M3: The evidence to show that concurrence is in place to allow communication using a
language other than English is missing. The Measure as written merely asks for evidence that
communication in a different language has occurred.
No
(i) R1: Suggest to revise the conditions for all levels to read "…failed to operationally test the
altarnative communication facilities within the last……… (ii) R2: The second part under
Severe is not needed since failing to notify any impacted entities would imply no
communication to the affected entities anyway. If verification of the functionality of the
alternate means of telecommunications is also critical even without communicating to the
affecte entities, then the second condition should be an "OR". (iii) R3: Failure to having
concurrence to use a language other than English for communications between and among
operating personnel responsible for real-time operations by itself does not consitute a violate of
any requirements; it is the absence of such a concurrence AND having used a language other
than English that would consitute a violation. Suggest to revise this condition.
Yes
Yes
Yes
No
(i) R2: the phrase "act without intentional delay" is not necessary since the urgency of taking
any actions as directed by the RC's are generally understood to be conveyed in the RC's
directives. (ii) R3: Given R2 requires the responsible entities to comply with the RC directives,
the part that says "immediately confirm the ability to comply with the directive or" is not
needed. R3 should simply require the responsible entities to notify the RC upon recognition of
the inability to perform the directive. (iii) The VRF for R5 should not be High. Failure to notify
others when potential threats to system reliability have been mitigated does not consititue a
high risk to the interconnected system. We suggest it be reduced to a Medium (i.e., that it
affects control of the BES).
No
Wording in some of the Measures needs to be revised to reflect changes to R2 and/or R3, if our
proposed changes are accepted. Also, we suggest the Requirement numbers be referenced in
the Measures.
No
(i) R1: There should not be any distinction made between an RC acting and an RC directing
others to act. Failure to mitigate adverse reliability impacts a severe violation of the
requirement. We therefore suggest to revise the High and Severe levels as: High if the RC did
not act or direct actions to prevent an Adverse Reliability Impact; Severe if the RC did not act
or direct ations to mitigate the magnitude or duration of an existing Adverse Reliability Impact.
(ii) R2: The High VSL seems contradictory to the requirement, which already has provision of
not fully complying with the RC directives due to safety, equipment, or regulatory or statutory
requirements. (iii) R3: We have proposed some wording change to R3, which if adopted, would
precipitate a need to revise the VSLs for R3 accordingly. (iv) R4 and R5: The VSLs for these
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
two requirements could be graded by assessing the number and/or timing of notifying the
affected entities.
No
(i) R1: There is a duplicating requirement in TOP-005 R1.1. Suggest to eliminate one of the
two. (ii) We do not agree with eliminating all of R5 to R8. There is a fundamental need for RCs
to monitor its area, and even some portion of its adjacent areas to be aware of situations that
require preventive and mitigating actions. While arguments can be made that requiring RCs to
prevent and mitigate adverse reliability impacts would imply monitoring, the latter is a
fundamental duty of any RCs to ensure system reliability. If monitoring is not explicitly stated
as a requirement, then the same argument may be extended to training and operational
facilities. We do not agree with the drafting team's conclusion that it is not practical to measure
real-time monitoring. Measuring can be illustrated, for example, by a compliance audit to
review system logs and assess the extent to which an RC follows and assesses system
conditions.
No
(i) M1: We suggest to change the word "letter" to "documented request" (ii) If our
recommendations to retain some of R5 to R9, some measures will need to be provided.
No
(i) R1: The wording for Low VSL is contradictory (e.g. it determined and requested in the first
part but did not request in the second part). Suggest to revise it. (ii) R1: We suggest to grade
the VSLs according to the extent to which the percentage of data specification and/or the
number of entities not requested. (iii) R2: The RC either has the right or it doesn't, and hence
it's a binary requirement. The VSL should be developed accordingly. Further, the wording for
the Severe VSL does not correspond to the requirement and measure. The condition should
simply be that the Reliability Coordinator failed to demonstrate that it had the authority to veto
planned outages to analysis tools, including final approvals for planned maintenance.
No
(i) R1: We not not agree with removing this requirement for the same reason given for the
proposal to remove R5 to R8 from IRO-002 (see comments on 10 (ii), above). (ii) R8: We do
not agree with completely removing this requirement, especially that part that requires an RC
to monitor system frequency. While DCS and CPS are largely a BA's responsibility, the RC is
the last line of defence for abnormal system performance and needs to monitor its BAs'
performance including their ability to address large frequency deviations, and direct or take
corrective actions as needed including requesting emergency assistance on the BAs' behalf and
directing load shedding. (iii) R9: The second part of this requirement needs to be retained.
IRO-004 covers operational planning, not current day operations. Coordinating pending
generator and transmission facility outages is an essential and necessary task by the RC to
ensure reliabiity. (iv) R11: The RC needs to monitor ACE, detect and identify the cause of any
abnormal ACE, and direct its BAs to take necessary actions to return ACE to within a normal
range. (v) R13: We do not agree with removing the latter part of R13. The FAC standards
cover the methodlology used in calculating SOLs and IROLs. Regardless of how these limits
are calculated, in practice there always exists the possibility that different entities come up with
SOLs/IROLs, especially of the inter-ties, that could be different. Operating to the lowest
SOLs/IROLs when more than one set exists is a necessary requirement for reliable operation.
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No
We suggest to replace the word "impacted" with"other" since there is a preconception that the
concered RC makes an assessment of which other RCs are impacted by the coordinatred
actions, which may not be the perspective of the other RCs who may in fact be impacted by
any coordinated actions among other RCs.
No
Measure 1 actually contains a number of subrequirements that should be stipulated in R1, not
M1. If indeed these are required, they should be stipulated in the Requirement section, not the
Measures Section.
No
(i) R2: the High and Severe VSLs contradict with the requirement. We believe all of the "nots"
should be removed. (ii) R6: The Low VSL should be a High since not agreeing to a plan but
implementing one that has not been agreed to is a high violation of the requirement. (iii) The
VSLs for R1 may need to be revised if our comments on M1 are adopted.
Yes
Yes
Group
Reliability Coordinator Comment Working Group
Linda Perez
WECC
Yes
No
on Measure 3 need to remove the word "all" in reference to voice logs. Measure needs to
include evidence of concurrance for using a language other than English
Yes
Yes
Yes
Yes
Yes
No
measures do not align with VSL's (see question 9)
No
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R1 talks about "ahall act or direct actions to be taken". High VSL - failure to act. Severe VSL failure to act and direct. Does "act" mean any action taken short of issuing a directive? Change
Severe VSL to failure to act or direct and eliminate the High VSL all together. R2 delay in
issuing a directive due to equipmnet problems should be included in the moderate VSL and the
body of the requirement and in the measure. The High VSL should be removed because not
following the directive for equipment failure is allowed per R2. R5 - Severe VSL should be
changed to moderate VSL since the problem has been mitigated and the system is stable and it
does not adversely impact reliability. M3 talks about the ability of reliability entities to meet a
directive. What constitutes evidence that confirms you are able to immeidately comply with the
directive? If the entity agrees to the directive and then is unable to comply due to events
outside of their control, such as a CT not starting, do they meet the measure? If the entity,
based on the circumstances at the time of the directive, agrees to comply in good faith are they
compliant? The Lower VSL should be made N/A because it is not practical for an entity to
immediately confirm they are able to meet the directive in all cases.
No
for R1, this should be 2 separate requirments and measures. R1 should have a methodology for
determining what data is needed and then a R2 should be a requirement to request this data
from the reliability entities.
Yes
add measures for R1 & R2 see question 10
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Fred Young
Northern California Power Agency
No
R3 should include in the last sentence that the Generator Operator and Distribution Provider
may use alternate language for internal operations.
No
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M3 should include Generator Operator and Distribution Provider in the applicability.
Yes
Yes and No
Remove Generator Operator from the Purpose Statement. The re-written statndard no longer
applies to GOP.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Denise Roeder
ElectriCities of North Carolina, Inc.
No
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We are a joint action agency registered on behalf of our member municipalities, who are all
TDUs, neither own nor operate any Bulk Electric System facilities, and perform no real-time
operations or operations planning for the BES. There are currently other standards that already
apply to us that require us to have processes and means to communicate with our RC, BA,
TOP, etc. The proposed modifications to this standard would now make our members subject
to this standard as well, based on the DP registration designation. Given that, we believe there
needs to be additional clarification of specifically what type of "telecommunications facilities"
are required to be considered compliant with this standard. Maybe in the past when this
standard applied to TOPs, BAs, and RCs, it was intuitive what type of telecommunications
facilities they needed to communicate with each other. However, when you bring in small DPs,
it doesn't seem so clear. Obviously we already communicate with our TOP and BA, and have
done so for years. As written, the standard is ambiguous in terms of what more, if anything, we
would have to put in place to satisfy this standard.
No
See comments on Question 1
No
Depends of what is meant by "telecommunications facilities"
Individual
Karl Bryan
US Army Corps of Engineers, Northwestern Division
No
R3 needs to have the last sentence revised to allow the Generator Operator and Distribution
Provider to use an alternate language for internal operations.
No
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M3 needs to include the GO and DP in its requirement for interutility communications in
English.
Yes
Group
PPL Supply Group
Annette Bannon
PPL Generation, LLC
Yes
Yes
Yes
PPL agrees with the changes to COM-002-3. However, for clarity PPL suggests that Generator
Operator should be removed from the purpose statement of this standard.
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Group
Standards Interface Subcommittee/Compliance Elements Drafting
John Blazekovich
Commonwealth Edison Co.
Standard – IRO-001 R1 Requirement (including sub-requirements) The Reliability Coordinator
shall act or direct actions to be taken by Transmission Operators, Balancing Authorities,
Generator Operators, Transmission Service Providers, Load-Serving Entities, Distribution
Providers and Purchasing-Selling Entities within its Reliability Coordinator Area to prevent or
mitigate the magnitude or duration of events that result in Adverse Reliability Impacts.
[Violation Risk Factor: High] [Time Horizon: Real-time Operations and Same Day Operations]
Proposed Measure Each Reliability Coordinator shall have evidence that it acted, or issued
directives, to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts
within its Reliability Coordinator Area Attributes of the requirement Binary Timing X
Omission X Communication X Quality Other Discussion – 1. As currently worded it can be
interpreted that any time an event occurs the RC would be in violation of the standard simply
because they had failed “to prevent” an event. 2. This requirement does not have a “timing”
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element included, although it implies timing based on the “duration of the event”. Including
that “duration of the event” is problematic – it appears to imply that human intervention may
provide a more timely response than relay operation, we would suggest more clarification
about what the “duration” element of the requirement is intended to address (e.g. generation redispatch?). 3. There also appears to be a “quality” element included based on the mitigation of
magnitude of the event. As a result we believe that timeliness, effectiveness and
communication should be the basis of the VSLs. 4. The VSLs as differentiate between
directing actions and acting. Practically, there is no difference. The RC is still giving the
directive. It is just a matter of who is carrying it out. This is not a valid basis for differentiating
between VSLs. We suggest the VSLs be defined based on actual system impact (i.e. Was the
RC acting or directing actions to prevent or to mitigate?) and to either modify the requirement
to remove timing aspects or to add the timing aspects to the VSLs. SDT Proposed Lower VSL
N/A CEDRP Proposed VSL No Comment SDT Proposed Moderate VSL N/A CEDRP
Proposed VSL No Comment SDT Proposed High VSL The Reliability Coordinator failed to
act to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts. CEDRP
Proposed VSL The Reliability Coordinator failed to act to prevent the magnitude or duration of
Adverse Reliability Impacts. SDT Proposed Severe VSL The Reliability Coordinator failed to
act and direct actions to prevent or mitigate the magnitude or duration of Adverse Reliability
Impacts CEDRP Proposed VSL The Reliability Coordinator failed to act and direct actions to
mitigate the magnitude or duration of Adverse Reliability Impacts FERC Guidance for VSLs 1.
Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Additional Compliance Elements Compliance Enforcement Authority NERC shall
be responsible for compliance monitoring of the Regional Entity. Regional Entities shall be
responsible for compliance monitoring of the Reliability Coordinators, Transmission
Operators, Generator Operators, Distribution Providers, and Load Serving Entities. Compliance
Monitoring Period and Reset Time Frame N/A Compliance Monitoring and Enforcement
Processes: Compliance Audits Self-Certifications Spot Checking Compliance Violation
Investigations Self-Reporting Complaints Data Retention Each applicable entity shall retain
data and evidence for a rolling 12 months unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an investigation. The
Compliance Enforcement Authority shall keep the last audit records and all requested and
submitted subsequent compliance records. Additional Compliance Information None CAE
Resource Pool Comments The Enforcement Authority Statement, “NERC shall be responsible
for compliance monitoring of the Regional Entity.” Is not clear, if it is intended to encompass
Regional Entities that perform RC functions is should be clearly stated, if not it should not be
included in the Enforcement Authority section. Standard – IRO-001 R2 Requirement
(including sub-requirements) Transmission Operators, Balancing Authorities, Generator
Operators, Transmission Service Providers, Load-Serving Entities, Distribution Providers, and
Purchasing-Selling Entities shall act without intentional delay to comply with Reliability
Coordinator directives unless such actions would violate safety, equipment, or regulatory or
statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time Operations
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and Same Day Operations] Proposed Measure Each Transmission Operator, Balancing
Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, or
Purchasing-Selling Entity shall have evidence that it acted without delay to comply with the
Reliability Coordinator's directives. Attributes of the requirement Binary Timing X Omission
X Communication X Quality X Other The team would suggest “intentional delay” be
eliminated from the requirement – e.g. “shall act to…”). To act with an intentional delay
represents a willful act to disregard the requirement. Willful disregard of requirements is one of
the factors that the enforcement authority uses to magnify penalties. Requirements should not
include attempts to avoid willful disregard of the requirement. The measure and VSLs do not
consider the exceptions for not following the RC objective. The drafting team should consider
combining requirements R2 and R3. Thus, one VSL would become failure to notify the RC of
the inability to comply. The drafting team could consider applying the numerical category of
VSLs for some directives such as an order to redispatch. Obviously, it would not work well if
the directive was to reconfigure the system. SDT Proposed Lower VSL N/A CEDRP Proposed
VSL No Comment SDT Proposed Moderate VSL The responsible entity followed the
Reliability Coordinators directive with a delay not caused by equipment problems. CEDRP
Proposed VSL The team does not agree that this is a valid VSL. SDT Proposed High VSL The
responsible entity followed the majority of the Reliability Coordinators directive but did not
fully follow the directive because it would violate safety, equipment, statutory or regulatory
requirements. CEDRP Proposed VSL The team does not agree that this is a valid VSL. The
word majority implies some ability to numerically measure the response to the directive. Thus,
the drafting team should consider applying the numerical category of the VSL guidelines. SDT
Proposed Severe VSL The responsible entity did not follow the Reliability Coordinators
directive. CEDRP Proposed VSL The responsible entity did not follow the Reliability
Coordinators directive, the directive would not have violated safety, equipment, regulatory, or
statutory requirements, and responsible entity did not communicate the inability to follow the
directive to the Reliability Coordinator. FERC Guidance for VSLs 1. Will the VSL assignment
signal entities that less compliance than has been historically achieved is condoned? No 2. Is
the VSL assignment a binary requirement? No 3. Is it truly a “binary” requirement? N/A 4. If
yes, is the VSL assignment consistent with other binary requirement assignments? N/A 5. Is
the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised? Yes 6. Does the VSL redefine or undermine the stated
requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? No Standard - IRO-001 R3 Requirement (including sub-requirements) The
Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider or Purchasing-Selling Entity shall
immediately confirm the ability to comply with the directive or inform the Reliability
Coordinator upon recognition of the inability to perform the directive. [Violation Risk Factor:
High] [Time Horizon: Real-time Operations and Same Day Operations] Proposed Measure
Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, or Purchasing-Selling Entity shall have evidence that it
confirmed its ability to comply with the Reliability Coordinator's directives, or if for safety,
equipment, regulatory or statutory requirements it could not comply, informed the Reliability
Coordinator upon recognition of the inability to comply. Attributes of the requirement Binary
Timing Omission Communication X Quality Other Discussion – The requirement appears to be
based on communication and can be problematic by including the requirement to immediately
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confirm the ability to comply, a directive can be issued to one entity or several entities at one
time (e.g. conference call, all call, electronic notification) that may create several issues when
attempting to process all confirmations, the requirement language presents a risk of being
found out of compliance for following a directive but not providing an “immediate”
confirmation to the RC. The CEDRP believes it to be a reasonable expectation that all entities
will comply with reliability directives and notification should be made only on exception. The
SDT should consider combining this requirement with R2. SDT Proposed Lower VSL The
responsible entity failed to immediately confirm the ability to comply with the directive issued
by the Reliability Coordinator. CEDRP Proposed VSL See above discussion note SDT
Proposed Moderate VSL N/A CEDRP Proposed VSL No comment SDT Proposed High VSL
N/A CEDRP Proposed VSL No comment SDT Proposed Severe VSL The responsible entity
failed to inform the Reliability Coordinator upon recognition of the inability to perform the
directive. CEDRP Proposed VSL No comment FERC Guidance for VSLs 1. Will the VSL
assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? No 3. Is it truly a “binary”
requirement? N/A 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? N/A 5. Is the VSL language clear & measurable (ambiguity removed)? If no,
does the requirement or measure need to be revised? As currently worded the CEDRP believe
that the requirement should be changed to eliminate that “immediate confirmation” portion of
the requirement 6. Does the VSL redefine or undermine the stated requirement? No 7. Is the
VSL based on a single violation of the requirement (not multiple violations)? No Standard IRO-001 R4 Requirement (including sub-requirements) Each Reliability Coordinator that
identifies an expected or actual threat with Adverse Reliability Impacts within its Reliability
Coordinator Area shall notify, without intentional delay, all impacted Transmission Operators
and Balancing Authorities in its Reliability Coordinator Area. [Violation Risk Factor: High]
[Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
Proposed Measure Each Reliability Coordinator shall have evidence that it notified, without
intentional delay, all impacted Transmission Operators and balancing Authorities in its
Reliability Coordinator Area when it identified a real or potential threat with Adverse
Reliability Impacts, within its Reliability Coordinator Area. Attributes of the requirement
Binary Timing X Omission Communication X Quality Other Discussion – To act with an
intentional delay represents a willful act to disregard the requirement. Willful disregard of
requirements is one of the factors that the enforcement authority uses to magnify penalties.
Requirements should not include attempts to avoid willful disregard of the requirement. This
requirement appears to fit the numerical category of the VSL guidelines best. SDT Proposed
Lower VSL N/A CEDRP Proposed VSL The Reliability Coordinator who identified an
expected or actual threat with Adverse Reliability Impacts within its Reliability Coordinator
Area failed to notify 25% or less of the Transmission Operators and Balancing Authorities
within its Reliability Coordination Area. SDT Proposed Moderate VSL N/A CEDRP Proposed
VSL The Reliability Coordinator who identified an expected or actual threat with Adverse
Reliability Impacts within its Reliability Coordinator Area failed to notify more than 25% but
less than or equal to 50% of the Transmission Operators and Balancing Authorities within its
Reliability Coordination Area. SDT Proposed High VSL N/A CEDRP Proposed VSL The
Reliability Coordinator who identified an expected or actual threat with Adverse Reliability
Impacts within its Reliability Coordinator Area failed to notify more than 50% but less than or
equal to 75% of the Transmission Operators and Balancing Authorities within its Reliability
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Coordination Area. SDT Proposed Severe VSL: The Reliability Coordinator who identified an
expected or actual threat with Adverse Reliability Impacts within its Reliability Coordinator
Area failed to issue an alert to all impacted Transmission Operators and Balancing Authorities
in its Reliability Coordinator Area. CEDRP Proposed Severe VSL: The Reliability Coordinator
who identified an expected or actual threat with Adverse Reliability Impacts within its
Reliability Coordinator Area failed to notify more than 75% of the Transmission Operators and
Balancing Authorities within its Reliability Coordination Area. FERC Guidance for VSLs 1.
Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? No 2. Is the VSL assignment a binary requirement? No 3. Is it truly a
“binary” requirement? N/A 4. If yes, is the VSL assignment consistent with other binary
requirement assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If
no, does the requirement or measure need to be revised? Yes 6. Does the VSL redefine or
undermine the stated requirement? No 7. Is the VSL based on a single violation of the
requirement (not multiple violations)? Yes Standard - IRO-001 R5 Requirement (including
sub-requirements) Each Reliability Coordinator who identifies an expected or actual threat with
Adverse Reliability Impacts, within its Reliability Coordinator Area shall notify, without
intentional delay, all impacted Transmission Operators and Balancing Authorities in its
Reliability Coordinator Area when the transmission problem has been mitigated. [Violation
Risk Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and
Operations Planning] Proposed Measure Each Reliability Coordinator shall have evidence that
it notified, without intentional delay, all impacted Transmission Operators and balancing
Authorities in its Reliability Coordinator Area when the real or potential threat with Adverse
Reliability Impacts within its Reliability Coordinator Area has been mitigated. Attributes of the
requirement Binary Timing X Omission Communication X Quality Other Discussion – To act
with an intentional delay represents a willful act to disregard the requirement. Willful disregard
of requirements is one of the factors that the enforcement authority uses to magnify penalties.
Requirements should not include attempts to avoid willful disregard of the requirement.
Measure 5 is written implying that there is an Adverse Reliability Impact. The drafting team
should consider wording the measurement to consider that there may not be an Adverse
Reliability Impact requiring a directive. The Commission in paragraph 27 of the VSL order has
stated that multiple VSLs are preferable where possible. Suggest applying the numerical
category of the VSL Guidelines based on the number of entities notified.. SDT Proposed
Lower VSL: N/A CEDRP Proposed Lower VSL: The Reliability Coordinator who identified
an expected or actual threat with Adverse Reliability Impacts within its Reliability Coordinator
Area failed to notify 25% or less of the impacted Transmission Operators and Balancing
Authorities within its Reliability Coordination Area that the Adverse Reliability Impact had
been mitigated. SDT Proposed Moderate VSL: N/A CEDRP Proposed Moderate VSL: The
Reliability Coordinator who identified an expected or actual threat with Adverse Reliability
Impacts within its Reliability Coordinator Area failed to notify more than 25% but less than or
equal to 50% of the impacted Transmission Operators and Balancing Authorities within its
Reliability Coordination Area that the Adverse Reliability Impact had been mitigated. SDT
Proposed High VSL: N/A CEDRP Proposed High VSL: The Reliability Coordinator who
identified an expected or actual threat with Adverse Reliability Impacts within its Reliability
Coordinator Area failed to notify more than 50% but less than or equal to 75% of the impacted
Transmission Operators and Balancing Authorities within its Reliability Coordination Area that
the Adverse Reliability Impact had been mitigated. SDT Proposed Severe VSL: The Reliability
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Coordinator failed to notify all impacted Transmission Operators, Balancing Authorities, when
the transmission problem had been mitigated. CEDRP Proposed Severe VSL: The Reliability
Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 75% of the impacted
Transmission Operators and Balancing Authorities within its Reliability Coordination Area that
the Adverse Reliability Impact had been mitigated. FERC Guidance for VSLs 1. Will the VSL
assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? No 3. Is it truly a “binary”
requirement? N/A 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? N/A 5. Is the VSL language clear & measurable (ambiguity removed)? If no,
does the requirement or measure need to be revised? Yes 6. Does the VSL redefine or
undermine the stated requirement? No 7. Is the VSL based on a single violation of the
requirement (not multiple violations)? Yes Standard – IRO-002-2 R1 Requirement (including
sub-requirements) Each Reliability Coordinator shall determine the data requirements to
support its reliability coordination tasks and shall request such data from its Transmission
Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation
Operators, and Load- Serving Entities, or adjacent Reliability Coordinators. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations
Planning] Proposed Measure Each Reliability Coordinator shall have and provide upon request
evidence that could include, but is not limited to, a letter to Transmission Operators, Balancing
Authorities, Transmission Owners, Generator Owners, Generator Operators, and Load-Serving
Entities, or adjacent Reliability Coordinators, or other equivalent evidence that will be used to
confirm that the Reliability Coordinator has requested the data required to support its reliability
coordination tasks. Attributes of the requirement Binary Timing Omission X Communication
X Quality Other Discussion – The VSLs attempt to measure the quality of the data
requirements. They require the compliance auditor to judge if another RC has material impact
and what data is administrative and what data is substantial. Given the typical length of a
compliance audit, it is doubtful that the compliance auditor can make these types of judgments
about the quality of the data and the material impact of another RC. The drafting team should
consider applying numerical category of VSLs based on the number of entities the data request
is made from. It is interesting that the measure also does not require any documentation of a
data specification. SDT Proposed Lower VSL: The Reliability Coordinator demonstrated that it
1) determined its data requirements and requested that data from its Transmission Operators,
Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and
Load-Serving Entities or Adjacent Reliability Coordinators with a material impact on the Bulk
Electric System in its Reliability Coordination Area but did not request the data from
Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners,
Generation Operators, and Load-Serving Entities or Adjacent Reliability Coordinators with
minimal impact on the Bulk Electric System in its Reliability Coordination Area orr 2)
determined its data requirements necessary to perform its reliability functions with the
exceptions of data that may be needed for administrative purposes such as data reporting.
CEDRP Proposed Lower VSL: The Reliability Coordinator failed to request data to support its
reliability coordination tasks from 25% or less of its Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and LoadServing Entities, or adjacent Reliability Coordinators. SDT Proposed Moderate VSL: The
Reliability Coordinator demonstrated that it determined the majority but not all of its data
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requirements necessary to support its reliability coordination functions and requested that data
from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load-Serving Entities or Adjacent Reliability
Coordinators. CEDRP Proposed Moderate VSL: The Reliability Coordinator failed to request
data to support its reliability coordination tasks from more than 25% but less than or equal to
50% of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load-Serving Entities, or adjacent Reliability
Coordinators. SDT Proposed High VSL: The Reliability Coordinator demonstrated that it
determined 1) some but less than the majority of its data requirements necessary to support its
reliability coordination functions and requested that data from its Transmission Operators,
Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and
Load-Serving Entities or Adjacent Reliability Coordinators Or 2) all of its data requirements
necessary to support its reliability coordination functions but failed to demonstrate that it
requested data from two of its Transmission Operators, Balancing Authorities, Transmission
Owners, Generation Owners, Generation Operators, and Load-Serving Entities or Adjacent
Reliability Coordinators. CEDRP Proposed High VSL: The Reliability Coordinator failed to
request data to support its reliability coordination tasks from more than 50% but less than or
equal to 75% of its Transmission Operators, Balancing Authorities, Transmission Owners,
Generation Owners, Generation Operators, and Load-Serving Entities, or adjacent Reliability
Coordinators. SDT Proposed Severe VSL: The Reliability Coordinator failed to demonstrate
that it 1) determined its data requirements necessary to support its reliability coordination
functions and requested that data from its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators Or 2) requested the data from three or more of its
Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners,
Generation Operators, and Load-Serving Entities or Adjacent Reliability Coordinators. CEDRP
Proposed Severe VSL: The Reliability Coordinator failed to request data to support its
reliability coordination tasks from more than 75% of its Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and LoadServing Entities, or adjacent Reliability Coordinators, Or, The Reliability Coordinator failed to
determine data requirements to support its reliability coordination tasks. FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Standard – IRO-002-2 R2 Requirement (including sub-requirements) Each
Reliability Coordinator shall have the authority to veto planned outages to analysis tools,
including final approvals for planned maintenance. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations, Same Day Operations and Operations Planning] Proposed
Measure Each Reliability Coordinator shall have and provide upon request evidence that could
include, but is not limited to, a documented procedure or equivalent evidence that will be used
to confirm that the Reliability Coordinator has the authority to veto planned outages to analysis
tools, including final approvals for planned maintenance as specified in Requirement 2.
Attributes of the requirement Binary Timing Omission Communication Quality Other X Is this
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requirement needed? R1 IRO-001-2 requires the RC to mitigate Adverse Reliability Impacts.
R2 IRO-001-2 requires responsible entities to comply with the RC directives. Wouldn’t the RC
thus have the right to cancel all types of outages (i.e. analysis tools, transmission equipment,
etc). FERC has stated in paragraph 112 of Order 693-A that an RC does not derive their
authority from agreements but rather from FERC’s approval of the standards. Barring the
team’s decision to remove this requirement, the Severe VSL is confusing. We have suggested
different wording. SDT Proposed Lower VSL Reliability Coordinator has approval rights for
planned outages of analysis tools but does not have approval rights for maintenance on analysis
tools. CEDRP Proposed VSL No Comment SDT Proposed Moderate VSL N/A CEDRP
Proposed VSL No Comment SDT Proposed High VSL N/A CEDRP Proposed VSL No
Comment SDT Proposed Severe VSL Reliability Coordinator approval is not required for
planned maintenance or planned outages. CEDRP Proposed VSL Reliability Coordinator does
not approve planned maintenance or planned outages. FERC Guidance for VSLs 1. Will the
VSL assignment signal entities that less compliance than has been historically achieved is
condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Standard – IRO-014-2 R1 Requirement (including sub-requirements) R1. The
Reliability Coordinator shall have Operating Procedures, Processes, or Plans for activities that
require notification, exchange of information or coordination of actions with impacted
Reliability Coordinators to support Interconnection reliability. These Operating Procedures,
Processes, or Plans shall collectively address, as a minimum, the following: [Violation Risk
Factor: Medium] [Time Horizon: Same Day Operations and Operations Planning] R1.1.
Communications and notifications, including the mutually agreed to conditions under which
one Reliability Coordinator notifies other Reliability Coordinators; the process to follow in
making those notifications; and the data and information to be exchanged with other Reliability
Coordinators. R1.2. Energy and capacity shortages. R1.3. Planned or unplanned outage
information. R1.4. Voltage control, including the coordination of reactive resources for voltage
control. R1.5. Coordination of information exchange to support reliability assessments. R1.6.
Authority to act to prevent and mitigate instances of causing Adverse Reliability Impacts to
other Reliability Coordinator Areas. Proposed Measure M1. The Reliability Coordinator’s
System Operators shall have available for Real-time use, the latest approved version of
Operating Procedures, Processes, or Plans that require notifications, information exchange or
the coordination of actions among impacted Reliability Coordinators. M1.1 These Operating
Procedures, Processes, or Plans shall address: M1.2 Communications and notifications,
including the mutually agreed to conditions under which one Reliability Coordinator notifies
other Reliability Coordinators; the process to follow in making those notifications; and the data
and information to be exchanged with other Reliability Coordinators. M1.3 Energy and
capacity shortages. M1.4 Planned or unplanned outage information. M1.5 Voltage control,
including the coordination of reactive resources for voltage control. M1.6 Coordination of
information exchange to support reliability assessments. Authority to act to prevent and
mitigate instances of causing Adverse Reliability Impacts to other Reliability Coordinator
Areas. Attributes of the requirement Binary Timing Omission x Communication x Quality
Other Discussion – The CEDRP has no recommendations regarding this requirement. SDT
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Proposed Lower VSL: The Reliability Coordinator has Operating Procedures, Processes, or
Plans in place for activities that require notification, exchange of information or coordination
of actions with impacted Reliability Coordinators to support Interconnection reliability but
failed to address one or two of the subrequirements. CEDRP Proposed Lower VSL: No
Comment SDT Proposed Moderate VSL: Coordinator has Operating Procedures, Processes, or
Plans in place for activities that require notification, exchange of information or coordination
of actions with impacted Reliability Coordinators to support Interconnection reliability but
failed to address three or four of the subrequirements. CEDRP Proposed High VSL: No
Comment SDT Proposed High VSL: The Reliability Coordinator has Operating Procedures,
Processes, or Plans in place for activities that require notification, exchange of information or
coordination of actions with impacted Reliability Coordinators to support Interconnection
reliability but failed to address five of the subrequirements. CEDRP Proposed High VSL: No
Comment SDT Proposed Severe VSL: The Reliability Coordinator failed to have Operating
Procedures, Processes, or Plans in place for activities that require notification, exchange of
information or coordination of actions with impacted Reliability Coordinators to support
Interconnection reliability. CEDRP Proposed Severe VSL: No Comment FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Standard – IRO-014-2 R2 Requirement (including sub-requirements) R2. Each
Reliability Coordinator’s Operating Procedure, Process, or Plan that requires one or more other
Reliability Coordinators to take action (e.g., make notifications, exchange information, or
coordinate actions) shall be: [Violation Risk Factor: Lower] [Time Horizon: Real-time
Operations and Operations Planning] R2.1. Agreed to by all the Reliability Coordinators
required to take the indicated action(s). R2.2. Distributed to all Reliability Coordinators that are
required to take the indicated action(s). Proposed Measure M2. The Reliability Coordinator
shall have evidence that the Operating Procedures, Processes, or Plans that require one or more
other Reliability Coordinators to take action (e.g., make notifications, exchange information, or
coordinate actions) were: M2.1 Agreed to by all the Reliability Coordinators required to take
the indicated action(s). M2.2 Distributed to all Reliability Coordinators that are required to take
the indicated action(s). Attributes of the requirement Binary Timing Omission X
Communication X Quality Other Discussion – The High and Severe VSLs appear to use “not”
incorrectly. SDT Proposed Lower VSL N/A CEDRP Proposed VSL No Comment SDT
Proposed Moderate VSL: The Reliability Coordinator failed to have evidence that the
Operating Procedures, Processes, or Plans that require one or more other Reliability
Coordinators to take action (e.g., make notifications, exchange information, or coordinate
actions) were distributed to all Reliability Coordinators that are required to take action. CEDRP
Proposed Moderate VSL: The Reliability Coordinator did not have evidence that the Operating
Procedures, Processes, or Plans that require one or more other Reliability Coordinators to take
action (e.g., make notifications, exchange information, or coordinate actions) were distributed
to all Reliability Coordinators that are required to take action. SDT Proposed High VSL: The
Reliability Coordinator failed to have evidence that the Operating Procedures, Processes, or
Plans that require one or more other Reliability Coordinators to take action (e.g., make
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notifications, exchange information, or coordinate actions) were not agreed to by all Reliability
Coordinators that are required to take action CEDRP Proposed High VSL: The Reliability
Coordinator did not have evidence that the Operating Procedures, Processes, or Plans that
require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were agreed to by all Reliability Coordinators that
are required to take action SDT Proposed Severe VSL: The Reliability Coordinator failed to
have evidence that the Operating Procedures, Processes, or Plans that require one or more other
Reliability Coordinators to take action (e.g., make notifications, exchange information, or
coordinate actions) were not agreed to by all Reliability Coordinators that are required to take
action and were not distributed to all Reliability Coordinators that are required to take action
CEDRP Proposed Severe VSL: The Reliability Coordinator did not have evidence that the
Operating Procedures, Processes, or Plans that require one or more other Reliability
Coordinators to take action (e.g., make notifications, exchange information, or coordinate
actions) were agreed to by all Reliability Coordinators that are required to take action and were
distributed to all Reliability Coordinators that are required to take action FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Standard – IRO-014-2 R3 XXX-XXX Requirement (including sub-requirements)
R3. The Reliability Coordinator shall make notifications and exchange reliability–related
information with impacted Reliability Coordinators using its predefined Operating Procedures,
Processes, or Plans for conditions that may impact other Reliability Coordinator Areas or other
means to accomplish the notifications and exchange of reliability-related information.
[Violation Risk Factor: Medium][Time Horizon: Real-time Operations and Operations
Planning] Proposed Measure M3. The Reliability Coordinator shall have evidence it made
notifications and exchanged reliability–related information with impacted Reliability
Coordinators using its predefined Operating Procedures, Processes, or Plans for conditions that
may impact other Reliability Coordinator Areas or other means to accomplish the notifications
and exchange of reliability-related information. Attributes of the requirement Binary Timing
Omission X Communication X Quality Other Discussion: The VSLs appear to be appropriate.
Since the only difference is the use of the “and” and “or”, we suggest emphasizing those words
in bold. We read this more than once before we noticed the difference. SDT Proposed Lower
VSL N/A CEDRP Proposed VSL N/A SDT Proposed Moderate VSL N/A CEDRP Proposed
VSL N/A SDT Proposed High VSL: The Reliability Coordinator failed to make notifications or
exchange reliability–related information with impacted Reliability Coordinators. CEDRP
Proposed High VSL: The Reliability Coordinator failed to make notifications or exchange
reliability–related information with impacted Reliability Coordinators. SDT Proposed Severe
VSL: The Reliability Coordinator failed to make notifications and exchange reliability–related
information with impacted Reliability Coordinators. CEDRP Proposed Severe VSL: The
Reliability Coordinator failed to make notifications and exchange reliability–related
information with impacted Reliability Coordinators. FERC Guidance for VSLs 1. Will the VSL
assignment signal entities that less compliance than has been historically achieved is
condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
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requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Standard – IRO-014-2 R4 XXX-XXX Requirement (including sub-requirements)
R4. The Reliability Coordinator shall participate in agreed upon conference calls and other
communication forums with impacted Reliability Coordinators. [Violation Risk Factor:
Lower][Time Horizon: Real-time Operations] The frequency of these conference calls shall be
agreed upon by all involved Reliability Coordinators and shall be at least weekly. Proposed
Measure M4. The Reliability Coordinator shall have evidence it participated in agreed upon (at
least weekly) conference calls and other communication forums with impacted Reliability
Coordinators. Attributes of the requirement Binary Timing X Omission X Communication X
Quality Other Discussion – This requirement is purely administrative and probably does not
rise to a level of a reliability standard requirement. It is in essence redundant, with R1.1 IRO014-2? It appears R1.1 addresses the same information that would be expected to be discussed
in a weekly conference call. Should the drafting team disagree and retain this requirement,
please consider applying multiple VSLs based on how often the RC participates in conference
calls, how many they missed, or how many impacted RCs they participated in conference calls
with. SDT Proposed Lower VSL: The Reliability Coordinator failed to participate in agreed
upon (at least weekly) conference calls and other communication forums with impacted
Reliability Coordinators. CEDRP Proposed Lower VSL: The Reliability Coordinator
participated in agreed upon conference calls and other communication forums with impacted
Reliability Coordinators bi-weekly, Or the Reliability Coordinator failed to participate in one
weekly conference call, Or the Reliability Coordinator agreed to participate in conference calls
with 25% or less of the impacted Reliability Coordinators. SDT Proposed Moderate VSL: N/A
CEDRP Proposed Moderate VSL: The Reliability Coordinator participated in agreed upon
conference calls and other communication forums with impacted Reliability Coordinators
every third week, Or the Reliability Coordinator failed to participate in two weekly conference
calls, Or the Reliability Coordinator agreed to participate in conference calls with more than
25% but less than or equal to 50% of the impacted Reliability Coordinators. SDT Proposed
High VSL: N/A CEDRP Proposed High VSL: The Reliability Coordinator participated in
agreed upon conference calls and other communication forums with impacted Reliability
Coordinators fourth week, Or the Reliability Coordinator failed to participate in three weekly
conference calls, Or the Reliability Coordinator agreed to participate in conference calls with
more than 50% but less than or equal to 75% of the impacted Reliability Coordinators. SDT
Proposed Severe VSL: N/A CEDRP Proposed Severe VSL: The Reliability Coordinator
participated in agreed upon conference calls and other communication forums with impacted
Reliability Coordinators at least every fifth week, Or the Reliability Coordinator failed to
participate in four weekly conference calls, Or the Reliability Coordinator failed to agree to
participate in any conference calls, Or the Reliability Coordinator agreed to participate in
conference calls with more than 75% but less than 100% of the impacted Reliability
Coordinators. FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less
compliance than has been historically achieved is condoned? 2. Is the VSL assignment a binary
requirement? 3. Is it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent
with other binary requirement assignments? 5. Is the VSL language clear & measurable
(ambiguity removed)? If no, does the requirement or measure need to be revised? 6. Does the
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VSL redefine or undermine the stated requirement? 7. Is the VSL based on a single violation of
the requirement (not multiple violations)? Standard – IRO-014-2 R5 XXX-XXX Requirement
(including sub-requirements) R5. When an expected or actual reliability issue is detected, the
Reliability Coordinator shall confirm the existence of the issue with the impacted Reliability
Coordinators. In the event that the issue cannot be confirmed, each Reliability Coordinator
shall operate as though the problem exists. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same Day Operations and Real-time Operations] Proposed Measure The
Reliability Coordinator shall have evidence that, in cases when an expected or actual reliability
issue was detected, it has confirmed the existence of the issue with the impacted Reliability
Coordinators. Attributes of the requirement Binary Timing Omission X Communication X
Quality Other Discussion – This requirement is confusing in the way it is worded. We think it
is trying to say that the RC should operate as though the reliability issue (should this be
Adverse Reliability Impact) is detected until the issue is confirmed not to exist. The way it is
worded might imply that if one doesn’t confirm it to exist, operate as though it does. This
leaves open the interpretation that a confirmation that it doesn’t exist must still be operated to
as though it does exist. The drafting team should consider splitting operating to prevent from
operating to mitigate an existing event in the VSLs. SDT Proposed Lower VSL The Reliability
Coordinator that detected an expected or actual reliability issue contacted the other Reliability
Coordinator(s) to confirm that there was a problem but could not confirm that the problem
existed and failed to operate as though the problem existed. CEDRP Proposed VSL N/A SDT
Proposed Moderate VSL N/A CEDRP Proposed VSL N/A SDT Proposed High VSL N/A
CEDRP Proposed VSL The Reliability Coordinator that detected an expected reliability issue
failed to contact the other Reliability Coordinator(s) to confirm that there was a problem. SDT
Proposed Severe VSL The Reliability Coordinator that detected an expected or actual
reliability issue failed to contact the other Reliability Coordinator(s) to confirm that there was a
problem. CEDRP Proposed VSL The Reliability Coordinator that detected an actual reliability
issue failed to contact the other Reliability Coordinator(s) to confirm that there was a problem.
FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance than
has been historically achieved is condoned? 2. Is the VSL assignment a binary requirement? 3.
Is it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent with other binary
requirement assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If
no, does the requirement or measure need to be revised? 6. Does the VSL redefine or
undermine the stated requirement? 7. Is the VSL based on a single violation of the requirement
(not multiple violations)? Standard – IRO-014-2 R6 XXX-XXX Requirement (including subrequirements) When an expected or actual reliability issue exists and the impacted Reliability
Coordinators cannot agree on a mitigation plan, all impacted Reliability Coordinators shall
implement the mitigation plan developed by the Reliability Coordinator who has the reliability
issue. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations] Proposed Measure The affected Reliability Coordinators
shall have evidence that, in cases when an expected or actual reliability issue existed and the
impacted Reliability Coordinators could not agree on a mitigation plan, they implemented the
mitigation plan developed by the Reliability Coordinator who has the reliability issue.
Attributes of the requirement Binary Timing Omission X Communication X Quality Other
Discussion: We are concerned the validity of this requirement, it may force an RC to
implement a solution that they don’t agree with and ultimately result in an Adverse Reliability
Impact. The RC may not agree with the solution because it may not be reliable for their
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footprint. They need to have the ability to veto mitigation plans that cause Adverse Reliability
Impacts in their footprint without incurring a compliance violation. SDT Proposed Lower VSL
The Reliability Coordinator did not agree on a mitigation plan and implemented a plan other
than the one developed by the Reliability Coordinator who had the reliability issue. CEDRP
Proposed VSL N/A SDT Proposed Moderate VSL N/A CEDRP Proposed VSL N/A SDT
Proposed High VSL N/A CEDRP Proposed VSL N/A SDT Proposed Severe VSL The
Reliability Coordinator did not agree on a mitigation plan and did not implement a mitigation
plan. CEDRP Proposed VSL What if the RC is correct in disagreeing and the mitigation plan
would have caused an Adverse Reliability Impact on their system? FERC Guidance for VSLs
1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary”
requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
requirement? 7. Is the VSL based on a single violation of the requirement (not multiple
violations)?
Group
MRO NERC Standards Review Subcommittee
Terry Bilke
MidwestISO
No
The new R2 requirement is too verbose. We suggest that you strike the final clause: "and shall
verify that alternate means of telecommunications are functional." It is obviated by the
requirement to notify impacted parties. The responsible entity is already implicitly required to
verify its alternate means of communication is functional since it is required to notify its
impacted parties of the failure of its normal telecommunications. It can't notify its impacted
parties if the alternate communications means are not funcitonal. This clause is similar to the
old requirement one that the drafting team appropriately struck. We tend to agree that striking
R1 makes sense due to the drafting team's reasoning. However, we are not clear why the new
R4 is necessary then. If the drafting team does not believe R1 is necessary shouldn't they
respond to the FERC directive with the same reason why R4 is not really necessary? The VRF
for new requirement 1 should be lower. It does not fit the definition of a medium VRF. A
medium VRF requires that a violation of the requirement directly affect the state or capability
or the ability to effectively monitor and control. Failure to test does not result in directly
affecting the state or capability or the ability to effectively monitor and control. At a minimum,
a failure of the alternative communication systems and primary communication systems must
occur first. The failure to perform a single test in a given quarter does not mean that primary
and alternative communication systems will fail. Thus, testing is really an administrative issue
and should thus be a lower VRF. In the Data Retention section, Distribution Provider and
Generation Operators should be added. Currently, there are no data retention requirements
listed for them. Suggest modifying the language regarding data retention for compliance
violations to: "… is found in violation of a requirement, it shall keep information related to the
violation until it the Compliance Enforcement Authority finds it compliant."
No
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M4 does not appear to be worded as a measurement. If R4 is kept, we suggest the following
modification: "The Distribution Provider and Generation Operator shall demonstrate the
existence of its telecommunication systems idenfitied in R4."
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission
established in their "Order on Violation Severity Levels Proposed by the Electric Reliability
Organization". Guideline 4 requires that a VSL should be based on a single violation. The
VSLs as defined accumulate the number of consecutive quarters. This would imply that a
single violation could last more than a year and that the compliance auditor could not
determine sanctions until the entity becomes compliant or year has passed. A single violation
appears to be the failure to test in a single quarter. This requirement is binary in nature in that it
is either met or it isn't. We suggest that only a lower VSL should be defined as: "The RC, TOP,
or BA failed to test the backup telecommunication facilities for a single calendar quarter." The
Lower VSL for R2 is not possible. The act of notifying all impacted entities of the failure of
their primary telecommunication system requires the use of the alternative telecommunications
systems which is a form of verying that the alternative telecommunications facilities are
functional. The drafting team should consider applying the numeric performance category of
the VSL Development Guideline Criteria for R2.
Yes
Yes
Yes
No
New requirement R2 should omit act without intentional delay. The desired outcome is for the
responsible entity to comply with the RC directive. Adding act without intentional delay only
confuses the situation and adds questions. What is an intentional delay? The word act implies
that the requirement is met simply if the responsible entity attempted to meet the directive but
was unable to do so. That is already considered in with the clause that begins "unless such
actions would violate …". Thus, the word act is not necessary. The word immediately should
be removed from the new R3. This attempts to time frame the response of the responsible
entity and remove the judgment from the compliance auditor. We agree with the concept of
doing this but in reality it only confuses the issue and the compliance auditor will likely apply
his judgment regarding what immediate is anyway. Additionallly, the requirement attempts to
separate the act of confirming that the responsible entity can take the action from notifying the
RC that the entity can't take the action. This is not logical. What RC is going to request a
responsible entity to take action that would violate safety, equipment, statutory, or regulatory
requirements? The RC should already be aware of those requirements and likely won't direct
actions that violate them. Thus, the likely scenario is that the responsible entity will attempt to
take action and discover that equipment is not funciton properly and thus notify the RC. We
suggest striking the "shall immediately confirm the ability to comply with the directive or"
from the requirement. This part of the requirement is not needed because the responsible entity
is already obligated to follow the RCs directive (see order 693.) Thus, the assumption is that
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the order will be followed unless it can't be followed because it will violated safety, equipment,
statutory, or regulatory requirements. Requirements R4 and R5 are unnecessary. New R1
requires the RC to direct actions to be taken by the TOP, BA, GOP, TSP, LSE, DP and PSE to
prevent or mitigate the magnitude or duration of events that result in Adverst Reliability
Impacts. The RC can't direct these actions without notifying all impacted TOPs and BAs. They
would also have to notify them when actions are no longer necessary.
No
Some compliance auditors have been taking the need for evidence to the extreme. We have
encountered actual situations where if a measure states evidence shall be provided for
requirements that are event based, the compliance auditor expected evidence even if no event
occurred. For example, some RCs rarely issue directives. As M1 is written, some compliance
auditors would require the RC to provide evidence that no reliability directives were issued.
This is not possible. We suggest modifying the measurement to: Each Reliability Coordinator
shall have evidence that it acted, or issued directives, to prevent or mitigate the magnitude or
duration of Adverse Reliability Impacts within its Reliability Coordiantor Area if needed. If
there were no directives issues (assuming there are no complaints or evidence to the contrary of
the need to issue a directive), no evidence is necessary."
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in
Severe. From a practical perspective, what is the difference between directing actions and
acting? We don't believe there is any. The actions are the result of the RC authority whether the
RC takes the actions themselves or directs someone else to. We suggest a better alternative for
the VSL levels would be for the High level to reflect that the RC did not act or direct actions to
prevent an Adverse Reliability Impact and Severe would be that the RC did not act or direct
ations to mitigate the magnitude or duration of an existing Adverse Reliability Impact. The
moderate VSL for R2 is not practical and too subjective. What constitutes a delay? What if the
responsible entity takes five minutes to determine how to carry out the action or if their
equipment currently is capable of carrying out the action? Is this a delay? We suggest striking
this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory,
or regulatory requirements a violation. This is in direct conflict with the requirement. We
suggest that the High VSL should be struck. We suggest the Severe VSL should be that the
responsible entity failed to follow the RC directive and it would not have violated the safety,
equipment, statutory or regulatory requirements. Currently, the Severe category does not allow
that the responsible entity may not be able to carry out the directive due to the violation of
safety, equipment, statutory, or regulatory requirements. In question 7, we request that the
drafting team strike part of requirement 3. The striking of that portion of requirement 3
obviates the lower VSL. In paragraph 27 of the ORDER ON VIOLATION SEVERITY
LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION, the
Commission expresses "that, as a general rule, gradated Violation Severity Levels, whereever
possible, would be preferable to binary Violation Severity Levels". Given that it is possible to
define gradated VSLs for R4 and R5, we suggest that the drafting team should consider
applying the numeric performance category of the Violation Severity Levels Development
Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
No
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New Requirement R1 is duplicate to the requirement TOP-005-1 R1.1. If the drafting team
can't delete TOP-005-1 R1.1, they should notify other appropriate drafting teams of the need to
remove the requirement. We do not agree with eliminating requirements R5, R6, R7, and R8 in
their entirety. The requirements as they are written are problematic. However, we do believe
that there is a need for a basic requirement to monitor the system. The requirements should be
that the RC should compare actual system flows to SOLs and IROLs. While some will argue
SOLs are not the responsibility of the RC, failure to monitor SOLs could cause the RC to miss
unknown IROLs since an SOL can become an IROL. Several SOL violations in a given area
also can be indicative of a broader system problem the RC should be addressing. We also do
not agree with the drafting team's conclusion that it is not practical to measure real-time
monitoring. It is very easy to measure. As an example, a compliance auditor could select a day
and an SOL or IROL and ask for the system flows from that day or hour etc. This is generally
easy for any RC to produce with today's data archiving software. We believe that there should
be a requirement that the RC have a state estimator and real-time contingency analysis as well
(RTCA). The drafting team needs to be careful in the construction of these requirements to
make them practical and measurable. For instance, making the requirement to have a state
estimator and RTCA is measurable in that the compliance auditor can verify their existence but
this is not stringent enough because they may only run once a week. At the same time, if we
create a requirement that SE and RTCA must run every 5 minutes, we could inadvertantly
create a requirement that any missing 5 minute run of RTCA and SE could be construed as a
violation. There also needs to be a requirement that there is a real-time assessment of voltage as
well. New Requirement R2 is no longer needed as a result of paragraph 112 in Order 693-A.
Since the RC's "authority to issue directives arises out of the Commission's approval of
Reliability Standards" the RC already has veto authority or will have once R1 IRO-001-2 is
approved. This requirement obligates the RC to take actions or direct actions to prevent
Adverse Reliabilty Impacts. Veto outages of equipment and analysis tools would fall into this
category even if the RC couldn't say for certain that an Adverse Relability Impact was going to
occur but rather they are concerned one could occur due to heavy loads for example.
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a
data specification document and actual verification that data has been received. The letter or
equivalent is only needed if data has not been supplied. Demonstration of the actual receipt the
data would be easy. Requirement 2 is not needed and thus Measure 2 is not needed per
paragraph 112 of Order 693-A. Additional measures are needed to address the proposed
requirements in question 10.
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its
data requirements and requested that data and then follows with that it didn't request that data.
The second option in the Lower VSL category is not practical and a compliance auditor would
not be in a position to determine this. In fact, if the administrative data is not requested, other
administrative requirements for reporting would be violated. Additionally, it does not make
sense that an RC would determine its data needs and then omit data for administrative
reporting. Further, is it the compliance auditor's job to judge if the data the RC requests is
sufficient or is it his job to see that the RC has met the requirement to define the data? The
remaining VSLs imply that the RC may define only partial data requirements. This does not
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seem likely. Why would the RC do this? This VSL appears to add to the requirement by
making it appear that the compliance auditor is to judge the completeness of the data
requirement. This violates Guideline 3 of the FERC ORDER ON VIOLATION SEVERITY
LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION. Practically, it
would not be enforceable anyway. It would require the RC to admit that they did not include
administrative data in the their data requirements. It is doubtful this would happen because the
RC likely believes they prepared a complete data requirement document. We suggest that the
VSLs should be: Severe: The RC did not determine it data requirements or the RC could not
demonstrate it requested the necessary data if actual receipt of the necessary data can't be
deomstrated for greater than 75 to 100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent
RCs. High: The RC could not demonstrate it requested the necessary data if actual receipt of
the necessary data can't be deomstrated for greater than 50 and less than or equal to 75% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Medium: The RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for
greater than 25% and less than or eqal to 50% of the TOPs, BA, TO, GO, GOPs, LSEs and
adjacent RCs. Lower: The RC could not demonstrate it requested the necessary data if actual
receipt of the necessary data can't be deomstrated for greater than 0% and less than or equal to
25% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. R2 VSLs are not needed er
paragraph 112 of Order 693-A. The Severe VSL contradicts the requirement.
No
R1 includes many requirements for monitoring the system that are important, measurable and
should be retained. Monitoring is too critical to operating the system to completely eliminate
these requirements. R4, R8 and R11 are problematic as currently written. However, there have
been actual instances of a large BA intentionally operating short hundreds of MWs of energy. I
believe this occurred during the summer of 1999. Thus, the RC should be monitoring the BAs
ACE and directing the BA to correct it if it becomes too large. It is not necessary or even useful
for the RC to monitor the BA CPS performance.
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum.
Please strike R1.6. RCs already have the authority to act per paragraph 112 of Order 693-A.
Since R2 requires the RCs to agree, is the "mutually agreed to" clause in R1.1 necessary?
Please strike requirements R4 and R4.1. It is duplicative to R1.1. Conference calls are a form
of communication and should be address per R1.1. R5 is confusing. If a reliability issue isn't
confirmed, doesn't this mean there is no reliability issue? Isn't this the point of confirming?
Additionally, we suggest using validate instead of confirm. R6 appears to be a rewrite of
requirements R1, R2 and their sub-requirements in IRO-016. We agree that those requirements
do need to be written more succinctly or removed altogether. However, R6 does not
accomplish the goal and only confuses that matter further. The reason the RCs may not be able
to agree on a mitigation plan is that RC with the reliability issue may be requesting mitigations
that the other RCs believe may cause them reliability issues. This requirement appears to
suggest that the solution to a disagreement on the mitigation plan is cut and dried. Generally,
the reason the disagreement arises is due to one RC not fully understanding the impact of their
actions on another RC. The bottom line is that the RCs may have disagreements and there is no
way to require a solution in these types of situations. Please revise R6 to require using the
mitigation plan developed by the Reliability Coordinator who has the reliability issue provided
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that the mitigation plan does not cause a reliability issue in the other region. As Requirement 1
is currently written, one could interpret the requirement for every Operating Process, Procedure
and Plan to address each of the sub-requirements. That is not necessary. The drafting team
needs to consider modifying the requirement to make it clear that not every sub-requirement
must be addressed in every Operating Process, Procedure, and Plan and to also make it clear
that the some sub-requirements may only be appropriately addressed in a Process but not a Plan
for instance.
No
Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about
System Operators yet the measurement does. The measurement should just be to verify that the
RC has have Operating Processes, Procedures, and Plans. The sub-measurements are not
measurements at all. There should be the single measurement to verify the Operating
Processes, Procedures, and Plans have been developed and address the sub-requirements. This
really points out the problem with making the criteria that must be considered in the Operating
Processes, Procedures, and Plans sub-requirements in the first place. They aren't requirements
of any sort. They represent criteria. The drafting team should consider making them a bulleted
list without the Rs, then the drafting team won't feel compelled to write sub-measures that don't
measure anything. We do not agree with M6 because we don't agree with R6.
No
For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots"
should be removed. We don’t' agree with the VSLs in R4 since we believe R4 should be struck.
The Lower VSL for R6 should not even be a violation unless the impact was negative. If the
RC implemented a different mitigation plan and resolved the issue, then the RC was likely
correct to disagree.
Yes
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the
wording of the requirement. The new wording is much more confusing. Until we reviewed
IRO-016-2, it was not clear at all that R6 in IRO-014 was attempting to mimic R1 and its subrequirements in IRO-016-2.
Group
Southern Company Transmission
Jim Busbin
Southern Company Services, Inc.
No
1.1 - In R1, we suggest that "operationally test by way of operator action" should be defined to
remove any confusion regarding what the term requires. The word "ensure" needs to be
changed to "assure" to more accurately convey the intent of the requirement. We also suggest
changing the word "facilities" to "capabilities". 1.2 - R2 is overly broad and should include a
reasonable time frame for notification. For example, as currently written, a telecom outage of
only one minute for which a notification is not made would be a severe violation. The VSL
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should be consistent with the language of the requirement. A very short, insignificant telecom
outage with no notification could result in a severe violation as the requirement is presently
written and VSL's applied. 1.3 - R1, R2 and R3 should be expanded to include the list of
entities the RC needs to talk with as included in the Applicability section of IRO-001-2 (RC,
TO, BA, GO, DP, TSP, LSE, PSE). These entities should also be included in the purpose
statement and R4 and M4 can then be eliminated. 1.4 - In R3, we suggest that the last sentence
of R3 should be changed to "entities may use an alternative language for internal operations"
rather than allowing only TOs and BAs to have this option.
No
2.1 - A general comment regards the production of evidence - such language should be
standardized as "have and provide upon request" and the authorized requestors identified. This
comment should apply to all standards. 2.2 - M2 is overly broad and should include a
reasonable time frame for notification. For example, as currently written, a telecom outage of
only one minute for which a notification is not made would be a severe violation. 2.3 - The
Drafting Team should coordinate the data retention time frame with the requirement measures
for R1. DPs and GOs should also be included in the measures requirements.
Yes
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included
the VSLs 3.2 - The Severe VSL for R2 should be corrected. Add the word 'to' as follows:
"…and failed to verify the …"
No
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved;
however we suggest the following changes should be made for the interim applicability of
COM-002-3: 4.2 - The Purpose statement should be revised to re-align with the revisions in the
Standard. 4.3 - The applicability of COM-002-3 should be consistent with the applicability of
IRO-001-2. 4.4 - The words "clear, concise, and definitive manner" in R1 are ambiguous and
impossible to measure. We suggest they be replaced with "the RC shall direct". 4.5 - An
additional requirement, R2, should be added that requires the Operator to repeat the
information back correctly (i.e., separate this requirement from R1). 4.6 - Grammatical changes
are suggested. The revised requriement reads as follows: " To ensure Balancing Authorities,
Transmission Operators, and Generator Operators have adequate communications; to ensure
that these communication capabilities are staffed and available for addressing a real-time
emergency condition; and to ensure effective communications by operating personnel." 4.7 - At
the Data Retion section, the reference to 'Requirement 3, Measure 3' should be consistent with
the modified standard. The revised standard only has one requirement. 4.8 - The use of
calendar days in the Data Retention seciton is inconsistent with related standards where
'months' are used.
No
5.1 - The measures need to be revised to match the new requirements.
No
6.1 - The severity levels need to be revised to match the new requirements.
No
7.1 - Applicability 4.2 - Transmission Operator should be plural. 7.2 - The revised definition of
"Adverse Reliability Impacts" (R1) should be included at the top of Standard IRO-001-2, per
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Glossary of Terms Used in Standards: All defined terms used in reliability standards shall be
defined in the glossary. Definitions may be approved as part of a standard action or as a
separate action. All definitions must be approved in accordance with the standards process. 7.3
- In R2 insert the word "its" before Reliability Coordinator. 7.4 - In R3, replace "immediately"
with "without intentional delay", replace "ability" with "intent", replace "or" with "and" and
replace "the" with "its" before Reliability Coordinator.
No
8.1 - In M2 and M3, Add Distribution Provider. 8.2 - In M2 add "intentional" between
"without" and "delay". 8.3 - In M3 replace "ability" with "intent", replace "or" with "and" and
replace "the" with "its" before Reliability Coordinator's and Reliability Coordinator. 8.4 - In
M5, change "has" to "had".
No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he
doesn't - If he fails to act, he fails to direct and mitigate the problem by default. 9.2 - R2 VSLs
need to be rewritten to recognize that some directives may not be followed because of safety,
regulatory or statuatory requirements. 9.3 - Remove the Lower severity level in R3 to conform
to changes in R3 and M3.
No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this
standard retired. If this standard is not retired then we recommend Comments 10.2 and 10.3.
10.2 - At Requirement R2, the RC is given 'veto' authority. Is a standard an appropriate place to
give this type of authority? 10.3 - The revised Purpose basically provides that the RC will have
access to information and control of analysis tools. What is the correlation of
information/control to veto authority/approval of planned maintenance?
No
11.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate measurement
requirements.
No
12.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate VSL requirements.
Yes
13.1 - We agree with retiring this standard.
No
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures,
processes and plans in place with each RC within the RC's Interconnection. We suggest the
phrasing should be tightened up to convey the original meaning that the team intended. For
example, does the team intend for the FRCC RC to have an agreement with the PJM or MISO
RC? 14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as follows:
R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing
a mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the
proper steps to be taken. 14.3 - We suggest deleting R4.1 and adding a second sentence to R4:
The frequency of these communications shall be at least weekly. 14.4 - R4: The word
"impacted" makes it sound like these calls are only to be made when problems are expected or
are occurring. If this requirement is intended more for operational awareness calls (such as the
daily SERC RC call), then the word "impacted" needs to be changed to "contiguous" or a
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similar term. 14.5 - We suggest rewriting R5 to read: In the event that a reliability issue cannot
be confirmed, each Reliability Coordinator shall operate as though the problem exists. 14.6 - At
Requirement R1, the use of the phrase "as a minimum" seems to add some flexibility for
development of procedures, processes and plans. A negative consequence is that it introduces
more abmiguity. The recommendation is to strike the phrase. 14.7 - At Requirement R1.6,
consider the following: "Authority to act to prevent and mitigate instances 'that have the
potential to cause' Adverse Reliability Impacts to other Reliability Coordinator Areas."
No
15.1 - In M1, delete "for Real-time use". 15.2 - Modify the measures to be consistent with
changes requested in R1, R2, R4, R4.1 and R5.
No
16.1 - In R2, severe should be "... and no action was taken by the RC". 16.2 - In R5, severe
should also include "... or that the RC failed to operate as though the problem existed." 16.3 Modify the VSLs to be consistent with changes requested in R1, R2, R4, R4.1 and R5.
Yes
17.1 - We agree with the recommendation to retire IRO-015-2.
Yes
18.1 - We agree with the recommendation to retire IRO-016-2.
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the
COM-001-2 Standard should be effective immediately upon regulatory approval. As written,
the Policy is unenforceable, contains no measures and is not germane to BES Reliability.
Individual
Kathleen Goodman
ISO New England Inc.
No
ISO New England does not support the removal of Requirement 1. Also, we believe
Requirement 3 is written such that it may pose an unnecessary requirement on the Hydro
Quebec area given the terminology "inter-entity" and support further clarification.
No
See answer to #1.
No
ISO New England believes it is inefficient to have a (temporary) Standard with only one
Requirement and recommend including this Requirement in COM-001, with COM-001
renamed to "Communications."
No
See response to Q#4
Yes and No
We beleive the word "threat" shoudl be replaced with "events" in Requirements 4 and 5.
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Yes and No
Suggest changing with word "request" to "document" in Requirement 1.
Yes
Yes and No
As Requirement 1 is currently written, one could interpret the requirement for every Operating
Process, Procedure and Plan to address each of the sub-requirements. That is not necessary.
The drafting team needs to consider modifying the requirement to make it clear that not every
sub-requirement must be addressed in every Operating Process, Procedure, and Plan and to also
make it clear that the some sub-requirements may only be appropriately addressed in a Process
but not a Plan for instance. Use of the term collectively may resolve this dilemma.
Yes
Yes
Individual
Edward Davis
Entergy Services, Inc
Yes
The drafting team should consider expanding the second sentence of R3 to apply to internal
communications of any affected entity not just BAs and TOPs.
Yes
Yes
Yes
Yes
Yes
No
PER-003 R1 does not specifically addresss delegated functions; therefore, this requirement is
not redundant with IRO-001 R6 without changes to PER-003 to specifically deal with
employees perforing delegated functions.
Yes
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No
The VSL for R2 does not seem consistent with the language in the requirement. It is not clear
why the entity should be subject to a high VSL if the entity did not comply with an RC
directive due to safety or regulatory prohibition, and made the RC aware of same.
No
IRO-002-1 R9, the deleted language of the second sentence is not adequately covered by the
language in EOP-008-0 R1, unless those outages are tied to the loss of a control center. EOP008-0 is in the process of being revised and this language could be included in the revision, but
it isn't adequately addressed by the version 0 standard.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Overall, we think the coordinated set of standards being developed by the RTOSDT and
IROLSDT are good for reliability, crisp, and tightens up the reliability concepts.
Individual
Danny Dees
MEAG Power
No
Directives that are mandatory under R2 of IRO-001-2 should have boundaries consistent with
the proper role of an RC. For example, if an RC directs an LSE with a 15% planning reserve
margin to execute purchase power agreements until its reserve margin is at least 20% and the
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LSE refuses, then the LSE may have violated this standard. Other examples of improper RC
directives are directives to increase coal inventories, buy firm fuel transportation rights,
reconductor transmission lines, purchase spare equipment, etc. Granted entities may be able to
conjure up a regulatory or statutory basis for refusing many improper RC directives but in
some instances there may be no permissible grounds to refuse. The appropriate solution is to
modify the standard to ensure that improper directives are never mandatory in the first place.
Specifically, NERC is urged to state that RC directives are mandatory only if they pertain to
specific categories such as: switching orders to reconfigure the BES, orders to postpone
scheduled outages of BES equipment, orders to change generator output, orders to curtail
transactions or orders to curtail load.
No
The M2 measure should not mandate compliance with RC directives that are improper as
defined in my response to question 7.
My other concerns are addressed in the comments of the SERC OC Standards Review Group.
Individual
Mike Gentry
Salt River Project
Yes
No
M3 should include providing evidence of concurrence to use a language other than English.
This will better align the measure with the VSL language.
Yes
Yes
Yes
Yes
Yes
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Yes
No
R1 states the RC must act OR direct. The R1 VSL's attempt to distinguish between act and
direct. The requirement allows for either action. I suggest that the High VSL be removed and
replaced by an N/A. The Severe VSL should be amended so that the words "act and direct" are
replaced by the words "act OR direct" as is consistent with the requirement and the measure.
R2:The moderate VSL introduces the phrase "equipment problems" for the first time in the
Standard. "Equipment Problems" needs to be included in the Requirement, R2, and defined in
the Measure for R2. R5: The Severe VSL needs to be moved to the Moderate category. This
condition does not constitute an Adverse Reliability Impact that severely threatens the BES.
Yes
No
R1: The Requirement and VSL's mention that the RC will determine it's data needs. Yet the
Measure for R1 does not mention this, it only mentions the RC requesting the data from it's
member emtities. This Measure needs to include a measure for how the RC determines it's data
needs.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
I appreciate the new comment form in Word version. his allows me to comment on each
requirement specifically addressing the requirement, measure or the VSL's
Group
SERC OC Standards Review Group
Jim Griffith
Southern Co.
Yes and No
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1.1 - In R1, we suggest that "operationally test" should be defined to remove any confusion
regarding what the term requires. The word "ensure" needs to be changed to "assure" to more
accurately convey the intent of the requirement. We also suggest changing the word "facilities"
to "capabilities". 1.2 - R2 is overly broad and should include a reasonable time frame for
notification. For example, as currently written, a telecom outage of only one minute for which
a notification is not made would be a severe violation. 1.3 - R1, R2 and R3 should be expanded
to include the list of entities the RC needs to talk with as included in the Applicability section
of IRO-001-2 (RC, TO, BA, GO, DP, TSP, LSE, PSE). These entities should also be included
in the purpose statement and R4 and M4 can then be eliminated. 1.4 - In R3, we suggest that
the last sentence of R3 should be changed to "entities may use an alternative language for
internal operations" rather than allowing only TOs and BAs to have this option.
Yes and No
2.1 - A general comment regards the production of evidence - such language should be
standardized as "have and provide upon request" and the authorized requestors identified. This
comment should apply to all standards. 2.2 - M2 is overly broad and should include a
reasonable time frame for notification. For example, as currently written, a telecom outage of
only one minute for which a notification is not made would be a severe violation. 2.3 - The
Drafting Team should coordinate the data retention time frame with the requirement measures
for R1. DPs and GOs should also be included in the measures requirements
Yes and No
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included
the VSLs
Yes and No
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved;
however we suggest the following changes should be made for the interim applicability of
COM-002-3: 4.2 - The Purpose statement should be revised to re-align with the revisions in the
Standard. 4.3 - The applicability of COM-002-3 should be consistent with the applicability of
IRO-001-2. 4.4 - The words "clear, concise, and definitive manner" in R1 are ambiguous and
impossible to measure. We suggest they be replaced with "the RC shall direct". 4.5 - An
additional requirement, R2, should be added that requires the Operator to repeat the
information back correctly (i.e., separate this requirement from R1).
No
5.1 - The measures need to be revised to match the new requirements.
No
6.1 - The severity levels need to be revised to match the new requirements
Yes and No
7.1 - Applicability 4.2 - Transmission Operator should be plural. 7.2 - The revised definition of
"Adverse Reliability Impacts" (R1) should be included at the top of Standard IRO-001-2, per
Glossary of Terms Used in Standards: All defined terms used in reliability standards shall be
defined in the glossary. Definitions may be approved as part of a standard action or as a
separate action. All definitions must be approved in accordance with the standards process. 7.3
- In R2 insert the word "its" before Reliability Coordinator 7.4 - In R3, replace "immediately"
with "without intentional delay", replace "ability" with "intent", replace "or" with "and" and
replace "the" with "its" before Reliability Coordinator.
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Yes and No
8.1 - In M2 and M3, Add Distribution Provider. 8.2 - In M2 add "intentional" between
"without" and "delay". 8.3 - In M3 replace "ability" with "intent", replace "or" with "and" and
replace "the" with "its" before Reliability Coordinator's and Reliability Coordinator. 8.4 - In
M5, change "has" to "had".
Yes and No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he
doesn't - If he fails to act, he fails to direct and mitigate the problem by default. 9.2 - R2 VSLs
need to be rewritten to recognize that some directives may not be followed because of safety,
regulatory or statuatory requirements. 9.3 - Remove the Lower severity level in R3 to conform
to changes in R3 and M3.
Yes and No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this
standard retired.
Yes and No
11.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate measurement
requirements.
Yes and No
12.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate VSL requirements.
Yes
13.1 - We agree with retiring this standard
Yes and No
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures,
processes and plans in place with each RC within the RC's Interconnection. We suggest the
phrasing should be tightened up to convey the original meaning that the team intended. For
example, does the team intend for the FRCC RC to have an agreement with the PJM or MISO
RC? 14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as follows:
R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing
a mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the
proper steps to be taken. 14.3 - We suggest deleting R4.1 and adding a second sentence to R4:
The frequency of these communications shall be at least weekly. 14.4 - R4: The word
"impacted" makes it sound like these calls are only to be made when problems are expected or
are occurring. If this requirement is intended more for operational awareness calls (such as the
daily SERC RC call), then the word "impacted" needs to be changed to "contiguous". 14.5 We suggest rewriting R5 to read: In the event that an operating issue cannot be confirmed, each
Reliability Coordinator shall operate as though the problem exists.
Yes and No
15.1 - In M1, delete "System Operator" and "for real-time use". 15.2 - Modify the measures to
be consistent with changes requested in R1, R2, R4, R4.1 and R5.
Yes and No
16.1 - In R2, severe should be "no action was taken by the RC". 16.2 - In R5, severe should
also include that the RC failed to operate as though the problem existed. 16.3 - Modify the
VSLs to be consistent with changes requested in R1, R2, R4, R4.1 and R5.
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Yes
17.1 - We agree with the recommendation to retire IRO-015-2
Yes
18.1 - We agree with the recommendation to retire IRO-016-2
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the
COM-001-2 Standard should be effective immediately upon regulatory approval. As written,
the Policy is unenforceable, contains no measures and is not germane to BES Reliability
Individual
Jay Seitz
US Bureau of Reclamation
No
Purpose Distribution Providers and Generator Operators were added to the applicability; the
Purpose should be revised to reflect that.
Yes
Yes
No
Purpose Since Generator Operators were deleted from the applicability; the Purpose should be
revised to reflect that and include Reliability Coordinators. The language is somewhat
redundant, recommend it be simplified to “To ensure Balancing Authorities, Reliability
Coordinators, and Transmission Operators communicate in an effective manner.”
Yes
Yes
No
R4. and R5. Both of these Requirements use the phrase “without intentional delay” to describe
the urgency of the notification to impacted entities. In both requirements we recommend the
language be changed from “notify, without intentional delay” to “immediately notify”.
No
M4. and M5. In both Measures, recommend “without intentional delay” be changed as
described above for R4. and R5.
Yes
No
R2. This requirement provides authority to the Reliability Coordinator to veto planned outages
and approve planned maintenance to “analysis tools”. It is not clear in this standard what these
“analysis tools” are. Per FERC Order 693, NERC was to identify a minimum set of analysis
tools and the task was assigned to the Real-Time Tools Best Practices Task Force. Until the
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tools are identified, it is premature to insert a placeholder in a mandatory standard; this also
applies to the violation severity levels table.
No
M2 again "analysis tools" have not been identified.
No
Until the tools are identified, it is premature to insert a placeholder in a mandatory standard;
this also applies to the violation severity levels table.
Yes
Yes
Yes
Yes
Yes
Yes
Group
PJM Interconnection
Patrick Brown
PJM Intercinnection
Yes
We agree with the revisions, but recommend adding applicability to Distribution Providers and
Generator Operators for data retention requirements.
Yes
M4 should be revised to reflect that each Distribution Provider and Generation Operator has
evidence demonstrating the functionality of telecommunications facilities with the TOP and
BA for the exchange of interconnection and operating information.
No
Recommend the following VSLs for R1: Proposed Lower VSL: The Reliability Coordinator,
Balancing Authority or Transmission Operator failed to operationally test alternative
telecommunications every three months on at least one occasion. Proposed Moderate VSL: The
Reliability Coordinator, Balancing Authority or Transmission Operator failed to operationally
test alternative telecommunications every three months on two separate occasions. Proposed
High VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed
to operationally test alternative telecommunications every three months on three separate
occasions. Proposed Severe VSL: The Reliability Coordinator, Balancing Authority or
Transmission Operator failed to operationally test alternative telecommunications every three
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months on more than three separate occasions. Recommend the following VSLs for R2:
Proposed Lower VSL: The Reliability Coordinator, Balancing Authority or Transmission
Operator failed to operationally test alternative telecommunications every three months on at
least one occasion. Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority
or Transmission Operator failed to operationally test alternative telecommunications every
three months on two separate occasions. Proposed High VSL: The Reliability Coordinator,
Balancing Authority or Transmission Operator failed to operationally test alternative
telecommunications every three months on three separate occasions. Proposed Severe VSL:
The Reliability Coordinator, Balancing Authority or Transmission Operator failed to
operationally test alternative telecommunications every three months on more than three
separate occasions. Recommend the following VSLs for R4: Proposed High VSL: The
Responsible Entity failed to establish telecommunications with either their Balancing Authority
or Transmission Operator for the exchange of Interconnection and operating information.
Proposed Severe VSL: The Responsible Entity failed to establish telecommunications with
their Balancing Authority and Transmission Operator for the exchange of Interconnection and
operating information.
Yes
We note that this requirement really is "3-part communication" and will be moved to the new
communications standard, COM-003-1.
Yes
No
The word "clear" is redundantly used in the High and Severe colums. Recommend that
"Moderate" should read: "The Responsible Entity provided a directive in a clear, concise and
definitive manner, but did not require the recipient to repeat the directive back to the
originator." Recommend that "High" should read: "The Responsible Entity failed to issue a
directive in a clear, concise and definitive manner while ensuring the recipient of the directive
repeated the information back correctly with acknowledgment by the originator that the
response was correct." Recommend that "Severe" should read: "The Responsible Entity failed
on more than one occasion to issue a directive in a clear, concise and definitive manner while
ensuring the recipient of the directive repeated the information back correctly with
acknowledgment by the originator that the response was correct."
Yes
Yes
Yes
Yes
Yes
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Group
#2 Standards Interface Subcommittee/Compliance Elements Development Resource Pool
John Blazekovich
Commonwealth Edison Co.
Standard – COM-001-2 Telecommunications Requirement 1: Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall operationally test, on a quarterly basis at
a minimum, alternative telecommunications facilities to ensure the availability of their use
when normal telecommunications facilities fail. Proposed Measure: Each Reliability
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Coordinator, Transmission Operator, and Balancing Authority shall provide evidence that it
operationally tested, on a quarterly basis at a minimum, alternative telecommunications
facilities to ensure the availability of their use when normal telecommunications facilities fail.
Attributes of the requirement Binary Quarterly operational tests of alternate
telecommunications Timing X Omission Communication Quality X Other SDT Proposed
Lower VSL: The Reliability Coordinator, Transmission Operator, or Balancing Authority
failed to operationally test within the last quarter. CEDRP Proposed Lower VSL: The
Reliability Coordinator, Balancing Authority or Transmission Operator performed operational
testing of alternative telecommunications, but did not perform a test in one of the previous four
quarters. SDT Proposed Moderate VSL: The Reliability Coordinator, Transmission Operator,
or Balancing Authority failed to operationally test within the last 2 quarters. CEDRP Proposed
Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
performed operational testing of alternative telecommunications, but did not perform a test in
two of the previous four quarters. SDT Proposed High VSL: The Reliability Coordinator,
Transmission Operator, or Balancing Authority failed to operationally test within the last 3
quarters. CEDRP Proposed High VSL: The Reliability Coordinator, Balancing Authority or
Transmission Operator performed operational testing of alternative telecommunications, but
did not perform a test in three of the previous four quarters. SDT Proposed Severe VSL: The
Reliability Coordinator, Transmission Operator, or Balancing Authority failed to operationally
test within the last 4 quarters. CEDRP Proposed Severe VSL: The Responsible Entity failed to
operationally test alternative telecommunications every quarter on more than three separate
occasions (i.e. more than any three different quarters). FERC Guidance for VSLs 1. Will the
VSL assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? Yes 3. Is it truly a “binary”
requirement? Yes 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? Yes 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does
the requirement or measure need to be revised? Yes 6. Does the VSL redefine or undermine the
stated requirement? No 7. Is the VSL based on a single violation of the requirement (not
multiple violations)? Yes Standard – COM-001-2 Telecommunications Requirement 2: Each
Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted
entities of the failure of its normal telecommunications facilities, and shall verify that alternate
means of telecommunications are functional. Proposed Measure: Each Reliability Coordinator,
Transmission Operator and Balancing Authority shall provide evidence that it notified
impacted entities of failure of their normal telecommunications facilities, and verified the
alternate means of telecommunications were functional. Attributes of the requirement Binary
Timing Notify impacted entities and verify functionality of alternate telecommunications
Omission Communication X Quality Other - Test X Discussion - This requirement needs to be
re-written to be more clearly define who the entities are that are “impacted.” The key attributes
appear to be notification of ALL (communication) impacted entities (possible omission if
some, but not all are not notified). The requirement does not give any guidance on the
“verification” side – this is a problem, one entity can interpret that to mean “we looked and it
was working”, another may be to verify with all impacted entities that alternate communication
is working. We suggest this requirement needs a little more clarification. The CEDRP does not
feel it can write a valid VSL for this requirement as currently worded. SDT Proposed Lower
VSL: The Reliability Coordinator, Transmission Operator or Balancing Authority notified all
impacted entities of the failure of their normal telecommunications facilities, but failed to
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verify the alternate means of telecommunications are functional. CEDRP Proposed Lower
VSL: See Discussion SDT Proposed Moderate VSL: The Reliability Coordinator,
Transmission Operator or Balancing Authority notified some, but not all, impacted entities of
the failure of their normal telecommunications facilities, and failed to verify the alternate
means of telecommunications are functional. CEDRP Proposed Moderate VSL: See Discussion
SDT Proposed High VSL: N/A CEDRP Proposed High VSL: See Discussion SDT Proposed
Severe VSL: The Reliability Coordinator, Transmission Operator or Balancing Authority failed
to notify any impacted entities of the failure of their normal telecommunications facilities, and
failed verify the alternate means of telecommunications are functional. CEDRP Proposed
Severe VSL: See Discussion FERC Guidance for VSLs 1. Will the VSL assignment signal
entities that less compliance than has been historically achieved is condoned? No 2. Is the VSL
assignment a binary requirement? No 3. Is it truly a “binary” requirement? No 4. If yes, is the
VSL assignment consistent with other binary requirement assignments? N/A 5. Is the VSL
language clear & measurable (ambiguity removed)? If no, does the requirement or measure
need to be revised? Yes 6. Does the VSL redefine or undermine the stated requirement? No 7.
Is the VSL based on a single violation of the requirement (not multiple violations)? Yes
Standard – COM-001-2 Telecommunications Requirement 3: Unless agreed to otherwise, each
Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator and
Distribution Provider shall use English as the language for all inter-entity Bulk Electric System
(BES) reliability communications between and among operating personnel responsible for the
real-time generation control and operation of the interconnected BES. Transmission Operators
and Balancing Authorities may use an alternate language for internal operations. Proposed
Measure: The Reliability Coordinator, Transmission Operator or Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or equivalent,
that will be used to determine that personnel used English as the language for all inter-entity
BES reliability communications between and among operating personnel responsible for the
real-time generation control and operation of the interconnected BES. Attributes of the
requirement Binary Use English for real-time communications unless agreed to otherwise.
NOTE: OK with this as is because the requirement and VSLs have been re-written, will be
removed from this standard shortly, and included in the new COM-003-1 standard. Timing
Omission Communication X Quality Other SDT Proposed Lower VSL: N/A CEDRP Proposed
Lower VSL: No change SDT Proposed Moderate VSL: N/A CEDRP Proposed Moderate VSL:
No change SDT Proposed High VSL: N/A CEDRP Proposed High VSL: No change SDT
Proposed Severe VSL: The responsible entity failed to provide evidence of concurrence to use
a language other than English for all communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected Bulk
Electric System. CEDRP Proposed Severe VSL: The Responsible Entity failed to provide
evidence of the concurrence to use a language other than English for all communications
between and among operating personnel responsible for the real-time generation control and
operation of the interconnected Bulk Electric System. FERC Guidance for VSLs 1. Will the
VSL assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? Yes 3. Is it truly a “binary”
requirement? Yes 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? It’s a little inflated as being Severe 5. Is the VSL language clear & measurable
(ambiguity removed)? If no, does the requirement or measure need to be revised? It’s OK for
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the interim 6. Does the VSL redefine or undermine the stated requirement? No 7. Is the VSL
based on a single violation of the requirement (not multiple violations)? Yes Standard – COM001-2 Telecommunications Requirement 4: Each Distribution Provider and Generation
Operator shall have telecommunications facilities with its Transmission Operator and
Balancing Authority for the exchange of Interconnection and operating information. Proposed
Measure: Each Distribution Provider and Generation Operator has telecommunications
facilities with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information. Attributes of the requirement Binary “has”
telecomm with TOP and BA Timing Omission Communication X Quality Other Discussion –
Telecommunication Facilities is ambiguous and is not included in the NERC glossary of terms
– the CEDRP recommend deleting the word “facilities” from the requirement and measure and
leaving it just as “telecommunications” with its TOP and BA . SDT Proposed Lower VSL: N/A
CEDRP Proposed Lower VSL: No change SDT Proposed Moderate VSL: N/A CEDRP
Proposed Moderate VSL: No change SDT Proposed High VSL: N/A CEDRP Proposed High
VSL: The Responsible Entity failed to establish telecommunications with either their
Balancing Authority OR Transmission Operator for the exchange of Interconnection and
operating information. SDT Proposed Severe VSL: The Distribution Provider or Generation
Operator failed to have telecommunications facilities with its Transmission Operator and
Balancing Authority CEDRP Proposed Severe VSL: The Responsible Entity failed to establish
telecommunications with their Balancing Authority AND Transmission Operator for the
exchange of Interconnection and operating information. FERC Guidance for VSLs 1. Will the
VSL assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? Mostly 3. Is it truly a “binary”
requirement? Mostly 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? Yes 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does
the requirement or measure need to be revised? Yes, considering the wording of the
requirement as written. More specifically, the word “have” as used in the requirement is a bit
vague. A better choice could have been, “established and maintains.” 6. Does the VSL redefine
or undermine the stated requirement? No 7. Is the VSL based on a single violation of the
requirement (not multiple violations)? Yes Standard: COM-002-3 Communications and
Coordination Requirement 1: Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and definitive manner; shall
ensure the recipient of the directive repeats the information back correctly; and shall
acknowledge the response as correct or repeat the original statement to resolve any
misunderstandings. Proposed Measure: Each Reliability Coordinator, Transmission Operator,
and Balancing Authority shall have evidence such as voice recordings or transcripts of voice
recordings to show that it issued directives in a clear, concise, and definitive manner; ensured
the recipient of the directive repeated the information back correctly; and acknowledged the
response as correct or repeated the original statement to resolve any misunderstandings.
Attributes of the requirement: Binary Timing Omission Communication X Quality X Other
SDT Proposed Lower VSL: None CEDRP Proposed Lower VSL: No Comment SDT Proposed
Moderate VSL: The responsible entity provided a clear directive in a clear, concise and
definitive manner and required the recipient to repeat the directive, but did not acknowledge
the recipient was correct in the repeated directive. CEDRP Proposed Moderate VSL: No
comment SDT Proposed High VSL: The responsible entity provided a clear directive in a clear,
concise and definitive manner, but did not require the recipient to repeat the directive. CEDRP
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Proposed High VSL: No comment SDT Proposed Severe VSL: The responsible entity failed to
provide a clear directive in a clear, concise and definitive manner when required. CEDRP
Proposed Severe VSL: No comment FERC Guidance for VSLs 1. Will the VSL assignment
signal entities that less compliance than has been historically achieved is condoned? No 2. Is
the VSL assignment a binary requirement? No 3. Is it truly a “binary” requirement? No 4. If
yes, is the VSL assignment consistent with other binary requirement assignments? 5. Is the
VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised? Yes 6. Does the VSL redefine or undermine the stated
requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Yes and No (Severe is for multiple occasions of not issuing directives per the
requirement).
Individual
Timothy C. (TC) Thomas
Progress Energy Carolinas
No
R1- The proposed requirement R1 as stated is too broad in reference to "telecommunications
facilities". It is unclear as to whether it is intending to specify facilities and equipment which
provide VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications
systems, or DATA EXCHANGE links or all of these. Please clarify either within the
requirement or within the Glossary of Terms which accompany the full standards set. R2 - The
proposed requirement R2 as stated is too broad in reference to "telecommunications facilities".
It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or
DATA EXCHANGE links or all of these. Please clarify either within the requirement or within
the Glossary of Terms which accompany the full standards set. R4 - The proposed requirement
R4 as stated is too broad in reference to "telecommunications facilities". It is unclear as to
whether it is intending to specify facilities and equipment which provide VOICE/VERBAL
communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the
Glossary of Terms which accompany the full standards set.
No
M1 - The proposed measure M1 as stated is too broad in reference to "telecommunications
facilities". It is unclear as to whether it is intending to specify facilities and equipment which
provide VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications
systems, or DATA EXCHANGE links or all of these. Please clarify either within the
requirement or within the Glossary of Terms which accompany the full standards set. M2 - The
proposed measure M2 as stated is too broad in reference to "telecommunications facilities". It
is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or
DATA EXCHANGE links or all of these. Please clarify either within the requirement or within
the Glossary of Terms which accompany the full standards set. M4 - The proposed measure
M4 as stated is too broad in reference to "telecommunications facilities". It is unclear as to
whether it is intending to specify facilities and equipment which provide VOICE/VERBAL
communications, or ELECTRONIC MESSAGING notifications systems, or DATA
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EXCHANGE links or all of these. Please clarify either within the requirement or within the
Glossary of Terms which accompany the full standards set.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
No
Purpose - The purpose does not include the GOP and DP entities. It may be better if the
purpose was written more generally as "To ensure adequate and reliable telecommunications
facilities for the exchange of Interconnection and operating information necessary to maintain
BES reliability". R1 - This requirement makes no distinction between data and voice
communications facilities and assumes a designated primary and backup facility configuration
such that the backup communications systems are not used regularly. This may be an accurate
assumption for data communications; however voice communications may be different. Today
many organizations use voice communications systems that allow the system to choose the
communication path each time a call is placed. This design ensures that all communications
paths are tested regularly in day-to-day use. However, the design of these systems makes it
difficult, if not impossible, to substantiate that a functional test of the circuitry has been
performed. This requirement should be broken into two requirements. The first should cover
data circuitry and the second should cover voice circuitry. This will allow the drafting team to
address the inherent differences in these two methods of communications. Lastly, the
requirements need to be much more specific concerning the criticality of the facilities to be
tested to improve the measurability of the standard. The drafting team dropped the phrase "for
the exchange of Interconnection and operating data" from the standard requirement. This
deletion appears to open the application of this standard to virtually every communication path
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used by an RC, BA, TOP whether or not it is used for communicating real-time operating
information or not. We do not believe this was the intention of the drafting team and suggest
this phrase be reinserted or another one added that limits applicability to only those
communication paths that support the real-time reliability of the bulk electric system. R2 - It is
not clear who the "impacted entities" would be in this requirement. The SDT should consider
specifying these entities. R3 - The last sentence of this requirement should be deleted. It is not
a requirement, it does not add clarity, and the first sentence is very specific as to the
communications covered by the requirement. R4 - This requirement makes no distinction
between data and voice communications facilities and assumes a designated primary and
backup facility configuration such that the backup communications systems are not used
regularly. This may be an accurate assumption for data communications; however voice
communications may be different. Today many organizations use voice communications
systems that allow the system to choose the communication path each time a call is placed.
This design ensures that all communications paths are tested regularly in day-to-day use.
However, the design of these systems makes it difficult, if not impossible, to substantiate that a
functional test of the circuitry has been performed. This requirement should be broken into two
requirements. The first should cover data circuitry and the second should cover voice circuitry.
This will allow the drafting team to address the inherent differences in these two methods of
communication.
No
The measures should be modified per our suggested modifications in question 1.
No
The VSL should be modified per our suggested modifications in question 1. R1 VSL - The
statement in the VSL that the responsible entity did not "operationally test" is too broad. It
should be more specific with the language used in the requirement.
No
Purpose - The GOP is still shown in the purpose statement although it was removed from the
applicability. Also, it may be better if the purpose was written more generally as "To ensure
adequate communications capabilities for addressing real-time emergency conditions and
ensure communications by operating personnel are effective to maintain BES reliability".
Applicability - In the SDT's document "Scope of Work Assigned to the Reliability
Coordination Standard Drafting Team", the team decided to not include the FERC directive to
include the DP in the applicability with the following reasoning "The proposed revisions do not
include the DP entity because they are not applicable." We would like clarification on this. R1 It does not appear that the implementation plan addresses the FERC direction to consider
comments from Santa Clara, FirstEnergy, and Six Cities per 693 par. 539 regarding staffing
requirements. Santa Clara asks that these requirements apply "only to operating staff available
on site at all times or includes repair personnel who are available only on an on-call basis".
FirstEnergy asks that the "term [staffed] should not require a physical presence at all facilities
at all times because some units, such as peaking units, are not staffed 24 hours a day".
FirstEnergy also suggest "because nuclear units are already subject to communications
requirements in their operating procedures, their compliance with NRC operating procedures
should be deemed in compliance with the NERC Reliability Standards". Six Cities "states that,
to avoid unnecessary staffing burdens, particularly for smaller entities, the Commission should
direct NERC to clarify COM-002-2 by providing that identification of an emergency contact
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person on call to respond to real-time emergency conditions will constitute adequate
compliance". R1 - Just as an FYI, with regard to the proposed replacement requirement
statement in the implementation plan: "TOP-005-1, R1 and R3 require adequate
telecommunications for BAs and TOPs to provide each other with operating data as well as
providing data to the RC", per recently stakeholder approved ballots, R1 of TOP-005-1 has
been retired and now covered in new standard IRO-010-1. R1.1 - The existing requirement
includes "through predetermined communication paths of any condition that could threaten the
reliability of its area or when firm load shedding is anticipated". The proposed replacement
requirements do not address the need for "predetermined communication paths".
No
The measures should be modified if our comments in question 4 result in changes to the
proposed requirements.
No
The VSL should be modified if our comments in question 4 result in changes to the proposed
requirements.
No
R3 - should be a sub requirement of R2. These two requirements are sequential in nature and
should be measured at the same time. The VRFs and Time Horizons are the same for both
requirements lending to their combination into a requirement with a sub requirement. In the
VSL for R2, an entity is being penalized with a high severity level for not completely following
an RC directive even though it violated safety, equipment, statutory, or regulatory
requirements. Measuring R2 and R3 at the same time allows for the process to complete prior
to the measurement taking place. R3 - The "or" between "Distribution Provider" and
"Purchasing-Selling Entity" should be replaced with an "and". R4 - Should be revised by
adding the phrase "of the expected or actual threat" to the end of the requirement to add clarity.
Existing R7 requirement - This requirement is proposed for retirement because it is redundant
with IRO-014-1 R1. However, it is not clear how the existing requirement to "have clear,
comprehensive coordination agreements with adjacent RCs to ensure that SOL or IROL
violation mitigation requiring actions in adjacent RC areas are coordinated" is covered in IRO014-1 R1. IRO-014-1 R1 requires agreements for coordination of actions between RCs to
support Interconnection reliability, but it does not specifically require "clear" and
"comprehensive" agreements to mitigate SOL or IROL violations. IRO-014-1 only vaguely
covers the existing requirement R7 of IRO-001-1.
No
M2 - The word "intentional" should be added between "without" and "delay".
No
R2 VSL - The Severe VSL should include after the word directive: "that would not violate
safety, equipment, statutory or regulatory requirements".
No
R2 - As written, this requirement does not clearly define the scope of the authority of the
Reliability Coordinator over analysis tools. Is it the intent of the drafting team to give the RC
authority over analysis tools owned and operated by the RC. Is it the intent of the drafting team
to give the RC authority over the analysis tools owned and operated by the BA, TOP, GOP,
etc.? Are the tools intended to be the real-time (EMS) or the off-line engineering planning
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analysis tools or any analysis tool used in real-time. Does this include the analysis tools used
by field personnel? This requirement should be revised to specify exactly the analysis tools
under the authority of the Reliability Coordinator.
No
The measures should be modified per our suggested modifications in question 10.
No
The VSL should be modified per our suggested modifications in question 10.
Yes
No
R1 - Should be revised as follows to improve readability and clarity: R1.3 - Add "Exchanging"
before "Planned" R1.4 - Add "Control of voltage" at the beginning of the requirement and
delete "for voltage control" at the end of the requirement. Add a new R1.7 as follows: "A
process for resolution of the disagreement covered by R6 of this standard."
No
The measures should be modified per our suggested modifications in question 14.
No
The VSL should be modified per our suggested modifications in question 14.
Yes
Yes
Group
Bonneville Power Administration
Denise Koehn
Transmission Reliability Program
Yes
Yes
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Greg Rowland
Duke Energy
No
Purpose - The purpose statement does not read very well. It either needs another sentence or
changes to the current sentence. The purpose of the standard is to assure proper
communications, not to suggest entities need proper communications as currently written.
Suggest changing to, “To assure each Reliability Coordinator, Transmission Operator and
Balancing Authority develops and maintains…. Requirement R1 - What is the definition of
"alternative telecommunications facilities"? Is there another requirement somewhere to have
alternative telecommunications facilities – or is this a new requirement being introduced by this
standard? What is the relationship, if any, between "alternative telecommunications facilities"
and EOP-008-1? What is the requirement for maintaining and testing "alternative
telecommunications facilities"; what does “operationally test” mean? Just because an
alternative facility works when it is tested does not mean it will work during an actual failure of
the primary system. Furthermore, what do we do if the “test” fails- are we still compliant? The
word “ensure” needs to be changed to “assure”. Requirement R2 - What does "impacted entity"
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mean? Requirement R3 - Why can’t others use alternate language – this limits alternate
language to just TOPs and BAs internal operations. TOs, GOPs, and others may want to use
alternate language internally. Need to define language to be used with and between other
relationships – BA to PSE, as an example. Is this a reliability issue or a certification issue?
Simply state that: “Entities may use alternative language for internal operations”. This will
allow any entity to use alternative language for internal operations. The inclusion of TSPs,
LSEs, and PSEs in IRO-001-2 indicates the need to include these functions in the COM-001-2
applicability and requirements concerning the use of English as the approved language.
Requirement R4 - Remove R4 and add DP and GO, as well as all of the other entities listed in
IRO-001-2, to R1 thru R3.
No
General comments - Not using consistent language regarding “provide evidence” and “shall
have and provide upon request evidence”. Also need to add corresponding requirement number
after each measure. Measure M1 - Just because an alternate facility works when it is tested
does not mean it will work during an actual failure of the primary system. - what do we do if
the “test” fails- are we complaint? Clarify that the requirement and measure is to “test” not "to
test successfully". We may test and find that something does not work as expected.
No
VSL for Requirement R1 - The VSL for R1 seems to imply that an operational test needs to
have been performed in the last 90 days – this is read in conjunction with the data retention
requirements. Need to clarify in the requirement how “quarter basis” is defined - is it the
calendar quarter, or a rolling 90 days? In addition, the VSLs for Requirement R1 appear to
violate NERC guidlelines, since the Moderate, High and Severe VSLs are based upon
cumulative violations of the Lower VSL.
No
Requirement R1 - As defined by Merriam Webster, the use of the word “ensure” implies
virtual guarantee ; while the use of the
alternative word “assure” implies the removal of doubt and suspense from a person's mind. We
suggest that “assure” is more appropriate than “ensure” in this context in the standards. The use
of words like “clear, concise, and definitive manner” is subject to interpretation. This same
language is used in the VSLs. Depending on the interpretation of this phrase, an entity could be
found to be in a “Severe” violation level. The issuer of the directive should not be subject to
non-compliance if the recipient of the directive refuses to repeat back. Need to add a
requirement, measure, and VSL that clarifies that the recipient of a directive is obliged to
perform their portion of a repeat-back. The inclusion of TSPs, LSEs, and PSEs in IRO-001-2
indicates the need to include these functions in the COM-002-3 requirement concerning repeatbacks. What is a “directive”? The regional compliance processes are having difficulty in
auditing this existing standard due to lack of clarity of what constitutes a directive. "Directive"
should be defined as being associated with real-time operational emergency conditions, and not
ordinary day-to-day communications. Otherwise a VRF of High is not warranted.
No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The
issuer of the directive should not be subject to non-compliance if the recipient of the directive
refuses to repeat back. Need to add a requirement, measure, and VSL that clarifies that the
recipient of a directive is obliged to perform their portion of a repeat-back.
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No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The
issuer of the directive should not be subject to non-compliance if the recipient of the directive
refuses to repeat back. Need to add a requirement, measure, and VSL that clarifies that the
recipient of a directive is obliged to perform their portion of a repeat-back.
No
Requirement R1 - What happens if the RC failed to recognize that such an event was
happening as opposed to failed to take action. Is this intended to cover both scenarios? The
term “Adverse Reliability Impacts” is being changed and is listed in the associated
Implementation Plan. The revision development of this definition needs to go thru Due
Process. The inclusion of TSPs, LSEs, and PSEs here indicates the need to include these
functions in the COM-001-2 requirements concerning the use of English as the approved
language. In addition, this also indicates the need for all of these listed entities to be included in
COM-002-3 requirements concerning repeat-backs. The RC, TOP, and BA should not be
placed in a possible non-complaint state because the counter party refuses a repeat-back AND
these requirements are not applicable to the counter party. Requirement R2 - The language in
the Moderate VSL of R2 recognizes another potential reason for delay in execution of a
directive. Requirement 2 of the Standards needs to be modified to also recognize this potential.
Requirements R2 and R3 - Clarify that entities are obligated to take action and confirm
directives only from their Reliability Coordinators, not from any Reliability Coordinator.
Requirements R2, R3, R4, R5 - Inconsistent use of “timing” words in the standards – "without
intentional delay" and "immediately". Suggest deleting these words due to the difficulty of
determining compliance. Requirement R4 - The term “Adverse Reliability Impacts” is being
changed and is listed in the associated Implementation Plan. The revision of this definition
needs to go through Due Process. Requirement R5 - The VRF should be "Lower" instead of
"High" since the notification is that the threat has been mitigated. Also, the term “Adverse
Reliability Impacts” is being changed and is listed in the associated Implementation Plan. The
revision of this definition needs to go through Due Process.
No
Measures M2, M4 and M5 use the terms "without delay" and "without intentional delay".
Suggest deleting these words due to the difficulty of determining compliance. The term
“Adverse Reliability Impacts” is being changed and is listed in the associated Implementation
Plan. The revision of this definition needs to go through Due Process.
No
The language in R1 of the VSL is not consistent with the requirements and measures in the
standard. The VSL needs to recognize that the RC may EITHER act or give direction to others
to act. The term “Adverse Reliability Impacts” is being changed and is listed in the associated
Implementation Plan. The revision of this definition needs to go through Due Process. The
language in R2 of the VSL places an entity in Moderate or High violation level even if failure
is “allowed” in the standard; i.e. failure to act is due to violation of safety, regulatory, statutory
requirements. The language in R2 of the VSL recognizes another potential reason for delay in
execution of a directive. Requirement R2 of the Standard needs to be modified to also
recognize this potential.
No
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Requirement R1 - This requirement is in the wrong standard – this is a Facilities standard. This
requirement belongs in another standard. Question: Is there a requirement in another standard
that compels the TOPS, BAs, etc to provide the requested data? Requirement R2 - Need to
clarify whose analysis tools (I assume it is the RCs analysis tools, not the analysis tools of
another entity) and planned maintenance to what – is it tools, facilities, transmission,
generation, etc. Depending on the answer above, this requirement is in the wrong standard –
this is a Facilities standard. This requirement belongs in another standard. Question: Where is
the Requirement for the RC to have analysis tools? It appears that the Requirement the RC has
analysis tools have been removed in the revisions to the standard.
No
See response to Question #12 above. If the requirements are moved to another standard, the
measures aren't needed here.
No
R1 VSL - As a general comment, this VSL is unclear and would be difficult to audit. This VSL
uses subjective terms like “material impact” and “minimal impact”. These terms are not used in
the associated requirement or measure and should be removed from the VSL. This VSL uses
terms like “majority, but not all”; “some, but less than a majority” which provides an
opportunity for a subjective review by Compliance as to what a complete listing of data
requirements should be. This term is not used in the Requirements or Measures and should be
removed from the VSL. This VSL introduces a concept, data the RC needs for “ …
administrative purposes, such as data reporting …”. This concept is not included in the
Requirements or Measures portions of the Standard and should be removed from the VSL. This
VSL should be written to simply assess whether the RC has made determination of what its
data needs are and whether those needs have been communicated to the entities in the footprint.
R2 VSL - This VSL clarifies the questions posed above regarding what the RC needs approval
rights over. R2 needs to be modified to include this clarity. This VSL needs to clarify that the
RC approval rights are for the RC's tools, not tools of other entities. The Severe level of this
VSL needs to be re-written along the lines of: The RC does not have approval rights for
planned maintenance or outages to its analysis tools.
Yes
No
R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures,
processes and plans in place with each RC within the RC's Interconnection. We suggest the
phrasing should be tightened up to convey the original meaning that the team intended. For
example, does the team intend for the FRCC RC to have an agreement with the PJM or MISO
RC? We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as follows: R1 The Dispute Resolution process will be followed when the Reliability Coordinator issuing a
mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the
proper steps to be taken. We suggest deleting R4.1 and adding a second sentence to R4: The
frequency of these communications shall be at least weekly. R4: The word "impacted" makes it
sound like these calls are only to be made when problems are expected or are occurring. If this
requirement is intended more for operational awareness calls (such as the daily SERC RC call),
then the word "impacted" needs to be changed to "contiguous". We suggest rewriting R5 to
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read: In the event that an operating issue cannot be confirmed, each Reliability Coordinator
shall operate as though the problem exists.
No
See comment #14 above. Also, Measure M5 is inconsistent with Requirement R5. It should
mirror the requirement. Also, need to add the requirement number at the end of each Measure.
No
See comments #14 and #15 above - VSLs need to be revised to correspond to the revised
Requirements and Measures.
Yes
No
See comment #14 above regarding re-write needed for Requirement R6 of IRO-014-2.
Individual
Thad Ness
AEP
No
A precise definition of telecommunications facilities needs to be established in this standard.
R2 needs to be clarified regarding impacted utilities. FERC Order 693 suggests that this
standard should apply Distribution Providers (DP) along with Generation Operators (GOP).
AEP acknowledges that there needs to be some level of coordination and communication
between DP’s and other function model entities; however, the requirements, as applied to the
DP, for telecommunications with the TOP and BA might not address the current
communication paths adequately. Today, the DP usually does not communicate with the RTO
(performing the BA and/or TOP function), but the DP could either communicate directly or
through a joint action agency to the IOU that may serve as the TO (or maybe the TOP). As this
draft is written the DP’s would be required to have telecommunication facilities with the RTO
in this scenario. There will likely be many exceptions to the rule that the requirements and
measures create when applied to the DP. We ask that the drafting team consider the
applicability, some of the current channels of communications, and options for addressing the
FERC comments without creating telecommunication paths that do not make practical sense.
No
M2 needs to be clarified regarding impacted functions.
Yes
Yes
Yes
Yes
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
Yes and No
Wording in question: R.2/M.2 Each … Load-Serving Entity, or Purchasing-Selling Entity shall
have evidence that it acted without intentional delay to comply with the Reliability
Coordinator's directives. R.3/M.3 Each … Load-Serving Entity, or Purchasing-Selling Entity
shall have evidence that it confirmed its ability to comply with the Reliability Coordinator's
directives. [1] Question: Is this wording absolutely necessary? And then, is it sufficient, if
needed? Comment: First, we would question whether there is a specific need to include this
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wording. Is the IRO-001 Reliability Standard sufficient without it? [2] Question: Is this
wording unambiguous? Comment: The wording seems somewhat vague and ambiguous.
Analysis: The wording appears to establish performance standards ("without intentional delay",
“shall immediately confirm”) and evidentiary requirements (“evidence that it acted” or
“evidence that it confirmed”), but without using pre-existing defined terms, establishing new
defined terms, or defining these terms as used in context. [3] Intentional vs. Unintentional,
Valid Intentional vs. Inappropriate Intentional? How does one differentiate between intentional
and unintentional delay? When is and how much delay is valid or inappropriate? Isn’t some
intentional delay necessary to ensure that the other parts of the requirement being are met, e.g.,
“… unless such actions would violate safety, equipment, or regulatory or statutory
requirements”? Mightn’t some acceptable amount of valid intentional delay be necessary to
insure that any such RC directive and entity action would not in fact violate these safety,
equipment, or regulatory or statutory requirements? [4] What is the timeliness standard? How
are the terms “without delay” and “immediately conform” defined? What standard commercial
measures would apply, e.g., “reasonably efforts” vs. “best efforts?” Are these terms measured
in units of time (seconds or minutes) or in units of performance quality? Does a poorly
considered “immediate” reply meet the standard, while a well considered reply, which is
intentionally delayed, yet still appropriate, fail to meet this standard? Is that the best outcome?
[5] What is this Evidentiary Standard? Is the sought-after “evidence” sufficiently well defined,
e.g., phone logs, computer e-mail, control center computer logs, hand-written operator journals,
etc.? What form of evidence is necessary and sufficient to demonstrate that the entity met this
evidentiary standard? How is failure to meet this uncertain standard measured, judged and
penalized?
Yes and No
[Comments repeated for Measures] Wording in question: R.2/M.2 Each … Load-Serving
Entity, or Purchasing-Selling Entity shall have evidence that it acted without intentional delay
to comply with the Reliability Coordinator's directives. R.3/M.3 Each … Load-Serving Entity,
or Purchasing-Selling Entity shall have evidence that it confirmed its ability to comply with the
Reliability Coordinator's directives. [1] Question: Is this wording absolutely necessary? And
then, is it sufficient, if needed? Comment: First, we would question whether there is a specific
need to include this wording. Is the IRO-001 Reliability Standard sufficient without it? [2]
Question: Is this wording unambiguous? Comment: The wording seems somewhat vague and
ambiguous. Analysis: The wording appears to establish performance standards ("without
intentional delay", “shall immediately confirm”) and evidentiary requirements (“evidence that
it acted” or “evidence that it confirmed”), but without using pre-existing defined terms,
establishing new defined terms, or defining these terms as used in context. [3] Intentional vs.
Unintentional, Valid Intentional vs. Inappropriate Intentional? How does one differentiate
between intentional and unintentional delay? When is and how much delay is valid or
inappropriate? Isn’t some intentional delay necessary to ensure that the other parts of the
requirement being are met, e.g., “… unless such actions would violate safety, equipment, or
regulatory or statutory requirements”? Mightn’t some acceptable amount of valid intentional
delay be necessary to insure that any such RC directive and entity action would not in fact
violate these safety, equipment, or regulatory or statutory requirements? [4] What is the
timeliness standard? How are the terms “without delay” and “immediately conform” defined?
What standard commercial measures would apply, e.g., “reasonably efforts” vs. “best efforts?”
Are these terms measured in units of time (seconds or minutes) or in units of performance
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quality? Does a poorly considered “immediate” reply meet the standard, while a well
considered reply, which is intentionally delayed, yet still appropriate, fail to meet this standard?
Is that the best outcome? [5] What is this Evidentiary Standard? Is the sought-after “evidence”
sufficiently well defined, e.g., phone logs, computer e-mail, control center computer logs,
hand-written operator journals, etc.? What form of evidence is necessary and sufficient to
demonstrate that the entity met this evidentiary standard? How is failure to meet this uncertain
standard measured, judged and penalized?
Yes and No
Agreement uncertain, subject to further clarification of Requirements and Measures
performance standards and definitions (see our comments on Requirements and Measures).
Without clearer definitions, e.g., for "immediate," or any allowance for appropriate intentional
delay, it is not entirely clear that the VSL's comport with the ultimate meaning, intent and
needed wording to be incorporated into the Requirements and Measures. Why would failure to
fully comply, when precluded by conditions specifically allowed in the standard, necessarily be
a problem, so long as the RC received timely notice, however defined?
Individual
Kevin Koloini
Buckeye Power, Inc.
Yes and No
What constitutes "telecommunications facilities"?
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
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abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Individual
Jason Shaver
American Transmission Company
Yes and No
If some language is clarified, we support the revisions. R2 states that "Each TO shall notify
impacted entities of the failure of its normal telecommunications facilities…". If a phone line
goes down and an alternate phone line is used, it is an excessive requirement to notify the
impacted entities when there is no impact upon communication or the BES. The wording
should be clear that notification is only required if an alternate means of communication is
necessary. A defined timeframe for notification should be added to the requirement. It is
possible that the loss of telecommunication facilties can occur without the loss of a control
center. So, the redundancy with EOP-008 to R4 should be clarified.
No
M2 should be changed to reflect the comments noted in Question 1 for R2.
Yes
Based upon revisions to Question 1.
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Yes
Yes and No
As long as the measurement of compliance does not include proving the negative, that no
directives were issued.
No
R1-High VSL-If the directive was followed and there was no threat to the BES, then a lack of
repetition of the directive does not constitute a "high" VSL. Suggest that this be a low or
moderate VSL.
No
R2 refers to "intentional delay". The determination of intent should be left to the VSL portion
of the standard, not the requirement portion.
Yes
If some language is changed, we support the revisions. R2 has language in it that should be
added to M4 to be consistent. In M2, we propose adding language "unless such actions would
violate safety, statutory or regulatory requirements."
No
VSL's for R2 and R3 are not appropriate. In order to assess a situation we may not be able to
immediately inform the RC of our ability to comply with the directive. The high VSL for R2
currently states that if we do not follow the directive because of safety, statutory or regulatory
requirements, it is a high VSL. An entity should not be penalized for not breaking the law.
Abstain.
Abstain.
Abstain.
No
The accountability and monitoring addressed in this Standard is still required. The drafting
team's intent was that the ability to monitor is part of the certification process. However,
certification is to Standards, and if there is not a Standard which addresses this issue, then an
entity cannot certify to it.
Abstain
Abstain
Abstain
Abstain
Abstain
Group
ISO/RTO Council Standards Review Subcommittee
Charles Yeung
SPP
Yes and No
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We suggest that a definition of telecommunications be written by the drafting team because it
is not clear what all telecommunications is intended to be included. Does this requirement
apply to data, voice, rtus, networks, etc? For requirement R2, e suggest that you strike the final
clause: "and shall verify that alternate means of telecommunications are functional." It is
obviated by the requirement to notify impacted parties. The responsible entity is already
implicitly required to verify its alternate means of communication is functional since it is
required to notify its impacted parties of the failure of its normal telecommunications. It can't
notify its impacted parties if the alternate communications means are not funcitonal. The VRF
for new requirement 1 should be lower. It does not fit the definition of a medium VRF. A
medium VRF requires that a violation of the requirement directly affect the state or capability
or the ability to effectively monitor and control. Failure to test does not result in directly
affecting the state or capability or the ability to effectively monitor and control. At a minimum,
a failure of the alternative communication systems and primary communication systems must
occur first. The failure to perform a single test in a given quarter does not mean that primary
and alternative communication systems will fail. Thus, testing is really an administrative issue
and should thus be a lower VRF. In the Data Retention section, Distribution Provider and
Generation Operators should be added. Currently, there are no data retention requirements
listed for them. Suggest modifying the language regarding data retention for compliance
violations to: "… is found in violation of a requirement, it shall keep information related to the
violation until it the Compliance Enforcement Authority finds it compliant."
Yes and No
M3: The evidence to show that concurrence is in place to allow communication using a
language other than English is missing. The Measure as written merely asks for evidence that
communication in a different language has occurred.
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission
established in their "Order on Violation Severity Levels Proposed by the Electric Reliability
Organization". Guideline 4 requires that a VSL should be based on a single violation. The
VSLs as defined accumulate the number of consecutive quarters. This would imply that a
single violation could last more than a year and that the compliance auditor could not
determine sanctions until the entity becomes compliant or year has passed. A single violation
appears to be the failure to test in a single quarter. This requirement is binary in nature in that it
is either met or it isn't. We suggest that only a lower VSL should be defined as: "The RC, TOP,
or BA failed to test the backup telecommunication facilities for a single calendar quarter." The
Lower VSL for R2 is not possible. The act of notifying all impacted entities of the failure of
their primary telecommunication system requires the use of the alternative telecommunications
systems which is a form of verying that the alternative telecommunications facilities are
functional. The drafting team should consider applying the numeric performance category of
the VSL Development Guideline Criteria for R2. (i) R1: Suggest to revise the conditions for all
levels to read "…failed to operationally test the altarnative communication facilities within the
last……… (ii) R2: The second part under Severe is not needed since failing to notify any
impacted entities would imply no communication to the affected entities anyway. If
verification of the functionality of the alternate means of telecommunications is also critical
even without communicating to the affecte entities, then the second condition should be an
"OR". (iii) R3: Failure to having concurrence to use a language other than English for
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communications between and among operating personnel responsible for real-time operations
by itself does not consitute a violate of any requirements; it is the absence of such a
concurrence AND having used a language other than English that would consitute a violation.
Suggest to revise this condition.
Yes
Yes
Yes
Yes and No
New requirement R2 should omit act without intentional delay. Use of intentional implies
willful disregard for compliance for the requirement. Intention should not be addressed as part
of the compliance with the requirement but rather through the enforcement process once the
compliance auditor has identified a violation. The word immediately should be removed from
the new R3. This attempts to time frame the response of the responsible entity and remove the
judgment from the compliance auditor. We agree with the concept of doing this but in reality it
only confuses the issue and the compliance auditor will likely apply his judgment regarding
what immediate is anyway. Additionallly, the requirement attempts to separate the act of
confirming that the responsible entity can take the action from notifying the RC that the entity
can't take the action. This is not logical. What RC is going to request a responsible entity to
take action that would violate safety, equipment, statutory, or regulatory requirements? The RC
should already be aware of those requirements and likely won't direct actions that violate them.
Thus, the likely scenario is that the responsible entity will attempt to take action and discover
that equipment is not funcitoning properly and thus notify the RC. We suggest striking the
"shall immediately confirm the ability to comply with the directive or" from the requirement.
This part of the requirement is not needed because the responsible entity is already obligated to
follow the RCs directive (see order 693.) Thus, the assumption is that the order will be
followed unless it can't be followed because it will violate safety, equipment, statutory, or
regulatory requirements. Requirements R4 and R5 are unnecessary. New R1 requires the RC to
direct actions to be taken by the TOP, BA, GOP, TSP, LSE, DP and PSE to prevent or mitigate
the magnitude or duration of events that result in Adverst Reliability Impacts. The RC can't
direct these actions without notifying all impacted TOPs and BAs. They would also have to
notify them when actions are no longer necessary. The VRF for R5 should not be High. Failure
to notify others when potential threats to system reliability have been mitigated does not
consititue a high risk to the interconnected system. We suggest it be reduced to a Medium (i.e.,
that it affects control of the BES).
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in
Severe. From a practical perspective, what is the difference between directing actions and
acting? We don't believe there is any. The actions are the result of the RC authority whether the
RC takes the actions themselves or directs someone else to. We suggest a better alternative for
the VSL levels would be for the High level to reflect that the RC did not act or direct actions to
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prevent an Adverse Reliability Impact and Severe would be that the RC did not act or direct
ations to mitigate the magnitude or duration of an existing Adverse Reliability Impact. The
moderate VSL for R2 is not practical and too subjective. What constitutes a delay? What if the
responsible entity takes five minutes to determine how to carry out the action or if their
equipment currently is capable of carrying out the action? Is this a delay? We suggest striking
this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory,
or regulatory requirements a violation. This is in direct conflict with the requirement. We
suggest that the High VSL should be struck. We suggest the Severe VSL should be that the
responsible entity failed to follow the RC directive and it would not have violated the safety,
equipment, statutory or regulatory requirements. Currently, the Severe category does not allow
that the responsible entity may not be able to carry out the directive due to the violation of
safety, equipment, statutory, or regulatory requirements. In question 7, we request that the
drafting team strike part of requirement 3. The striking of that portion of requirement 3
obviates the lower VSL. In paragraph 27 of the ORDER ON VIOLATION SEVERITY
LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION, the
Commission expresses "that, as a general rule, gradated Violation Severity Levels, whereever
possible, would be preferable to binary Violation Severity Levels". Given that it is possible to
define gradated VSLs for R4 and R5, we suggest that the drafting team should consider
applying the numeric performance category of the Violation Severity Levels Development
Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
No
New Requirement R2 is no longer needed as a result of paragraph 112 in Order 693-A. Since
the RC's "authority to issue directives arises out of the Commission's approval of Reliability
Standards" the RC already has veto authority or will have once R1 IRO-001-2 is approved.
This requirement obligates the RC to take actions or direct actions to prevent Adverse
Reliabilty Impacts. Veto outages of equipment and analysis tools would fall into this category
even if the RC couldn't say for certain that an Adverse Relability Impact was going to occur but
rather they are concerned one could occur due to heavy loads for example.
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a
data specification document and actual verification that data has been received. The letter or
equivalent is only needed if data has not been supplied. Demonstration of the actual receipt the
data would be easy.
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its
data requirements and requested that data and then follows with that it didn't request that data.
The second option in the Lower VSL category is not practical and a compliance auditor would
not be in a position to determine this. In fact, if the administrative data is not requested, other
administrative requirements for reporting would be violated. Additionally, it does not make
sense that an RC would determine its data needs and then omit data for administrative
reporting. Further, is it the compliance auditor's job to judge if the data the RC requests is
sufficient or is it his job to see that the RC has met the requirement to define the data? The
remaining VSLs imply that the RC may define only partial data requirements. This does not
seem likely. Why would the RC do this? This VSL appears to add to the requirement by
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making it appear that the compliance auditor is to judge the completeness of the data
requirement. This violates Guideline 3 of the FERC ORDER ON VIOLATION SEVERITY
LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION. Practically, it
would not be enforceable anyway. It would require the RC to admit that they did not include
administrative data in the their data requirements. It is doubtful this would happen because the
RC likely believes they prepared a complete data requirement document. We suggest that the
VSLs should be: Severe: The RC did not determine it data requirements or the RC could not
demonstrate it requested the necessary data if actual receipt of the necessary data can't be
deomstrated for greater than 75 to 100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent
RCs. High: The RC could not demonstrate it requested the necessary data if actual receipt of
the necessary data can't be deomstrated for greater than 50 and less than or equal to 75% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Medium: The RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for
greater than 25% and less than or eqal to 50% of the TOPs, BA, TO, GO, GOPs, LSEs and
adjacent RCs. Lower: The RC could not demonstrate it requested the necessary data if actual
receipt of the necessary data can't be deomstrated for greater than 0% and less than or equal to
25% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. R2 VSLs are not needed er
paragraph 112 of Order 693-A. The Severe VSL contradicts the requirement.
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum.
Please strike R1.6. RCs already have the authority to act per paragraph 112 of Order 693-A.
Since R2 requires the RCs to agree, is the "mutually agreed to" clause in R1.1 necessary?
Please strike requirements R4 and R4.1. It is duplicative to R1.1. Conference calls are a form
of communication and should be address per R1.1. R5 is confusing. If a reliability issue isn't
confirmed, doesn't this mean there is no reliability issue? Isn't this the point of confirming?
Additionally, we suggest using validate instead of confirm. As Requirement 1 is currently
written, one could interpret the requirement for every Operating Process, Procedure and Plan to
address each of the sub-requirements. That is not necessary. The drafting team needs to
consider modifying the requirement to make it clear that not every sub-requirement must be
addressed in every Operating Process, Procedure, and Plan and to also make it clear that the
some sub-requirements may only be appropriately addressed in a Process but not a Plan for
instance. Use of the term collectively may resolve this dilemma.
No
Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about
System Operators yet the measurement does. The measurement should just be to verify that the
RC has have Operating Processes, Procedures, and Plans. The sub-measurements are not
measurements at all. There should be the single measurement to verify the Operating
Processes, Procedures, and Plans have been developed and address the sub-requirements. This
really points out the problem with making the criteria that must be considered in the Operating
Processes, Procedures, and Plans sub-requirements in the first place. They aren't requirements
of any sort. They represent criteria. The drafting team should consider making them a bulleted
list without the Rs, then the drafting team won't feel compelled to write sub-measures that don't
measure anything.
No
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For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots"
should be removed. We don’t' agree with the VSLs in R4 since we believe R4 should be struck.
The Lower VSL for R6 should not even be a violation unless the impact was negative. If the
RC implemented a different mitigation plan and resolved the issue, then the RC was likely
correct to disagree.
Yes
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the
wording of the requirement. The new wording is much more confusing. Until we reviewed
IRO-016-2, it was not clear at all that R6 in IRO-014 was attempting to mimic R1 and its subrequirements in IRO-016-2.
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Individual or group. (29 Responses)
Name (17 Responses)
Organization (17 Responses)
Group Name (12 Responses)
Lead Contact (12 Responses)
Contact Organization (12 Responses)
Question 1 (25 Responses)
Question 1 Comments (29 Responses)
Question 2 (25 Responses)
Question 2 Comments (29 Responses)
Question 3 (21 Responses)
Question 3 Comments (29 Responses)
Question 4 (22 Responses)
Question 4 Comments (29 Responses)
Question 5 (21 Responses)
Question 5 Comments (29 Responses)
Question 6 (20 Responses)
Question 6 Comments (29 Responses)
Question 7 (23 Responses)
Question 7 Comments (29 Responses)
Question 8 (21 Responses)
Question 8 Comments (29 Responses)
Question 9 (21 Responses)
Question 9 Comments (29 Responses)
Question 10 (20 Responses)
Question 10 Comments (29 Responses)
Question 11 (19 Responses)
Question 11 Comments (29 Responses)
Question 12 (19 Responses)
Question 12 Comments (29 Responses)
Question 13 (21 Responses)
Question 13 Comments (29 Responses)
Question 14 (20 Responses)
Question 14 Comments (29 Responses)
Question 15 (19 Responses)
Question 15 Comments (29 Responses)
Question 16 (19 Responses)
Question 16 Comments (29 Responses)
Question 17 (20 Responses)
Question 17 Comments (29 Responses)
Question 18 (20 Responses)
Question 18 Comments (29 Responses)
Question 19 (29 Responses)
Individual
Kris Manchur
Manitoba Hydro
Yes
Yes
Yes
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Yes
Yes
Yes
No
I do not agree with the way IRO-001-2 R1 is written. In the present form the requirement may infer that directing
action is not an action. It may also infer that the RC is only required to do '"act "or "direct actions" but not both. The
way it is written also leads to problems with the VSLs. Perhaps R1 can be edited along the lines of: R1. The
Reliability Coordinator shall act to prevent or mitigate the magnitude or duration of events that result in Adverse
Reliability Impacts. When required, the actions initiated by the Reliability Coordinator will inlude, but is not limited
to, directing the actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators,
Transmission Service Providers, Load-Serving Entities, Distribution Providers and Purchasing-Selling Entities
within its Reliability Coordinator Area. I agree with the other Requirements in IRO-001-2 with the exception of the
"High" Violation Risk Factor assigned to IRO-001-2 requirement R5. This should be a "Medium" VRF at the most. If
the emergency has been mitigated, and the entities are not aware, they will still be operating to restrictions which
means the grid is operating well within limits. Not notifying the entities that the problem has been mitigated may
have some financial implications but it should not place the grid at risk.
Yes
No
IRO-001-2 R1 VSLs: You can not split "shall act" and "or direct actions" into separate VSLs. They are one and
same. If the RC directs action then they have acted. If the RC failed to direct action or have failed to other wise act
then they have failed to act appropriately. Perhaps the VSLs can be drafted along the lines of the following: IRO001-2 R1 High VSL… The Reliability Coordinator's action was incomplete in that it failed to demonstrate a specific
action to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts. IRO-001-2 R1 Severe VSL…
The Reliability Coordinator failed to act to prevent or mitigate the magnitude or duration of Adverse Reliability
Impacts. IRO-001-2 R2 VSLs: (1) Entities may be justified in an intentional delay in respnding to an RC directive. A
justified intential delay may due be equipment problems, a generators ramp rate or system voltage adjustments
prior to large system reconfiguration or large transmission loading changes. (2) An entity cannot be faulted for not
following an RC directive because to it would violate safety, equipment, regulatory or statutory requirements.
Perhaps the VSLs can be drafted along the lines of the following: Moderate VSL… should be deleted. High VSL…
The responsible enity followed the Reliability Coordinators directive but with an unjustified delay. Severe VSL… no
edits required. IRO-001-2 R5 VSLs: Perhaps the VSLs can be drafted along the lines of the following to reflect to
what degree the RC missed the mark: Lower VSL…The Reliability Coordinator failed to notify <25% of its impacted
Transmission Operators and Balancing Authorities when the transmission system problem had been mitigated.
Moderate VSL… The Reliability Coordinator failed to notify >24% but <50% of its impacted Transmission Operators
and Balancing Authorities when the transmission system problem had been mitigated. High VSL…The Reliability
Coordinator failed to notify >49% but <75% of its impacted Transmission Operators and Balancing Authorities
when the transmission system problem had been mitigated. Severe VSL… The Reliability Coordinator failed to
notify >74% of its impacted Transmission Operators and Balancing Authorities when the transmission system
problem had been mitigated.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
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Yes
Group
NPCC
Guy Zito
NPCC
No
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between entities (RC, TOP,
BA, GOP, DP) to use a language other than English in their communications. In M3, that option is not presented.
M3 should reflect what is written in R3.
No
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between entities (RC, TOP,
BA, GOP, DP) to use a language other than English in their communications. In M3, that option is not presented.
M3 should reflect what is written in R3.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Jeffrey V Hackman
Ameren
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes and No
While we agree that most of the requirements are redundancies that properly belong elsewhere, we are concerned
that Requirement 4 and Requirement 8 are not properly represented elsewhere and should not be retired until they
re-surface in another standard explicitly. We believe it is still very important for an RC to monitor their respective
BAs reserves and CPS performance. Likewise in R8, while the frequency monitoring is a BA function, we think that
it is important enough to also be included as an RC function explictly.
Yes
Yes
Yes
Yes
Yes
Individual
Dan Rochester
Independent Electricity System Operator - Ontario
Yes
No
M3: The evidence to show that concurrence is in place to allow communication using a language other than
English is missing. The Measure as written merely asks for evidence that communication in a different language
has occurred.
No
(i) R1: Suggest to revise the conditions for all levels to read "…failed to operationally test the altarnative
communication facilities within the last……… (ii) R2: The second part under Severe is not needed since failing to
notify any impacted entities would imply no communication to the affected entities anyway. If verification of the
functionality of the alternate means of telecommunications is also critical even without communicating to the affecte
entities, then the second condition should be an "OR". (iii) R3: Failure to having concurrence to use a language
other than English for communications between and among operating personnel responsible for real-time
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operations by itself does not consitute a violate of any requirements; it is the absence of such a concurrence AND
having used a language other than English that would consitute a violation. Suggest to revise this condition.
Yes
Yes
Yes
No
(i) R2: the phrase "act without intentional delay" is not necessary since the urgency of taking any actions as
directed by the RC's are generally understood to be conveyed in the RC's directives. (ii) R3: Given R2 requires the
responsible entities to comply with the RC directives, the part that says "immediately confirm the ability to comply
with the directive or" is not needed. R3 should simply require the responsible entities to notify the RC upon
recognition of the inability to perform the directive. (iii) The VRF for R5 should not be High. Failure to notify others
when potential threats to system reliability have been mitigated does not consititue a high risk to the interconnected
system. We suggest it be reduced to a Medium (i.e., that it affects control of the BES).
No
Wording in some of the Measures needs to be revised to reflect changes to R2 and/or R3, if our proposed changes
are accepted. Also, we suggest the Requirement numbers be referenced in the Measures.
No
(i) R1: There should not be any distinction made between an RC acting and an RC directing others to act. Failure
to mitigate adverse reliability impacts a severe violation of the requirement. We therefore suggest to revise the High
and Severe levels as: High if the RC did not act or direct actions to prevent an Adverse Reliability Impact; Severe if
the RC did not act or direct ations to mitigate the magnitude or duration of an existing Adverse Reliability Impact.
(ii) R2: The High VSL seems contradictory to the requirement, which already has provision of not fully complying
with the RC directives due to safety, equipment, or regulatory or statutory requirements. (iii) R3: We have proposed
some wording change to R3, which if adopted, would precipitate a need to revise the VSLs for R3 accordingly. (iv)
R4 and R5: The VSLs for these two requirements could be graded by assessing the number and/or timing of
notifying the affected entities.
No
(i) R1: There is a duplicating requirement in TOP-005 R1.1. Suggest to eliminate one of the two. (ii) We do not
agree with eliminating all of R5 to R8. There is a fundamental need for RCs to monitor its area, and even some
portion of its adjacent areas to be aware of situations that require preventive and mitigating actions. While
arguments can be made that requiring RCs to prevent and mitigate adverse reliability impacts would imply
monitoring, the latter is a fundamental duty of any RCs to ensure system reliability. If monitoring is not explicitly
stated as a requirement, then the same argument may be extended to training and operational facilities. We do not
agree with the drafting team's conclusion that it is not practical to measure real-time monitoring. Measuring can be
illustrated, for example, by a compliance audit to review system logs and assess the extent to which an RC follows
and assesses system conditions.
No
(i) M1: We suggest to change the word "letter" to "documented request" (ii) If our recommendations to retain some
of R5 to R9, some measures will need to be provided.
No
(i) R1: The wording for Low VSL is contradictory (e.g. it determined and requested in the first part but did not
request in the second part). Suggest to revise it. (ii) R1: We suggest to grade the VSLs according to the extent to
which the percentage of data specification and/or the number of entities not requested. (iii) R2: The RC either has
the right or it doesn't, and hence it's a binary requirement. The VSL should be developed accordingly. Further, the
wording for the Severe VSL does not correspond to the requirement and measure. The condition should simply be
that the Reliability Coordinator failed to demonstrate that it had the authority to veto planned outages to analysis
tools, including final approvals for planned maintenance.
No
(i) R1: We not not agree with removing this requirement for the same reason given for the proposal to remove R5
to R8 from IRO-002 (see comments on 10 (ii), above). (ii) R8: We do not agree with completely removing this
requirement, especially that part that requires an RC to monitor system frequency. While DCS and CPS are largely
a BA's responsibility, the RC is the last line of defence for abnormal system performance and needs to monitor its
BAs' performance including their ability to address large frequency deviations, and direct or take corrective actions
as needed including requesting emergency assistance on the BAs' behalf and directing load shedding. (iii) R9: The
second part of this requirement needs to be retained. IRO-004 covers operational planning, not current day
operations. Coordinating pending generator and transmission facility outages is an essential and necessary task by
the RC to ensure reliabiity. (iv) R11: The RC needs to monitor ACE, detect and identify the cause of any abnormal
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ACE, and direct its BAs to take necessary actions to return ACE to within a normal range. (v) R13: We do not
agree with removing the latter part of R13. The FAC standards cover the methodlology used in calculating SOLs
and IROLs. Regardless of how these limits are calculated, in practice there always exists the possibility that
different entities come up with SOLs/IROLs, especially of the inter-ties, that could be different. Operating to the
lowest SOLs/IROLs when more than one set exists is a necessary requirement for reliable operation.
No
We suggest to replace the word "impacted" with"other" since there is a preconception that the concered RC makes
an assessment of which other RCs are impacted by the coordinatred actions, which may not be the perspective of
the other RCs who may in fact be impacted by any coordinated actions among other RCs.
No
Measure 1 actually contains a number of subrequirements that should be stipulated in R1, not M1. If indeed these
are required, they should be stipulated in the Requirement section, not the Measures Section.
No
(i) R2: the High and Severe VSLs contradict with the requirement. We believe all of the "nots" should be removed.
(ii) R6: The Low VSL should be a High since not agreeing to a plan but implementing one that has not been agreed
to is a high violation of the requirement. (iii) The VSLs for R1 may need to be revised if our comments on M1 are
adopted.
Yes
Yes
Group
Reliability Coordinator Comment Working Group
Linda Perez
WECC
Yes
No
on Measure 3 need to remove the word "all" in reference to voice logs. Measure needs to include evidence of
concurrance for using a language other than English
Yes
Yes
Yes
Yes
Yes
No
measures do not align with VSL's (see question 9)
No
R1 talks about "ahall act or direct actions to be taken". High VSL - failure to act. Severe VSL - failure to act and
direct. Does "act" mean any action taken short of issuing a directive? Change Severe VSL to failure to act or direct
and eliminate the High VSL all together. R2 delay in issuing a directive due to equipmnet problems should be
included in the moderate VSL and the body of the requirement and in the measure. The High VSL should be
removed because not following the directive for equipment failure is allowed per R2. R5 - Severe VSL should be
changed to moderate VSL since the problem has been mitigated and the system is stable and it does not adversely
impact reliability. M3 talks about the ability of reliability entities to meet a directive. What constitutes evidence that
confirms you are able to immeidately comply with the directive? If the entity agrees to the directive and then is
unable to comply due to events outside of their control, such as a CT not starting, do they meet the measure? If the
entity, based on the circumstances at the time of the directive, agrees to comply in good faith are they compliant?
The Lower VSL should be made N/A because it is not practical for an entity to immediately confirm they are able to
meet the directive in all cases.
No
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for R1, this should be 2 separate requirments and measures. R1 should have a methodology for determining what
data is needed and then a R2 should be a requirement to request this data from the reliability entities.
Yes
add measures for R1 & R2 see question 10
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Fred Young
Northern California Power Agency
No
R3 should include in the last sentence that the Generator Operator and Distribution Provider may use alternate
language for internal operations.
No
M3 should include Generator Operator and Distribution Provider in the applicability.
Yes
Yes and No
Remove Generator Operator from the Purpose Statement. The re-written statndard no longer applies to GOP.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
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Yes
Yes
Yes
Individual
Denise Roeder
ElectriCities of North Carolina, Inc.
No
We are a joint action agency registered on behalf of our member municipalities, who are all TDUs, neither own nor
operate any Bulk Electric System facilities, and perform no real-time operations or operations planning for the BES.
There are currently other standards that already apply to us that require us to have processes and means to
communicate with our RC, BA, TOP, etc. The proposed modifications to this standard would now make our
members subject to this standard as well, based on the DP registration designation. Given that, we believe there
needs to be additional clarification of specifically what type of "telecommunications facilities" are required to be
considered compliant with this standard. Maybe in the past when this standard applied to TOPs, BAs, and RCs, it
was intuitive what type of telecommunications facilities they needed to communicate with each other. However,
when you bring in small DPs, it doesn't seem so clear. Obviously we already communicate with our TOP and BA,
and have done so for years. As written, the standard is ambiguous in terms of what more, if anything, we would
have to put in place to satisfy this standard.
No
See comments on Question 1
No
Depends of what is meant by "telecommunications facilities"
Individual
Karl Bryan
US Army Corps of Engineers, Northwestern Division
No
R3 needs to have the last sentence revised to allow the Generator Operator and Distribution Provider to use an
alternate language for internal operations.
No
M3 needs to include the GO and DP in its requirement for interutility communications in English.
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Yes
Group
PPL Supply Group
Annette Bannon
PPL Generation, LLC
Yes
Yes
Yes
PPL agrees with the changes to COM-002-3. However, for clarity PPL suggests that Generator Operator should be
removed from the purpose statement of this standard.
Group
Standards Interface Subcommittee/Compliance Elements Drafting
John Blazekovich
Commonwealth Edison Co.
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Standard – IRO-001 R1 Requirement (including sub-requirements) The Reliability Coordinator shall act or direct
actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, Distribution Providers and Purchasing-Selling Entities within its Reliability
Coordinator Area to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability
Impacts. [Violation Risk Factor: High] [Time Horizon: Real-time Operations and Same Day Operations] Proposed
Measure Each Reliability Coordinator shall have evidence that it acted, or issued directives, to prevent or mitigate
the magnitude or duration of Adverse Reliability Impacts within its Reliability Coordinator Area Attributes of the
requirement Binary Timing X Omission X Communication X Quality Other Discussion – 1. As currently worded it
can be interpreted that any time an event occurs the RC would be in violation of the standard simply because they
had failed “to prevent” an event. 2. This requirement does not have a “timing” element included, although it implies
timing based on the “duration of the event”. Including that “duration of the event” is problematic – it appears to
imply that human intervention may provide a more timely response than relay operation, we would suggest more
clarification about what the “duration” element of the requirement is intended to address (e.g. generation redispatch?). 3. There also appears to be a “quality” element included based on the mitigation of magnitude of the
event. As a result we believe that timeliness, effectiveness and communication should be the basis of the VSLs. 4.
The VSLs as differentiate between directing actions and acting. Practically, there is no difference. The RC is still
giving the directive. It is just a matter of who is carrying it out. This is not a valid basis for differentiating between
VSLs. We suggest the VSLs be defined based on actual system impact (i.e. Was the RC acting or directing actions
to prevent or to mitigate?) and to either modify the requirement to remove timing aspects or to add the timing
aspects to the VSLs. SDT Proposed Lower VSL N/A CEDRP Proposed VSL No Comment SDT Proposed
Moderate VSL N/A CEDRP Proposed VSL No Comment SDT Proposed High VSL The Reliability Coordinator
failed to act to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts. CEDRP Proposed VSL
The Reliability Coordinator failed to act to prevent the magnitude or duration of Adverse Reliability Impacts. SDT
Proposed Severe VSL The Reliability Coordinator failed to act and direct actions to prevent or mitigate the
magnitude or duration of Adverse Reliability Impacts CEDRP Proposed VSL The Reliability Coordinator failed to
act and direct actions to mitigate the magnitude or duration of Adverse Reliability Impacts FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically achieved is
condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary” requirement? 4. If yes, is the
VSL assignment consistent with other binary requirement assignments? 5. Is the VSL language clear &
measurable (ambiguity removed)? If no, does the requirement or measure need to be revised? 6. Does the VSL
redefine or undermine the stated requirement? 7. Is the VSL based on a single violation of the requirement (not
multiple violations)? Additional Compliance Elements Compliance Enforcement Authority NERC shall be
responsible for compliance monitoring of the Regional Entity. Regional Entities shall be responsible for compliance
monitoring of the Reliability Coordinators, Transmission Operators, Generator Operators, Distribution Providers,
and Load Serving Entities. Compliance Monitoring Period and Reset Time Frame N/A Compliance Monitoring and
Enforcement Processes: Compliance Audits Self-Certifications Spot Checking Compliance Violation Investigations
Self-Reporting Complaints Data Retention Each applicable entity shall retain data and evidence for a rolling 12
months unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of
time as part of an investigation. The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent compliance records. Additional Compliance Information None CAE Resource
Pool Comments The Enforcement Authority Statement, “NERC shall be responsible for compliance monitoring of
the Regional Entity.” Is not clear, if it is intended to encompass Regional Entities that perform RC functions is
should be clearly stated, if not it should not be included in the Enforcement Authority section. Standard – IRO-001
R2 Requirement (including sub-requirements) Transmission Operators, Balancing Authorities, Generator
Operators, Transmission Service Providers, Load-Serving Entities, Distribution Providers, and Purchasing-Selling
Entities shall act without intentional delay to comply with Reliability Coordinator directives unless such actions
would violate safety, equipment, or regulatory or statutory requirements. [Violation Risk Factor: High] [Time
Horizon: Real-time Operations and Same Day Operations] Proposed Measure Each Transmission Operator,
Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, or PurchasingSelling Entity shall have evidence that it acted without delay to comply with the Reliability Coordinator's directives.
Attributes of the requirement Binary Timing X Omission X Communication X Quality X Other The team would
suggest “intentional delay” be eliminated from the requirement – e.g. “shall act to…”). To act with an intentional
delay represents a willful act to disregard the requirement. Willful disregard of requirements is one of the factors
that the enforcement authority uses to magnify penalties. Requirements should not include attempts to avoid willful
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disregard of the requirement. The measure and VSLs do not consider the exceptions for not following the RC
objective. The drafting team should consider combining requirements R2 and R3. Thus, one VSL would become
failure to notify the RC of the inability to comply. The drafting team could consider applying the numerical category
of VSLs for some directives such as an order to redispatch. Obviously, it would not work well if the directive was to
reconfigure the system. SDT Proposed Lower VSL N/A CEDRP Proposed VSL No Comment SDT Proposed
Moderate VSL The responsible entity followed the Reliability Coordinators directive with a delay not caused by
equipment problems. CEDRP Proposed VSL The team does not agree that this is a valid VSL. SDT Proposed High
VSL The responsible entity followed the majority of the Reliability Coordinators directive but did not fully follow the
directive because it would violate safety, equipment, statutory or regulatory requirements. CEDRP Proposed VSL
The team does not agree that this is a valid VSL. The word majority implies some ability to numerically measure
the response to the directive. Thus, the drafting team should consider applying the numerical category of the VSL
guidelines. SDT Proposed Severe VSL The responsible entity did not follow the Reliability Coordinators directive.
CEDRP Proposed VSL The responsible entity did not follow the Reliability Coordinators directive, the directive
would not have violated safety, equipment, regulatory, or statutory requirements, and responsible entity did not
communicate the inability to follow the directive to the Reliability Coordinator. FERC Guidance for VSLs 1. Will the
VSL assignment signal entities that less compliance than has been historically achieved is condoned? No 2. Is the
VSL assignment a binary requirement? No 3. Is it truly a “binary” requirement? N/A 4. If yes, is the VSL assignment
consistent with other binary requirement assignments? N/A 5. Is the VSL language clear & measurable (ambiguity
removed)? If no, does the requirement or measure need to be revised? Yes 6. Does the VSL redefine or
undermine the stated requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? No Standard - IRO-001 R3 Requirement (including sub-requirements) The Transmission Operator,
Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider
or Purchasing-Selling Entity shall immediately confirm the ability to comply with the directive or inform the
Reliability Coordinator upon recognition of the inability to perform the directive. [Violation Risk Factor: High] [Time
Horizon: Real-time Operations and Same Day Operations] Proposed Measure Each Transmission Operator,
Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, or PurchasingSelling Entity shall have evidence that it confirmed its ability to comply with the Reliability Coordinator's directives,
or if for safety, equipment, regulatory or statutory requirements it could not comply, informed the Reliability
Coordinator upon recognition of the inability to comply. Attributes of the requirement Binary Timing Omission
Communication X Quality Other Discussion – The requirement appears to be based on communication and can be
problematic by including the requirement to immediately confirm the ability to comply, a directive can be issued to
one entity or several entities at one time (e.g. conference call, all call, electronic notification) that may create
several issues when attempting to process all confirmations, the requirement language presents a risk of being
found out of compliance for following a directive but not providing an “immediate” confirmation to the RC. The
CEDRP believes it to be a reasonable expectation that all entities will comply with reliability directives and
notification should be made only on exception. The SDT should consider combining this requirement with R2. SDT
Proposed Lower VSL The responsible entity failed to immediately confirm the ability to comply with the directive
issued by the Reliability Coordinator. CEDRP Proposed VSL See above discussion note SDT Proposed Moderate
VSL N/A CEDRP Proposed VSL No comment SDT Proposed High VSL N/A CEDRP Proposed VSL No comment
SDT Proposed Severe VSL The responsible entity failed to inform the Reliability Coordinator upon recognition of
the inability to perform the directive. CEDRP Proposed VSL No comment FERC Guidance for VSLs 1. Will the VSL
assignment signal entities that less compliance than has been historically achieved is condoned? No 2. Is the VSL
assignment a binary requirement? No 3. Is it truly a “binary” requirement? N/A 4. If yes, is the VSL assignment
consistent with other binary requirement assignments? N/A 5. Is the VSL language clear & measurable (ambiguity
removed)? If no, does the requirement or measure need to be revised? As currently worded the CEDRP believe
that the requirement should be changed to eliminate that “immediate confirmation” portion of the requirement 6.
Does the VSL redefine or undermine the stated requirement? No 7. Is the VSL based on a single violation of the
requirement (not multiple violations)? No Standard - IRO-001 R4 Requirement (including sub-requirements) Each
Reliability Coordinator that identifies an expected or actual threat with Adverse Reliability Impacts within its
Reliability Coordinator Area shall notify, without intentional delay, all impacted Transmission Operators and
Balancing Authorities in its Reliability Coordinator Area. [Violation Risk Factor: High] [Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning] Proposed Measure Each Reliability Coordinator shall
have evidence that it notified, without intentional delay, all impacted Transmission Operators and balancing
Authorities in its Reliability Coordinator Area when it identified a real or potential threat with Adverse Reliability
Impacts, within its Reliability Coordinator Area. Attributes of the requirement Binary Timing X Omission
Communication X Quality Other Discussion – To act with an intentional delay represents a willful act to disregard
the requirement. Willful disregard of requirements is one of the factors that the enforcement authority uses to
magnify penalties. Requirements should not include attempts to avoid willful disregard of the requirement. This
requirement appears to fit the numerical category of the VSL guidelines best. SDT Proposed Lower VSL N/A
CEDRP Proposed VSL The Reliability Coordinator who identified an expected or actual threat with Adverse
Reliability Impacts within its Reliability Coordinator Area failed to notify 25% or less of the Transmission Operators
and Balancing Authorities within its Reliability Coordination Area. SDT Proposed Moderate VSL N/A CEDRP
Proposed VSL The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability
Impacts within its Reliability Coordinator Area failed to notify more than 25% but less than or equal to 50% of the
Transmission Operators and Balancing Authorities within its Reliability Coordination Area. SDT Proposed High VSL
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N/A CEDRP Proposed VSL The Reliability Coordinator who identified an expected or actual threat with Adverse
Reliability Impacts within its Reliability Coordinator Area failed to notify more than 50% but less than or equal to
75% of the Transmission Operators and Balancing Authorities within its Reliability Coordination Area. SDT
Proposed Severe VSL: The Reliability Coordinator who identified an expected or actual threat with Adverse
Reliability Impacts within its Reliability Coordinator Area failed to issue an alert to all impacted Transmission
Operators and Balancing Authorities in its Reliability Coordinator Area. CEDRP Proposed Severe VSL: The
Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts within its
Reliability Coordinator Area failed to notify more than 75% of the Transmission Operators and Balancing
Authorities within its Reliability Coordination Area. FERC Guidance for VSLs 1. Will the VSL assignment signal
entities that less compliance than has been historically achieved is condoned? No 2. Is the VSL assignment a
binary requirement? No 3. Is it truly a “binary” requirement? N/A 4. If yes, is the VSL assignment consistent with
other binary requirement assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no,
does the requirement or measure need to be revised? Yes 6. Does the VSL redefine or undermine the stated
requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple violations)? Yes
Standard - IRO-001 R5 Requirement (including sub-requirements) Each Reliability Coordinator who identifies an
expected or actual threat with Adverse Reliability Impacts, within its Reliability Coordinator Area shall notify, without
intentional delay, all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area
when the transmission problem has been mitigated. [Violation Risk Factor: High] [Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning] Proposed Measure Each Reliability Coordinator shall
have evidence that it notified, without intentional delay, all impacted Transmission Operators and balancing
Authorities in its Reliability Coordinator Area when the real or potential threat with Adverse Reliability Impacts
within its Reliability Coordinator Area has been mitigated. Attributes of the requirement Binary Timing X Omission
Communication X Quality Other Discussion – To act with an intentional delay represents a willful act to disregard
the requirement. Willful disregard of requirements is one of the factors that the enforcement authority uses to
magnify penalties. Requirements should not include attempts to avoid willful disregard of the requirement. Measure
5 is written implying that there is an Adverse Reliability Impact. The drafting team should consider wording the
measurement to consider that there may not be an Adverse Reliability Impact requiring a directive. The
Commission in paragraph 27 of the VSL order has stated that multiple VSLs are preferable where possible.
Suggest applying the numerical category of the VSL Guidelines based on the number of entities notified.. SDT
Proposed Lower VSL: N/A CEDRP Proposed Lower VSL: The Reliability Coordinator who identified an expected or
actual threat with Adverse Reliability Impacts within its Reliability Coordinator Area failed to notify 25% or less of
the impacted Transmission Operators and Balancing Authorities within its Reliability Coordination Area that the
Adverse Reliability Impact had been mitigated. SDT Proposed Moderate VSL: N/A CEDRP Proposed Moderate
VSL: The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts within
its Reliability Coordinator Area failed to notify more than 25% but less than or equal to 50% of the impacted
Transmission Operators and Balancing Authorities within its Reliability Coordination Area that the Adverse
Reliability Impact had been mitigated. SDT Proposed High VSL: N/A CEDRP Proposed High VSL: The Reliability
Coordinator who identified an expected or actual threat with Adverse Reliability Impacts within its Reliability
Coordinator Area failed to notify more than 50% but less than or equal to 75% of the impacted Transmission
Operators and Balancing Authorities within its Reliability Coordination Area that the Adverse Reliability Impact had
been mitigated. SDT Proposed Severe VSL: The Reliability Coordinator failed to notify all impacted Transmission
Operators, Balancing Authorities, when the transmission problem had been mitigated. CEDRP Proposed Severe
VSL: The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts within
its Reliability Coordinator Area failed to notify more than 75% of the impacted Transmission Operators and
Balancing Authorities within its Reliability Coordination Area that the Adverse Reliability Impact had been mitigated.
FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? No 2. Is the VSL assignment a binary requirement? No 3. Is it truly a “binary” requirement?
N/A 4. If yes, is the VSL assignment consistent with other binary requirement assignments? N/A 5. Is the VSL
language clear & measurable (ambiguity removed)? If no, does the requirement or measure need to be revised?
Yes 6. Does the VSL redefine or undermine the stated requirement? No 7. Is the VSL based on a single violation of
the requirement (not multiple violations)? Yes Standard – IRO-002-2 R1 Requirement (including sub-requirements)
Each Reliability Coordinator shall determine the data requirements to support its reliability coordination tasks and
shall request such data from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load- Serving Entities, or adjacent Reliability Coordinators. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] Proposed
Measure Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not
limited to, a letter to Transmission Operators, Balancing Authorities, Transmission Owners, Generator Owners,
Generator Operators, and Load-Serving Entities, or adjacent Reliability Coordinators, or other equivalent evidence
that will be used to confirm that the Reliability Coordinator has requested the data required to support its reliability
coordination tasks. Attributes of the requirement Binary Timing Omission X Communication X Quality Other
Discussion – The VSLs attempt to measure the quality of the data requirements. They require the compliance
auditor to judge if another RC has material impact and what data is administrative and what data is substantial.
Given the typical length of a compliance audit, it is doubtful that the compliance auditor can make these types of
judgments about the quality of the data and the material impact of another RC. The drafting team should consider
applying numerical category of VSLs based on the number of entities the data request is made from. It is
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interesting that the measure also does not require any documentation of a data specification. SDT Proposed Lower
VSL: The Reliability Coordinator demonstrated that it 1) determined its data requirements and requested that data
from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation
Operators, and Load-Serving Entities or Adjacent Reliability Coordinators with a material impact on the Bulk
Electric System in its Reliability Coordination Area but did not request the data from Transmission Operators,
Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving
Entities or Adjacent Reliability Coordinators with minimal impact on the Bulk Electric System in its Reliability
Coordination Area orr 2) determined its data requirements necessary to perform its reliability functions with the
exceptions of data that may be needed for administrative purposes such as data reporting. CEDRP Proposed
Lower VSL: The Reliability Coordinator failed to request data to support its reliability coordination tasks from 25%
or less of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners,
Generation Operators, and Load-Serving Entities, or adjacent Reliability Coordinators. SDT Proposed Moderate
VSL: The Reliability Coordinator demonstrated that it determined the majority but not all of its data requirements
necessary to support its reliability coordination functions and requested that data from its Transmission Operators,
Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving
Entities or Adjacent Reliability Coordinators. CEDRP Proposed Moderate VSL: The Reliability Coordinator failed to
request data to support its reliability coordination tasks from more than 25% but less than or equal to 50% of its
Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators,
and Load-Serving Entities, or adjacent Reliability Coordinators. SDT Proposed High VSL: The Reliability
Coordinator demonstrated that it determined 1) some but less than the majority of its data requirements necessary
to support its reliability coordination functions and requested that data from its Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators Or 2) all of its data requirements necessary to support its reliability coordination
functions but failed to demonstrate that it requested data from two of its Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators. CEDRP Proposed High VSL: The Reliability Coordinator failed to request data to
support its reliability coordination tasks from more than 50% but less than or equal to 75% of its Transmission
Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and LoadServing Entities, or adjacent Reliability Coordinators. SDT Proposed Severe VSL: The Reliability Coordinator failed
to demonstrate that it 1) determined its data requirements necessary to support its reliability coordination functions
and requested that data from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load-Serving Entities or Adjacent Reliability Coordinators Or 2) requested the
data from three or more of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load-Serving Entities or Adjacent Reliability Coordinators. CEDRP Proposed
Severe VSL: The Reliability Coordinator failed to request data to support its reliability coordination tasks from more
than 75% of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners,
Generation Operators, and Load-Serving Entities, or adjacent Reliability Coordinators, Or, The Reliability
Coordinator failed to determine data requirements to support its reliability coordination tasks. FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically achieved is
condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary” requirement? 4. If yes, is the
VSL assignment consistent with other binary requirement assignments? 5. Is the VSL language clear &
measurable (ambiguity removed)? If no, does the requirement or measure need to be revised? 6. Does the VSL
redefine or undermine the stated requirement? 7. Is the VSL based on a single violation of the requirement (not
multiple violations)? Standard – IRO-002-2 R2 Requirement (including sub-requirements) Each Reliability
Coordinator shall have the authority to veto planned outages to analysis tools, including final approvals for planned
maintenance. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and
Operations Planning] Proposed Measure Each Reliability Coordinator shall have and provide upon request
evidence that could include, but is not limited to, a documented procedure or equivalent evidence that will be used
to confirm that the Reliability Coordinator has the authority to veto planned outages to analysis tools, including final
approvals for planned maintenance as specified in Requirement 2. Attributes of the requirement Binary Timing
Omission Communication Quality Other X Is this requirement needed? R1 IRO-001-2 requires the RC to mitigate
Adverse Reliability Impacts. R2 IRO-001-2 requires responsible entities to comply with the RC directives. Wouldn’t
the RC thus have the right to cancel all types of outages (i.e. analysis tools, transmission equipment, etc). FERC
has stated in paragraph 112 of Order 693-A that an RC does not derive their authority from agreements but rather
from FERC’s approval of the standards. Barring the team’s decision to remove this requirement, the Severe VSL is
confusing. We have suggested different wording. SDT Proposed Lower VSL Reliability Coordinator has approval
rights for planned outages of analysis tools but does not have approval rights for maintenance on analysis tools.
CEDRP Proposed VSL No Comment SDT Proposed Moderate VSL N/A CEDRP Proposed VSL No Comment SDT
Proposed High VSL N/A CEDRP Proposed VSL No Comment SDT Proposed Severe VSL Reliability Coordinator
approval is not required for planned maintenance or planned outages. CEDRP Proposed VSL Reliability
Coordinator does not approve planned maintenance or planned outages. FERC Guidance for VSLs 1. Will the VSL
assignment signal entities that less compliance than has been historically achieved is condoned? 2. Is the VSL
assignment a binary requirement? 3. Is it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent
with other binary requirement assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If
no, does the requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated
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requirement? 7. Is the VSL based on a single violation of the requirement (not multiple violations)? Standard – IRO014-2 R1 Requirement (including sub-requirements) R1. The Reliability Coordinator shall have Operating
Procedures, Processes, or Plans for activities that require notification, exchange of information or coordination of
actions with impacted Reliability Coordinators to support Interconnection reliability. These Operating Procedures,
Processes, or Plans shall collectively address, as a minimum, the following: [Violation Risk Factor: Medium] [Time
Horizon: Same Day Operations and Operations Planning] R1.1. Communications and notifications, including the
mutually agreed to conditions under which one Reliability Coordinator notifies other Reliability Coordinators; the
process to follow in making those notifications; and the data and information to be exchanged with other Reliability
Coordinators. R1.2. Energy and capacity shortages. R1.3. Planned or unplanned outage information. R1.4. Voltage
control, including the coordination of reactive resources for voltage control. R1.5. Coordination of information
exchange to support reliability assessments. R1.6. Authority to act to prevent and mitigate instances of causing
Adverse Reliability Impacts to other Reliability Coordinator Areas. Proposed Measure M1. The Reliability
Coordinator’s System Operators shall have available for Real-time use, the latest approved version of Operating
Procedures, Processes, or Plans that require notifications, information exchange or the coordination of actions
among impacted Reliability Coordinators. M1.1 These Operating Procedures, Processes, or Plans shall address:
M1.2 Communications and notifications, including the mutually agreed to conditions under which one Reliability
Coordinator notifies other Reliability Coordinators; the process to follow in making those notifications; and the data
and information to be exchanged with other Reliability Coordinators. M1.3 Energy and capacity shortages. M1.4
Planned or unplanned outage information. M1.5 Voltage control, including the coordination of reactive resources for
voltage control. M1.6 Coordination of information exchange to support reliability assessments. Authority to act to
prevent and mitigate instances of causing Adverse Reliability Impacts to other Reliability Coordinator Areas.
Attributes of the requirement Binary Timing Omission x Communication x Quality Other Discussion – The CEDRP
has no recommendations regarding this requirement. SDT Proposed Lower VSL: The Reliability Coordinator has
Operating Procedures, Processes, or Plans in place for activities that require notification, exchange of information
or coordination of actions with impacted Reliability Coordinators to support Interconnection reliability but failed to
address one or two of the subrequirements. CEDRP Proposed Lower VSL: No Comment SDT Proposed Moderate
VSL: Coordinator has Operating Procedures, Processes, or Plans in place for activities that require notification,
exchange of information or coordination of actions with impacted Reliability Coordinators to support Interconnection
reliability but failed to address three or four of the subrequirements. CEDRP Proposed High VSL: No Comment
SDT Proposed High VSL: The Reliability Coordinator has Operating Procedures, Processes, or Plans in place for
activities that require notification, exchange of information or coordination of actions with impacted Reliability
Coordinators to support Interconnection reliability but failed to address five of the subrequirements. CEDRP
Proposed High VSL: No Comment SDT Proposed Severe VSL: The Reliability Coordinator failed to have Operating
Procedures, Processes, or Plans in place for activities that require notification, exchange of information or
coordination of actions with impacted Reliability Coordinators to support Interconnection reliability. CEDRP
Proposed Severe VSL: No Comment FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less
compliance than has been historically achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is
it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised? 6. Does the VSL redefine or undermine the stated requirement? 7. Is the VSL based
on a single violation of the requirement (not multiple violations)? Standard – IRO-014-2 R2 Requirement (including
sub-requirements) R2. Each Reliability Coordinator’s Operating Procedure, Process, or Plan that requires one or
more other Reliability Coordinators to take action (e.g., make notifications, exchange information, or coordinate
actions) shall be: [Violation Risk Factor: Lower] [Time Horizon: Real-time Operations and Operations Planning]
R2.1. Agreed to by all the Reliability Coordinators required to take the indicated action(s). R2.2. Distributed to all
Reliability Coordinators that are required to take the indicated action(s). Proposed Measure M2. The Reliability
Coordinator shall have evidence that the Operating Procedures, Processes, or Plans that require one or more other
Reliability Coordinators to take action (e.g., make notifications, exchange information, or coordinate actions) were:
M2.1 Agreed to by all the Reliability Coordinators required to take the indicated action(s). M2.2 Distributed to all
Reliability Coordinators that are required to take the indicated action(s). Attributes of the requirement Binary Timing
Omission X Communication X Quality Other Discussion – The High and Severe VSLs appear to use “not”
incorrectly. SDT Proposed Lower VSL N/A CEDRP Proposed VSL No Comment SDT Proposed Moderate VSL:
The Reliability Coordinator failed to have evidence that the Operating Procedures, Processes, or Plans that require
one or more other Reliability Coordinators to take action (e.g., make notifications, exchange information, or
coordinate actions) were distributed to all Reliability Coordinators that are required to take action. CEDRP
Proposed Moderate VSL: The Reliability Coordinator did not have evidence that the Operating Procedures,
Processes, or Plans that require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were distributed to all Reliability Coordinators that are required to take
action. SDT Proposed High VSL: The Reliability Coordinator failed to have evidence that the Operating
Procedures, Processes, or Plans that require one or more other Reliability Coordinators to take action (e.g., make
notifications, exchange information, or coordinate actions) were not agreed to by all Reliability Coordinators that
are required to take action CEDRP Proposed High VSL: The Reliability Coordinator did not have evidence that the
Operating Procedures, Processes, or Plans that require one or more other Reliability Coordinators to take action
(e.g., make notifications, exchange information, or coordinate actions) were agreed to by all Reliability Coordinators
that are required to take action SDT Proposed Severe VSL: The Reliability Coordinator failed to have evidence that
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the Operating Procedures, Processes, or Plans that require one or more other Reliability Coordinators to take
action (e.g., make notifications, exchange information, or coordinate actions) were not agreed to by all Reliability
Coordinators that are required to take action and were not distributed to all Reliability Coordinators that are
required to take action CEDRP Proposed Severe VSL: The Reliability Coordinator did not have evidence that the
Operating Procedures, Processes, or Plans that require one or more other Reliability Coordinators to take action
(e.g., make notifications, exchange information, or coordinate actions) were agreed to by all Reliability Coordinators
that are required to take action and were distributed to all Reliability Coordinators that are required to take action
FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary” requirement? 4. If
yes, is the VSL assignment consistent with other binary requirement assignments? 5. Is the VSL language clear &
measurable (ambiguity removed)? If no, does the requirement or measure need to be revised? 6. Does the VSL
redefine or undermine the stated requirement? 7. Is the VSL based on a single violation of the requirement (not
multiple violations)? Standard – IRO-014-2 R3 XXX-XXX Requirement (including sub-requirements) R3. The
Reliability Coordinator shall make notifications and exchange reliability–related information with impacted Reliability
Coordinators using its predefined Operating Procedures, Processes, or Plans for conditions that may impact other
Reliability Coordinator Areas or other means to accomplish the notifications and exchange of reliability-related
information. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations and Operations Planning]
Proposed Measure M3. The Reliability Coordinator shall have evidence it made notifications and exchanged
reliability–related information with impacted Reliability Coordinators using its predefined Operating Procedures,
Processes, or Plans for conditions that may impact other Reliability Coordinator Areas or other means to
accomplish the notifications and exchange of reliability-related information. Attributes of the requirement Binary
Timing Omission X Communication X Quality Other Discussion: The VSLs appear to be appropriate. Since the only
difference is the use of the “and” and “or”, we suggest emphasizing those words in bold. We read this more than
once before we noticed the difference. SDT Proposed Lower VSL N/A CEDRP Proposed VSL N/A SDT Proposed
Moderate VSL N/A CEDRP Proposed VSL N/A SDT Proposed High VSL: The Reliability Coordinator failed to make
notifications or exchange reliability–related information with impacted Reliability Coordinators. CEDRP Proposed
High VSL: The Reliability Coordinator failed to make notifications or exchange reliability–related information with
impacted Reliability Coordinators. SDT Proposed Severe VSL: The Reliability Coordinator failed to make
notifications and exchange reliability–related information with impacted Reliability Coordinators. CEDRP Proposed
Severe VSL: The Reliability Coordinator failed to make notifications and exchange reliability–related information
with impacted Reliability Coordinators. FERC Guidance for VSLs 1. Will the VSL assignment signal entities that
less compliance than has been historically achieved is condoned? 2. Is the VSL assignment a binary requirement?
3. Is it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised? 6. Does the VSL redefine or undermine the stated requirement? 7. Is the VSL based
on a single violation of the requirement (not multiple violations)? Standard – IRO-014-2 R4 XXX-XXX Requirement
(including sub-requirements) R4. The Reliability Coordinator shall participate in agreed upon conference calls and
other communication forums with impacted Reliability Coordinators. [Violation Risk Factor: Lower][Time Horizon:
Real-time Operations] The frequency of these conference calls shall be agreed upon by all involved Reliability
Coordinators and shall be at least weekly. Proposed Measure M4. The Reliability Coordinator shall have evidence
it participated in agreed upon (at least weekly) conference calls and other communication forums with impacted
Reliability Coordinators. Attributes of the requirement Binary Timing X Omission X Communication X Quality Other
Discussion – This requirement is purely administrative and probably does not rise to a level of a reliability standard
requirement. It is in essence redundant, with R1.1 IRO-014-2? It appears R1.1 addresses the same information
that would be expected to be discussed in a weekly conference call. Should the drafting team disagree and retain
this requirement, please consider applying multiple VSLs based on how often the RC participates in conference
calls, how many they missed, or how many impacted RCs they participated in conference calls with. SDT Proposed
Lower VSL: The Reliability Coordinator failed to participate in agreed upon (at least weekly) conference calls and
other communication forums with impacted Reliability Coordinators. CEDRP Proposed Lower VSL: The Reliability
Coordinator participated in agreed upon conference calls and other communication forums with impacted Reliability
Coordinators bi-weekly, Or the Reliability Coordinator failed to participate in one weekly conference call, Or the
Reliability Coordinator agreed to participate in conference calls with 25% or less of the impacted Reliability
Coordinators. SDT Proposed Moderate VSL: N/A CEDRP Proposed Moderate VSL: The Reliability Coordinator
participated in agreed upon conference calls and other communication forums with impacted Reliability
Coordinators every third week, Or the Reliability Coordinator failed to participate in two weekly conference calls, Or
the Reliability Coordinator agreed to participate in conference calls with more than 25% but less than or equal to
50% of the impacted Reliability Coordinators. SDT Proposed High VSL: N/A CEDRP Proposed High VSL: The
Reliability Coordinator participated in agreed upon conference calls and other communication forums with impacted
Reliability Coordinators fourth week, Or the Reliability Coordinator failed to participate in three weekly conference
calls, Or the Reliability Coordinator agreed to participate in conference calls with more than 50% but less than or
equal to 75% of the impacted Reliability Coordinators. SDT Proposed Severe VSL: N/A CEDRP Proposed Severe
VSL: The Reliability Coordinator participated in agreed upon conference calls and other communication forums
with impacted Reliability Coordinators at least every fifth week, Or the Reliability Coordinator failed to participate in
four weekly conference calls, Or the Reliability Coordinator failed to agree to participate in any conference calls, Or
the Reliability Coordinator agreed to participate in conference calls with more than 75% but less than 100% of the
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impacted Reliability Coordinators. FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less
compliance than has been historically achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is
it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised? 6. Does the VSL redefine or undermine the stated requirement? 7. Is the VSL based
on a single violation of the requirement (not multiple violations)? Standard – IRO-014-2 R5 XXX-XXX Requirement
(including sub-requirements) R5. When an expected or actual reliability issue is detected, the Reliability
Coordinator shall confirm the existence of the issue with the impacted Reliability Coordinators. In the event that the
issue cannot be confirmed, each Reliability Coordinator shall operate as though the problem exists. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations] Proposed
Measure The Reliability Coordinator shall have evidence that, in cases when an expected or actual reliability issue
was detected, it has confirmed the existence of the issue with the impacted Reliability Coordinators. Attributes of
the requirement Binary Timing Omission X Communication X Quality Other Discussion – This requirement is
confusing in the way it is worded. We think it is trying to say that the RC should operate as though the reliability
issue (should this be Adverse Reliability Impact) is detected until the issue is confirmed not to exist. The way it is
worded might imply that if one doesn’t confirm it to exist, operate as though it does. This leaves open the
interpretation that a confirmation that it doesn’t exist must still be operated to as though it does exist. The drafting
team should consider splitting operating to prevent from operating to mitigate an existing event in the VSLs. SDT
Proposed Lower VSL The Reliability Coordinator that detected an expected or actual reliability issue contacted the
other Reliability Coordinator(s) to confirm that there was a problem but could not confirm that the problem existed
and failed to operate as though the problem existed. CEDRP Proposed VSL N/A SDT Proposed Moderate VSL N/A
CEDRP Proposed VSL N/A SDT Proposed High VSL N/A CEDRP Proposed VSL The Reliability Coordinator that
detected an expected reliability issue failed to contact the other Reliability Coordinator(s) to confirm that there was
a problem. SDT Proposed Severe VSL The Reliability Coordinator that detected an expected or actual reliability
issue failed to contact the other Reliability Coordinator(s) to confirm that there was a problem. CEDRP Proposed
VSL The Reliability Coordinator that detected an actual reliability issue failed to contact the other Reliability
Coordinator(s) to confirm that there was a problem. FERC Guidance for VSLs 1. Will the VSL assignment signal
entities that less compliance than has been historically achieved is condoned? 2. Is the VSL assignment a binary
requirement? 3. Is it truly a “binary” requirement? 4. If yes, is the VSL assignment consistent with other binary
requirement assignments? 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? 6. Does the VSL redefine or undermine the stated requirement? 7. Is
the VSL based on a single violation of the requirement (not multiple violations)? Standard – IRO-014-2 R6 XXXXXX Requirement (including sub-requirements) When an expected or actual reliability issue exists and the
impacted Reliability Coordinators cannot agree on a mitigation plan, all impacted Reliability Coordinators shall
implement the mitigation plan developed by the Reliability Coordinator who has the reliability issue. [Violation Risk
Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations] Proposed
Measure The affected Reliability Coordinators shall have evidence that, in cases when an expected or actual
reliability issue existed and the impacted Reliability Coordinators could not agree on a mitigation plan, they
implemented the mitigation plan developed by the Reliability Coordinator who has the reliability issue. Attributes of
the requirement Binary Timing Omission X Communication X Quality Other Discussion: We are concerned the
validity of this requirement, it may force an RC to implement a solution that they don’t agree with and ultimately
result in an Adverse Reliability Impact. The RC may not agree with the solution because it may not be reliable for
their footprint. They need to have the ability to veto mitigation plans that cause Adverse Reliability Impacts in their
footprint without incurring a compliance violation. SDT Proposed Lower VSL The Reliability Coordinator did not
agree on a mitigation plan and implemented a plan other than the one developed by the Reliability Coordinator who
had the reliability issue. CEDRP Proposed VSL N/A SDT Proposed Moderate VSL N/A CEDRP Proposed VSL N/A
SDT Proposed High VSL N/A CEDRP Proposed VSL N/A SDT Proposed Severe VSL The Reliability Coordinator
did not agree on a mitigation plan and did not implement a mitigation plan. CEDRP Proposed VSL What if the RC
is correct in disagreeing and the mitigation plan would have caused an Adverse Reliability Impact on their system?
FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically
achieved is condoned? 2. Is the VSL assignment a binary requirement? 3. Is it truly a “binary” requirement? 4. If
yes, is the VSL assignment consistent with other binary requirement assignments? 5. Is the VSL language clear &
measurable (ambiguity removed)? If no, does the requirement or measure need to be revised? 6. Does the VSL
redefine or undermine the stated requirement? 7. Is the VSL based on a single violation of the requirement (not
multiple violations)?
Group
MRO NERC Standards Review Subcommittee
Terry Bilke
MidwestISO
No
The new R2 requirement is too verbose. We suggest that you strike the final clause: "and shall verify that alternate
means of telecommunications are functional." It is obviated by the requirement to notify impacted parties. The
responsible entity is already implicitly required to verify its alternate means of communication is functional since it is
required to notify its impacted parties of the failure of its normal telecommunications. It can't notify its impacted
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parties if the alternate communications means are not funcitonal. This clause is similar to the old requirement one
that the drafting team appropriately struck. We tend to agree that striking R1 makes sense due to the drafting
team's reasoning. However, we are not clear why the new R4 is necessary then. If the drafting team does not
believe R1 is necessary shouldn't they respond to the FERC directive with the same reason why R4 is not really
necessary? The VRF for new requirement 1 should be lower. It does not fit the definition of a medium VRF. A
medium VRF requires that a violation of the requirement directly affect the state or capability or the ability to
effectively monitor and control. Failure to test does not result in directly affecting the state or capability or the ability
to effectively monitor and control. At a minimum, a failure of the alternative communication systems and primary
communication systems must occur first. The failure to perform a single test in a given quarter does not mean that
primary and alternative communication systems will fail. Thus, testing is really an administrative issue and should
thus be a lower VRF. In the Data Retention section, Distribution Provider and Generation Operators should be
added. Currently, there are no data retention requirements listed for them. Suggest modifying the language
regarding data retention for compliance violations to: "… is found in violation of a requirement, it shall keep
information related to the violation until it the Compliance Enforcement Authority finds it compliant."
No
M4 does not appear to be worded as a measurement. If R4 is kept, we suggest the following modification: "The
Distribution Provider and Generation Operator shall demonstrate the existence of its telecommunication systems
idenfitied in R4."
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission established in their
"Order on Violation Severity Levels Proposed by the Electric Reliability Organization". Guideline 4 requires that a
VSL should be based on a single violation. The VSLs as defined accumulate the number of consecutive quarters.
This would imply that a single violation could last more than a year and that the compliance auditor could not
determine sanctions until the entity becomes compliant or year has passed. A single violation appears to be the
failure to test in a single quarter. This requirement is binary in nature in that it is either met or it isn't. We suggest
that only a lower VSL should be defined as: "The RC, TOP, or BA failed to test the backup telecommunication
facilities for a single calendar quarter." The Lower VSL for R2 is not possible. The act of notifying all impacted
entities of the failure of their primary telecommunication system requires the use of the alternative
telecommunications systems which is a form of verying that the alternative telecommunications facilities are
functional. The drafting team should consider applying the numeric performance category of the VSL Development
Guideline Criteria for R2.
Yes
Yes
Yes
No
New requirement R2 should omit act without intentional delay. The desired outcome is for the responsible entity to
comply with the RC directive. Adding act without intentional delay only confuses the situation and adds questions.
What is an intentional delay? The word act implies that the requirement is met simply if the responsible entity
attempted to meet the directive but was unable to do so. That is already considered in with the clause that begins
"unless such actions would violate …". Thus, the word act is not necessary. The word immediately should be
removed from the new R3. This attempts to time frame the response of the responsible entity and remove the
judgment from the compliance auditor. We agree with the concept of doing this but in reality it only confuses the
issue and the compliance auditor will likely apply his judgment regarding what immediate is anyway. Additionallly,
the requirement attempts to separate the act of confirming that the responsible entity can take the action from
notifying the RC that the entity can't take the action. This is not logical. What RC is going to request a responsible
entity to take action that would violate safety, equipment, statutory, or regulatory requirements? The RC should
already be aware of those requirements and likely won't direct actions that violate them. Thus, the likely scenario is
that the responsible entity will attempt to take action and discover that equipment is not funciton properly and thus
notify the RC. We suggest striking the "shall immediately confirm the ability to comply with the directive or" from the
requirement. This part of the requirement is not needed because the responsible entity is already obligated to
follow the RCs directive (see order 693.) Thus, the assumption is that the order will be followed unless it can't be
followed because it will violated safety, equipment, statutory, or regulatory requirements. Requirements R4 and R5
are unnecessary. New R1 requires the RC to direct actions to be taken by the TOP, BA, GOP, TSP, LSE, DP and
PSE to prevent or mitigate the magnitude or duration of events that result in Adverst Reliability Impacts. The RC
can't direct these actions without notifying all impacted TOPs and BAs. They would also have to notify them when
actions are no longer necessary.
No
Some compliance auditors have been taking the need for evidence to the extreme. We have encountered actual
situations where if a measure states evidence shall be provided for requirements that are event based, the
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compliance auditor expected evidence even if no event occurred. For example, some RCs rarely issue directives.
As M1 is written, some compliance auditors would require the RC to provide evidence that no reliability directives
were issued. This is not possible. We suggest modifying the measurement to: Each Reliability Coordinator shall
have evidence that it acted, or issued directives, to prevent or mitigate the magnitude or duration of Adverse
Reliability Impacts within its Reliability Coordiantor Area if needed. If there were no directives issues (assuming
there are no complaints or evidence to the contrary of the need to issue a directive), no evidence is necessary."
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in Severe. From a practical
perspective, what is the difference between directing actions and acting? We don't believe there is any. The actions
are the result of the RC authority whether the RC takes the actions themselves or directs someone else to. We
suggest a better alternative for the VSL levels would be for the High level to reflect that the RC did not act or direct
actions to prevent an Adverse Reliability Impact and Severe would be that the RC did not act or direct ations to
mitigate the magnitude or duration of an existing Adverse Reliability Impact. The moderate VSL for R2 is not
practical and too subjective. What constitutes a delay? What if the responsible entity takes five minutes to
determine how to carry out the action or if their equipment currently is capable of carrying out the action? Is this a
delay? We suggest striking this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory, or regulatory
requirements a violation. This is in direct conflict with the requirement. We suggest that the High VSL should be
struck. We suggest the Severe VSL should be that the responsible entity failed to follow the RC directive and it
would not have violated the safety, equipment, statutory or regulatory requirements. Currently, the Severe category
does not allow that the responsible entity may not be able to carry out the directive due to the violation of safety,
equipment, statutory, or regulatory requirements. In question 7, we request that the drafting team strike part of
requirement 3. The striking of that portion of requirement 3 obviates the lower VSL. In paragraph 27 of the ORDER
ON VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION, the
Commission expresses "that, as a general rule, gradated Violation Severity Levels, whereever possible, would be
preferable to binary Violation Severity Levels". Given that it is possible to define gradated VSLs for R4 and R5, we
suggest that the drafting team should consider applying the numeric performance category of the Violation Severity
Levels Development Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
No
New Requirement R1 is duplicate to the requirement TOP-005-1 R1.1. If the drafting team can't delete TOP-005-1
R1.1, they should notify other appropriate drafting teams of the need to remove the requirement. We do not agree
with eliminating requirements R5, R6, R7, and R8 in their entirety. The requirements as they are written are
problematic. However, we do believe that there is a need for a basic requirement to monitor the system. The
requirements should be that the RC should compare actual system flows to SOLs and IROLs. While some will
argue SOLs are not the responsibility of the RC, failure to monitor SOLs could cause the RC to miss unknown
IROLs since an SOL can become an IROL. Several SOL violations in a given area also can be indicative of a
broader system problem the RC should be addressing. We also do not agree with the drafting team's conclusion
that it is not practical to measure real-time monitoring. It is very easy to measure. As an example, a compliance
auditor could select a day and an SOL or IROL and ask for the system flows from that day or hour etc. This is
generally easy for any RC to produce with today's data archiving software. We believe that there should be a
requirement that the RC have a state estimator and real-time contingency analysis as well (RTCA). The drafting
team needs to be careful in the construction of these requirements to make them practical and measurable. For
instance, making the requirement to have a state estimator and RTCA is measurable in that the compliance auditor
can verify their existence but this is not stringent enough because they may only run once a week. At the same
time, if we create a requirement that SE and RTCA must run every 5 minutes, we could inadvertantly create a
requirement that any missing 5 minute run of RTCA and SE could be construed as a violation. There also needs to
be a requirement that there is a real-time assessment of voltage as well. New Requirement R2 is no longer needed
as a result of paragraph 112 in Order 693-A. Since the RC's "authority to issue directives arises out of the
Commission's approval of Reliability Standards" the RC already has veto authority or will have once R1 IRO-001-2
is approved. This requirement obligates the RC to take actions or direct actions to prevent Adverse Reliabilty
Impacts. Veto outages of equipment and analysis tools would fall into this category even if the RC couldn't say for
certain that an Adverse Relability Impact was going to occur but rather they are concerned one could occur due to
heavy loads for example.
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a data specification
document and actual verification that data has been received. The letter or equivalent is only needed if data has
not been supplied. Demonstration of the actual receipt the data would be easy. Requirement 2 is not needed and
thus Measure 2 is not needed per paragraph 112 of Order 693-A. Additional measures are needed to address the
proposed requirements in question 10.
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its data requirements and
requested that data and then follows with that it didn't request that data. The second option in the Lower VSL
category is not practical and a compliance auditor would not be in a position to determine this. In fact, if the
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administrative data is not requested, other administrative requirements for reporting would be violated. Additionally,
it does not make sense that an RC would determine its data needs and then omit data for administrative reporting.
Further, is it the compliance auditor's job to judge if the data the RC requests is sufficient or is it his job to see that
the RC has met the requirement to define the data? The remaining VSLs imply that the RC may define only partial
data requirements. This does not seem likely. Why would the RC do this? This VSL appears to add to the
requirement by making it appear that the compliance auditor is to judge the completeness of the data requirement.
This violates Guideline 3 of the FERC ORDER ON VIOLATION SEVERITY LEVELS PROPOSED BY THE
ELECTRIC RELIABILITY ORGANIZATION. Practically, it would not be enforceable anyway. It would require the
RC to admit that they did not include administrative data in the their data requirements. It is doubtful this would
happen because the RC likely believes they prepared a complete data requirement document. We suggest that the
VSLs should be: Severe: The RC did not determine it data requirements or the RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 75 to
100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. High: The RC could not demonstrate it requested
the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 50 and less than or
equal to 75% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Medium: The RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 25% and
less than or eqal to 50% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Lower: The RC could not
demonstrate it requested the necessary data if actual receipt of the necessary data can't be deomstrated for
greater than 0% and less than or equal to 25% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. R2
VSLs are not needed er paragraph 112 of Order 693-A. The Severe VSL contradicts the requirement.
No
R1 includes many requirements for monitoring the system that are important, measurable and should be retained.
Monitoring is too critical to operating the system to completely eliminate these requirements. R4, R8 and R11 are
problematic as currently written. However, there have been actual instances of a large BA intentionally operating
short hundreds of MWs of energy. I believe this occurred during the summer of 1999. Thus, the RC should be
monitoring the BAs ACE and directing the BA to correct it if it becomes too large. It is not necessary or even useful
for the RC to monitor the BA CPS performance.
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum. Please strike R1.6. RCs
already have the authority to act per paragraph 112 of Order 693-A. Since R2 requires the RCs to agree, is the
"mutually agreed to" clause in R1.1 necessary? Please strike requirements R4 and R4.1. It is duplicative to R1.1.
Conference calls are a form of communication and should be address per R1.1. R5 is confusing. If a reliability
issue isn't confirmed, doesn't this mean there is no reliability issue? Isn't this the point of confirming? Additionally,
we suggest using validate instead of confirm. R6 appears to be a rewrite of requirements R1, R2 and their subrequirements in IRO-016. We agree that those requirements do need to be written more succinctly or removed
altogether. However, R6 does not accomplish the goal and only confuses that matter further. The reason the RCs
may not be able to agree on a mitigation plan is that RC with the reliability issue may be requesting mitigations that
the other RCs believe may cause them reliability issues. This requirement appears to suggest that the solution to a
disagreement on the mitigation plan is cut and dried. Generally, the reason the disagreement arises is due to one
RC not fully understanding the impact of their actions on another RC. The bottom line is that the RCs may have
disagreements and there is no way to require a solution in these types of situations. Please revise R6 to require
using the mitigation plan developed by the Reliability Coordinator who has the reliability issue provided that the
mitigation plan does not cause a reliability issue in the other region. As Requirement 1 is currently written, one
could interpret the requirement for every Operating Process, Procedure and Plan to address each of the subrequirements. That is not necessary. The drafting team needs to consider modifying the requirement to make it
clear that not every sub-requirement must be addressed in every Operating Process, Procedure, and Plan and to
also make it clear that the some sub-requirements may only be appropriately addressed in a Process but not a
Plan for instance.
No
Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about System Operators
yet the measurement does. The measurement should just be to verify that the RC has have Operating Processes,
Procedures, and Plans. The sub-measurements are not measurements at all. There should be the single
measurement to verify the Operating Processes, Procedures, and Plans have been developed and address the
sub-requirements. This really points out the problem with making the criteria that must be considered in the
Operating Processes, Procedures, and Plans sub-requirements in the first place. They aren't requirements of any
sort. They represent criteria. The drafting team should consider making them a bulleted list without the Rs, then the
drafting team won't feel compelled to write sub-measures that don't measure anything. We do not agree with M6
because we don't agree with R6.
No
For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots" should be removed. We
don’t' agree with the VSLs in R4 since we believe R4 should be struck. The Lower VSL for R6 should not even be a
violation unless the impact was negative. If the RC implemented a different mitigation plan and resolved the issue,
then the RC was likely correct to disagree.
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Yes
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the wording of the
requirement. The new wording is much more confusing. Until we reviewed IRO-016-2, it was not clear at all that R6
in IRO-014 was attempting to mimic R1 and its sub-requirements in IRO-016-2.
Group
Southern Company Transmission
Jim Busbin
Southern Company Services, Inc.
No
1.1 - In R1, we suggest that "operationally test by way of operator action" should be defined to remove any
confusion regarding what the term requires. The word "ensure" needs to be changed to "assure" to more
accurately convey the intent of the requirement. We also suggest changing the word "facilities" to "capabilities". 1.2
- R2 is overly broad and should include a reasonable time frame for notification. For example, as currently written,
a telecom outage of only one minute for which a notification is not made would be a severe violation. The VSL
should be consistent with the language of the requirement. A very short, insignificant telecom outage with no
notification could result in a severe violation as the requirement is presently written and VSL's applied. 1.3 - R1, R2
and R3 should be expanded to include the list of entities the RC needs to talk with as included in the Applicability
section of IRO-001-2 (RC, TO, BA, GO, DP, TSP, LSE, PSE). These entities should also be included in the
purpose statement and R4 and M4 can then be eliminated. 1.4 - In R3, we suggest that the last sentence of R3
should be changed to "entities may use an alternative language for internal operations" rather than allowing only
TOs and BAs to have this option.
No
2.1 - A general comment regards the production of evidence - such language should be standardized as "have and
provide upon request" and the authorized requestors identified. This comment should apply to all standards. 2.2 M2 is overly broad and should include a reasonable time frame for notification. For example, as currently written, a
telecom outage of only one minute for which a notification is not made would be a severe violation. 2.3 - The
Drafting Team should coordinate the data retention time frame with the requirement measures for R1. DPs and
GOs should also be included in the measures requirements.
Yes
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included the VSLs 3.2 - The
Severe VSL for R2 should be corrected. Add the word 'to' as follows: "…and failed to verify the …"
No
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved; however we suggest
the following changes should be made for the interim applicability of COM-002-3: 4.2 - The Purpose statement
should be revised to re-align with the revisions in the Standard. 4.3 - The applicability of COM-002-3 should be
consistent with the applicability of IRO-001-2. 4.4 - The words "clear, concise, and definitive manner" in R1 are
ambiguous and impossible to measure. We suggest they be replaced with "the RC shall direct". 4.5 - An additional
requirement, R2, should be added that requires the Operator to repeat the information back correctly (i.e., separate
this requirement from R1). 4.6 - Grammatical changes are suggested. The revised requriement reads as follows: "
To ensure Balancing Authorities, Transmission Operators, and Generator Operators have adequate
communications; to ensure that these communication capabilities are staffed and available for addressing a realtime emergency condition; and to ensure effective communications by operating personnel." 4.7 - At the Data
Retion section, the reference to 'Requirement 3, Measure 3' should be consistent with the modified standard. The
revised standard only has one requirement. 4.8 - The use of calendar days in the Data Retention seciton is
inconsistent with related standards where 'months' are used.
No
5.1 - The measures need to be revised to match the new requirements.
No
6.1 - The severity levels need to be revised to match the new requirements.
No
7.1 - Applicability 4.2 - Transmission Operator should be plural. 7.2 - The revised definition of "Adverse Reliability
Impacts" (R1) should be included at the top of Standard IRO-001-2, per Glossary of Terms Used in Standards: All
defined terms used in reliability standards shall be defined in the glossary. Definitions may be approved as part of a
standard action or as a separate action. All definitions must be approved in accordance with the standards process.
7.3 - In R2 insert the word "its" before Reliability Coordinator. 7.4 - In R3, replace "immediately" with "without
intentional delay", replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before Reliability
Coordinator.
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No
8.1 - In M2 and M3, Add Distribution Provider. 8.2 - In M2 add "intentional" between "without" and "delay". 8.3 - In
M3 replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before Reliability Coordinator's
and Reliability Coordinator. 8.4 - In M5, change "has" to "had".
No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he doesn't - If he fails to
act, he fails to direct and mitigate the problem by default. 9.2 - R2 VSLs need to be rewritten to recognize that
some directives may not be followed because of safety, regulatory or statuatory requirements. 9.3 - Remove the
Lower severity level in R3 to conform to changes in R3 and M3.
No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this standard retired. If
this standard is not retired then we recommend Comments 10.2 and 10.3. 10.2 - At Requirement R2, the RC is
given 'veto' authority. Is a standard an appropriate place to give this type of authority? 10.3 - The revised Purpose
basically provides that the RC will have access to information and control of analysis tools. What is the correlation
of information/control to veto authority/approval of planned maintenance?
No
11.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate measurement requirements.
No
12.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate VSL requirements.
Yes
13.1 - We agree with retiring this standard.
No
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures, processes and
plans in place with each RC within the RC's Interconnection. We suggest the phrasing should be tightened up to
convey the original meaning that the team intended. For example, does the team intend for the FRCC RC to have
an agreement with the PJM or MISO RC? 14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and
rewrite it as follows: R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing a
mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper steps to be
taken. 14.3 - We suggest deleting R4.1 and adding a second sentence to R4: The frequency of these
communications shall be at least weekly. 14.4 - R4: The word "impacted" makes it sound like these calls are only to
be made when problems are expected or are occurring. If this requirement is intended more for operational
awareness calls (such as the daily SERC RC call), then the word "impacted" needs to be changed to "contiguous"
or a similar term. 14.5 - We suggest rewriting R5 to read: In the event that a reliability issue cannot be confirmed,
each Reliability Coordinator shall operate as though the problem exists. 14.6 - At Requirement R1, the use of the
phrase "as a minimum" seems to add some flexibility for development of procedures, processes and plans. A
negative consequence is that it introduces more abmiguity. The recommendation is to strike the phrase. 14.7 - At
Requirement R1.6, consider the following: "Authority to act to prevent and mitigate instances 'that have the
potential to cause' Adverse Reliability Impacts to other Reliability Coordinator Areas."
No
15.1 - In M1, delete "for Real-time use". 15.2 - Modify the measures to be consistent with changes requested in R1,
R2, R4, R4.1 and R5.
No
16.1 - In R2, severe should be "... and no action was taken by the RC". 16.2 - In R5, severe should also include "...
or that the RC failed to operate as though the problem existed." 16.3 - Modify the VSLs to be consistent with
changes requested in R1, R2, R4, R4.1 and R5.
Yes
17.1 - We agree with the recommendation to retire IRO-015-2.
Yes
18.1 - We agree with the recommendation to retire IRO-016-2.
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the COM-001-2
Standard should be effective immediately upon regulatory approval. As written, the Policy is unenforceable,
contains no measures and is not germane to BES Reliability.
Individual
Kathleen Goodman
ISO New England Inc.
No
ISO New England does not support the removal of Requirement 1. Also, we believe Requirement 3 is written such
that it may pose an unnecessary requirement on the Hydro Quebec area given the terminology "inter-entity" and
support further clarification.
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No
See answer to #1.
No
ISO New England believes it is inefficient to have a (temporary) Standard with only one Requirement and
recommend including this Requirement in COM-001, with COM-001 renamed to "Communications."
No
See response to Q#4
Yes and No
We beleive the word "threat" shoudl be replaced with "events" in Requirements 4 and 5.
Yes and No
Suggest changing with word "request" to "document" in Requirement 1.
Yes
Yes and No
As Requirement 1 is currently written, one could interpret the requirement for every Operating Process, Procedure
and Plan to address each of the sub-requirements. That is not necessary. The drafting team needs to consider
modifying the requirement to make it clear that not every sub-requirement must be addressed in every Operating
Process, Procedure, and Plan and to also make it clear that the some sub-requirements may only be appropriately
addressed in a Process but not a Plan for instance. Use of the term collectively may resolve this dilemma.
Yes
Yes
Individual
Edward Davis
Entergy Services, Inc
Yes
The drafting team should consider expanding the second sentence of R3 to apply to internal communications of
any affected entity not just BAs and TOPs.
Yes
Yes
Yes
Yes
Yes
No
PER-003 R1 does not specifically addresss delegated functions; therefore, this requirement is not redundant with
IRO-001 R6 without changes to PER-003 to specifically deal with employees perforing delegated functions.
Yes
No
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The VSL for R2 does not seem consistent with the language in the requirement. It is not clear why the entity should
be subject to a high VSL if the entity did not comply with an RC directive due to safety or regulatory prohibition, and
made the RC aware of same.
No
IRO-002-1 R9, the deleted language of the second sentence is not adequately covered by the language in EOP008-0 R1, unless those outages are tied to the loss of a control center. EOP-008-0 is in the process of being
revised and this language could be included in the revision, but it isn't adequately addressed by the version 0
standard.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Overall, we think the coordinated set of standards being developed by the RTOSDT and IROLSDT are good for
reliability, crisp, and tightens up the reliability concepts.
Individual
Danny Dees
MEAG Power
No
Directives that are mandatory under R2 of IRO-001-2 should have boundaries consistent with the proper role of an
RC. For example, if an RC directs an LSE with a 15% planning reserve margin to execute purchase power
agreements until its reserve margin is at least 20% and the LSE refuses, then the LSE may have violated this
standard. Other examples of improper RC directives are directives to increase coal inventories, buy firm fuel
transportation rights, reconductor transmission lines, purchase spare equipment, etc. Granted entities may be able
to conjure up a regulatory or statutory basis for refusing many improper RC directives but in some instances there
may be no permissible grounds to refuse. The appropriate solution is to modify the standard to ensure that
improper directives are never mandatory in the first place. Specifically, NERC is urged to state that RC directives
are mandatory only if they pertain to specific categories such as: switching orders to reconfigure the BES, orders to
postpone scheduled outages of BES equipment, orders to change generator output, orders to curtail transactions
or orders to curtail load.
No
The M2 measure should not mandate compliance with RC directives that are improper as defined in my response
to question 7.
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My other concerns are addressed in the comments of the SERC OC Standards Review Group.
Individual
Mike Gentry
Salt River Project
Yes
No
M3 should include providing evidence of concurrence to use a language other than English. This will better align
the measure with the VSL language.
Yes
Yes
Yes
Yes
Yes
Yes
No
R1 states the RC must act OR direct. The R1 VSL's attempt to distinguish between act and direct. The requirement
allows for either action. I suggest that the High VSL be removed and replaced by an N/A. The Severe VSL should
be amended so that the words "act and direct" are replaced by the words "act OR direct" as is consistent with the
requirement and the measure. R2:The moderate VSL introduces the phrase "equipment problems" for the first time
in the Standard. "Equipment Problems" needs to be included in the Requirement, R2, and defined in the Measure
for R2. R5: The Severe VSL needs to be moved to the Moderate category. This condition does not constitute an
Adverse Reliability Impact that severely threatens the BES.
Yes
No
R1: The Requirement and VSL's mention that the RC will determine it's data needs. Yet the Measure for R1 does
not mention this, it only mentions the RC requesting the data from it's member emtities. This Measure needs to
include a measure for how the RC determines it's data needs.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
I appreciate the new comment form in Word version. his allows me to comment on each requirement specifically
addressing the requirement, measure or the VSL's
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Group
SERC OC Standards Review Group
Jim Griffith
Southern Co.
Yes and No
1.1 - In R1, we suggest that "operationally test" should be defined to remove any confusion regarding what the term
requires. The word "ensure" needs to be changed to "assure" to more accurately convey the intent of the
requirement. We also suggest changing the word "facilities" to "capabilities". 1.2 - R2 is overly broad and should
include a reasonable time frame for notification. For example, as currently written, a telecom outage of only one
minute for which a notification is not made would be a severe violation. 1.3 - R1, R2 and R3 should be expanded to
include the list of entities the RC needs to talk with as included in the Applicability section of IRO-001-2 (RC, TO,
BA, GO, DP, TSP, LSE, PSE). These entities should also be included in the purpose statement and R4 and M4
can then be eliminated. 1.4 - In R3, we suggest that the last sentence of R3 should be changed to "entities may
use an alternative language for internal operations" rather than allowing only TOs and BAs to have this option.
Yes and No
2.1 - A general comment regards the production of evidence - such language should be standardized as "have and
provide upon request" and the authorized requestors identified. This comment should apply to all standards. 2.2 M2 is overly broad and should include a reasonable time frame for notification. For example, as currently written, a
telecom outage of only one minute for which a notification is not made would be a severe violation. 2.3 - The
Drafting Team should coordinate the data retention time frame with the requirement measures for R1. DPs and
GOs should also be included in the measures requirements
Yes and No
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included the VSLs
Yes and No
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved; however we suggest
the following changes should be made for the interim applicability of COM-002-3: 4.2 - The Purpose statement
should be revised to re-align with the revisions in the Standard. 4.3 - The applicability of COM-002-3 should be
consistent with the applicability of IRO-001-2. 4.4 - The words "clear, concise, and definitive manner" in R1 are
ambiguous and impossible to measure. We suggest they be replaced with "the RC shall direct". 4.5 - An additional
requirement, R2, should be added that requires the Operator to repeat the information back correctly (i.e., separate
this requirement from R1).
No
5.1 - The measures need to be revised to match the new requirements.
No
6.1 - The severity levels need to be revised to match the new requirements
Yes and No
7.1 - Applicability 4.2 - Transmission Operator should be plural. 7.2 - The revised definition of "Adverse Reliability
Impacts" (R1) should be included at the top of Standard IRO-001-2, per Glossary of Terms Used in Standards: All
defined terms used in reliability standards shall be defined in the glossary. Definitions may be approved as part of a
standard action or as a separate action. All definitions must be approved in accordance with the standards process.
7.3 - In R2 insert the word "its" before Reliability Coordinator 7.4 - In R3, replace "immediately" with "without
intentional delay", replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before Reliability
Coordinator.
Yes and No
8.1 - In M2 and M3, Add Distribution Provider. 8.2 - In M2 add "intentional" between "without" and "delay". 8.3 - In
M3 replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before Reliability Coordinator's
and Reliability Coordinator. 8.4 - In M5, change "has" to "had".
Yes and No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he doesn't - If he fails to
act, he fails to direct and mitigate the problem by default. 9.2 - R2 VSLs need to be rewritten to recognize that
some directives may not be followed because of safety, regulatory or statuatory requirements. 9.3 - Remove the
Lower severity level in R3 to conform to changes in R3 and M3.
Yes and No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this standard retired.
Yes and No
11.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate measurement requirements.
Yes and No
12.1 - Moving R1 and R2 to the RC Certification Procedure, will eliminate VSL requirements.
Yes
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13.1 - We agree with retiring this standard
Yes and No
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures, processes and
plans in place with each RC within the RC's Interconnection. We suggest the phrasing should be tightened up to
convey the original meaning that the team intended. For example, does the team intend for the FRCC RC to have
an agreement with the PJM or MISO RC? 14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and
rewrite it as follows: R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing a
mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper steps to be
taken. 14.3 - We suggest deleting R4.1 and adding a second sentence to R4: The frequency of these
communications shall be at least weekly. 14.4 - R4: The word "impacted" makes it sound like these calls are only to
be made when problems are expected or are occurring. If this requirement is intended more for operational
awareness calls (such as the daily SERC RC call), then the word "impacted" needs to be changed to "contiguous".
14.5 - We suggest rewriting R5 to read: In the event that an operating issue cannot be confirmed, each Reliability
Coordinator shall operate as though the problem exists.
Yes and No
15.1 - In M1, delete "System Operator" and "for real-time use". 15.2 - Modify the measures to be consistent with
changes requested in R1, R2, R4, R4.1 and R5.
Yes and No
16.1 - In R2, severe should be "no action was taken by the RC". 16.2 - In R5, severe should also include that the
RC failed to operate as though the problem existed. 16.3 - Modify the VSLs to be consistent with changes
requested in R1, R2, R4, R4.1 and R5.
Yes
17.1 - We agree with the recommendation to retire IRO-015-2
Yes
18.1 - We agree with the recommendation to retire IRO-016-2
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the COM-001-2
Standard should be effective immediately upon regulatory approval. As written, the Policy is unenforceable,
contains no measures and is not germane to BES Reliability
Individual
Jay Seitz
US Bureau of Reclamation
No
Purpose Distribution Providers and Generator Operators were added to the applicability; the Purpose should be
revised to reflect that.
Yes
Yes
No
Purpose Since Generator Operators were deleted from the applicability; the Purpose should be revised to reflect
that and include Reliability Coordinators. The language is somewhat redundant, recommend it be simplified to “To
ensure Balancing Authorities, Reliability Coordinators, and Transmission Operators communicate in an effective
manner.”
Yes
Yes
No
R4. and R5. Both of these Requirements use the phrase “without intentional delay” to describe the urgency of the
notification to impacted entities. In both requirements we recommend the language be changed from “notify,
without intentional delay” to “immediately notify”.
No
M4. and M5. In both Measures, recommend “without intentional delay” be changed as described above for R4. and
R5.
Yes
No
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R2. This requirement provides authority to the Reliability Coordinator to veto planned outages and approve planned
maintenance to “analysis tools”. It is not clear in this standard what these “analysis tools” are. Per FERC Order
693, NERC was to identify a minimum set of analysis tools and the task was assigned to the Real-Time Tools Best
Practices Task Force. Until the tools are identified, it is premature to insert a placeholder in a mandatory standard;
this also applies to the violation severity levels table.
No
M2 again "analysis tools" have not been identified.
No
Until the tools are identified, it is premature to insert a placeholder in a mandatory standard; this also applies to the
violation severity levels table.
Yes
Yes
Yes
Yes
Yes
Yes
Group
PJM Interconnection
Patrick Brown
PJM Intercinnection
Yes
We agree with the revisions, but recommend adding applicability to Distribution Providers and Generator Operators
for data retention requirements.
Yes
M4 should be revised to reflect that each Distribution Provider and Generation Operator has evidence
demonstrating the functionality of telecommunications facilities with the TOP and BA for the exchange of
interconnection and operating information.
No
Recommend the following VSLs for R1: Proposed Lower VSL: The Reliability Coordinator, Balancing Authority or
Transmission Operator failed to operationally test alternative telecommunications every three months on at least
one occasion. Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on two separate occasions.
Proposed High VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed to
operationally test alternative telecommunications every three months on three separate occasions. Proposed
Severe VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed to operationally test
alternative telecommunications every three months on more than three separate occasions. Recommend the
following VSLs for R2: Proposed Lower VSL: The Reliability Coordinator, Balancing Authority or Transmission
Operator failed to operationally test alternative telecommunications every three months on at least one occasion.
Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed to
operationally test alternative telecommunications every three months on two separate occasions. Proposed High
VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed to operationally test
alternative telecommunications every three months on three separate occasions. Proposed Severe VSL: The
Reliability Coordinator, Balancing Authority or Transmission Operator failed to operationally test alternative
telecommunications every three months on more than three separate occasions. Recommend the following VSLs
for R4: Proposed High VSL: The Responsible Entity failed to establish telecommunications with either their
Balancing Authority or Transmission Operator for the exchange of Interconnection and operating information.
Proposed Severe VSL: The Responsible Entity failed to establish telecommunications with their Balancing
Authority and Transmission Operator for the exchange of Interconnection and operating information.
Yes
We note that this requirement really is "3-part communication" and will be moved to the new communications
standard, COM-003-1.
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Yes
No
The word "clear" is redundantly used in the High and Severe colums. Recommend that "Moderate" should read:
"The Responsible Entity provided a directive in a clear, concise and definitive manner, but did not require the
recipient to repeat the directive back to the originator." Recommend that "High" should read: "The Responsible
Entity failed to issue a directive in a clear, concise and definitive manner while ensuring the recipient of the
directive repeated the information back correctly with acknowledgment by the originator that the response was
correct." Recommend that "Severe" should read: "The Responsible Entity failed on more than one occasion to
issue a directive in a clear, concise and definitive manner while ensuring the recipient of the directive repeated the
information back correctly with acknowledgment by the originator that the response was correct."
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
#2 Standards Interface Subcommittee/Compliance Elements Development Resource Pool
John Blazekovich
Commonwealth Edison Co.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard – COM-001-2 Telecommunications Requirement 1: Each Reliability Coordinator, Transmission Operator,
and Balancing Authority shall operationally test, on a quarterly basis at a minimum, alternative telecommunications
facilities to ensure the availability of their use when normal telecommunications facilities fail. Proposed Measure:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall provide evidence that it
operationally tested, on a quarterly basis at a minimum, alternative telecommunications facilities to ensure the
availability of their use when normal telecommunications facilities fail. Attributes of the requirement Binary
Quarterly operational tests of alternate telecommunications Timing X Omission Communication Quality X Other
SDT Proposed Lower VSL: The Reliability Coordinator, Transmission Operator, or Balancing Authority failed to
operationally test within the last quarter. CEDRP Proposed Lower VSL: The Reliability Coordinator, Balancing
Authority or Transmission Operator performed operational testing of alternative telecommunications, but did not
perform a test in one of the previous four quarters. SDT Proposed Moderate VSL: The Reliability Coordinator,
Transmission Operator, or Balancing Authority failed to operationally test within the last 2 quarters. CEDRP
Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator performed
operational testing of alternative telecommunications, but did not perform a test in two of the previous four quarters.
SDT Proposed High VSL: The Reliability Coordinator, Transmission Operator, or Balancing Authority failed to
operationally test within the last 3 quarters. CEDRP Proposed High VSL: The Reliability Coordinator, Balancing
Authority or Transmission Operator performed operational testing of alternative telecommunications, but did not
perform a test in three of the previous four quarters. SDT Proposed Severe VSL: The Reliability Coordinator,
Transmission Operator, or Balancing Authority failed to operationally test within the last 4 quarters. CEDRP
Proposed Severe VSL: The Responsible Entity failed to operationally test alternative telecommunications every
quarter on more than three separate occasions (i.e. more than any three different quarters). FERC Guidance for
VSLs 1. Will the VSL assignment signal entities that less compliance than has been historically achieved is
condoned? No 2. Is the VSL assignment a binary requirement? Yes 3. Is it truly a “binary” requirement? Yes 4. If
yes, is the VSL assignment consistent with other binary requirement assignments? Yes 5. Is the VSL language
clear & measurable (ambiguity removed)? If no, does the requirement or measure need to be revised? Yes 6. Does
the VSL redefine or undermine the stated requirement? No 7. Is the VSL based on a single violation of the
requirement (not multiple violations)? Yes Standard – COM-001-2 Telecommunications Requirement 2: Each
Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities of the failure
of its normal telecommunications facilities, and shall verify that alternate means of telecommunications are
functional. Proposed Measure: Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
provide evidence that it notified impacted entities of failure of their normal telecommunications facilities, and
verified the alternate means of telecommunications were functional. Attributes of the requirement Binary Timing
Notify impacted entities and verify functionality of alternate telecommunications Omission Communication X Quality
Other - Test X Discussion - This requirement needs to be re-written to be more clearly define who the entities are
that are “impacted.” The key attributes appear to be notification of ALL (communication) impacted entities (possible
omission if some, but not all are not notified). The requirement does not give any guidance on the “verification” side
– this is a problem, one entity can interpret that to mean “we looked and it was working”, another may be to verify
with all impacted entities that alternate communication is working. We suggest this requirement needs a little more
clarification. The CEDRP does not feel it can write a valid VSL for this requirement as currently worded. SDT
Proposed Lower VSL: The Reliability Coordinator, Transmission Operator or Balancing Authority notified all
impacted entities of the failure of their normal telecommunications facilities, but failed to verify the alternate means
of telecommunications are functional. CEDRP Proposed Lower VSL: See Discussion SDT Proposed Moderate
VSL: The Reliability Coordinator, Transmission Operator or Balancing Authority notified some, but not all, impacted
entities of the failure of their normal telecommunications facilities, and failed to verify the alternate means of
telecommunications are functional. CEDRP Proposed Moderate VSL: See Discussion SDT Proposed High VSL:
N/A CEDRP Proposed High VSL: See Discussion SDT Proposed Severe VSL: The Reliability Coordinator,
Transmission Operator or Balancing Authority failed to notify any impacted entities of the failure of their normal
telecommunications facilities, and failed verify the alternate means of telecommunications are functional. CEDRP
Proposed Severe VSL: See Discussion FERC Guidance for VSLs 1. Will the VSL assignment signal entities that
less compliance than has been historically achieved is condoned? No 2. Is the VSL assignment a binary
requirement? No 3. Is it truly a “binary” requirement? No 4. If yes, is the VSL assignment consistent with other
binary requirement assignments? N/A 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does
the requirement or measure need to be revised? Yes 6. Does the VSL redefine or undermine the stated
requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple violations)? Yes
Standard – COM-001-2 Telecommunications Requirement 3: Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider shall use
English as the language for all inter-entity Bulk Electric System (BES) reliability communications between and
among operating personnel responsible for the real-time generation control and operation of the interconnected
BES. Transmission Operators and Balancing Authorities may use an alternate language for internal operations.
Proposed Measure: The Reliability Coordinator, Transmission Operator or Balancing Authority shall have and
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts
of voice recordings, electronic communications, or equivalent, that will be used to determine that personnel used
English as the language for all inter-entity BES reliability communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected BES. Attributes of the
requirement Binary Use English for real-time communications unless agreed to otherwise. NOTE: OK with this as is
because the requirement and VSLs have been re-written, will be removed from this standard shortly, and included
in the new COM-003-1 standard. Timing Omission Communication X Quality Other SDT Proposed Lower VSL: N/A
CEDRP Proposed Lower VSL: No change SDT Proposed Moderate VSL: N/A CEDRP Proposed Moderate VSL:
No change SDT Proposed High VSL: N/A CEDRP Proposed High VSL: No change SDT Proposed Severe VSL:
The responsible entity failed to provide evidence of concurrence to use a language other than English for all
communications between and among operating personnel responsible for the real-time generation control and
operation of the interconnected Bulk Electric System. CEDRP Proposed Severe VSL: The Responsible Entity failed
to provide evidence of the concurrence to use a language other than English for all communications between and
among operating personnel responsible for the real-time generation control and operation of the interconnected
Bulk Electric System. FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance
than has been historically achieved is condoned? No 2. Is the VSL assignment a binary requirement? Yes 3. Is it
truly a “binary” requirement? Yes 4. If yes, is the VSL assignment consistent with other binary requirement
assignments? It’s a little inflated as being Severe 5. Is the VSL language clear & measurable (ambiguity removed)?
If no, does the requirement or measure need to be revised? It’s OK for the interim 6. Does the VSL redefine or
undermine the stated requirement? No 7. Is the VSL based on a single violation of the requirement (not multiple
violations)? Yes Standard – COM-001-2 Telecommunications Requirement 4: Each Distribution Provider and
Generation Operator shall have telecommunications facilities with its Transmission Operator and Balancing
Authority for the exchange of Interconnection and operating information. Proposed Measure: Each Distribution
Provider and Generation Operator has telecommunications facilities with its Transmission Operator and Balancing
Authority for the exchange of Interconnection and operating information. Attributes of the requirement Binary “has”
telecomm with TOP and BA Timing Omission Communication X Quality Other Discussion – Telecommunication
Facilities is ambiguous and is not included in the NERC glossary of terms – the CEDRP recommend deleting the
word “facilities” from the requirement and measure and leaving it just as “telecommunications” with its TOP and BA
. SDT Proposed Lower VSL: N/A CEDRP Proposed Lower VSL: No change SDT Proposed Moderate VSL: N/A
CEDRP Proposed Moderate VSL: No change SDT Proposed High VSL: N/A CEDRP Proposed High VSL: The
Responsible Entity failed to establish telecommunications with either their Balancing Authority OR Transmission
Operator for the exchange of Interconnection and operating information. SDT Proposed Severe VSL: The
Distribution Provider or Generation Operator failed to have telecommunications facilities with its Transmission
Operator and Balancing Authority CEDRP Proposed Severe VSL: The Responsible Entity failed to establish
telecommunications with their Balancing Authority AND Transmission Operator for the exchange of Interconnection
and operating information. FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less
compliance than has been historically achieved is condoned? No 2. Is the VSL assignment a binary requirement?
Mostly 3. Is it truly a “binary” requirement? Mostly 4. If yes, is the VSL assignment consistent with other binary
requirement assignments? Yes 5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the
requirement or measure need to be revised? Yes, considering the wording of the requirement as written. More
specifically, the word “have” as used in the requirement is a bit vague. A better choice could have been,
“established and maintains.” 6. Does the VSL redefine or undermine the stated requirement? No 7. Is the VSL
based on a single violation of the requirement (not multiple violations)? Yes Standard: COM-002-3
Communications and Coordination Requirement 1: Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and definitive manner; shall ensure the recipient of the
directive repeats the information back correctly; and shall acknowledge the response as correct or repeat the
original statement to resolve any misunderstandings. Proposed Measure: Each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall have evidence such as voice recordings or transcripts of
voice recordings to show that it issued directives in a clear, concise, and definitive manner; ensured the recipient of
the directive repeated the information back correctly; and acknowledged the response as correct or repeated the
original statement to resolve any misunderstandings. Attributes of the requirement: Binary Timing Omission
Communication X Quality X Other SDT Proposed Lower VSL: None CEDRP Proposed Lower VSL: No Comment
SDT Proposed Moderate VSL: The responsible entity provided a clear directive in a clear, concise and definitive
manner and required the recipient to repeat the directive, but did not acknowledge the recipient was correct in the
repeated directive. CEDRP Proposed Moderate VSL: No comment SDT Proposed High VSL: The responsible
entity provided a clear directive in a clear, concise and definitive manner, but did not require the recipient to repeat
the directive. CEDRP Proposed High VSL: No comment SDT Proposed Severe VSL: The responsible entity failed
to provide a clear directive in a clear, concise and definitive manner when required. CEDRP Proposed Severe VSL:
No comment FERC Guidance for VSLs 1. Will the VSL assignment signal entities that less compliance than has
been historically achieved is condoned? No 2. Is the VSL assignment a binary requirement? No 3. Is it truly a
“binary” requirement? No 4. If yes, is the VSL assignment consistent with other binary requirement assignments? 5.
Is the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or measure need to be
revised? Yes 6. Does the VSL redefine or undermine the stated requirement? No 7. Is the VSL based on a single
violation of the requirement (not multiple violations)? Yes and No (Severe is for multiple occasions of not issuing
directives per the requirement).
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Timothy C. (TC) Thomas
Progress Energy Carolinas
No
R1- The proposed requirement R1 as stated is too broad in reference to "telecommunications facilities". It is
unclear as to whether it is intending to specify facilities and equipment which provide VOICE/VERBAL
communications, or ELECTRONIC MESSAGING notifications systems, or DATA EXCHANGE links or all of these.
Please clarify either within the requirement or within the Glossary of Terms which accompany the full standards set.
R2 - The proposed requirement R2 as stated is too broad in reference to "telecommunications facilities". It is
unclear as to whether it is intending to specify facilities and equipment which provide VOICE/VERBAL
communications, or ELECTRONIC MESSAGING notifications systems, or DATA EXCHANGE links or all of these.
Please clarify either within the requirement or within the Glossary of Terms which accompany the full standards set.
R4 - The proposed requirement R4 as stated is too broad in reference to "telecommunications facilities". It is
unclear as to whether it is intending to specify facilities and equipment which provide VOICE/VERBAL
communications, or ELECTRONIC MESSAGING notifications systems, or DATA EXCHANGE links or all of these.
Please clarify either within the requirement or within the Glossary of Terms which accompany the full standards set.
No
M1 - The proposed measure M1 as stated is too broad in reference to "telecommunications facilities". It is unclear
as to whether it is intending to specify facilities and equipment which provide VOICE/VERBAL communications, or
ELECTRONIC MESSAGING notifications systems, or DATA EXCHANGE links or all of these. Please clarify either
within the requirement or within the Glossary of Terms which accompany the full standards set. M2 - The proposed
measure M2 as stated is too broad in reference to "telecommunications facilities". It is unclear as to whether it is
intending to specify facilities and equipment which provide VOICE/VERBAL communications, or ELECTRONIC
MESSAGING notifications systems, or DATA EXCHANGE links or all of these. Please clarify either within the
requirement or within the Glossary of Terms which accompany the full standards set. M4 - The proposed measure
M4 as stated is too broad in reference to "telecommunications facilities". It is unclear as to whether it is intending to
specify facilities and equipment which provide VOICE/VERBAL communications, or ELECTRONIC MESSAGING
notifications systems, or DATA EXCHANGE links or all of these. Please clarify either within the requirement or
within the Glossary of Terms which accompany the full standards set.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
No
Purpose - The purpose does not include the GOP and DP entities. It may be better if the purpose was written more
generally as "To ensure adequate and reliable telecommunications facilities for the exchange of Interconnection
and operating information necessary to maintain BES reliability". R1 - This requirement makes no distinction
between data and voice communications facilities and assumes a designated primary and backup facility
configuration such that the backup communications systems are not used regularly. This may be an accurate
assumption for data communications; however voice communications may be different. Today many organizations
use voice communications systems that allow the system to choose the communication path each time a call is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
placed. This design ensures that all communications paths are tested regularly in day-to-day use. However, the
design of these systems makes it difficult, if not impossible, to substantiate that a functional test of the circuitry has
been performed. This requirement should be broken into two requirements. The first should cover data circuitry and
the second should cover voice circuitry. This will allow the drafting team to address the inherent differences in
these two methods of communications. Lastly, the requirements need to be much more specific concerning the
criticality of the facilities to be tested to improve the measurability of the standard. The drafting team dropped the
phrase "for the exchange of Interconnection and operating data" from the standard requirement. This deletion
appears to open the application of this standard to virtually every communication path used by an RC, BA, TOP
whether or not it is used for communicating real-time operating information or not. We do not believe this was the
intention of the drafting team and suggest this phrase be reinserted or another one added that limits applicability to
only those communication paths that support the real-time reliability of the bulk electric system. R2 - It is not clear
who the "impacted entities" would be in this requirement. The SDT should consider specifying these entities. R3 The last sentence of this requirement should be deleted. It is not a requirement, it does not add clarity, and the first
sentence is very specific as to the communications covered by the requirement. R4 - This requirement makes no
distinction between data and voice communications facilities and assumes a designated primary and backup facility
configuration such that the backup communications systems are not used regularly. This may be an accurate
assumption for data communications; however voice communications may be different. Today many organizations
use voice communications systems that allow the system to choose the communication path each time a call is
placed. This design ensures that all communications paths are tested regularly in day-to-day use. However, the
design of these systems makes it difficult, if not impossible, to substantiate that a functional test of the circuitry has
been performed. This requirement should be broken into two requirements. The first should cover data circuitry and
the second should cover voice circuitry. This will allow the drafting team to address the inherent differences in
these two methods of communication.
No
The measures should be modified per our suggested modifications in question 1.
No
The VSL should be modified per our suggested modifications in question 1. R1 VSL - The statement in the VSL
that the responsible entity did not "operationally test" is too broad. It should be more specific with the language
used in the requirement.
No
Purpose - The GOP is still shown in the purpose statement although it was removed from the applicability. Also, it
may be better if the purpose was written more generally as "To ensure adequate communications capabilities for
addressing real-time emergency conditions and ensure communications by operating personnel are effective to
maintain BES reliability". Applicability - In the SDT's document "Scope of Work Assigned to the Reliability
Coordination Standard Drafting Team", the team decided to not include the FERC directive to include the DP in the
applicability with the following reasoning "The proposed revisions do not include the DP entity because they are not
applicable." We would like clarification on this. R1 - It does not appear that the implementation plan addresses the
FERC direction to consider comments from Santa Clara, FirstEnergy, and Six Cities per 693 par. 539 regarding
staffing requirements. Santa Clara asks that these requirements apply "only to operating staff available on site at all
times or includes repair personnel who are available only on an on-call basis". FirstEnergy asks that the "term
[staffed] should not require a physical presence at all facilities at all times because some units, such as peaking
units, are not staffed 24 hours a day". FirstEnergy also suggest "because nuclear units are already subject to
communications requirements in their operating procedures, their compliance with NRC operating procedures
should be deemed in compliance with the NERC Reliability Standards". Six Cities "states that, to avoid
unnecessary staffing burdens, particularly for smaller entities, the Commission should direct NERC to clarify COM002-2 by providing that identification of an emergency contact person on call to respond to real-time emergency
conditions will constitute adequate compliance". R1 - Just as an FYI, with regard to the proposed replacement
requirement statement in the implementation plan: "TOP-005-1, R1 and R3 require adequate telecommunications
for BAs and TOPs to provide each other with operating data as well as providing data to the RC", per recently
stakeholder approved ballots, R1 of TOP-005-1 has been retired and now covered in new standard IRO-010-1.
R1.1 - The existing requirement includes "through predetermined communication paths of any condition that could
threaten the reliability of its area or when firm load shedding is anticipated". The proposed replacement
requirements do not address the need for "predetermined communication paths".
No
The measures should be modified if our comments in question 4 result in changes to the proposed requirements.
No
The VSL should be modified if our comments in question 4 result in changes to the proposed requirements.
No
R3 - should be a sub requirement of R2. These two requirements are sequential in nature and should be measured
at the same time. The VRFs and Time Horizons are the same for both requirements lending to their combination
into a requirement with a sub requirement. In the VSL for R2, an entity is being penalized with a high severity level
for not completely following an RC directive even though it violated safety, equipment, statutory, or regulatory
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requirements. Measuring R2 and R3 at the same time allows for the process to complete prior to the measurement
taking place. R3 - The "or" between "Distribution Provider" and "Purchasing-Selling Entity" should be replaced with
an "and". R4 - Should be revised by adding the phrase "of the expected or actual threat" to the end of the
requirement to add clarity. Existing R7 requirement - This requirement is proposed for retirement because it is
redundant with IRO-014-1 R1. However, it is not clear how the existing requirement to "have clear, comprehensive
coordination agreements with adjacent RCs to ensure that SOL or IROL violation mitigation requiring actions in
adjacent RC areas are coordinated" is covered in IRO-014-1 R1. IRO-014-1 R1 requires agreements for
coordination of actions between RCs to support Interconnection reliability, but it does not specifically require "clear"
and "comprehensive" agreements to mitigate SOL or IROL violations. IRO-014-1 only vaguely covers the existing
requirement R7 of IRO-001-1.
No
M2 - The word "intentional" should be added between "without" and "delay".
No
R2 VSL - The Severe VSL should include after the word directive: "that would not violate safety, equipment,
statutory or regulatory requirements".
No
R2 - As written, this requirement does not clearly define the scope of the authority of the Reliability Coordinator
over analysis tools. Is it the intent of the drafting team to give the RC authority over analysis tools owned and
operated by the RC. Is it the intent of the drafting team to give the RC authority over the analysis tools owned and
operated by the BA, TOP, GOP, etc.? Are the tools intended to be the real-time (EMS) or the off-line engineering
planning analysis tools or any analysis tool used in real-time. Does this include the analysis tools used by field
personnel? This requirement should be revised to specify exactly the analysis tools under the authority of the
Reliability Coordinator.
No
The measures should be modified per our suggested modifications in question 10.
No
The VSL should be modified per our suggested modifications in question 10.
Yes
No
R1 - Should be revised as follows to improve readability and clarity: R1.3 - Add "Exchanging" before "Planned"
R1.4 - Add "Control of voltage" at the beginning of the requirement and delete "for voltage control" at the end of the
requirement. Add a new R1.7 as follows: "A process for resolution of the disagreement covered by R6 of this
standard."
No
The measures should be modified per our suggested modifications in question 14.
No
The VSL should be modified per our suggested modifications in question 14.
Yes
Yes
Group
Bonneville Power Administration
Denise Koehn
Transmission Reliability Program
Yes
Yes
Yes
Yes
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Greg Rowland
Duke Energy
No
Purpose - The purpose statement does not read very well. It either needs another sentence or changes to the
current sentence. The purpose of the standard is to assure proper communications, not to suggest entities need
proper communications as currently written. Suggest changing to, “To assure each Reliability Coordinator,
Transmission Operator and Balancing Authority develops and maintains…. Requirement R1 - What is the definition
of "alternative telecommunications facilities"? Is there another requirement somewhere to have alternative
telecommunications facilities – or is this a new requirement being introduced by this standard? What is the
relationship, if any, between "alternative telecommunications facilities" and EOP-008-1? What is the requirement
for maintaining and testing "alternative telecommunications facilities"; what does “operationally test” mean? Just
because an alternative facility works when it is tested does not mean it will work during an actual failure of the
primary system. Furthermore, what do we do if the “test” fails- are we still compliant? The word “ensure” needs to
be changed to “assure”. Requirement R2 - What does "impacted entity" mean? Requirement R3 - Why can’t others
use alternate language – this limits alternate language to just TOPs and BAs internal operations. TOs, GOPs, and
others may want to use alternate language internally. Need to define language to be used with and between other
relationships – BA to PSE, as an example. Is this a reliability issue or a certification issue? Simply state that:
“Entities may use alternative language for internal operations”. This will allow any entity to use alternative language
for internal operations. The inclusion of TSPs, LSEs, and PSEs in IRO-001-2 indicates the need to include these
functions in the COM-001-2 applicability and requirements concerning the use of English as the approved
language. Requirement R4 - Remove R4 and add DP and GO, as well as all of the other entities listed in IRO-0012, to R1 thru R3.
No
General comments - Not using consistent language regarding “provide evidence” and “shall have and provide upon
request evidence”. Also need to add corresponding requirement number after each measure. Measure M1 - Just
because an alternate facility works when it is tested does not mean it will work during an actual failure of the
primary system. - what do we do if the “test” fails- are we complaint? Clarify that the requirement and measure is to
“test” not "to test successfully". We may test and find that something does not work as expected.
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No
VSL for Requirement R1 - The VSL for R1 seems to imply that an operational test needs to have been performed
in the last 90 days – this is read in conjunction with the data retention requirements. Need to clarify in the
requirement how “quarter basis” is defined - is it the calendar quarter, or a rolling 90 days? In addition, the VSLs for
Requirement R1 appear to violate NERC guidlelines, since the Moderate, High and Severe VSLs are based upon
cumulative violations of the Lower VSL.
No
Requirement R1 - As defined by Merriam Webster, the use of the word “ensure” implies virtual guarantee ; while the use of the alternative word “assure” implies the
removal of doubt and suspense from a person's mind. We suggest that “assure” is more appropriate than “ensure”
in this context in the standards. The use of words like “clear, concise, and definitive manner” is subject to
interpretation. This same language is used in the VSLs. Depending on the interpretation of this phrase, an entity
could be found to be in a “Severe” violation level. The issuer of the directive should not be subject to noncompliance if the recipient of the directive refuses to repeat back. Need to add a requirement, measure, and VSL
that clarifies that the recipient of a directive is obliged to perform their portion of a repeat-back. The inclusion of
TSPs, LSEs, and PSEs in IRO-001-2 indicates the need to include these functions in the COM-002-3 requirement
concerning repeat-backs. What is a “directive”? The regional compliance processes are having difficulty in auditing
this existing standard due to lack of clarity of what constitutes a directive. "Directive" should be defined as being
associated with real-time operational emergency conditions, and not ordinary day-to-day communications.
Otherwise a VRF of High is not warranted.
No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The issuer of the directive
should not be subject to non-compliance if the recipient of the directive refuses to repeat back. Need to add a
requirement, measure, and VSL that clarifies that the recipient of a directive is obliged to perform their portion of a
repeat-back.
No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The issuer of the directive
should not be subject to non-compliance if the recipient of the directive refuses to repeat back. Need to add a
requirement, measure, and VSL that clarifies that the recipient of a directive is obliged to perform their portion of a
repeat-back.
No
Requirement R1 - What happens if the RC failed to recognize that such an event was happening as opposed to
failed to take action. Is this intended to cover both scenarios? The term “Adverse Reliability Impacts” is being
changed and is listed in the associated Implementation Plan. The revision development of this definition needs to
go thru Due Process. The inclusion of TSPs, LSEs, and PSEs here indicates the need to include these functions in
the COM-001-2 requirements concerning the use of English as the approved language. In addition, this also
indicates the need for all of these listed entities to be included in COM-002-3 requirements concerning repeatbacks. The RC, TOP, and BA should not be placed in a possible non-complaint state because the counter party
refuses a repeat-back AND these requirements are not applicable to the counter party. Requirement R2 - The
language in the Moderate VSL of R2 recognizes another potential reason for delay in execution of a directive.
Requirement 2 of the Standards needs to be modified to also recognize this potential. Requirements R2 and R3 Clarify that entities are obligated to take action and confirm directives only from their Reliability Coordinators, not
from any Reliability Coordinator. Requirements R2, R3, R4, R5 - Inconsistent use of “timing” words in the standards
– "without intentional delay" and "immediately". Suggest deleting these words due to the difficulty of determining
compliance. Requirement R4 - The term “Adverse Reliability Impacts” is being changed and is listed in the
associated Implementation Plan. The revision of this definition needs to go through Due Process. Requirement R5
- The VRF should be "Lower" instead of "High" since the notification is that the threat has been mitigated. Also, the
term “Adverse Reliability Impacts” is being changed and is listed in the associated Implementation Plan. The
revision of this definition needs to go through Due Process.
No
Measures M2, M4 and M5 use the terms "without delay" and "without intentional delay". Suggest deleting these
words due to the difficulty of determining compliance. The term “Adverse Reliability Impacts” is being changed and
is listed in the associated Implementation Plan. The revision of this definition needs to go through Due Process.
No
The language in R1 of the VSL is not consistent with the requirements and measures in the standard. The VSL
needs to recognize that the RC may EITHER act or give direction to others to act. The term “Adverse Reliability
Impacts” is being changed and is listed in the associated Implementation Plan. The revision of this definition needs
to go through Due Process. The language in R2 of the VSL places an entity in Moderate or High violation level
even if failure is “allowed” in the standard; i.e. failure to act is due to violation of safety, regulatory, statutory
requirements. The language in R2 of the VSL recognizes another potential reason for delay in execution of a
directive. Requirement R2 of the Standard needs to be modified to also recognize this potential.
No
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Requirement R1 - This requirement is in the wrong standard – this is a Facilities standard. This requirement
belongs in another standard. Question: Is there a requirement in another standard that compels the TOPS, BAs,
etc to provide the requested data? Requirement R2 - Need to clarify whose analysis tools (I assume it is the RCs
analysis tools, not the analysis tools of another entity) and planned maintenance to what – is it tools, facilities,
transmission, generation, etc. Depending on the answer above, this requirement is in the wrong standard – this is a
Facilities standard. This requirement belongs in another standard. Question: Where is the Requirement for the RC
to have analysis tools? It appears that the Requirement the RC has analysis tools have been removed in the
revisions to the standard.
No
See response to Question #12 above. If the requirements are moved to another standard, the measures aren't
needed here.
No
R1 VSL - As a general comment, this VSL is unclear and would be difficult to audit. This VSL uses subjective terms
like “material impact” and “minimal impact”. These terms are not used in the associated requirement or measure
and should be removed from the VSL. This VSL uses terms like “majority, but not all”; “some, but less than a
majority” which provides an opportunity for a subjective review by Compliance as to what a complete listing of data
requirements should be. This term is not used in the Requirements or Measures and should be removed from the
VSL. This VSL introduces a concept, data the RC needs for “ … administrative purposes, such as data reporting
…”. This concept is not included in the Requirements or Measures portions of the Standard and should be removed
from the VSL. This VSL should be written to simply assess whether the RC has made determination of what its
data needs are and whether those needs have been communicated to the entities in the footprint. R2 VSL - This
VSL clarifies the questions posed above regarding what the RC needs approval rights over. R2 needs to be
modified to include this clarity. This VSL needs to clarify that the RC approval rights are for the RC's tools, not tools
of other entities. The Severe level of this VSL needs to be re-written along the lines of: The RC does not have
approval rights for planned maintenance or outages to its analysis tools.
Yes
No
R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures, processes and plans in
place with each RC within the RC's Interconnection. We suggest the phrasing should be tightened up to convey the
original meaning that the team intended. For example, does the team intend for the FRCC RC to have an
agreement with the PJM or MISO RC? We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as
follows: R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing a mitigation
plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper steps to be taken. We
suggest deleting R4.1 and adding a second sentence to R4: The frequency of these communications shall be at
least weekly. R4: The word "impacted" makes it sound like these calls are only to be made when problems are
expected or are occurring. If this requirement is intended more for operational awareness calls (such as the daily
SERC RC call), then the word "impacted" needs to be changed to "contiguous". We suggest rewriting R5 to read:
In the event that an operating issue cannot be confirmed, each Reliability Coordinator shall operate as though the
problem exists.
No
See comment #14 above. Also, Measure M5 is inconsistent with Requirement R5. It should mirror the requirement.
Also, need to add the requirement number at the end of each Measure.
No
See comments #14 and #15 above - VSLs need to be revised to correspond to the revised Requirements and
Measures.
Yes
No
See comment #14 above regarding re-write needed for Requirement R6 of IRO-014-2.
Individual
Thad Ness
AEP
No
A precise definition of telecommunications facilities needs to be established in this standard. R2 needs to be
clarified regarding impacted utilities. FERC Order 693 suggests that this standard should apply Distribution
Providers (DP) along with Generation Operators (GOP). AEP acknowledges that there needs to be some level of
coordination and communication between DP’s and other function model entities; however, the requirements, as
applied to the DP, for telecommunications with the TOP and BA might not address the current communication
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paths adequately. Today, the DP usually does not communicate with the RTO (performing the BA and/or TOP
function), but the DP could either communicate directly or through a joint action agency to the IOU that may serve
as the TO (or maybe the TOP). As this draft is written the DP’s would be required to have telecommunication
facilities with the RTO in this scenario. There will likely be many exceptions to the rule that the requirements and
measures create when applied to the DP. We ask that the drafting team consider the applicability, some of the
current channels of communications, and options for addressing the FERC comments without creating
telecommunication paths that do not make practical sense.
No
M2 needs to be clarified regarding impacted functions.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
Yes and No
Wording in question: R.2/M.2 Each … Load-Serving Entity, or Purchasing-Selling Entity shall have evidence that it
acted without intentional delay to comply with the Reliability Coordinator's directives. R.3/M.3 Each … Load-
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Serving Entity, or Purchasing-Selling Entity shall have evidence that it confirmed its ability to comply with the
Reliability Coordinator's directives. [1] Question: Is this wording absolutely necessary? And then, is it sufficient, if
needed? Comment: First, we would question whether there is a specific need to include this wording. Is the IRO001 Reliability Standard sufficient without it? [2] Question: Is this wording unambiguous? Comment: The wording
seems somewhat vague and ambiguous. Analysis: The wording appears to establish performance standards
("without intentional delay", “shall immediately confirm”) and evidentiary requirements (“evidence that it acted” or
“evidence that it confirmed”), but without using pre-existing defined terms, establishing new defined terms, or
defining these terms as used in context. [3] Intentional vs. Unintentional, Valid Intentional vs. Inappropriate
Intentional? How does one differentiate between intentional and unintentional delay? When is and how much delay
is valid or inappropriate? Isn’t some intentional delay necessary to ensure that the other parts of the requirement
being are met, e.g., “… unless such actions would violate safety, equipment, or regulatory or statutory
requirements”? Mightn’t some acceptable amount of valid intentional delay be necessary to insure that any such
RC directive and entity action would not in fact violate these safety, equipment, or regulatory or statutory
requirements? [4] What is the timeliness standard? How are the terms “without delay” and “immediately conform”
defined? What standard commercial measures would apply, e.g., “reasonably efforts” vs. “best efforts?” Are these
terms measured in units of time (seconds or minutes) or in units of performance quality? Does a poorly considered
“immediate” reply meet the standard, while a well considered reply, which is intentionally delayed, yet still
appropriate, fail to meet this standard? Is that the best outcome? [5] What is this Evidentiary Standard? Is the
sought-after “evidence” sufficiently well defined, e.g., phone logs, computer e-mail, control center computer logs,
hand-written operator journals, etc.? What form of evidence is necessary and sufficient to demonstrate that the
entity met this evidentiary standard? How is failure to meet this uncertain standard measured, judged and
penalized?
Yes and No
[Comments repeated for Measures] Wording in question: R.2/M.2 Each … Load-Serving Entity, or PurchasingSelling Entity shall have evidence that it acted without intentional delay to comply with the Reliability Coordinator's
directives. R.3/M.3 Each … Load-Serving Entity, or Purchasing-Selling Entity shall have evidence that it confirmed
its ability to comply with the Reliability Coordinator's directives. [1] Question: Is this wording absolutely necessary?
And then, is it sufficient, if needed? Comment: First, we would question whether there is a specific need to include
this wording. Is the IRO-001 Reliability Standard sufficient without it? [2] Question: Is this wording unambiguous?
Comment: The wording seems somewhat vague and ambiguous. Analysis: The wording appears to establish
performance standards ("without intentional delay", “shall immediately confirm”) and evidentiary requirements
(“evidence that it acted” or “evidence that it confirmed”), but without using pre-existing defined terms, establishing
new defined terms, or defining these terms as used in context. [3] Intentional vs. Unintentional, Valid Intentional vs.
Inappropriate Intentional? How does one differentiate between intentional and unintentional delay? When is and
how much delay is valid or inappropriate? Isn’t some intentional delay necessary to ensure that the other parts of
the requirement being are met, e.g., “… unless such actions would violate safety, equipment, or regulatory or
statutory requirements”? Mightn’t some acceptable amount of valid intentional delay be necessary to insure that
any such RC directive and entity action would not in fact violate these safety, equipment, or regulatory or statutory
requirements? [4] What is the timeliness standard? How are the terms “without delay” and “immediately conform”
defined? What standard commercial measures would apply, e.g., “reasonably efforts” vs. “best efforts?” Are these
terms measured in units of time (seconds or minutes) or in units of performance quality? Does a poorly considered
“immediate” reply meet the standard, while a well considered reply, which is intentionally delayed, yet still
appropriate, fail to meet this standard? Is that the best outcome? [5] What is this Evidentiary Standard? Is the
sought-after “evidence” sufficiently well defined, e.g., phone logs, computer e-mail, control center computer logs,
hand-written operator journals, etc.? What form of evidence is necessary and sufficient to demonstrate that the
entity met this evidentiary standard? How is failure to meet this uncertain standard measured, judged and
penalized?
Yes and No
Agreement uncertain, subject to further clarification of Requirements and Measures performance standards and
definitions (see our comments on Requirements and Measures). Without clearer definitions, e.g., for "immediate,"
or any allowance for appropriate intentional delay, it is not entirely clear that the VSL's comport with the ultimate
meaning, intent and needed wording to be incorporated into the Requirements and Measures. Why would failure to
fully comply, when precluded by conditions specifically allowed in the standard, necessarily be a problem, so long
as the RC received timely notice, however defined?
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Individual
Kevin Koloini
Buckeye Power, Inc.
Yes and No
What constitutes "telecommunications facilities"?
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Yes and No
abstain
Individual
Jason Shaver
American Transmission Company
Yes and No
If some language is clarified, we support the revisions. R2 states that "Each TO shall notify impacted entities of the
failure of its normal telecommunications facilities…". If a phone line goes down and an alternate phone line is used,
it is an excessive requirement to notify the impacted entities when there is no impact upon communication or the
BES. The wording should be clear that notification is only required if an alternate means of communication is
necessary. A defined timeframe for notification should be added to the requirement. It is possible that the loss of
telecommunication facilties can occur without the loss of a control center. So, the redundancy with EOP-008 to R4
should be clarified.
No
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M2 should be changed to reflect the comments noted in Question 1 for R2.
Yes
Based upon revisions to Question 1.
Yes
Yes and No
As long as the measurement of compliance does not include proving the negative, that no directives were issued.
No
R1-High VSL-If the directive was followed and there was no threat to the BES, then a lack of repetition of the
directive does not constitute a "high" VSL. Suggest that this be a low or moderate VSL.
No
R2 refers to "intentional delay". The determination of intent should be left to the VSL portion of the standard, not the
requirement portion.
Yes
If some language is changed, we support the revisions. R2 has language in it that should be added to M4 to be
consistent. In M2, we propose adding language "unless such actions would violate safety, statutory or regulatory
requirements."
No
VSL's for R2 and R3 are not appropriate. In order to assess a situation we may not be able to immediately inform
the RC of our ability to comply with the directive. The high VSL for R2 currently states that if we do not follow the
directive because of safety, statutory or regulatory requirements, it is a high VSL. An entity should not be penalized
for not breaking the law.
Abstain.
Abstain.
Abstain.
No
The accountability and monitoring addressed in this Standard is still required. The drafting team's intent was that
the ability to monitor is part of the certification process. However, certification is to Standards, and if there is not a
Standard which addresses this issue, then an entity cannot certify to it.
Abstain
Abstain
Abstain
Abstain
Abstain
Group
ISO/RTO Council Standards Review Subcommittee
Charles Yeung
SPP
Yes and No
We suggest that a definition of telecommunications be written by the drafting team because it is not clear what all
telecommunications is intended to be included. Does this requirement apply to data, voice, rtus, networks, etc? For
requirement R2, e suggest that you strike the final clause: "and shall verify that alternate means of
telecommunications are functional." It is obviated by the requirement to notify impacted parties. The responsible
entity is already implicitly required to verify its alternate means of communication is functional since it is required to
notify its impacted parties of the failure of its normal telecommunications. It can't notify its impacted parties if the
alternate communications means are not funcitonal. The VRF for new requirement 1 should be lower. It does not fit
the definition of a medium VRF. A medium VRF requires that a violation of the requirement directly affect the state
or capability or the ability to effectively monitor and control. Failure to test does not result in directly affecting the
state or capability or the ability to effectively monitor and control. At a minimum, a failure of the alternative
communication systems and primary communication systems must occur first. The failure to perform a single test
in a given quarter does not mean that primary and alternative communication systems will fail. Thus, testing is
really an administrative issue and should thus be a lower VRF. In the Data Retention section, Distribution Provider
and Generation Operators should be added. Currently, there are no data retention requirements listed for them.
Suggest modifying the language regarding data retention for compliance violations to: "… is found in violation of a
requirement, it shall keep information related to the violation until it the Compliance Enforcement Authority finds it
compliant."
Yes and No
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M3: The evidence to show that concurrence is in place to allow communication using a language other than
English is missing. The Measure as written merely asks for evidence that communication in a different language
has occurred.
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission established in their
"Order on Violation Severity Levels Proposed by the Electric Reliability Organization". Guideline 4 requires that a
VSL should be based on a single violation. The VSLs as defined accumulate the number of consecutive quarters.
This would imply that a single violation could last more than a year and that the compliance auditor could not
determine sanctions until the entity becomes compliant or year has passed. A single violation appears to be the
failure to test in a single quarter. This requirement is binary in nature in that it is either met or it isn't. We suggest
that only a lower VSL should be defined as: "The RC, TOP, or BA failed to test the backup telecommunication
facilities for a single calendar quarter." The Lower VSL for R2 is not possible. The act of notifying all impacted
entities of the failure of their primary telecommunication system requires the use of the alternative
telecommunications systems which is a form of verying that the alternative telecommunications facilities are
functional. The drafting team should consider applying the numeric performance category of the VSL Development
Guideline Criteria for R2. (i) R1: Suggest to revise the conditions for all levels to read "…failed to operationally test
the altarnative communication facilities within the last……… (ii) R2: The second part under Severe is not needed
since failing to notify any impacted entities would imply no communication to the affected entities anyway. If
verification of the functionality of the alternate means of telecommunications is also critical even without
communicating to the affecte entities, then the second condition should be an "OR". (iii) R3: Failure to having
concurrence to use a language other than English for communications between and among operating personnel
responsible for real-time operations by itself does not consitute a violate of any requirements; it is the absence of
such a concurrence AND having used a language other than English that would consitute a violation. Suggest to
revise this condition.
Yes
Yes
Yes
Yes and No
New requirement R2 should omit act without intentional delay. Use of intentional implies willful disregard for
compliance for the requirement. Intention should not be addressed as part of the compliance with the requirement
but rather through the enforcement process once the compliance auditor has identified a violation. The word
immediately should be removed from the new R3. This attempts to time frame the response of the responsible
entity and remove the judgment from the compliance auditor. We agree with the concept of doing this but in reality
it only confuses the issue and the compliance auditor will likely apply his judgment regarding what immediate is
anyway. Additionallly, the requirement attempts to separate the act of confirming that the responsible entity can
take the action from notifying the RC that the entity can't take the action. This is not logical. What RC is going to
request a responsible entity to take action that would violate safety, equipment, statutory, or regulatory
requirements? The RC should already be aware of those requirements and likely won't direct actions that violate
them. Thus, the likely scenario is that the responsible entity will attempt to take action and discover that equipment
is not funcitoning properly and thus notify the RC. We suggest striking the "shall immediately confirm the ability to
comply with the directive or" from the requirement. This part of the requirement is not needed because the
responsible entity is already obligated to follow the RCs directive (see order 693.) Thus, the assumption is that the
order will be followed unless it can't be followed because it will violate safety, equipment, statutory, or regulatory
requirements. Requirements R4 and R5 are unnecessary. New R1 requires the RC to direct actions to be taken by
the TOP, BA, GOP, TSP, LSE, DP and PSE to prevent or mitigate the magnitude or duration of events that result in
Adverst Reliability Impacts. The RC can't direct these actions without notifying all impacted TOPs and BAs. They
would also have to notify them when actions are no longer necessary. The VRF for R5 should not be High. Failure
to notify others when potential threats to system reliability have been mitigated does not consititue a high risk to the
interconnected system. We suggest it be reduced to a Medium (i.e., that it affects control of the BES).
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in Severe. From a practical
perspective, what is the difference between directing actions and acting? We don't believe there is any. The actions
are the result of the RC authority whether the RC takes the actions themselves or directs someone else to. We
suggest a better alternative for the VSL levels would be for the High level to reflect that the RC did not act or direct
actions to prevent an Adverse Reliability Impact and Severe would be that the RC did not act or direct ations to
mitigate the magnitude or duration of an existing Adverse Reliability Impact. The moderate VSL for R2 is not
practical and too subjective. What constitutes a delay? What if the responsible entity takes five minutes to
determine how to carry out the action or if their equipment currently is capable of carrying out the action? Is this a
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delay? We suggest striking this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory, or regulatory
requirements a violation. This is in direct conflict with the requirement. We suggest that the High VSL should be
struck. We suggest the Severe VSL should be that the responsible entity failed to follow the RC directive and it
would not have violated the safety, equipment, statutory or regulatory requirements. Currently, the Severe category
does not allow that the responsible entity may not be able to carry out the directive due to the violation of safety,
equipment, statutory, or regulatory requirements. In question 7, we request that the drafting team strike part of
requirement 3. The striking of that portion of requirement 3 obviates the lower VSL. In paragraph 27 of the ORDER
ON VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY ORGANIZATION, the
Commission expresses "that, as a general rule, gradated Violation Severity Levels, whereever possible, would be
preferable to binary Violation Severity Levels". Given that it is possible to define gradated VSLs for R4 and R5, we
suggest that the drafting team should consider applying the numeric performance category of the Violation Severity
Levels Development Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
No
New Requirement R2 is no longer needed as a result of paragraph 112 in Order 693-A. Since the RC's "authority to
issue directives arises out of the Commission's approval of Reliability Standards" the RC already has veto authority
or will have once R1 IRO-001-2 is approved. This requirement obligates the RC to take actions or direct actions to
prevent Adverse Reliabilty Impacts. Veto outages of equipment and analysis tools would fall into this category even
if the RC couldn't say for certain that an Adverse Relability Impact was going to occur but rather they are
concerned one could occur due to heavy loads for example.
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a data specification
document and actual verification that data has been received. The letter or equivalent is only needed if data has
not been supplied. Demonstration of the actual receipt the data would be easy.
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its data requirements and
requested that data and then follows with that it didn't request that data. The second option in the Lower VSL
category is not practical and a compliance auditor would not be in a position to determine this. In fact, if the
administrative data is not requested, other administrative requirements for reporting would be violated. Additionally,
it does not make sense that an RC would determine its data needs and then omit data for administrative reporting.
Further, is it the compliance auditor's job to judge if the data the RC requests is sufficient or is it his job to see that
the RC has met the requirement to define the data? The remaining VSLs imply that the RC may define only partial
data requirements. This does not seem likely. Why would the RC do this? This VSL appears to add to the
requirement by making it appear that the compliance auditor is to judge the completeness of the data requirement.
This violates Guideline 3 of the FERC ORDER ON VIOLATION SEVERITY LEVELS PROPOSED BY THE
ELECTRIC RELIABILITY ORGANIZATION. Practically, it would not be enforceable anyway. It would require the
RC to admit that they did not include administrative data in the their data requirements. It is doubtful this would
happen because the RC likely believes they prepared a complete data requirement document. We suggest that the
VSLs should be: Severe: The RC did not determine it data requirements or the RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 75 to
100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. High: The RC could not demonstrate it requested
the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 50 and less than or
equal to 75% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Medium: The RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be deomstrated for greater than 25% and
less than or eqal to 50% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. Lower: The RC could not
demonstrate it requested the necessary data if actual receipt of the necessary data can't be deomstrated for
greater than 0% and less than or equal to 25% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs. R2
VSLs are not needed er paragraph 112 of Order 693-A. The Severe VSL contradicts the requirement.
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum. Please strike R1.6. RCs
already have the authority to act per paragraph 112 of Order 693-A. Since R2 requires the RCs to agree, is the
"mutually agreed to" clause in R1.1 necessary? Please strike requirements R4 and R4.1. It is duplicative to R1.1.
Conference calls are a form of communication and should be address per R1.1. R5 is confusing. If a reliability
issue isn't confirmed, doesn't this mean there is no reliability issue? Isn't this the point of confirming? Additionally,
we suggest using validate instead of confirm. As Requirement 1 is currently written, one could interpret the
requirement for every Operating Process, Procedure and Plan to address each of the sub-requirements. That is not
necessary. The drafting team needs to consider modifying the requirement to make it clear that not every subrequirement must be addressed in every Operating Process, Procedure, and Plan and to also make it clear that the
some sub-requirements may only be appropriately addressed in a Process but not a Plan for instance. Use of the
term collectively may resolve this dilemma.
No
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Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about System Operators
yet the measurement does. The measurement should just be to verify that the RC has have Operating Processes,
Procedures, and Plans. The sub-measurements are not measurements at all. There should be the single
measurement to verify the Operating Processes, Procedures, and Plans have been developed and address the
sub-requirements. This really points out the problem with making the criteria that must be considered in the
Operating Processes, Procedures, and Plans sub-requirements in the first place. They aren't requirements of any
sort. They represent criteria. The drafting team should consider making them a bulleted list without the Rs, then the
drafting team won't feel compelled to write sub-measures that don't measure anything.
No
For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots" should be removed. We
don’t' agree with the VSLs in R4 since we believe R4 should be struck. The Lower VSL for R6 should not even be a
violation unless the impact was negative. If the RC implemented a different mitigation plan and resolved the issue,
then the RC was likely correct to disagree.
Yes
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the wording of the
requirement. The new wording is much more confusing. Until we reviewed IRO-016-2, it was not clear at all that R6
in IRO-014 was attempting to mimic R1 and its sub-requirements in IRO-016-2.
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Consideration of Comments on Set of Reliability Coordination Standards (Project
2006-06)
The Reliability Coordination Standards Drafting Team (RC SDT) thanks all commenters who submitted
comments on the set of Reliability Coordination Standards. These standards were posted for a 45-day
public comment period from August 5, 2008 through September 16, 2008. Stakeholders were asked to
provide feedback on the standards through a special electronic standard comment form. There were 29
sets of comments, including comments from more than 70 different people from approximately 50
companies representing 8 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
The following standards remain within the scope of this project:
COM-001-2 — Communications
COM-002-3 — Communication and Coordination
IRO-001-2 — Reliability Coordination — Responsibilities and Authorities
IRO-002-2 — Reliability Coordination — Facilities
IRO-005-1 — Reliability Coordination — Current Day Operations
IRO-014-2 — Coordination among Reliability Coordinators
IRO-015-1 — Notifications and Information Exchange between Reliability Coordinators
IRO-016-1 — Coordination of Real-time Activities between Reliability Coordinators
The RC SDT has revised some of the requirements, measures, violation risk factors and violation severity
levels for COM-001, COM-002, and IRO-001, and IRO-014 based on the comments received. A
summary of the drafting team’s consideration of comments follows:
Requirements, Measures and VSLs in COM-001-2
Requirements: The RC SDT received several comments regarding the intent of the term
“telecommunications facilities”. For COM-001-2, the RC SDT envisions telecommunications to be voice
or message communication between operating personnel. The standard has been renamed
“Communications” and the term “telecommunications facilities” was replaced with “interpersonal
communications capabilities” throughout the standard to better reflect the intent of the RC SDT.
We also received comments regarding the applicability of the standard that suggested adding the other
entities listed in IRO-001 (Transmission Service Provider, Load-serving Entity and Purchasing-Selling
Entity). The RC SDT contends that, in order to receive and carry out directives, an entity must be able to
communicate with the Reliability Coordinator …either directly or through other entities (e.g. – a
Distribution Provider may receive a directive from the Transmission Operator who received it from the
Reliability Coordinator). We have not expanded the applicability as suggested as we feel that this
expands the standard beyond the reliability intent. The RC SDT contends that the addition of the
Transmission Service Provider, Load-Serving Entity and Purchasing Selling Entity to COM-001 adds no
reliability benefit as the interactions with these entities are commercial in nature. It is not necessary nor is
it practical, for reliability purposes, for every entity to have normal and back-up interpersonal
communications capabilities with every other entity. The SDT did, however add the Transmission Service
Provider, Load-serving Entity and Purchasing-Selling Entity to the list of entities in R3 that must use
English Language for inter-entity communications.
Other commenters had concerns with regard to R2 and the intent with regard to length of outages. The
requirement was revised as:
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify
impacted entities within 60 minutes of the detection of a failure (30 minutes or longer) of its their
normal interpersonal communications capabilities telecommunications facilities, and verify the
alternate means of telecommunications are functional.
The informational (last) sentence of R3 was removed per stakeholder suggestions:
R3. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, Balancing
Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, PurchasingSelling Entity, and Distribution Provider shall use English as the language for all inter-entity Bulk
Electric System reliability communications between and among operating personnel responsible
for the real-time generation control and operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use an alternate language for internal
operations.
Measures: Commenters suggested general as well as specific revisions to the measures. One general
comment suggested making the language consistent among the measures regarding evidence. M1-M3
were revised to include the phrase “shall have and provide upon request evidence that …”.
Several commenters suggested revisions to M3. The RC SDT revised M3 based on the comments
received suggesting that the applicability be expanded and added the Generator Operator, Distribution
Provider, Transmission Service Provider, Purchasing-selling Entity, and Load-serving Entity to the
measure. Several entities commented that M3 did not match R3 which included an explanatory sentence
that allowed an entity to use a language other than English for its internal communications. The
informational second sentence was removed from Requirement R3, thus eliminating the “disconnect”
between the requirement and the measure. All measures were revised as necessary to reflect revisions
to requirements.
VSLs: The RC SDT made revisions to the VSL’s based on the comments received and also to reflect
revisions to the associated requirements. The SDT received comments that the VSLs for R1 and R2
were based on multiple violations rather than a single violation and revised the VSLs to reflect a single
violation, which is one of FERC’s guidelines for VSLs.
Requirements, Measures and VSLs in COM-002-3
The work of the IROL SDT resulted in the retirement of R1 from the standard. The RC SDT received
comments recommending expanding the applicability of the standard and separating Requirement R1
into two distinct requirements. The applicability was expanded to include Reliability Coordinator,
Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, LoadServing Entity, Distribution Provider, and Purchasing-Selling Entity. The requirements were revised to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a
directive associated with real-time operational emergency conditions shall require the recipient of
the directive to repeat the intent of the directive back; and shall acknowledge the response as
correct or repeat the original statement to resolve any misunderstandings. [Violation Risk Factor:
High][Time Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity that is the recipient of a directive issued per Requirement R1 shall
repeat the intent of the directive back to the issuer of the directive. [Violation Risk Factor:
High][Time Horizon: Real-Time]
The purpose statement was also revised to reflect the revisions to the standard: “To ensure
communications by operating personnel are effective.”
The RC SDT received comments recommending expanding the applicability of the standard and
separating Requirement R1 into two distinct requirements. The applicability was expanded to include
Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity. The
measures were revised to:
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a
directive associated with real-time operational emergency conditions shall have evidence such
as voice recordings or transcripts of voice recordings to show that it required the recipient of
the directive to repeat the intent of the directive back; and acknowledged the response as
correct or repeated the original statement to resolve any misunderstandings.
M2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and PurchasingSelling Entity that is the recipient of a directive issued per Requirement R1 shall have evidence
such as voice recordings or transcripts of voice recordings to show that it repeated the intent of
the directive back to the issuer of the directive.
VSLs: The RC SDT received comments recommending revisions to the VSLs based on revisions to the
requirements and measures. The RC SDT did this and created new VSLs for new Requirement R2.
Requirements, Measures and VSLs in IRO-001-2
The RC SDT has received a notable number of comments suggesting edits to the proposed requirements
and measures for the draft standard, particularly regarding the phrase “without intentional delay.” The
comments do not oppose the objective of the phrase, but often point out the issues of measuring intent
and measuring delay time.
To maintain the intent while improving the measurability of the requirement, the SDT proposes to modify
the standard as follows: delete the phrase ‘without intentional delay’ and leave the obligation of response
and timing an unstated requirement of R1 “The RC shall act or direct actions…”
An RC that requires a given action in a given time will be expected to inform the impacted entities of
those actions and time requirements. This would obviate the need for providing a measure for “intent”,
but still maintain the reliability intent of the original requirement.
The VSLs were revised to reflect revisions to the requirements as well as the comments of stakeholders.
Several comments suggested that there was no fundamental difference between the RC “acting” or
“directing actions”. The RC SDT agreed and removed the High VSL for R1 and revised the Severe VSL
accordingly. Other commenters suggested removing the High VSL from R2 as the VSL contradicted the
requirement. The RC SDT agreed and removed the VSL.
Requirements, Measures and VSLs in IRO-002-2
Since the inception of this project (2006-06), the IROL Standards Drafting Team has proposed,
successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1:
Reliability Coordinator Data Specification and Collection. The work of the IROL SDT retired IRO-002-2
Requirement R1. The team also received concern about eliminating the requirement to monitor
frequency. While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even
more concerned with the subjectivity that any attempt to measure “Monitoring” can provide. It is the SDT’s
contention that adherence to reliability standards that require the said monitoring cannot be demonstrated
unless the entity is closely monitoring the system parameters. Furthermore, the SDT contends that any
requirements that describe the monitoring facilities needed to fulfill fundamental duties should be
embedded in entity certification requirements. With IRO-014 and IRO-001 R1 in place, the actual act of
monitoring is a secondary task that is inherent in responding to situations or events that could have an
adverse impact on reliability. The team declined to delete R2 (Reliability Coordinator veto over analysis
tool outages) as it was a specific recommendation from the 2003 Blackout report. This requirement was
revised and moved into IRO-001-2 as R6.
Retirement of IRO-005-1
Several commenters had concerns around removing the requirement to monitor frequency (IRO-005-1
R8). The intent of this monitoring activity was incorporated into IRO-002-2, R1. Other commenters had
concerns with the removal of other monitoring requirements in the standard. While the Standard Drafting
Team (SDT) recognizes the concern raised, the SDT is even more concerned with the subjectivity
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
associated with any attempt to measure “Monitoring.” It is the SDT’s contention that adherence to
reliability standards that require the said monitoring cannot be demonstrated unless the entity is closely
monitoring the system parameters. Furthermore, the SDT contends that any requirements that describe
the monitoring facilities needed to fulfill fundamental duties should be embedded in entity certification
process requirements. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a
secondary task that is inherent in responding to situations or events that could have an adverse impact on
reliability.
Requirements, Measures and VSLs in IRO-014-2
Several commenters expressed concerns with the term “impacted” and suggested replacing this with
“other”. The RC SDT believes “impacted” directly relates to the purpose statement. The original wording
of “one or more other” is vague and difficult to measure. Using the word “other” presents a similar
situation. The RC SDT chose to use the word “impacted” to tighten the requirement and remove
ambiguity. The RC SDT does not intend for non-contiguous Reliability Coordinators to have “Reliability
Coordinator Agreements”, but to have Procedures, Processes, or Plans with impacted Reliability
Coordinators. Other commenters suggested striking the term “as a minimum” in R1 and the RC SDT
agrees and has modified R1 accordingly.
Some commenters did not agree with the wording of the two new requirements in IRO-014 that were
formerly in IRO-016. The SDT modified and subdivided the requirements into four requirements (R5 –
R8) shown below:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify
impacted Reliability Coordinators. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the
identified Adverse Reliability Impact cannot be agreed to by the impacted Reliability Coordinators.
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and
Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a
mitigation plan when the impacted Reliability Coordinators can not agree that the problem exists.
[Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and
Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the
Reliability Coordinator who has the identified Adverse Reliability Impact when the impacted
Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor: Medium][Time
Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Several commenters suggested that the High and Severe VSLs for R2 contradicted the requirement. The
RC SDT agreed and removed the “nots” from the VSLs. Several commenters had suggested revisions
for the VSLs for R6, which was imported from IRO-016. VSLs were changed to support the revised
requirements.
IRO-015-2
Stakeholders agree with the proposal to move the requirements into IRO-014-2 and retire IRO-015 as a
separate standard.
IRO-016-1
Stakeholders agree with the concept of moving the requirements of IRO-016-1 into IRO-014-2. Some
commenters did not agree with the wording of the new requirements in IRO-014 that were formerly in
IRO-016. The RC SDT made some revisions to the requirements listed in IRO-014-2. There are now 4
requirements are listed above in IRO-014-2 summary.
Implementation Plan - Proposed Effective Dates
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
The RC SDT received comments that COM-001-2, R5 should have an effective date immediately upon
regulatory approval. The RC SDT agrees and will request an effective date that is the first possible
effective date – the first day of the first calendar quarter following applicable regulatory approval – or in
those jurisdictions where no regulatory approval is required, the first day of the first calendar quarter
following Board of Trustees adoption.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission, you
can contact the Vice President and Director of Standards, Gerry Adamski, at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Index to Questions, Comments, and Responses
1.
Do you agree with the revisions to the Requirements in COM-001-2 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 11
2.
Do you agree with the revisions to the Measures in COM-001-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ........................................... 27
3.
Do you agree with the Violation Severity Levels proposed in COM-001-2 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 35
4.
Do you agree with the revisions to the Requirements in COM-002-3 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 42
5.
Do you agree with the revisions to the Measures in COM-002-3 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ........................................... 50
6.
Do you agree with the Violation Severity Levels proposed in COM-002-3 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 54
7.
Do you agree with the revisions to the Requirements in IRO-001-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ........................................... 58
8.
Do you agree with the revisions to the Measures in IRO-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area. .................................................. 69
9.
Do you agree with the Violation Severity Levels proposed in IRO-001-2 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 75
10.
Do you agree with the revisions to the Requirements in IRO-002-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ........................................... 85
11.
Do you agree with the revisions to the Measures in IRO-002-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area. .................................................. 93
12.
Do you agree with the Violation Severity Levels proposed in IRO-002-2 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area............................. 97
13.
Do you agree with the revisions to IRO-005-1 as shown in the posted Standard and Implementation
Plan? The RC SDT is recommending retiring or moving all of the requirements and retiring this
standard. If not, please explain in the comment area. .................................................................... 103
14.
Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ......................................... 108
15.
Do you agree with the revisions to the Measures in IRO-014-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area. ................................................ 119
16.
Do you agree with the Violation Severity Levels proposed in IRO-014-2 as shown in the posted
Standard and Implementation Plan? If not, please explain in the comment area........................... 124
17.
Do you agree with the RC SDT recommendation to retire IRO-015-2 and move the requirements
into IRO-014-2? If not, please explain in the comment area........................................................... 129
18.
Do you agree with the revisions to IRO-016-2 as shown in the posted Standard and Implementation
Plan? If not, please explain in the comment area. .......................................................................... 132
19.
If you have any other comments, not expressed in questions above, on this set of revisions, please
provide your comments here............................................................................................................ 136
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
1.
2.
Organization
Kris Manchur
Guy Zito
1
x
Manitoba Hydro
NPCC
Additional Member Additional Organization
Region
Roger Champagne
Hydro One TransEnergie NPCC
2
Lee Pedowicz
NPCC
NPCC
10
Gerry Dunbar
NPCC
NPCC
10
Jeffrey V Hackman
Dan Rochester
5.
Linda Perez (WECC)
6.
7.
8.
Fred Young
Denise Roeder
Karl Bryan
9.
Annette Bannon
Additional Member Additional Organization
July 10, 2009
Ameren
Independent Electricity System Operator Ontario
Reliability Coordinator Comment Working
Group
Northern California Power Agency
ElectriCities of North Carolina, Inc.
US Army Corps of Engineers,
Northwestern Division
PPL Supply Group
Region
Industry Segment
4
5
6
7
x
x
8
9
10
x
2.
3.
3
x
Segment
Selection
1.
3.
4.
2
x
x
x
x
x
x
x
x
x
x
x
x
x
Segment
Selection
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Commenter
Organization
1
1.
Mark Heimbach
PPL EnergyPlus
RFC
6
2.
MRO
6
3.
NPCC
6
4.
SERC
6
5.
SPP
6
6.
John Cummings
PPL EnergyPlus
WECC
6
7.
Jon Williamson
PPL EnergyPlus
WECC
6
8.
Tom Lehman
PPL Montana
WECC
5, 6
9.
Joe Kisela
PPL Generation
RFC
5
NPCC
5
10.
11.
David Gladey
10.
John Blazekovich (Commonwealth
Edison)
11.
Terry Bilke (MRO)
PPL Susquehanna RFC
Industry Segment
4
5
6
7
8
9
10
x
Segment
Selection
1.
Neal Balu
WPS
MRO
3, 4, 5, 6
2.
Carol Gerou
MP
MRO
1, 3, 5, 6
3.
Jim Haigh
WAPA MRO
1, 6
4.
Charles Lawrence
ATC
MRO
1
5.
Ken Goldsmith
ALTW
MRO
4
6.
Tom Mielnik
MEC
MRO
1, 3, 5, 6
7.
Pam Sordet
XCEL
MRO
1, 3, 5, 6
8.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
9.
Eric Rudolph
LES
MRO
1, 3, 5, 6
10.
Joseph Knight
GRE
MRO
1, 3, 5, 6
11.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
12.
Maire Knox
MISO
MRO
2
13.
Michael Brytowski
MRO
MRO
10
July 10, 2009
3
5
#1 Standards Interface
Subcommittee/Compliance Elements
Drafting
MRO NERC SDTandards Review
Subcommittee
Additional Member Additional Organization Region
2
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comments for Set of Reliability Coordination Standards (Project 2006-06)
Commenter
Organization
1
14.
12.
Larry Brusseau
Jim Busbin
MRO
MRO
Region
Southern Company Services, Inc. SERC
1
2.
Mike Hardy
Southern Company Services, Inc. SERC
1
3.
Chris Wilson
Southern Company Services, Inc. SERC
1
4.
Terry Coggins
Southern Company Services, Inc. SERC
1
5.
Dean Ulch
Southern Company Services, Inc. SERC
1
6.
J. T. Wood
Southern Company Services, Inc. SERC
1
7.
Roman Carter
Southern Company Services, Inc. SERC
1
Marc Butts
Southern Company Services, Inc. SERC
1
Kathleen Goodman
Edward Davis
Danny Dees
Mike Gentry
Jim Griffith (Southern Company)
ISO New England Inc.
Entergy Services, Inc
MEAG Power
Salt River Project
SERC OC Standards Review Group
Additional Member Additional Organization
Region
9
10
x
x
x
x
x
x
x
x
x
x
x
x
Segment
Selection
1.
Alan Jones
Alcoa
SERC
1, 3, 5
2.
Al McMeekin
SCE&G
SERC
1, 3, 5
3.
Brett Koelsch
Progress Energy
SERC
1, 3, 5
4.
Raymond Vice
Southern Co.
SERC
1, 3, 5
5.
Danny Dees
MEAG
SERC
1, 3, 5
6.
Raleigh Nobles
Ga System Operations Corp SERC
1, 3, 5
7.
Greg Stone
Duke Energy
SERC
1, 3, 5
8.
Tim Hattaway
PowerSouth
SERC
1, 3, 4, 5
9.
Jack Kerr
Dominion VP
SERC
1, 3, 5
10.
Richard McCall
NCEMC
SERC
3, 4
11.
Jim Case
Entergy
SERC
1, 3, 5
12.
Joel Wise
TVA
SERC
1, 3, 5, 9
July 10, 2009
8
x
Raymond Vice
8.
Industry Segment
4
5
6
7
Segment
Selection
1.
13.
14.
15.
16.
17.
3
10
Southern Company Transmission
Additional Member Additional Organization
2
9
Commenter
Organization
1
2
13.
John Rembold
SIPC
SERC
1, 3, 5
14.
Lawrence Rodriquez
Entegra Power
SERC
3, 4, 5, 6
Mike Bryson
PJM
SERC
2
15.
18.
19.
Jay Seitz
Patrick Brown
US Bureau of Reclamation
PJM Interconnection
Additional Member Additional Organization
Region
PJM Interconnection RFC
2
Leanne Harrison
PJM Interconnection RFC
2
Timothy C. (TC) Thomas
Sam Ciccone
#2 Standards Interface
Subcommittee/Compliance Elements
Development Resource Pool
Progress Energy Carolinas
FirstEnergy
Additional Member Additional Organization Region
Dave Folk
FE
RFC
1, 3, 4, 5, 6
2.
Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
Steve Lux
FE
RFC
1, 3, 4, 5, 6
3.
Denise Koehn
Additional
Member
1.
Bonneville Power Administration
Additional
Organization
x
x
x
x
Region
x
x
Transmission Dispatch
WECC
2.
Jeffrey Cook
Transmission Communications & Grid
Modeling
WECC
1
3.
Robin Chung
Generation Support
WECC
3, 5,
6
Greg Rowland
Thad Ness
Chris de Graffenried
Kevin Koloini
Jason Shaver
Charles Yeung (SPP)
July 10, 2009
x
x
x
x
x
x
x
x
x
x
x
x
Segment
Selection
Rich Ellison
24.
25.
26.
27.
28.
29.
10
Segment
Selection
1.
23.
9
Segment
Selection
William Harm
21.
22.
8
x
2.
John Blazekovich (Commonwealth
Edison)
Industry Segment
4
5
6
7
x
1.
20.
3
Duke Energy
AEP
Consolidated Edison Co. of NY, Inc.
Buckeye Power, Inc.
American Transmission Company
ISO/RTO Council Standards Review
Subcommittee
x
x
x
x
x
x
x
x
x
x
x
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comments for Set of Reliability Coordination Standards (Project 2006-06)
1. Do you agree with the revisions to the Requirements in COM-001-2 as shown in the posted Standard and Implementation Plan? If
not, please explain in the comment area.
Summary Consideration: The RC SDT received several comments regarding the intent of the term “telecommunications
facilities”. For COM-001-2, the RC SDT envisions telecommunications to be voice or message communication between
operating personnel. The standard has been renamed “Communications” and the term “telecommunications facilities” was
replaced with “interpersonal communications capabilities” throughout the standard to better reflect the intent of the RC SDT.
Based on stakeholder comments, R1 was changed as follows:
R1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall operationally test, on a quarterly
basis at a minimum, alternative interpersonal telecommunications facilities capabilities used for communicating real-time
operating information. to ensure the availability of their use when normal telecommunications facilities fail.If the test is
unsuccessful, the entity shall develop a mitigation plan to restore its interpersonal communications capabilities.
We also received comments regarding the applicability of the standard that suggested adding other entities listed in IRO-001.
The RC SDT contends that, in order to receive and carry out directives, an entity must be able to communicate with the
RC…either directly or through other entities (e.g. – a Distribution Provider may receive the directive from the Transmission
Operator who received it from the Reliability Coordinator). We have not expanded the applicability of R1 to include the TSP,
LSE and PSE as suggested as we feel that this expands the standard beyond the reliability intent. It is not necessary nor is it
practical, for reliability purposes, for every entity to have normal and back-up interpersonal communications capabilities with
every other entity. The TSP, LSE and PSE were, however, added to R3 to add these entities to the list of entities that must use
the English language when exchanging inter-entity information.
Other commenters had concerns with regard to R2 and the intent with regard to length of outages. The requirement was
revised as follows:
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60
minutes of the detection of the a failure (30 minutes or longer) of its normal interpersonal tele communications
facilitiescapabilities. , and shall verify that alternate means of telecommunications are functional.
The TSP, LSE and PSE were added to the list of responsible entities and the informational (last) sentence of R3 was removed
per stakeholder suggestions:
R3. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Purchasing-Selling Entity, and Distribution Provider shall use English as the
July 10, 2009
11
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
language for all inter-entity Bulk Electric System (BES) reliability communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected BES. Transmission Operators and Balancing
Authorities may use an alternate language for internal operations.
Organization
Question 1:
AEP
No
Question 1 Comments:
A precise definition of telecommunications facilities needs to be established in this standard.
R2 needs to be clarified regarding impacted utilities. FERC Order 693 suggests that this standard
should apply Distribution Providers (DP) along with Generation Operators (GOP). AEP
acknowledges that there needs to be some level of coordination and communication between DPs
and other function model entities; however, the requirements, as applied to the DP, for
telecommunications with the TOP and BA might not address the current communication paths
adequately. Today, the DP usually does not communicate with the RTO (performing the BA and/or
TOP function), but the DP could either communicate directly or through a joint action agency to the
IOU that may serve as the TO (or maybe the TOP). As this draft is written the DPs would be required
to have telecommunication facilities with the RTO in this scenario. There will likely be many
exceptions to the rule that the requirements and measures create when applied to the DP. We ask
that the drafting team consider the applicability, some of the current channels of communications, and
options for addressing the FERC comments without creating telecommunication paths that do not
make practical sense.
Response: The RC SDT thanks you for your comment.
COM-001-2 has been renamed “Communications”. The RC SDT envisions COM-001-2 as referring to voice or text communications only. We
have revised the term “telecommunications facilities” to “interpersonal communications capabilities” to better reflect the intent.
In R2, the phrase, “impacted entities” refers to any entity with whom the TC, TOP or BA has lost interpersonal communications capabilities.
The requirements were written to address the differences in any entity’s facility needs allowing for adequate flexibility to incorporate cost
effective solutions as well as accommodate future technologies (FERC Order 693 directives).
ElectriCities of North
Carolina, Inc.
July 10, 2009
No
We are a joint action agency registered on behalf of our member municipalities, who are all TDUs,
neither own nor operate any Bulk Electric System facilities, and perform no real-time operations or
operations planning for the BES. There are currently other standards that already apply to us that
require us to have processes and means to communicate with our RC, BA, TOP, etc. The proposed
modifications to this standard would now make our members subject to this standard as well, based
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
on the DP registration designation. Given that, we believe there needs to be additional clarification of
specifically what type of "telecommunications facilities" are required to be considered compliant with
this standard. Maybe in the past when this standard applied to TOPs, BAs, and RCs, it was intuitive
what type of telecommunications facilities they needed to communicate with each other. However,
when you bring in small DPs, it doesn't seem so clear. Obviously we already communicate with our
TOP and BA, and have done so for years. As written, the standard is ambiguous in terms of what
more, if anything, we would have to put in place to satisfy this standard.
Response: The RC SDT thanks you for your comment. COM-001-2 has been renamed “Communications”. The RC SDT envisions COM001-2 as referring to voice or text communications only. We have revised the term “telecommunications facilities” to “interpersonal
communications capabilities” to better reflect the intent. The purpose statement is revised as:
To ensure that operating entities have adequate interpersonal communication capabilities.
The requirement R4 was written to meet a FERC directive with respect to COM-001. The requirement states:
Each Distribution Provider and Generation Operator shall demonstrate the existence of its interpersonal communications capabilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection and operating information.
Compliance with NERC requirements can be achieved through agreements with other entities to meet the intent of the requirement. The RC
SDT can not address compliance issues, as this is the scope of NERC Compliance.
US Army Corps of
Engineers,
Northwestern
Division
No
R3 needs to have the last sentence revised to allow the Generator Operator and Distribution Provider
to use an alternate language for internal operations.
Response: The RC SDT thanks you for your comment. The requirement and measure were revised to delete the last sentence as it was not
a requirement, but only information.
US Bureau of
Reclamation
No
Purpose Distribution Providers and Generator Operators were added to the applicability; the Purpose
should be revised to reflect that.
Response: The RC SDT thanks you for your comment. The Purpose Statement was revised to:
To ensure that operating entities have adequate interpersonal communication capabilities.
July 10, 2009
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
CU of Springfield
No
Question 1 Comments:
City Utilities of Springfield, Missouri (CU) supports the effort of the drafting team to add Distribution
Providers and Generator Operators to the "Applicability" section, the change in language regarding
testing of alternate telecommunication facilities and the future effort to move COM-001-2 R3 to the
new COM-003-1 standard.
However, it is still necessary to define all parties that are responsible for having "adequate and
reliable telecommunication facilities" and to require them to have both primary and backup
telecommunication facilities. Since this standard is designed to address telecommunication facilities,
any redundancy that exists should be removed from other standards instead. The proposal from the
drafting team to remove all of the language from COM-001-1 R1 will create a gap in responsibility,
since none of the standards mentioned in the Implementation Plan specifically require a RC, BA or
TOP to have these facilities. It is the opinion of CU that you have defined the parties that need to
communicate "Interconnection and operating information" in IRO-001-2, where a BA, TOP, GOP,
TSP, LSE, DP and PSE receive and comply with directives from the RC. Therefore to maintain
consistency are not all of these entities expected to have "adequate and reliable" telecommunication
facilities?
CU suggests that COM-001-2 R4 be moved to R1 and standard language changed to say:
Purpose: Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing
Selling Entity needs adequate and reliable telecommunications facilities internally and with others in
the Reliability Coordinator's area, for the exchange of Interconnection and operating information
necessary to maintain reliability.
R1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall have primary and backup telecommunications facilities for the exchange of
Interconnection and operating information.
R2. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall operationally test, on a quarterly basis at a minimum, alternative telecommunications
facilities to ensure the availability of their use when normal telecommunications facilities fail.
R3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
July 10, 2009
14
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
Entity shall notify impacted entities of the failure of its normal telecommunications facilities, and shall
verify that alternate means of telecommunications are functional.
R4. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, Balancing
Authority, Generator Operator, Transmission Service Provider, Distribution Provider, Load Serving
Entity and Purchasing Selling Entity shall use English as the language for all inter-entity Bulk Electric
System (BES) reliability communications between and among operating personnel responsible for the
real-time generation control and operation of the interconnected BES. Transmission Operators and
Balancing Authorities may use an alternate language for internal operations.
The end result will be a standard that requires all applicable entities to:
A. Have primary and backup telecommunication facilities.
B. Test the telecommunication facilities.
C. Utilize the telecommunication facilities.
Response: The RC SDT thanks you for your comment.
Applicability: You are correct with regards to IRO-001 and the entities involved in carrying out directives. The RC SDT contends that, in order
to receive and carry out directives, an entity must be able to communicate with the RC…either directly or through other entities (e.g. – a
Distribution Provider may receive the directive from the Transmission Operator who received it from the Reliability Coordinator). The RC SDT
has changed the name of this standard to “Communications and revised the Purpose Statement to:
To ensure that operating entities have adequate interpersonal communication capabilities.
We have replaced the term “Telecommunications Facilities” with “interpersonal communications capabilities” to better reflect the intent of the
standard. We have not expanded the applicability of R1 or R2 as you suggest as we feel that this expands the standard beyond the reliability
intent. It is not necessary nor is it practical, for reliability purposes, for every entity to have normal and back-up interpersonal communications
capabilities with every other entity. The SDT did, however, expand the applicability for the requirement to use English language to include the
TSP, LSE and PSE in support of your suggestion.
Northern California
Power Agency
No
R3 should include in the last sentence that the Generator Operator and Distribution Provider may use
alternate language for internal operations.
Response: The RC SDT thanks you for your comment. The requirement and measure were revised to delete the last sentence since it was
informational only and not a requirement.
July 10, 2009
15
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
MRO NERC
SDTandards Review
Subcommittee
No
Question 1 Comments:
The new R2 requirement is too verbose. We suggest that you strike the final clause: "and shall verify
that alternate means of telecommunications are functional." It is obviated by the requirement to notify
impacted parties. The responsible entity is already implicitly required to verify its alternate means of
communication is functional since it is required to notify its impacted parties of the failure of its normal
telecommunications. It can't notify its impacted parties if the alternate communications means are not
functional. This clause is similar to the old requirement one that the drafting team appropriately
struck.
We tend to agree that striking R1 makes sense due to the drafting team's reasoning. However, we
are not clear why the new R4 is necessary then. If the drafting team does not believe R1 is necessary
shouldn't they respond to the FERC directive with the same reason why R4 is not really necessary?
The VRF for new requirement 1 should be lower. It does not fit the definition of a medium VRF. A
medium VRF requires that a violation of the requirement directly affect the state or capability or the
ability to effectively monitor and control. Failure to test does not result in directly affecting the state or
capability or the ability to effectively monitor and control. At a minimum, a failure of the alternative
communication systems and primary communication systems must occur first. The failure to perform
a single test in a given quarter does not mean that primary and alternative communication systems
will fail. Thus, testing is really an administrative issue and should thus be a lower VRF.
In the Data Retention section, Distribution Provider and Generation Operators should be added.
Currently, there are no data retention requirements listed for them. Suggest modifying the language
regarding data retention for compliance violations to: "… is found in violation of a requirement, it shall
keep information related to the violation until it the Compliance Enforcement Authority finds it
compliant."
Response: The RC SDT thanks you for your comments.
R2: The RC SDT deleted the final clause as you suggest.
R4: This was added because of the FERC directive:
Include generator operators and distribution provider as applicable entities and include requirements for their telecommunications.
VRF: We concur and have modified the VRF.
July 10, 2009
16
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
Data Retention: We have revised the Data Retention to section to comport with your comment.
Southern Company
Transmission
No
1.1 - In R1, we suggest that "operationally test by way of operator action" should be defined to
remove any confusion regarding what the term requires. The word "ensure" needs to be changed to
"assure" to more accurately convey the intent of the requirement. We also suggest changing the
word "facilities" to "capabilities".
1.2 - R2 is overly broad and should include a reasonable time frame for notification. For example, as
currently written, a telecom outage of only one minute for which a notification is not made would be a
severe violation. The VSL should be consistent with the language of the requirement. A very short,
insignificant telecom outage with no notification could result in a severe violation as the requirement
is presently written and VSL's applied.
1.3 - R1, R2 and R3 should be expanded to include the list of entities the RC needs to talk with as
included in the Applicability section of IRO-001-2 (RC, TO, BA, GO, DP, TSP, LSE, PSE). These
entities should also be included in the purpose statement and R4 and M4 can then be eliminated.
1.4 - In R3, we suggest that the last sentence of R3 should be changed to "entities may use an
alternative language for internal operations" rather than allowing only TOs and BAs to have this
option.
Response: The RC SDT thanks you for your comment.
1.1: The RC SDT removed the word “operationally” from the requirement. The requirement was revised to remove the “assurance” part as it
does not add to the requirement. We have changed to term “telecommunications facilities” to “interpersonal communication capabilities” to
better reflect the intent of the standard.
1.2: We have revised the requirement to place time bounds on outages that require notification. The new R2 is:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
1.3: The RC SDT contends that the addition of the TSP, LSE and PSE to R1 and R2 of COM-001 expands the scope beyond the reliability
intent, but has added the TSP, LSE and PSE to the list of entities that must use the English language in R3.
1.4: We have removed the informational (last) sentence as it is not a requirement. Others can use an alternate language, but the entities must
agree to do so. This is in the first sentence of the requirement which states “Unless agreed to otherwise…” R3 was revised so that the last
July 10, 2009
17
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
sentence, which was explanatory and did not include any required performance, was deleted.
Progress Energy
Carolinas
No
R1 - The proposed requirement R1 as stated is too broad in reference to "telecommunications
facilities". It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary of
Terms which accompany the full standards set.
R2 - The proposed requirement R2 as stated is too broad in reference to "telecommunications
facilities". It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary of
Terms which accompany the full standards set.
R4 - The proposed requirement R4 as stated is too broad in reference to "telecommunications
facilities". It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary of
Terms which accompany the full standards set.
Response: The RC SDT thanks you for your comment. COM-001-2 has been renamed “Communications”. The RC SDT envisions COM001-2 as referring to voice or message communications only. We have revised the term “telecommunications facilities” to “interpersonal
communications capabilities” throughout the standard to better reflect the intent.
NPCC
No
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between
entities (RC, TOP, BA, GOP, DP) to use a language other than English in their communications. In
M3, that option is not presented. M3 should reflect what is written in R3.
Response: The RC SDT thanks you for your comment. The provision that you mention was removed from the requirement since it is not a
requirement, but an informational statement. The English language Requirement begins with the phrase “Unless agreed to otherwise…”. This
allows for the use of other languages where agreed to.
ISO New England
Inc.
July 10, 2009
No
ISO New England does not support the removal of Requirement 1.
Also, we believe Requirement 3 is written such that it may pose an unnecessary requirement on the
18
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
Hydro Quebec area given the terminology "inter-entity" and support further clarification.
Response: The RC SDT thanks you for your comment. The majority of commenters agreed with the removal of R1.
The last sentence of the requirement 3 was deleted as it was an informational statement only. The English language Requirement begins with
the phrase “Unless agreed to otherwise…” This allows for the use of other languages where agreed to.
FirstEnergy
No
Purpose - The purpose does not include the GOP and DP entities. It may be better if the purpose was
written more generally as "To ensure adequate and reliable telecommunications facilities for the
exchange of Interconnection and operating information necessary to maintain BES reliability".
R1 - This requirement makes no distinction between data and voice communications facilities and
assumes a designated primary and backup facility configuration such that the backup
communications systems are not used regularly. This may be an accurate assumption for data
communications; however voice communications may be different. Today many organizations use
voice communications systems that allow the system to choose the communication path each time a
call is placed. This design ensures that all communications paths are tested regularly in day-to-day
use. However, the design of these systems makes it difficult, if not impossible, to substantiate that a
functional test of the circuitry has been performed. This requirement should be broken into two
requirements. The first should cover data circuitry and the second should cover voice circuitry. This
will allow the drafting team to address the inherent differences in these two methods of
communications. Lastly, the requirements need to be much more specific concerning the criticality of
the facilities to be tested to improve the measurability of the standard. The drafting team dropped the
phrase "for the exchange of Interconnection and operating data" from the standard requirement. This
deletion appears to open the application of this standard to virtually every communication path used
by an RC, BA, TOP whether or not it is used for communicating real-time operating information or
not. We do not believe this was the intention of the drafting team and suggest this phrase be
reinserted or another one added that limits applicability to only those communication paths that
support the real-time reliability of the bulk electric system.
R2 - It is not clear who the "impacted entities" would be in this requirement. The SDT should consider
specifying these entities.
R3 - The last sentence of this requirement should be deleted. It is not a requirement, it does not add
clarity, and the first sentence is very specific as to the communications covered by the requirement.
R4 - This requirement makes no distinction between data and voice communications facilities and
July 10, 2009
19
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 1:
Question 1 Comments:
assumes a designated primary and backup facility configuration such that the backup
communications systems are not used regularly. This may be an accurate assumption for data
communications; however voice communications may be different. Today many organizations use
voice communications systems that allow the system to choose the communication path each time a
call is placed. This design ensures that all communications paths are tested regularly in day-to-day
use. However, the design of these systems makes it difficult, if not impossible, to substantiate that a
functional test of the circuitry has been performed. This requirement should be broken into two
requirements. The first should cover data circuitry and the second should cover voice circuitry. This
will allow the drafting team to address the inherent differences in these two methods of
communication.
Response: The RC SDT thanks you for your comment.
Purpose: To better reflect the intent of the standard, we have modified the Purpose Statement to:
To ensure that operating entities have adequate interpersonal communication capabilities.
R1: The standard has been revised to remove the term “telecommunications facilities” and replace it with “interpersonal communications
capabilities”. This reflects the intent of the standard, which is to have voice and message communication capabilities. R1 has been revised as:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall test, on a quarterly basis, alternative interpersonal
communications capabilities used for communicating real-time operating information. If the test is unsuccessful, the entity shall develop a
mitigation plan to restore its interpersonal communications capabilities. [Violation Risk Factor: Lower][Time Horizon: Real-time Operations]
R2: The term “impacted entities” indicates those entities with which you have lost interpersonal communications capabilities. R2 has been
revised to:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
R3: We concur and have deleted the sentence.
R4: COM-001-2 only covers voice and message communications and R4 has no provision for primary / alternate capabilities.
Duke Energy
July 10, 2009
No
Purpose - The purpose statement does not read very well. It either needs another sentence or
changes to the current sentence. The purpose of the standard is to assure proper communications,
not to suggest entities need proper communications as currently written. Suggest changing to, “To
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Organization
Question 1:
Question 1 Comments:
assure each Reliability Coordinator, Transmission Operator and Balancing Authority develops and
maintains”.
Requirement R1 - What is the definition of "alternative telecommunications facilities"? Is there
another requirement somewhere to have alternative telecommunications facilities — or is this a new
requirement being introduced by this standard? What is the relationship, if any, between "alternative
telecommunications facilities" and EOP-008-1? What is the requirement for maintaining and testing
"alternative telecommunications facilities"; what does “operationally test” mean Just because an
alternative facility works when it is tested does not mean it will work during an actual failure of the
primary system. Furthermore, what do we do if the “test” fails — are we still compliant? The word
“ensure” needs to be changed to “assure”.
Requirement R2 - What does "impacted entity" mean?
Requirement R3 - Why can’t others use alternate language — this limits alternate language to just
TOPs and BAs internal operations. TOs, GOPs, and others may want to use alternate language
internally. Need to define language to be used with and between other relationships — BA to PSE,
as an example. Is this a reliability issue or a certification issue? Simply state that: “Entities may use
alternative language for internal operations”. This will allow any entity to use alternative language for
internal operations. The inclusion of TSPs, LSEs, and PSEs in IRO-001-2 indicates the need to
include these functions in the COM-001-2 applicability and requirements concerning the use of
English as the approved language.
Requirement R4 - Remove R4 and add DP and GO, as well as all of the other entities listed in IRO001-2, to R1 thru R3.
Response: The RC SDT thanks you for your comment.
Purpose: To better reflect the intent of the standard, we have modified the Purpose Statement to:
To ensure that operating entities have adequate interpersonal communication capabilities.
R1: “Alternative telecommunications facilities” was used in place of “redundant”. Many entities have multiple “primary facilities” which could be
construed as redundant. The use of “alternative” is intended to indicate at least one primary and one other facility.
R2: The term “impacted entities” indicates those entities with which you have lost communications capabilities. Based on other’s comments,
R2 has been revised to:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
July 10, 2009
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Organization
Question 1:
Question 1 Comments:
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
R3: The second sentence was removed as it was a statement and not a requirement. Others can use an alternate language, but the entities
must agree to do so. This is in the first sentence of the requirement which states “Unless agreed to otherwise…”
R4: The DP and GOP were added to this standard per a FERC directive (paragraph 509 of Order 693). Putting these entities in R1-R3 would
add requirements not envisioned by the directive and provide no additional reliability benefit. The RC SDT contends that the addition of the
TSP, LSE and PSE (from IRO-001) to COM-001 R1 and R2 expands the scope beyond the reliability intent, but has added the TSP, LSE and
PSE to the list of entities that must use the English language in R3.
ISO/RTO Council
Standards Review
Subcommittee
Yes and No
We suggest that a definition of telecommunications be written by the drafting team because it is not
clear what all telecommunications is intended to be included. Does this requirement apply to data,
voice, rtus, networks, etc?
For requirement R2, we suggest that you strike the final clause: "and shall verify that alternate
means of telecommunications are functional." It is obviated by the requirement to notify impacted
parties. The responsible entity is already implicitly required to verify its alternate means of
communication is functional since it is required to notify its impacted parties of the failure of its normal
telecommunications. It can't notify its impacted parties if the alternate communications means are not
functional.
The VRF for new requirement 1 should be lower. It does not fit the definition of a medium VRF. A
medium VRF requires that a violation of the requirement directly affect the state or capability or the
ability to effectively monitor and control. Failure to test does not result in directly affecting the state or
capability or the ability to effectively monitor and control. At a minimum, a failure of the alternative
communication systems and primary communication systems must occur first. The failure to perform
a single test in a given quarter does not mean that primary and alternative communication systems
will fail. Thus, testing is really an administrative issue and should thus be a lower VRF.
In the Data Retention section, Distribution Provider and Generation Operators should be added.
Currently, there are no data retention requirements listed for them. Suggest modifying the language
regarding data retention for compliance violations to: "…is found in violation of a requirement, it shall
keep information related to the violation until it the Compliance Enforcement Authority finds it
compliant."
July 10, 2009
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Organization
Question 1:
Question 1 Comments:
Response: The RC SDT thanks you for your comment. The intent of this standard is reflected in the revised purpose statement:
To ensure that operating entities have adequate interpersonal communication capabilities.
COM-001-2 only deals with voice or message communications. We have renamed the standard to “Communications” and replaced the term
“telecommunications facilities’ with “interpersonal communications capabilities” throughout the standard.
R2: We have revised R2 as you suggest. R2 has been revised to:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
VRF: We concur and have modified the VRF.
Data Retention: We have revised the Data Retention as you suggested.
SERC OC
Standards Review
Group
Yes and No
1.1 - In R1, we suggest that "operationally test" should be defined to remove any confusion regarding
what the term requires. The word "ensure" needs to be changed to "assure" to more accurately
convey the intent of the requirement. We also suggest changing the word "facilities" to
"capabilities".
1.2 - R2 is overly broad and should include a reasonable time frame for notification. For example, as
currently written, a telecom outage of only one minute for which a notification is not made would be a
severe violation.
1.3 - R1, R2 and R3 should be expanded to include the list of entities the RC needs to talk with as
included in the Applicability section of IRO-001-2 (RC, TO, BA, GO, DP, TSP, LSE, PSE). These
entities should also be included in the purpose statement and R4 and M4 can then be eliminated.
1.4 - In R3, we suggest that the last sentence of R3 should be changed to "entities may use an
alternative language for internal operations" rather than allowing only TOs and BAs to have this
option.
Response: The RC SDT thanks you for your comment.
1.1: The RC SDT removed the word “operationally” from the requirement. The requirement was revised remove the “assurance” part as it
does not add to the requirement. We have changed to term “facilities” to “capabilities” as you suggest.
July 10, 2009
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Organization
Question 1:
Question 1 Comments:
1.2: We have revised the requirement to place time bounds on outages that require notification. The new R2 is:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
1.3: The RC SDT contends that the addition of the TSP, LSE and PSE to COM-001 expands the scope beyond the reliability intent, but has
added the TSP, LSE and PSE to the list of entities that must use the English language in R3.
1.4: We have removed the informational (last) sentence as it is not a requirement. Others can use an alternate language, but the entities must
agree to do so. This is in the first sentence of the requirement which states “Unless agreed to otherwise…”
Buckeye Power, Inc.
Yes and No
What constitutes "telecommunications facilities"?
Response: The RC SDT thanks you for your comment. COM-001-2 deals with voice or message communications only and has been
renamed “Communications. We have replaced the phrase “telecommunications facilities” with “interpersonal communications capabilities”
throughout the standard to better reflect the intent. The purpose statement has been revised to
To ensure that operating entities have adequate interpersonal communication capabilities.
American
Transmission
Company
Yes and No
If some language is clarified, we support the revisions. R2 states that "Each TO shall notify impacted
entities of the failure of its normal telecommunications facilities". If a phone line goes down and an
alternate phone line is used, it is an excessive requirement to notify the impacted entities when there
is no impact upon communication or the BES. The wording should be clear that notification is only
required if an alternate means of communication is necessary. A defined timeframe for notification
should be added to the requirement. It is possible that the loss of telecommunication faculties can
occur without the loss of a control center. So, the redundancy with EOP-008 to R4 should be
clarified.
Response: The RC SDT thanks you for your comment.
The RC SDT believes that entities should contact others when their normal communication capability is lost. For example, the normal phone
line could be cut and someone trying to contact that entity may only get a busy signal and have no idea that alternate communications is
necessary.
We have revised the requirement to place time bounds on outages that require notification as you suggest. The new R2 is:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of
July 10, 2009
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Organization
Question 1:
Question 1 Comments:
a failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
Based on these revisions, we do not believe further clarification with regards to EOP-008 is necessary.
PJM Interconnection
Yes
We agree with the revisions, but recommend adding applicability to Distribution Providers and
Generator Operators for data retention requirements.
Response: The RC SDT thanks you for your comment. The data retention requirements have been revised as you suggested.
Entergy Services,
Inc
Yes
The drafting team should consider expanding the second sentence of R3 to apply to internal
communications of any affected entity not just BAs and TOPs.
Response: The RC SDT thanks you for your comment. We concur with your sentiment and the second sentence has been removed as it was
not a requirement, but an informational statement. Use of an alternate language by any entity is allowed under the requirement which begins
with the phrase: “Unless agreed to otherwise…” The requirement has been revised to:
R3. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Purchasing-Selling Entity, and Distribution Provider shall use English as the language for all inter-entity
Bulk Electric System (BES) reliability communications between and among operating personnel responsible for the real-time generation control
and operation of the interconnected BES. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
Salt River Project
Yes
Manitoba Hydro
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
Reliability
Coordinator
Yes
July 10, 2009
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Organization
Question 1:
Question 1 Comments:
Comment Working
Group
PPL Supply Group
Yes
Bonneville Power
Administration
Yes
July 10, 2009
26
2. Do you agree with the revisions to the Measures in COM-001-2 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Summary Consideration: Commenters suggested general as well as specific revisions to the measures. One general
comment suggested making the language consistent among the measures regarding evidence. M1-M3 were revised to include
the phrase “shall have and provide upon request evidence that …”.
The revisions to M1 are shown below:
M1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have and provide upon request,
evidence that could include, but is not limited to dated test records, operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or equivalent, it operationally tested, on a quarterly basis at a minimum,
alternative interpersonal telecommunications facilities capabilities used for communicating real-time operating
information. to ensure the availability of their use when normal telecommunications facilities fail. If the test was
unsuccessful, the entity shall have and provide upon request evidence that it developed a mitigation plan to restore the
interpersonal communications capabilities.
Several commenters suggested revisions to M3. The RC SDT revised M3 based on the comments received suggesting that the
applicability be expanded to include Generator Operators, Transmission Service Providers, Load-Serving Entities, PurchasingSelling Entities, and Distribution Providers. Several entities commented that M3 did not match R3 which included an
explanatory sentence that allowed an entity to use a language other than English for its internal communications. The
informational second sentence was removed from Requirement R3, thus eliminating the “disconnect” between the requirement
and the measure.
The revisions to M3 are shown below:
M3. The Each Reliability Coordinator, Transmission Operator or Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Purchasing-Selling Entity, and Distribution Provider shall have and provide upon request
evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, that will be used to determine that personnel used English as the language for
all inter-entity BES reliability communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected BES. If a language other than English is used, each party shall
have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or
transcripts of voice recordings, electronic communications, or equivalent, of agreement to use the alternate language.
July 10, 2009
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M4 was revised based on stakeholder comments as follows:
M4. Each Distribution Provider and Generation Operator shall demonstrate the existence of has its teleinterpersonal
communications facilities capabilities with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information.
All measures were revised as necessary to reflect revisions to requirements.
Organization
Question 2:
NPCC
No
Question 2 Comments:
There is inconsistency between R3 and M3. In R3, there is a provision for agreement between
entities (RC, TOP, BA, GOP, DP) to use a language other than English in their communications. In
M3, that option is not presented. M3 should reflect what is written in R3.
Response: The RC SDT thanks you for your comment. The informational second sentence was removed from the requirement so there is no
longer a disconnect between the requirement and the measure.
CU of Springfield
No
CU suggests that COM-001-2 M4 be moved to M1 and language in the measures changed to:
M1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall have evidence of primary and backup telecommunication facilities.
M2.Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall provide evidence that it operationally tested, on a quarterly basis at a minimum,
alternative telecommunications facilities to ensure the availability of their use when normal
telecommunications facilities fail.
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall provide evidence that it notified impacted entities of failure of their normal
telecommunications facilities, and verified the alternate means of telecommunications were
functional.
M4. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Distribution Provider, Load Serving Entity and Purchasing Selling
Entity shall have and provide upon request evidence that could include, but is not limited to operator
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Organization
Question 2:
Question 2 Comments:
logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent,
that will be used to determine that personnel used English as the language for all inter-entity BES
reliability communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected BES.
Response: The RC SDT thanks you for your comment. We have revised the requirements for COM-001 based on the comments received from
all stakeholders. We also revised the measures to reflect the new verbiage of the requirements.
We have replaced the term “Telecommunications Facilities” with “interpersonal communications capabilities” to better reflect the intent of the
standard.
The RC SDT contends that the addition of the TSP, LSE and PSE to COM-001 to R1 and R2 expands the scope beyond the reliability intent, but
has added the TSP, LSE and PSE to the list of entities that must use the English language in R3. It is not necessary nor is it practical, for
reliability purposes, for every entity to have normal and back-up interpersonal communications capabilities with every other entity.
Independent Electricity
System Operator Ontario
No
M3: The evidence to show that concurrence is in place to allow communication using a language
other than English is missing. The Measure as written merely asks for evidence that communication
in a different language has occurred.
Response: The RC SDT thanks you for your comment. The informational second sentence was removed from the requirement so there is no
longer a requirement for evidence regarding this.
Reliability Coordinator
Comment Working
Group
No
On Measure 3 need to remove the word "all" in reference to voice logs. Measure needs to include
evidence of concurrence for using a language other than English
Response: The RC SDT thanks you for your comment. The informational second sentence was removed from the requirement so there is no
longer a requirement for evidence regarding this.
Northern California
Power Agency
No
M3 should include Generator Operator and Distribution Provider in the applicability.
Response: The RC SDT thanks you for your comment. The measure has been revised to include the Generator Operator and Distribution
Provider.
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Organization
Question 2:
ElectriCities of North
Carolina, Inc.
No
Question 2 Comments:
See comments on Question 1
Response: Please see response to question 1.
US Army Corps of
Engineers,
Northwestern Division
No
M3 needs to include the GO and DP in its requirement for inter-utility communications in English.
Response: The RC SDT thanks you for your comment. The measure has been revised to include the Generator Operator and Distribution
Provider.
MRO NERC
SDTandards Review
Subcommittee
No
M4 does not appear to be worded as a measurement. If R4 is kept, we suggest the following
modification: "The Distribution Provider and Generation Operator shall demonstrate the existence of
its telecommunication systems identified in R4."
Response: The RC SDT thanks you for your comment. We have revised M4 per your suggestion.
Southern Company
Transmission
No
2.1 - A general comment regards the production of evidence - such language should be standardized
as "have and provide upon request" and the authorized requestors identified. This comment should
apply to all standards.
2.2 - M2 is overly broad and should include a reasonable time frame for notification. For example, as
currently written, a telecom outage of only one minute for which a notification is not made would be a
severe violation.
2.3 - The Drafting Team should coordinate the data retention time frame with the requirement
measures for R1. DPs and GOs should also be included in the measures requirements.
Response: The RC SDT thanks you for your comment.
2.1 - The measures for this standard have all been revised per your comment.
2.2 – The requirement for this measure has been modified to reflect time frames for notification as well as a length of time applicable to the
outage. The measure has been revised accordingly.
July 10, 2009
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Organization
Question 2:
Question 2 Comments:
2.3 - The Data Retention section for this standard has been revised to comport with NERC Compliance guidelines. DP and GOP have been
added to the measure.
ISO New England Inc.
No
See answer to #1.
Response: Please see response to question 1.
Salt River Project
No
M3 should include providing evidence of concurrence to use a language other than English. This will
better align the measure with the VSL language.
Response: The RC SDT thanks you for your comment.
We have revised the measure by adding the following sentence:
If a language other than English is used, both parties shall have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent, of agreement to use the alternate
language.
SERC OC Standards
Review Group
Yes and No
2.1 - A general comment regards the production of evidence - such language should be standardized
as "have and provide upon request" and the authorized requestors identified. This comment should
apply to all standards.
2.2 - M2 is overly broad and should include a reasonable time frame for notification. For example, as
currently written, a telecom outage of only one minute for which a notification is not made would be a
severe violation.
2.3 - The Drafting Team should coordinate the data retention time frame with the requirement
measures for R1. DPs and GOs should also be included in the measures requirements
Response: The RC SDT thanks you for your comment.
2.1 - The measures for this standard have all been revised per your comment.
2.2 – The requirement for this measure has been modified to reflect time frames for notification as well as a length of time applicable to the
outage. The measure has been revised accordingly.
2.3 - The Data Retention section for this standard has been revised to comport with NERC Compliance guidelines. DP and GOP have been
added to the measure.
July 10, 2009
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Organization
Question 2:
Progress Energy
Carolinas
No
Question 2 Comments:
M1 - The proposed measure M1 as stated is too broad in reference to "telecommunications facilities".
It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary
of Terms which accompany the full standards set.
M2 - The proposed measure M2 as stated is too broad in reference to "telecommunications facilities".
It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary of
Terms which accompany the full standards set.
M4 - The proposed measure M4 as stated is too broad in reference to "telecommunications facilities".
It is unclear as to whether it is intending to specify facilities and equipment which provide
VOICE/VERBAL communications, or ELECTRONIC MESSAGING notifications systems, or DATA
EXCHANGE links or all of these. Please clarify either within the requirement or within the Glossary of
Terms which accompany the full standards set.
Response: The RC SDT thanks you for your comment. COM-001-2 has been renamed “Communications”. The RC SDT envisions COM-001-2
as referring to voice or text communications only. We have revised the term “telecommunications facilities” to “interpersonal communications
capabilities” to better reflect the intent.
FirstEnergy
No
The measures should be modified per our suggested modifications in question 1.
Response: The RC SDT thanks you for your comment. The measures were revised based on the revisions to requirements that resulted from
stakeholder comments.
Duke Energy
No
General comments - Not using consistent language regarding “provide evidence” and “shall have and
provide upon request evidence”. Also need to add corresponding requirement number after each
measure.
Measure M1 - Just because an alternate facility works when it is tested does not mean it will work
during an actual failure of the primary system. - what do we do if the “test” fails — are we complaint?
Clarify that the requirement and measure is to “test” not "to test successfully". We may test and find
that something does not work as expected.
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Organization
Question 2:
Question 2 Comments:
Response: The RC SDT thanks you for your comment. We have modified the “evidence” language for consistency. Each measure
corresponds to the measure with the same number. There is a one-to-one relationship between requirements and measures – however the SDT
did add the requirement numbers to ensure this is clear to all stakeholders.
M1: We have added the following sentence to R1 and M1.
R1: If the test is unsuccessful, the entity shall develop a mitigation plan to restore its interpersonal communications capabilities.
M1: If the test was unsuccessful, the entity shall have and provide upon request evidence that it developed a mitigation plan to restore the
interpersonal communications capabilities.
AEP
No
M2 needs to be clarified regarding impacted functions.
Response: The RC SDT thanks you for your comment. The requirement, as written, has sufficient clarity regarding the impacted entities.
American
Transmission
Company
No
M2 should be changed to reflect the comments noted in Question 1 for R2.
Response: The RC SDT thanks you for your comment. The RC SDT believes that entities should contact others when their normal
communication capability is lost. For example, the normal phone line could be cut and someone trying to contact that entity may only get a busy
signal and have no idea that alternate communications is necessary. We have revised the requirement to place time bounds on outages that
require notification. The new R2 is:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of a
failure (30 minutes or longer) of its normal interpersonal communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
The measure reflects the new requirement.
ISO/RTO Council
Standards Review
Subcommittee
Yes and No
M3: The evidence to show that concurrence is in place to allow communication using a language
other than English is missing. The Measure as written merely asks for evidence that communication
in a different language has occurred.
Response: The RC SDT thanks you for your comment. The measure has been revised as:
M1: The Reliability Coordinator, Transmission Operator or Balancing Authority shall have and provide upon request evidence that could include,
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Organization
Question 2:
Question 2 Comments:
but is not limited to dated test records, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent, that will be used to determine that personnel used English as the language for all inter-entity Bulk Electric System reliability
communications between and among operating personnel responsible for the real-time generation control and operation of the interconnected
Bulk Electric System. If a language other than English is used, both parties shall have and provide upon request evidence that could include, but
is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent, of agreement to use
the alternate language.
PJM Interconnection
Yes
M4 should be revised to reflect that each Distribution Provider and Generation Operator has evidence
demonstrating the functionality of telecommunications facilities with the TOP and BA for the
exchange of interconnection and operating information.
Response: The RC SDT thanks you for your comment. The measure was modified as:
Each Distribution Provider and Generation Operator shall demonstrate the existence of its interpersonal communications capabilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection and operating information.
Buckeye Power, Inc.
Yes and No
US Bureau of
Reclamation
Yes
Bonneville Power
Administration
Yes
Manitoba Hydro
Yes
Ameren
Yes
PPL Supply Group
Yes
Entergy Services, Inc
Yes
July 10, 2009
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3. Do you agree with the Violation Severity Levels proposed in COM-001-2 as shown in the posted Standard and Implementation Plan?
If not, please explain in the comment area.
Summary Consideration: The RC SDT made revisions to the VSLs based on the comments received and also to reflect
revisions to the associated requirements. We received comments that the VSLs for R1 and R2 were based on multiple
violations, which do not support FERC’s Guideline 4 for VSLs - Guideline 4 requires that a VSL should be based on a single
violation. We agreed and revised the VSLs to reflect a single violation.
Organization
Question 3:
Independent
Electricity System
Operator - Ontario
No
Question 3 Comments:
R1: Suggest to revise the conditions for all levels to read "failed to operationally test the
alternative communication facilities within the last???
R2: The second part under Severe is not needed since failing to notify any impacted
entities would imply no communication to the affected entities anyway. If verification of the
functionality of the alternate means of telecommunications is also critical even without communicating
to the affect entities, then the second condition should be an "OR".
R3: Failure to having concurrence to use a language other than English for
communications between and among operating personnel responsible for real-time operations by
itself does not constitute a violate of any requirements; it is the absence of such a concurrence AND
having used a language other than English that would constitute a violation. Suggest to revise this
condition.
Response: The RC SDT thanks you for your comment.
We have revised the VSLs per your suggestions and comments from other stakeholders, and revisions made to the wording of the
associated requirement.
We have revised the VSLs per your suggestions and the revisions made to the associated requirement
We have revised the VSLs per your suggestions.
CU of Springfield
No
Revise to reflect proposed changes above
Response: The RC SDT thanks you for your comment. The Requirement, Measures and VSLs have been revised per your and other
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Organization
Question 3:
Question 3 Comments:
stakeholders’ comments.
ElectriCities of North
Carolina, Inc.
No
Depends of what is meant by "telecommunications facilities"
Response: The RC SDT thanks you for your comment. We have clarified the requirements and measures to use the term “interpersonal
communications capabilities” rather than “telecommunications facilities”.
MRO NERC
SDTandards Review
Subcommittee
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission
established in their "Order on Violation Severity Levels Proposed by the Electric Reliability
Organization". Guideline 4 requires that a VSL should be based on a single violation. The VSLs as
defined accumulate the number of consecutive quarters. This would imply that a single violation
could last more than a year and that the compliance auditor could not determine sanctions until the
entity becomes compliant or year has passed. A single violation appears to be the failure to test in a
single quarter. This requirement is binary in nature in that it is either met or it isn't. We suggest that
only a lower VSL should be defined as: "The RC, TOP, or BA failed to test the backup
telecommunication facilities for a single calendar quarter."
The Lower VSL for R2 is not possible. The act of notifying all impacted entities of the failure of their
primary telecommunication system requires the use of the alternative telecommunications systems
which is a form of verifying that the alternative telecommunications facilities are functional. The
drafting team should consider applying the numeric performance category of the VSL Development
Guideline Criteria for R2.
Response: The RC SDT thanks you for your comment.
R1: We have revised the VSLs per the guideline and the revised requirement.
R2: We have revised the requirement to have time constraints for the length of an outage as well as a timeframe for notification. The VSL has
been revised to reflect the revised requirement.
PJM Interconnection
No
Recommend the following VSLs for R1:
Proposed Lower VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on at least one
occasion.
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Organization
Question 3:
Question 3 Comments:
Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on two separate
occasions.
Proposed High VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed
to operationally test alternative telecommunications every three months on three separate occasions.
Proposed Severe VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on more than three
separate occasions.
Recommend the following VSLs for R2:
Proposed Lower VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on at least one
occasion.
Proposed Moderate VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on two separate
occasions.
Proposed High VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator failed
to operationally test alternative telecommunications every three months on three separate occasions.
Proposed Severe VSL: The Reliability Coordinator, Balancing Authority or Transmission Operator
failed to operationally test alternative telecommunications every three months on more than three
separate occasions.
Recommend the following VSLs for R4:
Proposed High VSL: The Responsible Entity failed to establish telecommunications with either their
Balancing Authority or Transmission Operator for the exchange of Interconnection and operating
information.
Proposed Severe VSL: The Responsible Entity failed to establish telecommunications with their
Balancing Authority and Transmission Operator for the exchange of Interconnection and operating
information.
Response: The RC SDT thanks you for your comment.
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Organization
Question 3:
Question 3 Comments:
R1: The proposed VSLs reflect multiple violations of the requirement. Each VSL must be written for a single violation (failure to test quarterly).
R2: The proposed VSLs reflect multiple violations of the requirement and are a duplication of the VSLs proposed for R1, not for R2.
R4: We have revised the VSLs per your suggestion.
FirstEnergy
No
The VSL should be modified per our suggested modifications in question 1.R1 VSL - The statement
in the VSL that the responsible entity did not "operationally test" is too broad. It should be more
specific with the language used in the requirement.
Response: The RC SDT thanks you for your comment. The requirement, measure and VSLs have been revised per stakeholder comments
and the phrase, “operationally test” is no longer used in the standard.
Duke Energy
No
VSL for Requirement R1 - The VSL for R1 seems to imply that an operational test needs to have
been performed in the last 90 days — this is read in conjunction with the data retention requirements.
Need to clarify in the requirement how ?quarter basis? is defined - is it the calendar quarter, or a
rolling 90 days? In addition, the VSLs for Requirement R1 appear to violate NERC guidelines, since
the Moderate, High and Severe VSLs are based upon cumulative violations of the Lower VSL.
Response: The RC SDT thanks you for your comment. The data retention was changed from three months to three years. The VSLs were
revised to reflect the guidelines as you suggested. There are now 2 VSLs.
ISO/RTO Council
Standards Review
Subcommittee
No
The VSLs as defined for Requirement 1 appear to violate Guideline 4 that the Commission
established in their "Order on Violation Severity Levels Proposed by the Electric Reliability
Organization". Guideline 4 requires that a VSL should be based on a single violation. The VSLs as
defined accumulate the number of consecutive quarters. This would imply that a single violation could
last more than a year and that the compliance auditor could not determine sanctions until the entity
becomes compliant or year has passed. A single violation appears to be the failure to test in a single
quarter. This requirement is binary in nature in that it is either met or it isn't. We suggest that only a
lower VSL should be defined as: "The RC, TOP, or BA failed to test the backup telecommunication
facilities for a single calendar quarter."
The Lower VSL for R2 is not possible. The act of notifying all impacted entities of the failure of their
primary telecommunication system requires the use of the alternative telecommunications systems
which is a form of verifying that the alternative telecommunications facilities are functional. The
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Organization
Question 3:
Question 3 Comments:
drafting team should consider applying the numeric performance category of the VSL Development
Guideline Criteria for R2.
(i) R1: Suggest to revise the conditions for all levels to read "…failed to operationally test the
alternative communication facilities within the last………
(ii) R2: The second part under Severe is not needed since failing to notify any impacted entities
would imply no communication to the affected entities anyway. If verification of the functionality of the
alternate means of
telecommunications is also critical even without communicating to the affect entities, then the
second condition should be an "OR".
(iii) R3: Failure to having concurrence to use a language other than English for communications
between and among operating personnel responsible for real-time operations by itself does not
constitute a violate of any requirements; it is the absence of such a concurrence AND having used a
language other than English that would constitute a violation. Suggest to revise this condition.
Response: The RC SDT thanks you for your comment.
R1: We have revised the requirement to have a provision to test as well as a provision to develop a mitigation plan when a test fails. The
VSLs reflect the revised requirement.
R2: (i) We have revised the requirement to have a provision to test as well as a provision to develop a mitigation plan when a test fails. The
VSLs reflect the revised requirement.
The second part of the VSL was removed.
The VSL was revised to:
The responsible entity failed to provide evidence of concurrence to use a language other than English for communications between and among
operating personnel responsible for the real-time generation control or operation of the interconnected Bulk Electric System when a language
other than English was used.
SERC OC
Standards Review
Group
July 10, 2009
Yes and No
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included the
VSLs
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Organization
Question 3:
Question 3 Comments:
Response: The RC SDT thanks you for your comment. Please see response to comment 1.3 and 1.4.
Buckeye Power, Inc.
Yes and No
abstain
Southern Company
Transmission
Yes
3.1 - The expanded list of entities recommended in comment 1.3 and 1.4 need to be included the
VSLs
3.2 - The Severe VSL for R2 should be corrected. Add the word 'to' as follows: "…and failed to verify
the…"
Response: The RC SDT thanks you for your comment.
3.1 - Please see response to comment 1.3 and 1.4.
3.2 - The VSLs were revised based on revisions to the requirement.
American
Transmission
Company
Yes
Based upon revisions to Question 1.
Response: The RC SDT thanks you for your comment. The VSLs were revised to reflect changes to the requirements.
Bonneville Power
Administration
Yes
AEP
Yes
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Reliability
Yes
July 10, 2009
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Organization
Question 3:
Question 3 Comments:
Coordinator
Comment Working
Group
Northern California
Power Agency
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
US Bureau of
Reclamation
Yes
July 10, 2009
41
4. Do you agree with the revisions to the Requirements in COM-002-3 as shown in the posted Standard and Implementation Plan? If
not, please explain in the comment area.
Summary Consideration: The work of the IROL SDT resulted in the retirement of R1 from the standard. The RC SDT
received comments recommending expanding the applicability of the standard and separating Requirement R2 (now R1) into
two distinct requirements. The applicability was expanded to include Reliability Coordinator, Balancing Authority, Transmission
Operator, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and PurchasingSelling Entity. The requirements were revised to:
R1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with
real-time operational emergency conditions shall issue directives in a clear, concise, and definitive manner; shall
ensurerequire the recipient of the verbal directive to repeats the intent of the directive back information back correctly;
and shall acknowledge the response as correct or repeat the original statement to resolve any misunderstandings.
R2.
Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a directive issued
per Requirement R1 shall repeat the intent of the directive back to the issuer of the directive
The purpose statement was also revised to reflect the revisions to the standard:
To ensure Balancing Authorities, Transmission Operators, and Generator Operators have adequate communications and
that these communications capabilities are staffed and available for addressing a real time emergency condition. To ensure
emergency communications by between operating personnel are effective.
Organization
Question 4:
Southern Company
Transmission
No
Question 4 Comments:
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved;
however we suggest the following changes should be made for the interim applicability of COM-0023:
4.2 - The Purpose statement should be revised to re-align with the revisions in the Standard.
4.3 - The applicability of COM-002-3 should be consistent with the applicability of IRO-001-2.
4.4 - The words "clear, concise, and definitive manner" in R1 are ambiguous and impossible to
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Organization
Question 4:
Question 4 Comments:
measure. We suggest they be replaced with "the RC shall direct".
4.5 - An additional requirement, R2, should be added that requires the Operator to repeat the
information back correctly (i.e., separate this requirement from R1).
4.6 - Grammatical changes are suggested. The revised requirement reads as follows: " To ensure
Balancing Authorities, Transmission Operators, and Generator Operators have adequate
communications; to ensure that these communication capabilities are staffed and available for
addressing a real-time emergency condition; and to ensure effective communications by operating
personnel."
4.7 - At the Data Retention section, the reference to 'Requirement 3, Measure 3' should be consistent
with the modified standard. The revised standard only has one requirement.
4.8 - The use of calendar days in the Data Retention section is inconsistent with related standards
where 'months' are used.
Response: The RC SDT thanks you for your comments.
4.2 - We have revised the purpose statement to:
To ensure emergency communications between operating personnel are effective.
4.3 – We have changed the applicability of COM-002 to match that of IRO-001.
4.4 and 4.5 - We have separated the requirement into two requirements to ensure that the requirements are measurable and distinct. We
concur with your comments and have revised the requirements to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with real-time
operational emergency conditions shall require the recipient of the verbal directive to repeat the intent of the directive back; and shall
acknowledge the response as correct or repeat the original statement to resolve any misunderstandings. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, LoadServing Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive issued per Requirement R1, shall
repeat the intent of the directive back to the issuer of the directive. [Violation Risk Factor: High][Time Horizon: Real-Time]
4.6 - We have revised the purpose statement to:
To ensure emergency communications between operating personnel are effective.
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Organization
Question 4:
Question 4 Comments:
4.7 and 4.8 – We have updated the data retention section with the latest compliance template information.
ISO New England
Inc.
No
ISO New England believes it is inefficient to have a (temporary) Standard with only one Requirement
and recommend including this Requirement in COM-001, with COM-001 renamed to
"Communications."
Response: The RC SDT thanks you for your comments. Based on other stakeholder feedback, we have added applicable entities and
another requirement for those entities. This standard will be retired upon adoption of COM-003-1.
US Bureau of
Reclamation
No
Purpose: Since Generator Operators were deleted from the applicability; the Purpose should be
revised to reflect that and include Reliability Coordinators. The language is somewhat redundant,
recommend it be simplified to “To ensure Balancing Authorities, Reliability Coordinators, and
Transmission Operators communicate in an effective manner.”
Response The RC SDT thanks you for your comments. Several entities were added to the applicability and the purpose statement was
revised to:
To ensure emergency communications between operating personnel are effective.
FirstEnergy
No
Purpose - The GOP is still shown in the purpose statement although it was removed from the
applicability. Also, it may be better if the purpose was written more generally as "To ensure adequate
communications capabilities for addressing real-time emergency conditions and ensure
communications by operating personnel are effective to maintain BES reliability".
Applicability - In the SDT's document "Scope of Work Assigned to the Reliability Coordination
Standard Drafting Team", the team decided to not include the FERC directive to include the DP in the
applicability with the following reasoning "The proposed revisions do not include the DP entity
because they are not applicable." We would like clarification on this.
R1 - It does not appear that the implementation plan addresses the FERC direction to consider
comments from Santa Clara, FirstEnergy, and Six Cities per 693 par. 539 regarding staffing
requirements. Santa Clara asks that these requirements apply "only to operating staff available on
site at all times or includes repair personnel who are available only on an on-call basis". FirstEnergy
asks that the "term [staffed] should not require a physical presence at all facilities at all times because
some units, such as peaking units, are not staffed 24 hours a day". FirstEnergy also suggest
"because nuclear units are already subject to communications requirements in their operating
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Organization
Question 4:
Question 4 Comments:
procedures, their compliance with NRC operating procedures should be deemed in compliance with
the NERC Reliability Standards". Six Cities "states that, to avoid unnecessary staffing burdens,
particularly for smaller entities, the Commission should direct NERC to clarify COM-002-2 by
providing that identification of an emergency contact person on call to respond to real-time
emergency conditions will constitute adequate compliance".
R1 - Just as an FYI, with regard to the proposed replacement requirement statement in the
implementation plan: "TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to the RC", per recently
stakeholder approved ballots, R1 of TOP-005-1 has been retired and now covered in new standard
IRO-010-1.R1.1 - The existing requirement includes "through predetermined communication paths of
any condition that could threaten the reliability of its area or when firm load shedding is anticipated".
The proposed replacement requirements do not address the need for "predetermined communication
paths".
Response: The RC SDT thanks you for your comments.
Purpose: Several entities were added to the applicability and the purpose statement was revised to:
To ensure emergency communications between operating personnel are effective.
Applicability: The applicability was expanded to include Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity.
R1: The RC SDT considered these comments when developing the proposed COM-001-2 specification requirements. We have revised the
requirement to indicate that directives being issued relate to real-time operating emergencies. We do not feel that this would place an undue
burden on any entity with respect to staffing as the requirement makes no mention of staffing.
R1 FYI: Thank you for the FYI.
Duke Energy
July 10, 2009
No
Requirement R1 - As defined by Merriam Webster, the use of the word “ensure” implies virtual
guarantee ; while the use of the alternative
word “assure” implies the removal of doubt and suspense from a person's mind. We suggest that
“assure” is more appropriate than “ensure” in this context in the standards. The use of words like
“clear, concise, and definitive manner” is subject to interpretation. This same language is used in the
VSLs. Depending on the interpretation of this phrase, an entity could be found to be in a “Severe”
violation level. The issuer of the directive should not be subject to non-compliance if the recipient of
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Organization
Question 4:
Question 4 Comments:
the directive refuses to repeat back. Need to add a requirement, measure, and VSL that clarifies that
the recipient of a directive is obliged to perform their portion of a repeat-back. The inclusion of TSPs,
LSEs, and PSEs in IRO-001-2 indicates the need to include these functions in the COM-002-3
requirement concerning repeat-backs. What is a “directive”? The regional compliance processes are
having difficulty in auditing this existing standard due to lack of clarity of what constitutes a directive.
"Directive" should be defined as being associated with real-time operational emergency conditions,
and not ordinary day-to-day communications. Otherwise a VRF of High is not warranted.
Response: The RC SDT thanks you for your comments.
We concur with your comments and have revised the requirements to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with real-time
operational emergency conditions shall require the recipient of the verbal directive to repeat the intent of the directive back; and shall
acknowledge the response as correct or repeat the original statement to resolve any misunderstandings. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, LoadServing Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive issued per Requirement R1, shall
repeat the intent of the directive back to the issuer of the directive. [Violation Risk Factor: High][Time Horizon: Real-Time]
Northern California
Power Agency
Yes and No
Remove Generator Operator from the Purpose Statement. The re-written standard no longer applies
to GOP
Response: The RC SDT thanks you for your comments. The applicability was expanded to include Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity.
We have revised the purpose statement to: “To ensure emergency communications between operating personnel are effective[ML1].”
SERC OC
Standards Review
Group
Yes and No
4.1 - We agree with the recommendation to retire COM-002-3 when COM-003-1 is approved;
however we suggest the following changes should be made for the interim applicability of COM-0023:
4.2 - The Purpose statement should be revised to re-align with the revisions in the Standard.
4.3 - The applicability of COM-002-3 should be consistent with the applicability of IRO-001-2.
4.4 - The words "clear, concise, and definitive manner" in R1 are ambiguous and impossible to
July 10, 2009
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Organization
Question 4:
Question 4 Comments:
measure. We suggest they be replaced with "the RC shall direct".
4.5 - An additional requirement, R2, should be added that requires the Operator to repeat the
information back correctly (i.e., separate this requirement from R1).
Response: The RC SDT thanks you for your comments.
4.2 - We have revised the purpose statement to:
To ensure emergency communications between operating personnel are effective.
4.3 – We have changed the applicability of COM-002 to match that of IRO-001.
4.4 and 4.5 - We have separated the requirement into two requirements to ensure that the requirements are measurable and distinct. We
concur with your comments and have revised the requirements to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with real-time
operational emergency conditions shall require the recipient of the verbal directive to repeat the intent of the directive back; and shall
acknowledge the response as correct or repeat the original statement to resolve any misunderstandings. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, LoadServing Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive issued per Requirement R1, shall
repeat the intent of the directive back to the issuer of the directive. [Violation Risk Factor: High][Time Horizon: Real-Time]
Buckeye Power, Inc.
Yes and No
Abstain
PJM Interconnection
Yes
We note that this requirement really is "3-part communication" and will be moved to the new
communications standard, COM-003-1.
Response: The RC SDT thanks you for your comments. As envisioned, the 3-part communication requirements in this standard are
temporary – they will be retired when COM-003-1 becomes effective.
CU of Springfield
Yes
CU supports moving R1 to COM-003 and retiring COM-002.
Response: The RC SDT thanks you for your comment. As envisioned, the 3-part communication requirements in this standard are
temporary – they will be retired when COM-003-1 becomes effective.
July 10, 2009
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Organization
Question 4:
PPL Supply Group
Yes
Question 4 Comments:
PPL agrees with the changes to COM-002-3. However, for clarity PPL suggests that Generator
Operator should be removed from the purpose statement of this standard.
Response: The RC SDT thanks you for your comments. The applicability was expanded to include Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity.
We have revised the purpose statement to:
To ensure emergency communications between operating personnel are effective.
Manitoba Hydro
Yes
Bonneville Power
Administration
Yes
AEP
Yes
American
Transmission
Company
Yes
ISO/RTO Council
Standards Review
Subcommittee
Yes
NPCC
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
July 10, 2009
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Organization
Question 4:
Reliability
Coordinator
Comment Working
Group
Yes
MRO NERC
SDTandards Review
Subcommittee
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
July 10, 2009
Question 4 Comments:
49
5. Do you agree with the revisions to the Measures in COM-002-3 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Summary Consideration: The RC SDT received comments recommending expanding the applicability of the standard and
separating Requirement R1 into two distinct requirements. The applicability was expanded to include Reliability Coordinator,
Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, Load-Serving Entity,
Distribution Provider, and Purchasing-Selling Entity. The requirements and measures were revised to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with
real-time operational emergency conditions shall issue directives in a clear, concise, and definitive manner; shall ensure require
the recipient of the verbal directive to repeats the information intent of the directive back correctly; and shall acknowledge the
response as correct or repeat the original statement to resolve any misunderstandings. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive
issued per Requirement R1, shall repeat the intent of the directive back to the issuer of the directive. [Violation Risk Factor:
High][Time Horizon: Real-Time]
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with
real-time operational emergency conditions shall have evidence such as voice recordings or transcripts of voice recordings
to show that it required issued directives in a clear, concise, and definitive manner; ensured the recipient of the verbal
directive to repeated the information intent of the directive back correctly; and acknowledged the response as correct or
repeated the original statement to resolve any misunderstandings.
M2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive
issued per Requirement R1 shall have evidence such as voice recordings or transcripts of voice recordings to show that it
repeated the intent of the directive back to the issuer of the directive.
Organization
Question 5:
Southern Company
No
July 10, 2009
Question 5 Comments:
5.1 - The measures need to be revised to match the new requirements.
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Organization
Question 5:
Question 5 Comments:
Transmission
Response: The RC SDT thanks you for your comment. The measures have been revised to reflect revisions to the requirements.
SERC OC
Standards Review
Group
No
5.1 - The measures need to be revised to match the new requirements.
Response: The RC SDT thanks you for your comment. The measures have been revised to reflect revisions to the requirements.
ISO New England
Inc.
No
See response to Q#4
Response: The RC SDT thanks you for your comment. Please see response to Q4.
FirstEnergy
No
The measures should be modified if our comments in question 4 result in changes to the proposed
requirements.
Response: The RC SDT thanks you for your comment. The measures have been revised to reflect revisions to the requirements.
Duke Energy
No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The issuer of
the directive should not be subject to non-compliance if the recipient of the directive refuses to repeat
back. Need to add a requirement, measure, and VSL that clarifies that the recipient of a directive is
obliged to perform their portion of a repeat-back.
Response: The RC SDT thanks you for your comments. We concur with you comments – the phrase, “clear, concise, and definitive” was
removed from the standard and the requirement was subdivided so that there is a separate requirement that obligates the recipients to repeat
the intent of the directive. Measures and VSLs were revised to reflect the modifications to the requirements. The new measures are:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a verbal directive associated with real-time operational
emergency conditions shall have evidence such as voice recordings or transcripts of voice recordings to show that it required the recipient of
the verbal directive to repeat the intent of the directive back; and acknowledged the response as correct or repeated the original statement to
resolve any misunderstandings.
Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service Provider, Load-Serving
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Question 5:
Question 5 Comments:
Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a verbal directive issued per Requirement R1 shall have
evidence such as voice recordings or transcripts of voice recordings
American
Transmission
Company
Yes and No
As long as the measurement of compliance does not include proving the negative, that no directives
were issued.
Response: The RC SDT thanks you for your comment.
Buckeye Power, Inc.
Yes and No
Abstain
CU of Springfield
Yes
CU supports moving M1 to COM-003 and retiring COM-002.
Response: The RC SDT thanks you for your comment.
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
July 10, 2009
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Organization
Question 5:
MRO NERC
SDTandards Review
Subcommittee
Yes
Salt River Project
Yes
US Bureau of
Reclamation
Yes
PJM Interconnection
Yes
Bonneville Power
Administration
Yes
AEP
Yes
ISO/RTO Council
Standards Review
Subcommittee
Yes
July 10, 2009
Question 5 Comments:
53
6. Do you agree with the Violation Severity Levels proposed in COM-002-3 as shown in the posted Standard and Implementation Plan?
If not, please explain in the comment area.
Summary Consideration: The RC SDT received comments recommending revisions to the VSLs based on revisions to the
requirements and measures. The RC SDT did this and created new VSLs for new Requirement R2. The revised VSLs are:
Requirement
Lower
Moderate
High
Severe
R1
N/A
The responsible entity
provided a clear issued a
verbal directive in a
clear, concise and definitive
manner associated with realtime operating emergency
conditions and required the
recipient to repeat the
directiveintent of the directive,
but did not
acknowledge the recipient
was correct in the repeated
directive OR failed to repeat
the intent of the original
statement to resolve any
misunderstandings.
The responsible entity
provided a clear issued a
verbal directive associated
with real-time operating
emergency conditionsin a
clear, concise and definitive
manner, but did not require
the recipient to repeat the
intent of the directive.
The responsible entity
issued a verbal directive
associated with real-time
operating emergency
conditions and required the
recipient to repeat the
intent of the directive, but did
not acknowledge the
recipient
was correct in the repeated
directive AND failed to repeat
the intent of the original
statement to resolve any
misunderstandings..
The responsible entity failed
to provide a clear directive in
a clear, concise and definitive
manner when required.
R2
N/A
N/A
N/A
The responsible entity that is
the recipient of a verbal
directive issued per
Requirement R1 failed to
repeat the intent of the
directive back to the issuer of
the directive.
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Question 6:
Southern Company
Transmission
No
Question 6 Comments:
6.1 - The severity levels need to be revised to match the new requirements.
Response: The RC SDT thanks you for your comment. The VSLs were revised based on revisions to the requirements.
SERC OC
Standards Review
Group
No
6.1 - The severity levels need to be revised to match the new requirements
Response: The RC SDT thanks you for your comment. The VSLs were revised based on revisions to the requirements.
PJM Interconnection
No
The word "clear" is redundantly used in the High and Severe columns.
Recommend that "Moderate" should read: "The Responsible Entity provided a directive in a clear,
concise and definitive manner, but did not require the recipient to repeat the directive back to the
originator."
Recommend that "High" should read: "The Responsible Entity failed to issue a directive in a clear,
concise and definitive manner while ensuring the recipient of the directive repeated the information
back correctly with acknowledgment by the originator that the response was correct."
Recommend that "Severe" should read: "The Responsible Entity failed on more than one occasion
to issue a directive in a clear, concise and definitive manner while ensuring the recipient of the
directive repeated the information back correctly with acknowledgment by the originator that the
response was correct."
Response: The RC SDT thanks you for your comment. We have removed the language “clear, concise and definitive manner” from the
requirements, measures and VSLs. Based on the requirements, the VSLs were revised as shown above in the Summary Consideration
section. We do not agree with your suggestion on the Severe VSL regarding the number of occasions. The requirement is a stand alone
which requires the entity to perform it each time.
FirstEnergy
July 10, 2009
No
The VSL should be modified if our comments in question 4 result in changes to the proposed
requirements.
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Question 6:
Question 6 Comments:
Response: The RC SDT thanks you for your comment. The VSLs were revised based on revisions to the requirements.
Duke Energy
No
The use of words like “clear, concise, and definitive manner” is subject to interpretation. The issuer
of the directive should not be subject to non-compliance if the recipient of the directive refuses to
repeat back. Need to add a requirement, measure, and VSL that clarifies that the recipient of a
directive is obliged to perform their portion of a repeat-back.
Response: The RC SDT thanks you for your comment. We concur with your comments. The words “clear, concise, and definitive manner”
have been removed from the requirement, measure and VSLs. A separate requirement has been added per your suggestion.
American
Transmission
Company
No
R1-High VSL-If the directive was followed and there was no threat to the BES, then a lack of
repetition of the directive does not constitute a "high" VSL. Suggest that this be a low or moderate
VSL.
Response: The RC SDT thanks you for your comment. We have revised the requirements, measures and VSLs to reflect that these
directives are those that are issued for real-time operating emergency conditions.
Buckeye Power, Inc.
Yes and No
Manitoba Hydro
Yes
NPCC
Yes
CU of Springfield
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
Reliability
Coordinator
Yes
July 10, 2009
abstain
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Question 6:
Question 6 Comments:
Comment Working
Group
Northern California
Power Agency
Yes
MRO NERC
SDTandards Review
Subcommittee
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
US Bureau of
Reclamation
Yes
Bonneville Power
Administration
Yes
AEP
Yes
ISO/RTO Council
Standards Review
Subcommittee
Yes
July 10, 2009
57
7. Do you agree with the revisions to the Requirements in IRO-001-2 as shown in the posted Standard and Implementation Plan? If
not, please explain in the comment area.
Summary Consideration: The RC SDT has received a notable number of comments suggesting edits to the proposed
requirements and measures for the draft standard, particularly regarding the phrase “without intentional delay.” The
comments do not oppose the objective of the phrase, but often point out the issues of measuring intent and measuring time
delay.
To maintain the intent while improving the measurability of the requirement, the SDT proposes to modify the standard as
follows: delete the phrase ‘without intentional delay’ and leave the obligation of response and timing an unstated requirement
of R1 “The RC shall act or direct actions…”
R2 was modified as shown below – note that the phrase, “without intentional delay” was removed from all requirements,
measures and VSLs:
R2.
Each Transmission Operators, Balancing AuthoritiesAuthority, Generator Operators, Transmission Service Providers, LoadServing EntitiesEntity, Distribution Providers, and Purchasing-Selling Entities Entity shall act without intentional delay to
comply with its Reliability Coordinator’s directives unless such actions would violate safety, equipment, or regulatory or
statutory requirements.
An RC that requires a given action in a given time will be expected to inform the impacted entities of those actions and time
requirements. This revision would obviate the need for providing a measure for “intent”, while still maintaining the reliability
intent of the original requirement.
The SDT proposes to re-post the standard to obtain stakeholder feedback on the suggested revisions
Organization
Question 7:
Manitoba Hydro
No
Question 7 Comments:
I do not agree with the way IRO-001-2 R1 is written. In the present form the requirement may infer
that directing action is not an action. It may also infer that the RC is only required to do '"act "or
"direct actions" but not both. The way it is written also leads to problems with the VSLs. Perhaps R1
can be edited along the lines of:
R1. The Reliability Coordinator shall act to prevent or mitigate the magnitude or duration of events
that result in Adverse Reliability Impacts. When required, the actions initiated by the Reliability
Coordinator will include, but is not limited to, directing the actions to be taken by Transmission
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Question 7:
Question 7 Comments:
Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, LoadServing Entities, Distribution Providers and Purchasing-Selling Entities within its Reliability
Coordinator Area.
I agree with the other Requirements in IRO-001-2 with the exception of the "High" Violation Risk
Factor assigned to IRO-001-2 requirement R5. This should be a "Medium" VRF at the most. If the
emergency has been mitigated, and the entities are not aware, they will still be operating to
restrictions, which means the grid is operating well within limits. Not notifying the entities that the
problem has been mitigated may have some financial implications but it should not place the grid at
risk.
Response: The RC SDT thanks you for your comment. The recommended language change is what the requirement means. The SDT did
not modify the original language as they say the same thing.
The RC SDT agrees and modified the VRF for R5 to medium.
Independent
Electricity System
Operator - Ontario
No
R2: the phrase "act without intentional delay" is not necessary since the urgency of taking
any actions as directed by the RC's are generally understood to be conveyed in the RC's directives.
R3: Given R2 requires the responsible entities to comply with the RC directives, the part
that says "immediately confirm the ability to comply with the directive or" is not needed. R3 should
simply require the responsible entities to notify the RC upon recognition of the inability to perform the
directive.
The VRF for R5 should not be High. Failure to notify others when potential threats to
system reliability have been mitigated does not constitute a high risk to the interconnected system.
We suggest it be reduced to a Medium (i.e., that it affects control of the BES).
Response: The RC SDT thanks you for your comment.
The RC SDT agrees to remove this phrase. The majority of commenters found this to be unnecessary.
Agreed, the RC SDT modified R3 to remove “immediately confirm the ability to comply with the directive or”
The RC SDT agrees and modified the VRF for R5 to medium.
MRO NERC
SDTandards Review
July 10, 2009
No
New requirement R2 should omit act without intentional delay. The desired outcome is for the
responsible entity to comply with the RC directive. Adding act without intentional delay only confuses
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Question 7:
Subcommittee
Question 7 Comments:
the situation and adds questions. What is an intentional delay? The word act implies that the
requirement is met simply if the responsible entity attempted to meet the directive but was unable to
do so. That is already considered in with the clause that begins "unless such actions would violate
…". Thus, the word act is not necessary.
The word immediately should be removed from the new R3. This attempts to time frame the response
of the responsible entity and remove the judgment from the compliance auditor. We agree with the
concept of doing this but in reality it only confuses the issue and the compliance auditor will likely
apply his judgment regarding what immediate is anyway. Additionally, the requirement attempts to
separate the act of confirming that the responsible entity can take the action from notifying the RC
that the entity can't take the action. This is not logical. What RC is going to request a responsible
entity to take action that would violate safety, equipment, statutory, or regulatory requirements? The
RC should already be aware of those requirements and likely won't direct actions that violate them.
Thus, the likely scenario is that the responsible entity will attempt to take action and discover that
equipment is not function properly and thus notify the RC. We suggest striking the "shall immediately
confirm the ability to comply with the directive or" from the requirement. This part of the requirement
is not needed because the responsible entity is already obligated to follow the RCs directive (see
order 693.) Thus, the assumption is that the order will be followed unless it can't be followed because
it will violated safety, equipment, statutory, or regulatory requirements.
Requirements R4 and R5 are unnecessary. New R1 requires the RC to direct actions to be taken by
the TOP, BA, GOP, TSP, LSE, DP and PSE to prevent or mitigate the magnitude or duration of
events that result in Adverse Reliability Impacts. The RC can't direct these actions without notifying
all impacted TOPs and BAs. They would also have to notify them when actions are no longer
necessary.
Response: The RC SDT thanks you for your comment. The RC SDT agrees to remove this phrase. The majority of commenters found this to
be unnecessary.
The RC SDT agrees. We have modified R3 to remove “immediately” and “confirm the ability to comply with the directive or”.
The RC SDT does not agree with regard to R4 and R5, as some impacted entities may not need to take action or be issued directives but
would benefit from the situational awareness associated with knowing the status of operating issues.
Southern Company
July 10, 2009
No
7.1 - Applicability 4.2 - Transmission Operator should be plural.
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Question 7:
Transmission
Question 7 Comments:
7.2 - The revised definition of "Adverse Reliability Impacts" (R1) should be included at the top of
Standard IRO-001-2, per Glossary of Terms Used in Standards: All defined terms used in reliability
standards shall be defined in the glossary. Definitions may be approved as part of a standard action
or as a separate action. All definitions must be approved in accordance with the standards process.
7.3 - In R2 insert the word "its" before Reliability Coordinator.
7.4 - In R3, replace "immediately" with "without intentional delay", replace "ability" with "intent",
replace "or" with "and" and replace "the" with "its" before Reliability Coordinator.
Response: The RC SDT thanks you for your comment.
7.1 agreed, The RC SDT modified the applicability section.
7.2 The revision to the definition will be placed in the correct location on the next posting and will be balloted along with the standard revisions.
7.3 The RC SDT agrees and modified R2, the expectation is the entity’s RC will issue the directives, not a different RC.
7.4 R3 has been modified and changed “the” with “its” before RC. Note that based on comments from other stakeholders, the phrase,
“immediately confirm the ability to comply” has been omitted from the revised requirement.
ISO New England
Inc.
Yes and No
We believe the word "threat" should be replaced with "events" in Requirements 4 and 5.
Response: The RC SDT thanks you for your comment. The RC SDT chose the term “threat with Adverse Reliability Impacts” to convey the
concept that action may be taken to prevent an event when an RC identified a potential threat. This will help better ensure reliability by
mitigating threats rather than waiting for an event to occur.
Entergy Services,
Inc
No
PER-003 R1 does not specifically address delegated functions; therefore, this requirement is not
redundant with IRO-001 R6 without changes to PER-003 to specifically deal with employees
performing delegated functions.
Response: The RC SDT thanks you for your comment.
The RC SDT references the NERC ROP in the Implementation plan which address your delegation concern. .
Per NERC ROP appendix 5, Organization Registration and Certification Manual v3.3 Sec IV and V:
The applicant retains the responsibility for all delegated tasks. The applicant shall identify to the review team all tasks that have been delegated
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Question 7:
Question 7 Comments:
to another entity prior to the on-site visit. The review team shall conduct at least one on-site visit to the applicant’s facilities. This may also
apply to the facilities of entities responsible for delegated tasks. During the visit, the review team will:
a. Review with the applicant the data collected through the questionnaires;
b. Interview the operations and management personnel;
c. Inspect the facilities and equipment;
d. Request a demonstration of all tools identified in the certification standard;
e. Review all necessary documents and data including all agreements, processes, and procedures identified in the certification standard;
f. Review certification documents and projected system operator work schedules; and
g. Review any additional documentation that is needed to support the completed questionnaire or inquiries arising during the site-visit.
MEAG Power
No
Directives that are mandatory under R2 of IRO-001-2 should have boundaries consistent with the
proper role of an RC. For example, if an RC directs an LSE with a 15% planning reserve margin to
execute purchase power agreements until its reserve margin is at least 20% and the LSE refuses,
then the LSE may have violated this standard. Other examples of improper RC directives are
directives to increase coal inventories, buy firm fuel transportation rights, reconductor transmission
lines, purchase spare equipment, etc. Granted entities may be able to conjure up a regulatory or
statutory basis for refusing many improper RC directives but in some instances there may be no
permissible grounds to refuse. The appropriate solution is to modify the standard to ensure that
improper directives are never mandatory in the first place. Specifically, NERC is urged to state that
RC directives are mandatory only if they pertain to specific categories such as: switching orders to
reconfigure the BES, orders to postpone scheduled outages of BES equipment, orders to change
generator output, orders to curtail transactions or orders to curtail load.
Response: The RC SDT thanks you for your comment. It is envisioned by the RC SDT that such RC directives consist of real-time and sameday operating actions that prevent or mitigate events that may or will cause Adverse Reliability impacts.
FirstEnergy
July 10, 2009
No
R3 - should be a sub requirement of R2. These two requirements are sequential in nature and should
be measured at the same time. The VRFs and Time Horizons are the same for both requirements
lending to their combination into a requirement with a sub requirement. In the VSL for R2, an entity is
being penalized with a high severity level for not completely following an RC directive even though it
violated safety, equipment, statutory, or regulatory requirements. Measuring R2 and R3 at the same
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Question 7:
Question 7 Comments:
time allows for the process to complete prior to the measurement taking place.
R3 - The "or" between "Distribution Provider" and "Purchasing-Selling Entity" should be replaced with
an "and".
R4 - Should be revised by adding the phrase "of the expected or actual threat" to the end of the
requirement to add clarity.
Existing R7 requirement - This requirement is proposed for retirement because it is redundant with
IRO-014-1 R1. However, it is not clear how the existing requirement to "have clear, comprehensive
coordination agreements with adjacent RCs to ensure that SOL or IROL violation mitigation requiring
actions in adjacent RC areas are coordinated" is covered in IRO-014-1 R1. IRO-014-1 R1 requires
agreements for coordination of actions between RCs to support Interconnection reliability, but it does
not specifically require "clear" and "comprehensive" agreements to mitigate SOL or IROL violations.
IRO-014-1 only vaguely covers the existing requirement R7 of IRO-001-1.
Response: The RC SDT thanks you for your comment. The intent of the drafting team is to have distinct requirements that are measured
independently. Having one as a subrequirement will not allow that to occur.
The RC SDT revised the “or” to an “and”.
R4, The recommended language change is what the requirement means. The RC SDT did not modify the original language as they say the
same thing.
R7, The industry comments do not support being more specific in IRO-014-1 R1 in order to retire IRO-001-1 R7.
SERC OC
Standards Review
Group
Yes and No
7.1 - Applicability 4.2 - Transmission Operator should be plural.
7.2 - The revised definition of "Adverse Reliability Impacts" (R1) should be included at the top of
Standard IRO-001-2, per Glossary of Terms Used in Standards: All defined terms used in reliability
standards shall be defined in the glossary. Definitions may be approved as part of a standard action
or as a separate action. All definitions must be approved in accordance with the standards process.
7.3 - In R2 insert the word "its" before Reliability Coordinator
7.4 - In R3, replace "immediately" with "without intentional delay", replace "ability" with "intent",
replace "or" with "and" and replace "the" with "its" before Reliability Coordinator.
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Question 7:
Question 7 Comments:
Response: The RC SDT thanks you for your comment.
7.1 The RC SDT agrees and will modify the applicability section.
7.2 The revision to the definition will be placed in the correct location on the next posting and will be balloted along with the standard revisions.
7.3 Agreed, The RC SDT modified R2, the expectation is the entities RC will issue the directives, not a different RC.
7.4 R3 has been modified and changed “the” with “its” before RC. Note that based on comments from other stakeholders, the phrase,
“immediately confirm the ability to comply” has been omitted from the revised requirement.
US Bureau of
Reclamation
No
R4. and R5. Both of these Requirements use the phrase “without intentional delay” to describe the
urgency of the notification to impacted entities. In both requirements we recommend the language be
changed from “notify, without intentional delay” to “immediately notify”.
Response: The RC SDT thanks you for your comment. We have removed the phrase from the requirements.
American
Transmission
Company
No
R2 refers to "intentional delay". The determination of intent should be left to the VSL portion of the
standard, not the requirement portion.
Response: The RC SDT thanks you for your comment. The RC SDT has removed “without intentional delay” from the proposed requirement.
Consolidated Edison
Co. of NY, Inc.
Yes and No
Wording in question: R.2/M.2 Each Load-Serving Entity, or Purchasing-Selling Entity shall have
evidence that it acted without intentional delay to comply with the Reliability Coordinator's
directives.R.3/M.3 Each — Load-Serving Entity, or Purchasing-Selling Entity shall have evidence
that it confirmed its ability to comply with the Reliability Coordinator's directives.
[1] Question: Is this wording absolutely necessary? And then, is it sufficient, if needed? Comment:
First, we would question whether there is a specific need to include this wording. Is the IRO-001
Reliability Standard sufficient without it?
[2] Question: Is this wording unambiguous? Comment: The wording seems somewhat vague and
ambiguous. Analysis: The wording appears to establish performance standards ("without intentional
delay", “shall immediately confirm”) and evidentiary requirements (“evidence that it acted” or
“evidence that it confirmed”), but without using pre-existing defined terms, establishing new defined
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Question 7:
Question 7 Comments:
terms, or defining these terms as used in context.
[3] Intentional vs. Unintentional, Valid Intentional vs. Inappropriate Intentional? How does one
differentiate between intentional and unintentional delay? When is and how much delay is valid or
inappropriate? Isn’t some intentional delay necessary to ensure that the other parts of the
requirement being are met, e.g., — unless such actions would violate safety, equipment, or regulatory
or statutory requirements?? Mightn’t some acceptable amount of valid intentional delay be necessary
to insure that any such RC directive and entity action would not in fact violate these safety,
equipment, or regulatory or statutory requirements?
[4] What is the timeliness standard?
How are the terms “without delay” and “immediately conform” defined? What standard commercial
measures would apply, e.g., “reasonably efforts” vs. “best efforts”? Are these terms measured in units
of time (seconds or minutes) or in units of performance quality? Does a poorly considered
“immediate” reply meet the standard, while a well considered reply, which is intentionally delayed, yet
still appropriate, fail to meet this standard? Is that the best outcome?
[5] What is this Evidentiary Standard? Is the sought-after “evidence” sufficiently well defined, e.g.,
phone logs, computer e-mail, control center computer logs, hand-written operator journals, etc.?
What form of evidence is necessary and sufficient to demonstrate that the entity met this evidentiary
standard? How is failure to meet this uncertain standard measured, judged and penalized?
Response: The RC SDT thanks you for your comment.
The RC SDT has removed the phrases “immediately” and “without intentional delay” from the proposed requirements.
Duke Energy
July 10, 2009
No
Requirement R1 - What happens if the RC failed to recognize that such an event was happening as
opposed to failed to take action? Is this intended to cover both scenarios? The term “Adverse
Reliability Impacts” is being changed and is listed in the associated Implementation Plan. The
revision development of this definition needs to go thru Due Process. The inclusion of TSPs, LSEs,
and PSEs here indicates the need to include these functions in the COM-001-2 requirements
concerning the use of English as the approved language. In addition, this also indicates the need for
all of these listed entities to be included in COM-002-3 requirements concerning repeat-backs. The
RC, TOP, and BA should not be placed in a possible non-complaint state because the counter party
refuses a repeat-back AND these requirements are not applicable to the counter party.
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Question 7:
Question 7 Comments:
Requirement R2 - The language in the Moderate VSL of R2 recognizes another potential reason for
delay in execution of a directive. Requirement 2 of the Standards needs to be modified to also
recognize this potential.
Requirements R2 and R3 - Clarify that entities are obligated to take action and confirm directives only
from their Reliability Coordinators, not from any Reliability Coordinator. Requirements R2, R3, R4, R5
- Inconsistent use of “timing” words in the standards — "without intentional delay" and "immediately".
Suggest deleting these words due to the difficulty of determining compliance.
Requirement R4 - The term “Adverse Reliability Impacts? is being changed and is listed in the
associated Implementation Plan. The revision of this definition needs to go through Due Process.
Requirement R5 - The VRF should be "Lower" instead of "High" since the notification is that the
threat has been mitigated. Also, the term “Adverse Reliability Impacts” is being changed and is listed
in the associated Implementation Plan. The revision of this definition needs to go through Due
Process.
Response: The RC SDT thanks you for your comment.
R1 Both scenarios are envisioned by the requirement. The proposed revision to the definition will be balloted along with the standard revision.
& R4, &R5. The TSPs, LSEs, and PSEs have been added to COM-001 and COM-002 as you suggest.
R2, already included in R2 “unless such actions would violate safety, equipment, or regulatory or statutory requirements.”
R2, R3, The RC SDT modified R2, R3 to identify “its” RC. The phrases “immediately” and “without intentional delay” have been removed from
the standard.
R4 The revision to the definition will be placed in the correct location on the next posting and will be balloted along with the standard revisions.
R5, The RC SDT modified the VRF for R5 to medium based on other industry comments.
Buckeye Power, Inc.
Yes and No
abstain
ISO/RTO Council
Standards Review
Subcommittee
Yes and No
New requirement R2 should omit act without intentional delay. Use of intentional implies willful
disregard for compliance for the requirement. Intention should not be addressed as part of the
compliance with the requirement but rather through the enforcement process once the compliance
auditor has identified a violation.
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Organization
Question 7:
Question 7 Comments:
The word immediately should be removed from the new R3. This attempts to time frame the response
of the responsible entity and remove the judgment from the compliance auditor. We agree with the
concept of doing this but in reality it only confuses the issue and the compliance auditor will likely
apply his judgment regarding what immediate is anyway. Additionally, the requirement attempts to
separate the act of confirming that the responsible entity can take the action from notifying the RC
that the entity can't take the action. This is not logical. What RC is going to request a responsible
entity to take action that would violate safety, equipment, statutory, or regulatory requirements? The
RC should already be aware of those requirements and likely won't direct actions that violate them.
Thus, the likely scenario is that the responsible entity will attempt to take action and discover that
equipment is not functioning properly and thus notify the RC. We suggest striking the "shall
immediately confirm the ability to comply with the directive or" from the requirement. This part of the
requirement is not needed because the responsible entity is already obligated to follow the RCs
directive (see order 693.) Thus, the assumption is that the order will be followed unless it can't be
followed because it will violate safety, equipment, statutory, or regulatory requirements.
Requirements R4 and R5 are unnecessary. New R1 requires the RC to direct actions to be taken by
the TOP, BA, GOP, TSP, LSE, DP and PSE to prevent or mitigate the magnitude or duration of
events that result in Adverse Reliability Impacts. The RC can't direct these actions without notifying
all impacted TOPs and BAs. They would also have to notify them when actions are no longer
necessary.
The VRF for R5 should not be High. Failure to notify others when potential threats to system reliability
have been mitigated does not constitute a high risk to the interconnected system. We suggest it be
reduced to a Medium (i.e., that it affects control of the BES).
Response: The RC SDT thanks you for your comment. The RC SDT has removed the phrases “immediately” and “without intentional delay”
from the proposed requirements. The RC SDT modified R3 based on industry comments and the phrase, “shall immediately confirm the ability
to comply with the directive or" was removed from the requirement.
The RC SDT does not agree with regard to R4 and R5, as some impacted entities may not need to take action or be issued directives but
would benefit from the situational awareness associated with knowing the status of operating issues.
The RC SDT modified the VRF for R5 to medium based on industry comments.
CU Springfield
July 10, 2009
Yes
CU supports the effort to consolidate redundant requirements in the standards.
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Organization
Question 7:
Question 7 Comments:
Response: The RC SDT thanks you for your comment.
PJM Interconnection
Yes
Salt River Project
Yes
NPCC
Yes
Ameren
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
Bonneville Power
Administration
Yes
AEP
Yes
July 10, 2009
68
8. Do you agree with the revisions to the Measures in IRO-001-2 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Summary Consideration:
The RC SDT has received a notable number of comments suggesting edits to the proposed requirements and measures for the
draft standard, particularly regarding the phrase “without intentional delay.” The comments do not oppose the objective of the
phrase, but often point out the issues of measuring intent and measuring time delay.
To maintain the intent while improving the measurability of the requirement, the SDT proposes to modify the standard as
follows: delete the phrase ‘without intentional delay’ and leave the obligation of response and timing an unstated requirement
of R1 “The RC shall act or direct actions…”
An RC that requires a given action in a given time will be expected to inform the impacted entities of those actions and time
requirements. This revision would obviate the need for providing a measure for “intent”, while still maintaining the reliability
intent of the original requirement.
The SDT proposes to re-post the standard to obtain stakeholder feedback on the suggested revisions.
Organization
Question 8:
CU of Springfield
No
Question 8 Comments:
M2 and M3 should include Distribution Provider as one of the entities to comply with directives from
the Reliability Coordinator.
Response: The RC SDT thanks you for your comment.
The SDT will correct the oversight.
Independent
Electricity System
Operator - Ontario
No
Wording in some of the Measures needs to be revised to reflect changes to R2 and/or R3, if our
proposed changes are accepted. Also, we suggest the Requirement numbers be referenced in the
Measures.
Response: The RC SDT thanks you for your comment.
The SDT has revised the R2 and R3 and the associated measures per stakeholder comments. We have also added the associated
requirement number to each measure.
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Organization
Question 8:
Reliability
Coordinator
Comment Working
Group
No
Question 8 Comments:
Measures do not align with VSLs (see question 9)
Response: The RC SDT thanks you for your comment. We will ensure that the VSLs and measures align.
MRO NERC
SDTandards Review
Subcommittee
No
Some compliance auditors have been taking the need for evidence to the extreme. We have
encountered actual situations where if a measure states evidence shall be provided for requirements
that are event based, the compliance auditor expected evidence even if no event occurred. For
example, some RCs rarely issue directives. As M1 is written, some compliance auditors would
require the RC to provide evidence that no reliability directives were issued. This is not possible. We
suggest modifying the measurement to: Each Reliability Coordinator shall have evidence that it
acted, or issued directives, to prevent or mitigate the magnitude or duration of Adverse Reliability
Impacts within its Reliability Coordinator Area if needed. If there were no directives issues (assuming
there are no complaints or evidence to the contrary of the need to issue a directive), no evidence is
necessary."
Response: The RC SDT thanks you for your comment. The RC SDT agrees with the principle (i.e. should not have to prove a negative to an
auditor). This issue should be addressed with NERC or Regional Compliance personnel. The RC SDT has the obligation to draft measures
based on the requirements. The measure (M1) for R1 accomplishes that as written.
Southern Company
Transmission
No
8.1 - In M2 and M3, Add Distribution Provider.
8.2 - In M2 add "intentional" between "without" and "delay".
8.3 - In M3 replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before
Reliability Coordinator's and Reliability Coordinator.8.4 - In M5, change "has" to "had".
Response: The RC SDT thanks you for your comment. We have added DP to the measures M2 and M3.
We have removed the phrases “immediately” and “without intentional delay” from the measures.
The RC SDT has left the word “inability” in the measure to mirror the requirement. We have made the other revisions that you suggested.
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Organization
Question 8:
MEAG Power
No
Question 8 Comments:
The M2 measure should not mandate compliance with RC directives that are improper as defined in
my response to question 7.
Response: The RC SDT thanks you for your comment. It is envisioned by the RC SDT that RC directives consist of real-time and same-day
operating actions that prevent or mitigate events that may or will cause Adverse Reliability impacts.
SERC OC
Standards Review
Group
Yes and No
8.1 - In M2 and M3, Add Distribution Provider.
8.2 - In M2 add "intentional" between "without" and "delay".
8.3 - In M3 replace "ability" with "intent", replace "or" with "and" and replace "the" with "its" before
Reliability Coordinator's and Reliability Coordinator.8.4 - In M5, change "has" to "had".
Response: The RC SDT thanks you for your comment. We have added DP to the measures M2 and M3.
We have removed the phrases “immediately” and “without intentional delay” from the measures.
The RC SDT has left the word “inability” in the measure to mirror the requirement. We have made the other revisions that you suggested.
US Bureau of
Reclamation
No
M4. and M5. In both Measures, recommend “without intentional delay” be changed as described
above for R4. and R5.
Response: The RC SDT thanks you for your comment. Based on stakeholder comments, we have removed “without intentional delay” from
the requirement and measure.
Progress Energy
Carolinas
FirstEnergy
No
M2 - The word "intentional" should be added between "without" and "delay".
Response: The RC SDT thanks you for your comment. Based on stakeholder comments, we have removed the phrase “without intentional
delay” from the requirement and measure.
Duke Energy
July 10, 2009
No
Measures M2, M4 and M5 use the terms "without delay" and "without intentional delay". Suggest
deleting these words due to the difficulty of determining compliance. The term “Adverse Reliability
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Organization
Question 8:
Question 8 Comments:
Impacts” is being changed and is listed in the associated Implementation Plan. The revision of this
definition needs to go through Due Process.
Response: The RC SDT thanks you for your comment.
We have removed the phrases “immediately” and “without intentional delay” from the measures.
The proposed definition has been added to the standard and will be posted with the proposed revisions to the standard.
Consolidated Edison
Co. of NY, Inc.
Yes and No
[Comments repeated for Measures] Wording in question:R.2/M.2 Each Load-Serving Entity, or
Purchasing-Selling Entity shall have evidence that it acted without intentional delay to comply with the
Reliability Coordinator's directives.R.3/M.3 Each Load-Serving Entity, or Purchasing-Selling Entity
shall have evidence that it confirmed its ability to comply with the Reliability Coordinator's directives.
[1] Question: Is this wording absolutely necessary? And then, is it sufficient, if needed? Comment:
First, we would question whether there is a specific need to include this wording. Is the IRO-001
Reliability Standard sufficient without it?
[2] Question: Is this wording unambiguous? Comment: The wording seems somewhat vague and
ambiguous. Analysis: The wording appears to establish performance standards ("without intentional
delay", “shall immediately confirm”) and evidentiary requirements (“evidence that it acted” or
“evidence that it confirmed”), but without using pre-existing defined terms, establishing new defined
terms, or defining these terms as used in context.
[3] Intentional vs. Unintentional, Valid Intentional vs. Inappropriate Intentional? How does one
differentiate between intentional and unintentional delay? When is and how much delay is valid or
inappropriate? Isn’t some intentional delay necessary to ensure that the other parts of the
requirement being are met, e.g., unless such actions would violate safety, equipment, or regulatory or
statutory requirements?? Mightn’t some acceptable amount of valid intentional delay be necessary to
insure that any such RC directive and entity action would not in fact violate these safety, equipment,
or regulatory or statutory requirements?
[4] What is the timeliness standard? How are the terms “without delay” and “immediately conform”
defined? What standard commercial measures would apply, e.g., “reasonably efforts” vs. “best
efforts”? Are these terms measured in units of time (seconds or minutes) or in units of performance
quality? Does a poorly considered “immediate” reply meet the standard, while a well considered
reply, which is intentionally delayed, yet still appropriate, fail to meet this standard? Is that the best
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Organization
Question 8:
Question 8 Comments:
outcome?
[5] What is this Evidentiary Standard? Is the sought-after “evidence” sufficiently well defined, e.g.,
phone logs, computer e-mail, control center computer logs, hand-written operator journals, etc.?
What form of evidence is necessary and sufficient to demonstrate that the entity met this evidentiary
standard? How is failure to meet this uncertain standard measured, judged and penalized?
Response: The RC SDT thanks you for your comment. We have removed the phrases “immediately” and “without intentional delay” from the
measures.
Buckeye Power, Inc.
Yes and No
abstain
American
Transmission
Company
Yes
If some language is changed, we support the revisions. R2 has language in it that should be added
to M4 to be consistent. In M2, we propose adding language "unless such actions would violate
safety, statutory or regulatory requirements."
Response: The RC SDT thanks you for your comment.
The suggested change has been made.
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Northern California
Power Agency
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
July 10, 2009
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Organization
Question 8:
PJM Interconnection
Yes
Bonneville Power
Administration
Yes
AEP
Yes
July 10, 2009
Question 8 Comments:
74
9. Do you agree with the Violation Severity Levels proposed in IRO-001-2 as shown in the posted Standard and Implementation Plan?
If not, please explain in the comment area.
Summary Consideration: The VSLs were revised to reflect revisions to the requirements as well as the comments of
stakeholders. Several comments suggested that there was no fundamental difference between the RC “acting” or “directing
actions”. The RC SDT agreed and removed the High VSL for R1 and revised the Severe VSL accordingly. Other commenters
suggested removing the High VSL from R2 as the VSL contradicted the requirement. The RC SDT agreed and removed the VSL.
All of the revised VSLs are in the table below.
Requirement
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
N/A
N/A
N/A
The Reliability Coordinator failed
to act or direct actions to prevent
or mitigate the magnitude or
duration of Adverse Reliability
Impacts
R2
N/A
N/A
N/A
The responsible entity failed to
follow the Reliability Coordinator
directive and it would not have
violated the safety, equipment,
statutory or regulatory
requirements.The responsible
entity did not follow the Reliability
Coordinators directive per
requirement 2.
R3
N/A
N/A
N/A
The responsible entity failed to
inform the its Reliability
Coordinator upon recognition of
the its inability to perform the
directive.
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R4
The Reliability Coordinator who
identified an expected or actual
threat with Adverse Reliability
Impacts within its Reliability
Coordinator Area and failed to
issue an alert to one, but not all,
impacted Transmission
Operators and Balancing
Authorities in its Reliability
Coordinator Area.
R5
R6
The Reliability Coordinator who
identified an expected or actual
threat with Adverse Reliability
Impacts within its Reliability
Coordinator Area and failed to
issue an alert to two, but not all,
impacted Transmission
Operators and Balancing
Authorities in its Reliability
Coordinator Area.
The Reliability Coordinator who
identified an expected or actual
threat with Adverse Reliability
Impacts within its Reliability
Coordinator Area and failed to
issue an alert to three or more,
but not all, impacted
Transmission Operators and
Balancing Authorities in its
Reliability Coordinator Area.
The Reliability Coordinator who
identified an expected or actual
threat with Adverse Reliability
Impacts within its Reliability
Coordinator Area and failed to
issue an alert to all impacted
Transmission Operators and
Balancing Authorities in its
Reliability Coordinator Area.
The Reliability Coordinator
issued an alert failed to notify
entities of a transmission problem
but failed to notify one, but not
all, impacted Transmission
Operators, Balancing Authorities,
when the transmission problem
had been mitigated.
The Reliability Coordinator
issued an alert to notify entities of
a transmission problem but failed
to notify two, but not all, impacted
Transmission Operators,
Balancing Authorities, when the
transmission problem had been
mitigated.
The Reliability Coordinator
issued an alert to notify entities of
a transmission problem but failed
to notify three or more, but not
all, impacted Transmission
Operators, Balancing Authorities,
when the transmission problem
had been mitigated.
The Reliability Coordinator
issued an alert to notify entities of
a transmission problem but failed
to notify all impacted
Transmission Operators,
Balancing Authorities, when the
transmission problem had been
mitigated.
N/A
N/A
N/A
The Reliability Coordinator failed
to provide its Operating operating
Personnel personnel with the
authority to veto planned outages
of its own analysis tools.
Organization
Question 9:
Question 9 Comments:
Manitoba Hydro
No
IRO-001-2 R1 VSLs: You can not split "shall act" and "or direct actions" into separate VSLs. They are one and same. If the RC
directs action then they have acted. If the RC failed to direct action or have failed to other wise act then they have failed to act
appropriately. Perhaps the VSLs can be drafted along the lines of the following:
IRO-001-2 R1 High VSL… The Reliability Coordinator's action was incomplete in that it failed to demonstrate a specific
action to prevent or mitigate the magnitude or duration of Adverse Reliability Impacts.
IRO-001-2 R1 Severe VSL… The Reliability Coordinator failed to act to prevent or mitigate the magnitude or duration of
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Organization
Question 9:
Question 9 Comments:
Adverse Reliability Impacts.
IRO-001-2 R2 VSLs:
(1) Entities may be justified in an intentional delay in responding to an RC directive. A justified intential delay may due be
equipment problems, a generators ramp rate or system voltage adjustments prior to large system reconfiguration or large
transmission loading changes.
(2) An entity cannot be faulted for not following an RC directive because to it would violate safety, equipment, regulatory or
statutory requirements.
Perhaps the VSLs can be drafted along the lines of the following:
Moderate VSL… should be deleted.
High VSL… The responsible entity followed the Reliability Coordinators directive but with an unjustified delay.
Severe VSL… no edits required.
IRO-001-2 R5 VSLs:
Perhaps the VSLs can be drafted along the lines of the following to reflect to what degree the RC missed the mark:
Lower VSL…The Reliability Coordinator failed to notify <25% of its impacted Transmission Operators and Balancing
Authorities when the transmission system problem had been mitigated.
Moderate VSL… The Reliability Coordinator failed to notify >24% but <50% of its impacted Transmission Operators and
Balancing Authorities when the transmission system problem had been mitigated.
High VSL…The Reliability Coordinator failed to notify >49% but <75% of its impacted Transmission Operators and
Balancing Authorities when the transmission system problem had been mitigated.
Severe VSL… The Reliability Coordinator failed to notify >74% of its impacted Transmission Operators and Balancing
Authorities when the transmission system problem had been mitigated.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and direct actions. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL.
R2: 1. The SDT removed the “intentional delay” wording. 2. We concur with your statement. The RC SDT believes that the revised requirement is a binary and thus only
requires one VSL. We have removed the High VSL and revised the severe VSL to:
The responsible entity failed to follow the Reliability Coordinator directive and it would not have violated the safety, equipment, statutory or regulatory requirements.
R5: The RC SDT developed a revised set of VSLs that are graded in a way that gives consideration to the number of impacted entities since some entities will have a very
small number of entities to contact, and using percentages may not be effective.
Independent
Electricity System
July 10, 2009
No
R1: There should not be any distinction made between an RC acting and an RC directing others to act. Failure to
mitigate adverse reliability impacts a severe violation of the requirement. We therefore suggest to revise the High and Severe
levels as: High if the RC did not act or direct actions to prevent an Adverse Reliability Impact; Severe if the RC did not act or
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Organization
Question 9:
Operator - Ontario
Question 9 Comments:
direct actions to mitigate the magnitude or duration of an existing Adverse Reliability Impact.
R2: The High VSL seems contradictory to the requirement, which already has provision of not fully complying with
the RC directives due to safety, equipment, or regulatory or statutory requirements.
R3: We have proposed some wording change to R3, which if adopted, would precipitate a need to revise the VSLs
for R3 accordingly.
(iv) R4 and R5: The VSLs for these two requirements could be graded by assessing the number and/or timing of
notifying the affected entities.
Response: The RC SDT thanks you for your comment.
The RC SDT agrees with you regarding “act” and “direct actions”. Based on yours and other stakeholders’ comments, we have removed the High VSL and
revised the severe VSL.
We agree and have removed the High VSL.
R3. The requirement was revised and the Lower VSL removed.
R4 and R5: We concur and have expanded the VSLs to include notification of a varying number of entities.
Reliability
Coordinator
Comment Working
Group
No
R1 talks about "shall act or direct actions to be taken".
High VSL - failure to act.
Severe VSL - failure to act and direct. Does "act" mean any action taken short of issuing a directive? Change Severe VSL to
failure to act or direct and eliminate the High VSL all together.
R2 delay in issuing a directive due to equipment problems should be included in the moderate VSL and the body of the
requirement and in the measure. The High VSL should be removed because not following the directive for equipment failure
is allowed per R2.
R5 - Severe VSL should be changed to moderate VSL since the problem has been mitigated and the system is stable and it
does not adversely impact reliability.
M3 talks about the ability of reliability entities to meet a directive. What constitutes evidence that confirms you are able to
immediately comply with the directive? If the entity agrees to the directive and then is unable to comply due to events outside
of their control, such as a CT not starting, do they meet the measure? If the entity, based on the circumstances at the time of
the directive, agrees to comply in good faith are they compliant? The Lower VSL should be made N/A because it is not
practical for an entity to immediately confirm they are able to meet the directive in all cases.
Response: The RC SDT thanks you for your comment.
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Organization
Question 9:
Question 9 Comments:
R1 - The RC SDT agrees with you regarding “act” and “direct actions” and has removed the High VSL and revised the Severe VSL.
R2 - Based on your and other stakeholders’ comments, we have removed the High VSL and revised the severe VSL.
R5: The VSL relates to how badly an entity missed the requirement, not the threat to reliability (this is the VRF). The requirement is to notify “all”. The RC SDT has
developed a revised set of graded VSLs for this requirement.
M3. The requirement was revised to remove words such as “immediately” and intentional delay:
R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and PurchasingSelling Entity shall inform its Reliability Coordinator upon recognition of its inability to perform a directive.
The measure was revised to reflect the new requirement which addresses your concerns. The Lower VSL was revised to N/A.
MRO NERC
SDTandards Review
Subcommittee
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in Severe. From a practical
perspective, what is the difference between directing actions and acting? We don't believe there is any. The actions are the
result of the RC authority whether the RC takes the actions themselves or directs someone else to. We suggest a better
alternative for the VSL levels would be for the High level to reflect that the RC did not act or direct actions to prevent an
Adverse Reliability Impact and Severe would be that the RC did not act or direct actions to mitigate the magnitude or duration
of an existing Adverse Reliability Impact.
The moderate VSL for R2 is not practical and too subjective. What constitutes a delay? What if the responsible entity takes
five minutes to determine how to carry out the action or if their equipment currently is capable of carrying out the action? Is
this a delay? We suggest striking this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory, or regulatory requirements a
violation. This is in direct conflict with the requirement. We suggest that the High VSL should be struck. We suggest the
Severe VSL should be that the responsible entity failed to follow the RC directive and it would not have violated the safety,
equipment, statutory or regulatory requirements. Currently, the Severe category does not allow that the responsible entity may
not be able to carry out the directive due to the violation of safety, equipment, statutory, or regulatory requirements.
In question 7, we request that the drafting team strike part of requirement 3. The striking of that portion of requirement 3
obviates the lower VSL.
In paragraph 27 of the ORDER ON VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY
ORGANIZATION, the Commission expresses "that, as a general rule, gradated Violation Severity Levels, wherever possible,
would be preferable to binary Violation Severity Levels". Given that it is possible to define gradated VSLs for R4 and R5, we
suggest that the drafting team should consider applying the numeric performance category of the Violation Severity Levels
Development Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
Response: The RC SDT thanks you for your comment.
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Organization
Question 9:
Question 9 Comments:
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL to include failure to “act or direct actions”.
R2. We have removed the “intentional delay” verbiage and subsequently removed the Moderate VSL. We agree with you regarding the High VSL and have removed it from
the table. The Severe VSL was revised per your suggestion.
R3. The requirement was revised and the Lower VSL removed.
R4 and R5: We concur and have expanded the VSLs to include notification of a varying number of entities.
Southern Company
Transmission
No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he doesn't - If he fails to act, he
fails to direct and mitigate the problem by default.
9.2 - R2 VSLs need to be rewritten to recognize that some directives may not be followed because of safety, regulatory or
statutory requirements.
9.3 - Remove the Lower severity level in R3 to conform to changes in R3 and M3.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL. This is now treated as a binary requirement with just one VSL.
R2. We agree and have removed the High VSL and revised the severe VSL to:
The responsible entity failed to follow the Reliability Coordinator directive and it would not have violated the safety, equipment, statutory or regulatory requirements.
R3. The requirement was revised and the Lower VSL removed.
Entergy Services,
Inc
No
The VSL for R2 does not seem consistent with the language in the requirement. It is not clear why the entity should be
subject to a high VSL if the entity did not comply with an RC directive due to safety or regulatory prohibition, and made the RC
aware of same.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. The High VSL for R2 was removed.
Salt River Project
No
R1 states the RC must act OR direct. The R1 VSLs attempt to distinguish between act and direct. The requirement allows for
either action. I suggest that the High VSL be removed and replaced by an N/A. The Severe VSL should be amended so that
the words "act and direct" are replaced by the words "act OR direct" as is consistent with the requirement and the measure.
R2: The moderate VSL introduces the phrase "equipment problems" for the first time in the Standard. "Equipment Problems"
needs to be included in the Requirement, R2, and defined in the Measure for
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Question 9:
Question 9 Comments:
R2.R5: The Severe VSL needs to be moved to the Moderate category. This condition does not constitute an Adverse
Reliability Impact that severely threatens the BES.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL to use the phrase, “act or direct.”
R2. The moderate VSL was removed.
R5: The VSL relates to how badly an entity missed the requirement, not the threat to reliability (this is the VRF). The requirement is to notify “all”. The RC SDT believes it
has developed appropriate VSLs for this requirement.
FirstEnergy
No
R2 VSL - The Severe VSL should include after the word directive: "that would not violate safety, equipment, statutory or
regulatory requirements".
Response: The RC SDT thanks you for your comment. We agree with your premise, but the suggested wording of the VSL appears cumbersome. The VSL has been
revised to:
The responsible entity did not follow the Reliability Coordinator’s directive per Requirement R2.
Duke Energy
No
The language in R1 of the VSL is not consistent with the requirements and measures in the standard. The VSL needs to
recognize that the RC may EITHER act or give direction to others to act.
The term “Adverse Reliability Impacts” is being changed and is listed in the associated Implementation Plan. The revision of
this definition needs to go through Due Process.
The language in R2 of the VSL places an entity in Moderate or High violation level even if failure is “allowed” in the standard;
i.e. failure to act is due to violation of safety, regulatory, statutory requirements.
The language in R2 of the VSL recognizes another potential reason for delay in execution of a directive. Requirement R2 of
the Standard needs to be modified to also recognize this potential.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL to use the phrase, “act or direct.”
The proposed revision to the term, “Adverse Reliability Impact” will be posted for stakeholder comment with the next version of the standard.
R2. We agree and have removed the Moderate and High VSLs and revised the Severe VSL to :
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Question 9:
Question 9 Comments:
The responsible entity failed to follow the Reliability Coordinator directive and it would not have violated the safety, equipment, statutory or regulatory requirements.
The requirement already addresses equipment.
American
Transmission
Company
No
VSLs for R2 and R3 are not appropriate. In order to assess a situation we may not be able to immediately inform the RC of
our ability to comply with the directive. The high VSL for R2 currently states that if we do not follow the directive because of
safety, statutory or regulatory requirements, it is a high VSL. An entity should not be penalized for not breaking the law.
Response: The RC SDT thanks you for your comment.
R2: We agree and have removed the Moderate and high VSLs.
R3. The requirement was revised to remove the “immediately” verbiage and the VSLs were revised accordingly – the Lower VSL was removed.
ISO/RTO Council
Standards Review
Subcommittee
No
The R1 High and Severe VSL appear to differ only by the inclusion of directing actions in Severe. From a practical
perspective, what is the difference between directing actions and acting? We don't believe there is any. The actions are the
result of the RC authority whether the RC takes the actions themselves or directs someone else to. We suggest a better
alternative for the VSL levels would be for the High level to reflect that the RC did not act or direct actions to prevent an
Adverse Reliability Impact and Severe would be that the RC did not act or direct actions to mitigate the magnitude or duration
of an existing Adverse Reliability Impact.
The moderate VSL for R2 is not practical and too subjective. What constitutes a delay? What if the responsible entity takes
five minutes to determine how to carry out the action or if their equipment currently is capable of carrying out the action? Is
this a delay? We suggest striking this Moderate VSL. The High VSL does not agree with the requirement. It considers the
inability to fully follow an RC directive due to a violation of the safety, equipment, statutory, or regulatory requirements a
violation. This is in direct conflict with the requirement. We suggest that the High VSL should be struck. We suggest the
Severe VSL should be that the responsible entity failed to follow the RC directive and it would not have violated the safety,
equipment, statutory or regulatory requirements. Currently, the Severe category does not allow that the responsible entity may
not be able to carry out the directive due to the violation of safety, equipment, statutory, or regulatory requirements.
In question 7, we request that the drafting team strike part of requirement 3. The striking of that portion of requirement 3
obviates the lower VSL.
In paragraph 27 of the ORDER ON VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY
ORGANIZATION, the Commission expresses "that, as a general rule, gradated Violation Severity Levels, wherever possible,
would be preferable to binary Violation Severity Levels". Given that it is possible to define gradated VSLs for R4 and R5, we
suggest that the drafting team should consider applying the numeric performance category of the Violation Severity Levels
Development Guidelines Criteria based on the number of impacted TOPs and BAs that were notified.
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Organization
Question 9:
Question 9 Comments:
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL to use the phrase, “act or direct.”
R2. We agree and have removed the Moderate and High VSLs and revised the Severe VSL to :
The responsible entity failed to follow the Reliability Coordinator directive and it would not have violated the safety, equipment, statutory or regulatory requirements.
R3. The requirement was revised and the Lower VSL removed.
R4 and R5: We concur and have expanded the VSLs to include notification of a varying number of entities.
SERC OC
Standards Review
Group
Yes and No
9.1 - R1 is a binary requirement and should have only a severe VSL. The RC either acts or he doesn't - If he fails to act, he
fails to direct and mitigate the problem by default.
9.2 - R2 VSLs need to be rewritten to recognize that some directives may not be followed because of safety, regulatory or
statutory requirements.
9.3 - Remove the Lower severity level in R3 to conform to changes in R3 and M3.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with you regarding “act” and “direct actions”. Based on your and other stakeholders’ comments, we have removed the High VSL and revised the
severe VSL to use the phrase, “act or direct.”
R2. We agree and have removed the High VSL and revised the Severe VSL to:
The responsible entity failed to follow the Reliability Coordinator directive and it would not have violated the safety, equipment, statutory or regulatory requirements..
R3. The requirement was revised and the Lower VSL removed.
Consolidated Edison
Co. of NY, Inc.
Yes and No
Agreement uncertain, subject to further clarification of Requirements and Measures performance standards and definitions
(see our comments on Requirements and Measures). Without clearer definitions, e.g., for "immediate," or any allowance for
appropriate intentional delay, it is not entirely clear that the VSLs comport with the ultimate meaning, intent and needed
wording to be incorporated into the Requirements and Measures. Why would failure to fully comply, when precluded by
conditions specifically allowed in the standard, necessarily be a problem, so long as the RC received timely notice, however
defined?
Response: The RC SDT thanks you for your comment. The SDT removed the word, “immediate” and the phrase, “without intentional delay” from the standard.
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Organization
Question 9:
Question 9 Comments:
Buckeye Power, Inc.
Yes and No
abstain
Northern California
Power Agency
Yes
CU of Springfield
Yes
NPCC
Yes
Ameren
Yes
US Bureau of
Reclamation
Yes
PJM Interconnection
Yes
Bonneville Power
Administration
Yes
AEP
Yes
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84
10. Do you agree with the revisions to the Requirements in IRO-002-2 as shown in the posted Standard and Implementation Plan? If
not, please explain in the comment area.
Summary Consideration: The last proposed version of IRO-002-2 had two requirements – R1 required the Reliability
Coordinator to request data from other entities; R2 required the Reliability Coordinator to provide its operating personnel with
authority to veto planned outages of analysis tools.
Since the inception of this project (2006-06), the IROL Standards Drafting Team has proposed, successfully balloted and
obtained NERC Board of Trustees’ approval for a new Standard IRO-010-1: Reliability Coordinator Data Specification and
Collection. The work of the IROL SDT retired IRO-002 Requirement R1 and eliminated the need for the proposed R2.
The team received comments expressing concern about eliminating the requirement to monitor frequency which had been in an
earlier approved version of IRO-002. While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even
more concerned with the subjectivity that any attempt to measure “Monitoring” can provide. It is the SDT’s contention that
adherence to reliability standards that require the said monitoring cannot be demonstrated unless the entity is closely
monitoring the system parameters. Furthermore, the SDT contends that any requirements that describe the monitoring
facilities needed to fulfill fundamental duties should be embedded in Certification Requirements. With IRO-014 and IRO-001 R1
in place, the actual act of monitoring is a secondary task that is inherent in responding to situations or events that could have
an adverse impact on reliability. The team retained the remaining requirement (Reliability Coordinator’s authority to veto
analysis tool outages) as it was a specific recommendation from the 2003 Blackout report. This requirement was revised and
moved into IRO-001-2, R6.
R6.
Each Reliability Coordinator shall haveprovide its operating personnel with the authority to veto planned outages to its
own analysis tools, including final approvals for planned maintenance. [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations, Same Day Operations and Operations Planning]
Organization
Question 10:
Independent
Electricity System
Operator - Ontario
No
July 10, 2009
Question 10 Comments:
R1: There is a duplicating requirement in TOP-005 R1.1. Suggest to eliminate one of the
two.
We do not agree with eliminating all of R5 to R8. There is a fundamental need for RCs to
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Question 10:
Question 10 Comments:
monitor its area, and even some portion of its adjacent areas to be aware of situations that require
preventive and mitigating actions. While arguments can be made that requiring RCs to prevent and
mitigate adverse reliability impacts would imply monitoring, the latter is a fundamental duty of any
RCs to ensure system reliability. If monitoring is not explicitly stated as a requirement, then the same
argument may be extended to training and operational facilities. We do not agree with the drafting
team's conclusion that it is not practical to measure real-time monitoring. Measuring can be
illustrated, for example, by a compliance audit to review system logs and assess the extent to which
an RC follows and assesses system conditions.
Response: R1: The RC SDT thanks you for your comment. Several NERC drafting teams are working on related standards. The RTO SDT
just posted changes to TOP-005 that will retire that standard upon approval. Therefore, there will be no redundancy because TOP-005 R1.1
will be removed.
Monitoring: While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even more concerned with the subjectivity that
any attempt to measure “Monitoring” can provide. It is the SDT’s contention that adherence to reliability standards that require the said
monitoring cannot be demonstrated unless the entity is closely monitoring the system parameters. Furthermore, the SDT contends that any
requirements that describe the monitoring facilities needed to fulfill fundamental duties should be embedded in Certification Requirements.
With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in responding to situations or events
that could have an adverse impact on reliability.
Reliability
Coordinator
Comment Working
Group
No
For R1, this should be 2 separate requirements and measures. R1 should have a methodology for
determining what data is needed and then a R2 should be a requirement to request this data from the
reliability entities.
Response: The RC SDT appreciates your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1.
MRO NERC
SDTandards
Review
Subcommittee
No
New Requirement R1 is duplicate to the requirement TOP-005-1 R1.1. If the drafting team can't
delete TOP-005-1 R1.1, they should notify other appropriate drafting teams of the need to remove the
requirement.
We do not agree with eliminating requirements R5, R6, R7, and R8 in their entirety. The requirements
as they are written are problematic. However, we do believe that there is a need for a basic
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Question 10:
Question 10 Comments:
requirement to monitor the system. The requirements should be that the RC should compare actual
system flows to SOLs and IROLs. While some will argue SOLs are not the responsibility of the RC,
failure to monitor SOLs could cause the RC to miss unknown IROLs since an SOL can become an
IROL. Several SOL violations in a given area also can be indicative of a broader system problem the
RC should be addressing. We also do not agree with the drafting team's conclusion that it is not
practical to measure real-time monitoring. It is very easy to measure. As an example, a compliance
auditor could select a day and an SOL or IROL and ask for the system flows from that day or hour
etc. This is generally easy for any RC to produce with today's data archiving software. We believe
that there should be a requirement that the RC have a state estimator and real-time contingency
analysis as well (RTCA). The drafting team needs to be careful in the construction of these
requirements to make them practical and measurable. For instance, making the requirement to have
a state estimator and RTCA is measurable in that the compliance auditor can verify their existence
but this is not stringent enough because they may only run once a week. At the same time, if we
create a requirement that SE and RTCA must run every 5 minutes, we could inadvertently create a
requirement that any missing 5 minute run of RTCA and SE could be construed as a violation. There
also needs to be a requirement that there is a real-time assessment of voltage as well.
New Requirement R2 is no longer needed as a result of paragraph 112 in Order 693-A. Since the
RC's "authority to issue directives arises out of the Commission's approval of Reliability Standards"
the RC already has veto authority or will have once R1 IRO-001-2 is approved. This requirement
obligates the RC to take actions or direct actions to prevent Adverse Reliability Impacts. Veto outages
of equipment and analysis tools would fall into this category even if the RC couldn't say for certain
that an Adverse Reliability Impact was going to occur but rather they are concerned one could occur
due to heavy loads for example.
Response: The RC SDT appreciates your comments. The RTO SDT has recently posted the proposed retirement of TOP-005. This
eliminates the redundancy with R1.
The RC SDT appreciates your comments and recognizes that NERC standards historically have included requirements to ensure that each
entity is acting responsibly in the portion of the Interconnect over which it has authority. The IRO-014, as proposed by this team, requires RCs
to act in coordinated fashion to protect the Interconnection. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary
task that is inherent in responding to situations or events that could have an adverse impact on reliability.
The RC must respond to these situations proactively in order to prevent separation or cascading events.
The RC SDT agrees philosophically with your comment regarding the redundancy of Requirement R2, however, this issue was enumerated in
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Question 10:
Question 10 Comments:
the report on the 2003 Blackout as a key improvement. The team believes that, while this is redundant as you stated, it is too soon to remove it
from standards. At some point in the future after the industry assimilates the set of changes currently proposed, this requirement could be
proposed for deletion.
Southern
Company
Transmission
No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this
standard retired. If this standard is not retired then we recommend Comments
10.2 and 10.3.10.2 - At Requirement R2, the RC is given 'veto' authority. Is a standard an
appropriate place to give this type of authority?
10.3 - The revised Purpose basically provides that the RC will have access to information and control
of analysis tools. What is the correlation of information/control to veto authority/approval of planned
maintenance?
Response: The RC SDT appreciates your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1.
R2. This is a Blackout recommendation and therefore is appropriate within a standard. We revised the wording to indicate that the RC will
provide its Operating Personnel the authority. This clarified the intent of the requirement. This requirement will also be moved into IRO-001-2,
R6.
10.3 This standard will be retired making the purpose statement moot.
ISO New England
Inc.
Yes and No
Suggest changing with word "request" to "document" in Requirement 1.
Response: The RC SDT appreciates your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1.
Entergy Services,
Inc
July 10, 2009
No
IRO-002-1 R9, the deleted language of the second sentence is not adequately covered by the
language in EOP-008-0 R1, unless those outages are tied to the loss of a control center. EOP-008-0
is in the process of being revised and this language could be included in the revision, but it isn't
adequately addressed by the version 0 standard.
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Question 10:
Question 10 Comments:
Response: The RC SDT appreciates your comments. The RC SDT took this comment into consideration when making revisions to this
requirement as well as to COM-001-2 regarding specifications. The data specification required in IRO-010 should address mitigation plans for
analysis tool outages and proposed COM-001 specifications should include mitigation plans for communications outages.
US Bureau of
Reclamation
No
R2. This requirement provides authority to the Reliability Coordinator to veto planned outages and
approve planned maintenance to “analysis tools”. It is not clear in this standard what these “analysis
tools” are. Per FERC Order 693, NERC was to identify a minimum set of analysis tools and the task
was assigned to the Real-Time Tools Best Practices Task Force. Until the tools are identified, it is
premature to insert a placeholder in a mandatory standard; this also applies to the violation severity
levels table.
Response: The RC SDT appreciates your comments. The Reliability Coordinator has a set of tools in use to monitor and analyze its area as
well as to provide a wide area view. These tools may include a SCADA system, state estimator and contingency analysis programs. It is the
responsibility of the Reliability Coordinator to ensure that these tools are operational or that a plan or procedure is in place to mitigate their
outages. The Real-time Tools Best Practices Task Force work has resulted in the inception of a new standard development project. It is
scheduled to begin in 2009.
FirstEnergy
No
R2 - As written, this requirement does not clearly define the scope of the authority of the Reliability
Coordinator over analysis tools. Is it the intent of the drafting team to give the RC authority over
analysis tools owned and operated by the RC. Is it the intent of the drafting team to give the RC
authority over the analysis tools owned and operated by the BA, TOP, GOP, etc.? Are the tools
intended to be the real-time (EMS) or the off-line engineering planning analysis tools or any analysis
tool used in real-time. Does this include the analysis tools used by field personnel? This requirement
should be revised to specify exactly the analysis tools under the authority of the Reliability
Coordinator.
Response: The RC SDT thanks you for your comment. The intent of the requirement is to have veto authority over its own tools. The
requirement is revised to:
R2. Each Reliability Coordinator shall provide its Operating Personnel with the authority to veto planned outages to its own analysis tools.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
The intended tools are any tools that the Reliability Coordinator needs to perform its reliability functions.
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Question 10:
Question 10 Comments:
Duke Energy
No
Requirement R1 - This requirement is in the wrong standard — this is a Facilities standard. This
requirement belongs in another standard. Question: Is there a requirement in another standard that
compels the TOPS, BAs, etc to provide the requested data? Requirement R2 - Need to clarify whose
analysis tools (I assume it is the RCs analysis tools, not the analysis tools of another entity) and
planned maintenance to what — is it tools, facilities, transmission, generation, etc. Depending on the
answer above, this requirement is in the wrong standard — this is a Facilities standard. This
requirement belongs in another standard. Question: Where is the Requirement for the RC to have
analysis tools? It appears that the Requirement the RC has analysis tools have been removed in the
revisions to the standard.
Response: The RC SDT thanks you for your comment. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1 and does compel entities to provide data to the Reliability Coordinator
For R2, the intent of the requirement is to have veto authority over its own tools. The requirement is revised to:
R2. Each Reliability Coordinator shall provide its Operating Personnel with the authority to veto planned outages to its own analysis tools.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
The intended tools are any tools that the Reliability Coordinator needs to perform its reliability functions.
ISO/RTO Council
Standards Review
Subcommittee
No
New Requirement R2 is no longer needed as a result of paragraph 112 in Order 693-A. Since the
RC's "authority to issue directives arises out of the Commission's approval of Reliability Standards"
the RC already has veto authority or will have once R1 IRO-001-2 is approved. This requirement
obligates the RC to take actions or direct actions to prevent Adverse Reliability Impacts. Veto
outages of equipment and analysis tools would fall into this category even if the RC couldn't say for
certain that an Adverse Reliability Impact was going to occur but rather they are concerned one could
occur due to heavy loads for example.
Response: The RC SDT agrees philosophically with your comment regarding the redundancy of Requirement R2, however, this issue was
enumerated in the report on the 2003 Blackout as a key improvement. The team believes that, while this is redundant as you stated, it is too
soon to remove it from standards. At some point in the future after the industry assimilates the set of changes currently proposed, this
requirement could be proposed for deletion.
SERC OC
July 10, 2009
Yes and No
10.1 - We propose that R1 and R2 should be moved to the RC Certification Procedure and this
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Question 10:
Standards Review
Group
Question 10 Comments:
standard retired.
Response: The RC SDT appreciates your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1.
For R2, the intent of the requirement is to have veto authority over its own tools. The requirement is revised and moved into IRO-001-2, R6:
R2. Each Reliability Coordinator shall provide its Operating Personnel with the authority to veto planned outages to its own analysis tools.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
This will retire IRO-002-1.
Buckeye Power,
Inc.
Yes and No
PJM
Interconnection
Yes
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Northern California
Power Agency
Yes
Salt River Project
Yes
Bonneville Power
Administration
Yes
July 10, 2009
Abstain
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Organization
Question 10:
AEP
Yes
American
Transmission
Company
July 10, 2009
Question 10 Comments:
Abstain.
92
11. Do you agree with the revisions to the Measures in IRO-002-2 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Summary Consideration: Since the inception of this project (2006-06), the IROL Standards Drafting Team has proposed,
successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator
Data Specification and Collection. The work of the IROL SDT retired R1 and M1.
For R2, the intent of the requirement is to have veto authority over its own tools. The requirement and measure have been
revised based on stakeholder comment and moved into IRO-001-2 as Requirement R6. The revisions made are shown below:
R6. Each Reliability Coordinator shall have provide its operating personnel with the authority to veto planned outages to its
own analysis tools including final approvals for planned maintenance. [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning]
M6. Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, a
documented procedure or equivalent evidence that will be used to confirm that the Reliability Coordinator has provided its
operating personnel with the authority to veto planned outages to of its own analysis tools., including final approvals for
planned maintenance as specified in Requirement 2.
Organization
Question 11:
Independent
Electricity System
Operator - Ontario
No
Question 11 Comments:
M1: We suggest to change the word "letter" to "documented request"
If our recommendations to retain some of R5 to R9, some measures will need to be
provided.
Response: The RC SDT thanks you for your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1 and M1.
As stated in our response to your comments in Question 10, we do not intend to retain R5 through R9.
MRO NERC
SDTandards Review
July 10, 2009
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a data
specification document and actual verification that data has been received. The letter or equivalent
is only needed if data has not been supplied. Demonstration of the actual receipt the data would be
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Question 11:
Subcommittee
Question 11 Comments:
easy. Requirement 2 is not needed and thus Measure 2 is not needed per paragraph 112 of Order
693-A. Additional measures are needed to address the proposed requirements in question 10.
Response: The RC SDT thanks you for your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1 and M1.
The RC SDT did not agree to remove R2 in response to your comments in Question 10.
Southern Company
Transmission
No
11.1 - Moving R1 and R2 to the RC Certification Procedure will eliminate measurement
requirements.
Response: The RC SDT thanks you for your comments. See our response to your comments in Question 10.
Salt River Project
No
R1: The Requirement and VSLs mention that the RC will determine it's data needs. Yet the Measure
for R1 does not mention this, it only mentions the RC requesting the data from it's member entities.
This Measure needs to include a measure for how the RC determines it's data needs.
Response: The RC SDT appreciates your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1 and M1.
US Bureau of
Reclamation
No
M2 again "analysis tools" have not been identified.
Response: The RC SDT appreciates your comments. See our response to your comments on Question 10.
FirstEnergy
No
The measures should be modified per our suggested modifications in question 10.
Response: The RC SDT thanks you for your comments. The requirements were not modified. See our response to your comments on
Question 10.
Duke Energy
July 10, 2009
No
See response to Question #12 above. If the requirements are moved to another standard, the
measures aren't needed here.
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Question 11:
Question 11 Comments:
Response: The RC SDT thanks you for your comments. We believe that “#12” in this comment was a typo and that you intended it to read
“Q10”. See our response to your comments on Question 10.
ISO/RTO Council
Standards Review
Subcommittee
No
Measure 1 should not focus on a letter as evidence. A more appropriate measure would be a data
specification document and actual verification that data has been received. The letter or equivalent
is only needed if data has not been supplied. Demonstration of the actual receipt the data would be
easy.
Response: The RC SDT thanks you for your comments. Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator Data
Specification and Collection. The work of the IROL SDT retired R1 and M1.
Buckeye Power, Inc.
Yes and No
abstain
SERC OC
Standards Review
Group
Yes and No
11.1 - Moving R1 and R2 to the RC Certification Procedure will eliminate measurement
requirements.
Response: The RC SDT thanks you for your comments. See our response to your comments in Question 10.
Reliability
Coordinator
Comment Working
Group
Yes
add measures for R1 & R2 see question 10
Response: The RC SDT appreciates your suggestion. See our response to Question 10.
Entergy Services,
Inc
Yes
PJM Interconnection
Yes
AEP
Yes
July 10, 2009
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Organization
Question 11:
Bonneville Power
Administration
Yes
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Northern California
Power Agency
Yes
American
Transmission
Company
July 10, 2009
Question 11 Comments:
Abstain.
96
12. Do you agree with the Violation Severity Levels proposed in IRO-002-2 as shown in the posted Standard and Implementation Plan?
If not, please explain in the comment area.
Summary Consideration: Since the inception of this project (2006-06), the IROL Standards Drafting Team has proposed,
successfully balloted and obtained NERC Board of Trustees approval for a new Standard IRO-010-1: Reliability Coordinator
Data Specification and Collection. The work of the IROL SDT retired R1 and M1. The RC SDT has revised R2 and M2 and
moved them to IRO-001-2, as Requirement R6 and Measure M6. The VSLs have been revised to reflect the modifications made
to the requirement and measure and in response to stakeholders who indicated this is a “binary” requirement.
R6
Reliability Coordinator has
approval rights for planned
outages of analysis tools but
does not have approval
rights for maintenance on
analysis tools.
N/A
N/A
Reliability Coordinator failed to provide its
operating personnel with the authority to
veto
approval is not required for planned
maintenance or planned outages of its
own analysis tools.
Organization
Question 12:
Question 12 Comments:
Independent Electricity
System Operator Ontario
No
R1: The wording for Low VSL is contradictory (e.g. it determined and requested in the
first part but did not request in the second part). Suggest to revise it.
R1: We suggest to grade the VSLs according to the extent to which the percentage of
data specification and/or the number of entities not requested.
R2: The RC either has the right or it doesn't, and hence it's a binary requirement. The
VSL should be developed accordingly. Further, the wording for the Severe VSL does not
correspond to the requirement and measure. The condition should simply be that the Reliability
Coordinator failed to demonstrate that it had the authority to veto planned outages to analysis
tools, including final approvals for planned maintenance.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. The first requirement was retired as part
July 10, 2009
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Question 12:
Question 12 Comments:
of the IROL project. The lower VSL was removed as proposed for the second requirement.
Southern Company
Transmission
No
12.1 - Moving R1 and R2 to the RC Certification Procedure will eliminate VSL requirements.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. R1 was retired – and R2 was moved into
IRO-001 as Requirement R6. The VSLs for R6 are still needed.
US Bureau of
Reclamation
No
Until the tools are identified, it is premature to insert a placeholder in a mandatory standard; this
also applies to the violation severity levels table.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. As envisioned, the intent is to protect the
analysis tools used by real time operating personnel – and not all companies have the same set of tools, so the SDT will not name specific
tools in this standard. The intent is to give the real time operating personnel control over the availability of their tools so that the real time
operating personnel will always know if their tools are “unavailable” due to maintenance. Names of specific tools are not needed to enforce the
intent of this requirement.
MRO NERC
SDTandards Review
Subcommittee
July 10, 2009
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its data
requirements and requested that data and then follows with that it didn't request that data. The
second option in the Lower VSL category is not practical and a compliance auditor would not be in
a position to determine this. In fact, if the administrative data is not requested, other administrative
requirements for reporting would be violated. Additionally, it does not make sense that an RC
would determine its data needs and then omit data for administrative reporting. Further, is it the
compliance auditor's job to judge if the data the RC requests is sufficient or is it his job to see that
the RC has met the requirement to define the data? The remaining VSLs imply that the RC may
define only partial data requirements. This does not seem likely. Why would the RC do this? This
VSL appears to add to the requirement by making it appear that the compliance auditor is to judge
the completeness of the data requirement. This violates Guideline 3 of the FERC ORDER ON
VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY
ORGANIZATION. Practically, it would not be enforceable anyway. It would require the RC to
admit that they did not include administrative data in their data requirements. It is doubtful this
would happen because the RC likely believes they prepared a complete data requirement
document.
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Question 12:
Question 12 Comments:
We suggest that the VSLs should be:
Severe: The RC did not determine it data requirements or the RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be demonstrated for
greater than 75 to 100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
High: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 50 and less than or equal to 75% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
Medium: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 25% and less than or equal to 50% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
Lower: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 0% and less than or equal to 25% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
R2 VSLs are not needed or paragraph 112 of Order 693-A. The Severe VSL contradicts the
requirement.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. The first requirement was retired as part
of the IROL project. For R2, based on your comments and the comments of others, the VSLs were modified – the lower was removed and the
requirement was treated as binary with just a Severe VSL rephrased to more closely match the language in the revised requirement.
FirstEnergy
No
The VSL should be modified per our suggested modifications in question 10.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above.
Duke Energy
July 10, 2009
No
R1 VSL - As a general comment, this VSL is unclear and would be difficult to audit. This VSL
uses subjective terms like “material impact” and “minimal impact”. These terms are not used in
the associated requirement or measure and should be removed from the VSL. This VSL uses
terms like “majority, but not all”; “some, but less than a majority” which provides an opportunity for
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Question 12:
Question 12 Comments:
a subjective review by Compliance as to what a complete listing of data requirements should be.
This term is not used in the Requirements or Measures and should be removed from the VSL.
This VSL introduces a concept, data the RC needs for ? ? administrative purposes, such as data
reporting ??. This concept is not included in the Requirements or Measures portions of the
Standard and should be removed from the VSL. This VSL should be written to simply assess
whether the RC has made determination of what its data needs are and whether those needs
have been communicated to the entities in the footprint.
R2 VSL - This VSL clarifies the questions posed above regarding what the RC needs approval
rights over. R2 needs to be modified to include this clarity. This VSL needs to clarify that the RC
approval rights are for the RC's tools, not tools of other entities. The Severe level of this VSL
needs to be re-written along the lines of: The RC does not have approval rights for planned
maintenance or outages to its analysis tools.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. The first requirement was retired as part
of the IROL project. For R2, based on your comments and the comments of others, the requirement, measure and VSLs were all modified –
the lower was removed and the requirement was treated as binary with just a Severe VSL rephrased to more closely match the language in the
revised requirement.
ISO/RTO Council
Standards Review
Subcommittee
July 10, 2009
No
For R1, the lower VSL contradicts itself. It states that RC demonstrated that it determined its data
requirements and requested that data and then follows with that it didn't request that data. The
second option in the Lower VSL category is not practical and a compliance auditor would not be in
a position to determine this. In fact, if the administrative data is not requested, other administrative
requirements for reporting would be violated. Additionally, it does not make sense that an RC
would determine its data needs and then omit data for administrative reporting. Further, is it the
compliance auditor's job to judge if the data the RC requests is sufficient or is it his job to see that
the RC has met the requirement to define the data? The remaining VSLs imply that the RC may
define only partial data requirements. This does not seem likely. Why would the RC do this? This
VSL appears to add to the requirement by making it appear that the compliance auditor is to judge
the completeness of the data requirement. This violates Guideline 3 of the FERC ORDER ON
VIOLATION SEVERITY LEVELS PROPOSED BY THE ELECTRIC RELIABILITY
ORGANIZATION. Practically, it would not be enforceable anyway. It would require the RC to
admit that they did not include administrative data in their data requirements. It is doubtful this
would happen because the RC likely believes they prepared a complete data requirement
document.
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Question 12:
Question 12 Comments:
We suggest that the VSLs should be:
Severe: The RC did not determine it data requirements or the RC could not demonstrate it
requested the necessary data if actual receipt of the necessary data can't be demonstrated for
greater than 75 to 100% of the TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
High: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 50 and less than or equal to 75% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
Medium: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 25% and less than or equal to 50% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
Lower: The RC could not demonstrate it requested the necessary data if actual receipt of the
necessary data can't be demonstrated for greater than 0% and less than or equal to 25% of the
TOPs, BA, TO, GO, GOPs, LSEs and adjacent RCs.
R2 VSLs are not needed er paragraph 112 of Order 693-A. The Severe VSL contradicts the
requirement.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. The first requirement was retired as part
of the IROL project. For R2, based on your comments and the comments of others, the requirement, measure and VSLs were all modified –
the lower was removed and the requirement was treated as binary with just a Severe VSL rephrased to more closely match the language in the
revised requirement.
SERC OC Standards
Review Group
Yes and No
12.1 - Moving R1 and R2 to the RC Certification Procedure will eliminate VSL requirements.
Response: The RC SDT thanks you for your comment. Please see Summary Consideration above. R1 was retired – and R2 was moved
into IRO-001 as Requirement R6. The VSLs for R6 are still needed.
July 10, 2009
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Organization
Question 12:
Question 12 Comments:
Buckeye Power, Inc.
Yes and No
abstain
Manitoba Hydro
Yes
NPCC
Yes
CU of Springfield
Yes
Ameren
Yes
Reliability Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
Entergy Services, Inc
Yes
Salt River Project
Yes
AEP
Yes
PJM Interconnection
Yes
Bonneville Power
Administration
Yes
American Transmission
Company
July 10, 2009
Abstain.
102
13. Do you agree with the revisions to IRO-005-1 as shown in the posted Standard and Implementation Plan? The RC SDT is
recommending retiring or moving all of the requirements and retiring this standard. If not, please explain in the comment area.
Summary Consideration: Several commenters had concerns around removing the requirement to monitor frequency.
Other commenters had concerns with the removal of other monitoring requirements in the standard. While the Standard
Drafting Team (SDT) recognizes the concerns raised, the SDT is even more concerned with the subjectivity that any attempt to
measure “Monitoring” can provide. It is the SDT’s contention that adherence to reliability standards that require the said
monitoring cannot be demonstrated unless the entity is closely monitoring the system parameters. Furthermore, the SDT
contends that any requirements that describe the monitoring facilities needed to fulfill fundamental duties should be embedded
in organization certification process requirements. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a
secondary task that is inherent in assessing and responding to situations or events that could have an adverse impact on
reliability.
Organization
Question 13:
Question 13 Comments:
Independent
Electricity System
Operator - Ontario
No
R1: We not agree with removing this requirement for the same reason given for the
proposal to remove R5 to R8 from IRO-002 (see comments on 10 (ii), above).
R8: We do not agree with completely removing this requirement, especially that part that
requires an RC to monitor system frequency. While DCS and CPS are largely a BA's responsibility,
the RC is the last line of defense for abnormal system performance and needs to monitor its BAs'
performance including their ability to address large frequency deviations, and direct or take corrective
actions as needed including requesting emergency assistance on the BAs' behalf and directing load
shedding.
R9: The second part of this requirement needs to be retained. IRO-004 covers operational
planning, not current day operations. Coordinating pending generator and transmission facility
outages is an essential and necessary task by the RC to ensure reliability.
R11: The RC needs to monitor ACE, detect and identify the cause of any abnormal ACE,
and direct its BAs to take necessary actions to return ACE to within a normal range.
R13: We do not agree with removing the latter part of R13. The FAC standards cover the
methodology used in calculating SOLs and IROLs. Regardless of how these limits are calculated, in
practice there always exists the possibility that different entities come up with SOLs/IROLs, especially
of the inter-ties, that could be different. Operating to the lowest SOLs/IROLs when more than one set
July 10, 2009
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Question 13:
Question 13 Comments:
exists is a necessary requirement for reliable operation.
Response: The RC SDT thanks you for your comment.
I While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even more concerned with the subjectivity that any
attempt to measure “Monitoring” can provide. It is the SDT contention that adherence to reliability standards that require the said monitoring
cannot be demonstrated unless the entity is closely monitoring the system parameters. Furthermore, the SDT contends that any requirements
that describe the monitoring facilities needed to fulfill fundamental duties should be embedded in organization certification process
Requirements. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in responding to
situations or events that could have an adverse impact on reliability.
Ii With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in assessing and responding to
situations or events that could have an adverse impact on reliability.
Iii The RC SDT proposes retiring this requirement as it is redundant with TOP-003 and IRO-004 (all requirements) for next day requirements.
The RC has the authority to coordinate pending outages in real-time through IRO-001-2, R1 (proposed).
Iv The SDT feels that there are better avenues to ensure BAs operate within established and acceptable thresholds as described in the BAL001 and BAL-002 standards. Current standards projects are addressing revisions to the BAL set of standards.
V The SDT believes this requirement is redundant with FAC-014. FAC-014 states the requirement for developing and sharing SOL and IROL
between the RC, PA, TP and TOP in both the planning and operating time frames.
American
Transmission
Company
No
The accountability and monitoring addressed in this Standard is still required. The drafting team's
intent was that the ability to monitor is part of the certification process. However, certification is to
Standards, and if there is not a Standard which addresses this issue, then an entity cannot certify to
it.
Response: The RC SDT thanks you for your comment. While the Standard Drafting Team (SDT) recognizes the concerns raised, the SDT is
even more concerned with the subjectivity that any attempt to measure “Monitoring” can provide. It is the SDT’s contention that adherence to
reliability standards that require the said monitoring cannot be demonstrated unless the entity is closely monitoring the system parameters.
Furthermore, the SDT contends that any requirements that describe the monitoring facilities needed to fulfill fundamental duties should be
embedded in organization certification process Requirements. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a
secondary task that is inherent in responding to situations or events that could have an adverse impact on reliability.
MRO NERC
SDTandards
July 10, 2009
No
R1 includes many requirements for monitoring the system that are important, measurable and should
be retained. Monitoring is too critical to operating the system to completely eliminate these
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Question 13:
Review
Subcommittee
Question 13 Comments:
requirements.
R4, R8 and R11 are problematic as currently written. However, there have been actual instances of
a large BA intentionally operating short hundreds of MWs of energy. I believe this occurred during
the summer of 1999. Thus, the RC should be monitoring the BAs ACE and directing the BA to
correct it if it becomes too large. It is not necessary or even useful for the RC to monitor the BA CPS
performance.
Response: The RC SDT thanks you for your comment. The SDT feels that there are better avenues to ensure BAs operate within established
and acceptable thresholds as described in the BAL-001 and BAL-002 standards. If a BA chooses to operate off schedule then the BAL
standards need to revisited and tightened up. This is being done in the current projects addressing the BAL standards. Monitoring capability
can be objectively measured and is essential to real-time operations – however real-time monitoring is a supporting activity and is only one of
several processes used to support operation within defined parameters. Monitoring capability should be assessed during the entity registration
certification process and should not be a requirement. Note that certification is aimed at verifying that an entity has the “capability” of operating
reliably. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in assessing and responding
to situations or events that could have an adverse impact on reliability.
Ameren
Yes and No
While we agree that most of the requirements are redundancies that properly belong elsewhere, we
are concerned that Requirement 4 and Requirement 8 are not properly represented elsewhere and
should not be retired until they re-surface in another standard explicitly. We believe it is still very
important for an RC to monitor their respective BAs reserves and CPS performance. Likewise in R8,
while the frequency monitoring is a BA function, we think that it is important enough to also be
included as an RC function explicitly.
Response: The RC SDT thanks you for your comment. The SAR for this project included eliminating redundancies within the standards. In
the Implementation Plan for this standard, we show the redundancy between this requirement, R4, and EOP-002-2. (please see pages 6-8 of
the Implementation Plan). While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even more concerned with the
subjectivity that any attempt to measure “Monitoring” can provide. It is the SDT’s contention that adherence to reliability standards that require
the said monitoring cannot be demonstrated unless the entity is closely monitoring the system parameters. Furthermore, the SDT contends that
any requirements that describe the monitoring facilities needed to fulfill fundamental duties should be embedded in organization certification
process Requirements. With IRO-014 and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in responding
to situations or events that could have an adverse impact on reliability.
Buckeye Power,
July 10, 2009
Yes and No
Abstain
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Question 13:
Question 13 Comments:
Yes
CU supports the retirement of this standard.
Inc.
CU Springfield
Response: The RC SDT thanks you for your comment.
Southern
Company
Transmission
Yes
13.1 - We agree with retiring this standard.
Response: The RC SDT thanks you for your comment.
SERC OC
Standards Review
Group
Yes
13.1 - We agree with retiring this standard
Response: The RC SDT thanks you for your comment.
ISO New England
Inc.
Yes
Entergy Services,
Inc
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
US Army Corps of
Yes
July 10, 2009
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Question 13:
Question 13 Comments:
Engineers,
Northwestern
Division
Salt River Project
Yes
US Bureau of
Reclamation
Yes
PJM
Interconnection
Yes
FirstEnergy
Yes
Bonneville Power
Administration
Yes
Duke Energy
Yes
AEP
Yes
Manitoba Hydro
Yes
NPCC
Yes
July 10, 2009
107
14. Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the posted Standard and Implementation Plan? If
not, please explain in the comment area.
Summary Consideration: Several commenters expressed concerns with the term “impacted” and suggested replacing this
with “other”. The RC SDT believes “impacted” directly relates to the purpose statement. The original wording of “one or more
other” is vague and difficult to measure. Using the word “other” presents a similar situation. The RC SDT chose to use the
word “impacted” to tighten the requirement and remove ambiguity. The RC SDT does not intend for non-contiguous reliability
coordinators to have “RC agreements”, but to have Procedures, Processes, or Plans with impacted reliability coordinators.
Other commenters suggested striking the term “as a minimum” in R1 and the RC SDT agrees and has modified R1 accordingly.
Some commenters did not agree with the wording of the new requirements in IRO-014 that were formerly in IRO-016. The RC
SDT reviewed the Implementation Plan for IRO-016 and its requirements and made some revisions to the requirements listed in
IRO-014-2. The requirement that was transferred from IRO-016 has been translated into 4 requirements in IRO-014:
R5. When an expected or actual reliability issue is detected, theEach Reliability Coordinator, upon identification of an Adverse
Reliability Impact, shall notify impacted Reliability Coordinators. confirm the existence of the issue with the impacted Reliability
Coordinators.
R6. In the event that the issue cannot be confirmed, eEach impacted Reliability Coordinator shall operate as though the
problem exists when the identified Adverse Reliability Impact cannot be agreed to by the impacted Reliability Coordinators.
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted
Reliability Coordinators can not agree that the problem exists.
R6R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who
has the identified Adverse Reliability Impact when When an expected or actual reliability issue exists and the impacted
Reliability Coordinators cannot agree on a mitigation plan, all impacted Reliability Coordinators shall implement the mitigation
plan developed by the Reliability Coordinator who has the reliability issue.
Organization
Question 14:
Independent
Electricity System
No
July 10, 2009
Question 14 Comments:
We suggest to replace the word "impacted" with "other" since there is a preconception that the
concerned RC makes an assessment of which other RCs are impacted by the coordinated actions,
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Question 14:
Operator - Ontario
Question 14 Comments:
which may not be the perspective of the other RCs who may in fact be impacted by any coordinated
actions among other RCs.
Response: The RC SDT thanks you for your comment. The RC SDT believes “impacted” directly relates to the purpose statement. The
original wording of “one or more other” is vague and difficult to measure. Using the word “other” presents a similar situation. The RCSDT
chose to use the word “impacted” to tighten the requirement and remove ambiguity. Additionally, R1.1 reconciles the preconception of the
Reliability Coordinator making an assessment:
R1.1 Communications and notifications, including the mutually agreed to conditions under which one Reliability Coordinator notifies other
Reliability Coordinators; the process to follow in making those notifications; and the data and information to be exchanged with other Reliability
Coordinators.
MRO NERC
SDTandards
Review
Subcommittee
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum. Please
strike R1.6. RCs already have the authority to act per paragraph 112 of Order 693-A.
Since R2 requires the RCs to agree, is the "mutually agreed to" clause in R1.1 necessary?
Please strike requirements R4 and R4.1. It is duplicative to R1.1. Conference calls are a form of
communication and should be address per R1.1.
R5 is confusing. If a reliability issue isn't confirmed, doesn't this mean there is no reliability issue?
Isn't this the point of confirming? Additionally, we suggest using validate instead of confirm.
R6 appears to be a rewrite of requirements R1, R2 and their sub-requirements in IRO-016. We agree
that those requirements do need to be written more succinctly or removed altogether. However, R6
does not accomplish the goal and only confuses that matter further. The reason the RCs may not be
able to agree on a mitigation plan is that RC with the reliability issue may be requesting mitigations
that the other RCs believe may cause them reliability issues. This requirement appears to suggest
that the solution to a disagreement on the mitigation plan is cut and dried. Generally, the reason the
disagreement arises is due to one RC not fully understanding the impact of their actions on another
RC. The bottom line is that the RCs may have disagreements and there is no way to require a
solution in these types of situations. Please revise R6 to require using the mitigation plan developed
by the Reliability Coordinator who has the reliability issue provided that the mitigation plan does not
cause a reliability issue in the other region.
As Requirement 1 is currently written, one could interpret the requirement for every Operating
Process, Procedure and Plan to address each of the sub-requirements. That is not necessary. The
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Question 14:
Question 14 Comments:
drafting team needs to consider modifying the requirement to make it clear that not every subrequirement must be addressed in every Operating Process, Procedure, and Plan and to also make it
clear that the some sub-requirements may only be appropriately addressed in a Process but not a
Plan for instance.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with striking “as a minimum” and the requirement is modified accordingly. The RC SDT believes that the term
“collectively” addresses the interpretation of R1 (your last comment).
R1.6: The RC SDT disagrees with the MRO interpretation of 693-A and believes R1.6 reinforces the Commission’s determination in paragraph
112 of 693-A which clarifies the reliability coordinator’s authority stating “…authority to issue directives arises out of the Commission’s approval
of Reliability Standards that mandate compliance with such directives.”
R1.1: R1.1 provides the conditions under which the RC’s will communicate or notify each other. R2 deals with actions that are to be taken
beyond notifications.
R4 and R4.1: The RC SDT disagrees with the duplicity. R1.1 is a sub-requirement of R1 which requires the reliability coordinator “to have”
procedures, processes, or plans, and R4 requires “participation.”
R5 & R6: Some commenters did not agree with the wording of the new requirements in IRO-014 that were formerly in IRO-016. The RC SDT
reviewed the Implementation Plan for IRO-016 and its requirements and made some revisions to the requirements listed in IRO-014-2. There
are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
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Organization
Question 14:
Southern
Company
Transmission
No
Question 14 Comments:
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures,
processes and plans in place with each RC within the RC's Interconnection. We suggest the
phrasing should be tightened up to convey the original meaning that the team intended. For
example, does the team intend for the FRCC RC to have an agreement with the PJM or MISO RC?
14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as follows: R1 - The
Dispute Resolution process will be followed when the Reliability Coordinator issuing a mitigation plan
and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper steps to be taken.
14.3 - We suggest deleting R4.1 and adding a second sentence to R4: The frequency of these
communications shall be at least weekly.
14.4 - R4: The word "impacted" makes it sound like these calls are only to be made when problems
are expected or are occurring. If this requirement is intended more for operational awareness calls
(such as the daily SERC RC call), then the word "impacted" needs to be changed to "contiguous" or a
similar term.
14.5 - We suggest rewriting R5 to read: In the event that a reliability issue cannot be confirmed, each
Reliability Coordinator shall operate as though the problem exists.
14.6 - At Requirement R1, the use of the phrase "as a minimum" seems to add some flexibility for
development of procedures, processes and plans. A negative consequence is that it introduces more
ambiguity. The recommendation is to strike the phrase.
14.7 - At Requirement R1.6, consider the following: "Authority to act to prevent and mitigate instances
'that have the potential to cause' Adverse Reliability Impacts to other Reliability Coordinator Areas."
Response: The RC SDT thanks you for your comments.
14.1: The RC SDT believes “impacted” directly relates to the purpose statement. The original wording of “one or more other” is vague and
difficult to measure. Using the word “other” presents a similar situation. The RCSDT chose to use the word “impacted” to tighten the
requirement and remove ambiguity. The RC SDT does not intend for non-contiguous reliability coordinators to have “RC agreements”, but to
have Procedures, Processes, or Plans with impacted reliability coordinators.
14.2: The RC SDT respectfully disagrees with your comment. R6 requires implementation (“shall implement”) and R1 is a “shall have”
requirement; keeping these separate provides clarity of related measures. The Dispute Resolution process is more administrative in nature
regarding compliance, certification, audit processes, or contracts.
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Question 14:
Question 14 Comments:
14.3: The RC SDT deleted 4.1 modified R4 to: “The RC shall participate in agreed upon conference calls at least weekly and other
communication forums with impacted Reliability Coordinators.”
14.4: The RC SDT chose the word “impacted” after much discussion. Impacted has the implication that the RC is immediately impacted or the
RC may be impacted by a future situation. We feel that the requirement for weekly calls addresses your concern.
14.5: R5 & R6: Some commenters did not agree with the wording of the new requirements in IRO-014 that were formerly in IRO-016. The RC
SDT made some revisions to the requirements listed in IRO-014-2. There are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
14.6: The RC SDT agrees with striking “as a minimum” and the requirement is modified accordingly.
14.7: The RC SDT believes that if a reliability coordinator acts to prevent or mitigate instances the “potential to cause” already exists.
ISO New England
Inc.
Yes and No
As Requirement 1 is currently written, one could interpret the requirement for every Operating
Process, Procedure and Plan to address each of the sub-requirements. That is not necessary. The
drafting team needs to consider modifying the requirement to make it clear that not every subrequirement must be addressed in every Operating Process, Procedure, and Plan and to also make it
clear that the some sub-requirements may only be appropriately addressed in a Process but not a
Plan for instance. Use of the term collectively may resolve this dilemma.
Response: The RC SDT thanks you for your comment. The RC SDT agrees that the term “collectively” addresses your interpretation and it is
already included in R1.
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Organization
Question 14:
FirstEnergy
No
Question 14 Comments:
R1 - Should be revised as follows to improve readability and clarity:
R1.3 - Add "Exchanging" before "Planned"
R1.4 - Add "Control of voltage" at the beginning of the requirement and delete "for voltage control" at
the end of the requirement.
Add a new R1.7 as follows: "A process for resolution of the disagreement covered by R6 of this
standard."
Response: The RC SDT thanks you for your comment.
R1.3: The RC SDT believes adding the term “Exchanging” before “Planned” is redundant with “… exchange of information” stated in R1.
R1.4: The RC SDT modified R1.4 to read as “Control of voltage including the coordination of reactive resources.”
R1.7: R6: To address the process for resolution of disagreements, the RC SDT proposes the 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Duke Energy
July 10, 2009
No
R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures, processes
and plans in place with each RC within the RC's Interconnection. We suggest the phrasing should be
tightened up to convey the original meaning that the team intended. For example, does the team
intend for the FRCC RC to have an agreement with the PJM or MISO RC? We suggest bringing R6
under R1 as subrequirement R1.7 and rewrite it as follows:
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Question 14:
Question 14 Comments:
R1 - The Dispute Resolution process will be followed when the Reliability Coordinator issuing a
mitigation plan and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper
steps to be taken. We suggest deleting R4.1 and adding a second sentence to R4: The frequency of
these communications shall be at least weekly.
R4: The word "impacted" makes it sound like these calls are only to be made when problems are
expected or are occurring. If this requirement is intended more for operational awareness calls (such
as the daily SERC RC call), then the word "impacted" needs to be changed to "contiguous". We
suggest rewriting R5 to read: In the event that an operating issue cannot be confirmed, each
Reliability Coordinator shall operate as though the problem exists.
Response: The RC SDT thanks you for your comment.
R1 and R2: The RC SDT believes “impacted” directly relates to the purpose statement. The original wording of “one or more other” is vague
and difficult to measure. Using the word “other” presents a similar situation. The RC SDT chose to use the word “impacted” to tighten the
requirement and remove ambiguity. The RC SDT does not intend for non-contiguous reliability coordinators to have “RC agreements”, but to
have Procedures, Processes, or Plans with impacted reliability coordinators.
To address your comments on the process for resolution of disagreements and R5, the RC SDT proposes the 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R4: The RC SDT deleted 4.1 modified R4 to: “The RC shall participate in agreed upon conference calls, at least weekly, and other
communication forums with impacted Reliability Coordinators.” The RC SDT chose the word “impacted” after much discussion. Impacted has
the implication that the RC is immediately impacted or the RC may be impacted by a future situation. We feel that the requirement for weekly
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Organization
Question 14:
Question 14 Comments:
calls addresses your concern
ISO/RTO Council
Standards Review
Subcommittee
No
Please strike "as a minimum" in R1. By definition, the requirement defines the minimum. Please
strike R1.6. RCs already have the authority to act per paragraph 112 of Order 693-A. Since R2
requires the RCs to agree, is the "mutually agreed to" clause in R1.1 necessary? Please strike
requirements R4 and R4.1. It is duplicative to R1.1. Conference calls are a form of communication
and should be address per R1.1.
R5 is confusing. If a reliability issue isn't confirmed, doesn't this mean there is no reliability issue?
Isn't this the point of confirming? Additionally, we suggest using validate instead of confirm. As
Requirement 1 is currently written, one could interpret the requirement for every Operating Process,
Procedure and Plan to address each of the sub-requirements. That is not necessary. The drafting
team needs to consider modifying the requirement to make it clear that not every sub-requirement
must be addressed in every Operating Process, Procedure, and Plan and to also make it clear that
the some sub-requirements may only be appropriately addressed in a Process but not a Plan for
instance. Use of the term collectively may resolve this dilemma.
Response: The RC SDT thanks you for your comment.
R1: The RC SDT agrees with striking “as a minimum” and the requirement is modified accordingly. The RC SDT believes that the term
“collectively” addresses your interpretation of R1.
R1.6: The RC SDT disagrees with your interpretation of 693-A, and believes R1.6 reinforces the Commission’s determination in paragraph 112
of 693-A which clarifies the reliability coordinator’s authority stating “…authority to issue directives arises out of the Commission’s approval of
Reliability Standards that mandate compliance with such directives.”
R1.1: The RC SDT believes “mutually agreed to” reinforces R2.
R4 and R4.1: The RC SDT disagrees with the duplicity. R1.1 is a sub-requirement of R1 which requires the reliability coordinator “to have”
procedures, processes, or plans, and R4 requires “participation.”
R5: The RC SDT proposes the 4 requirements for clarity:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
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Question 14:
Question 14 Comments:
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
SERC OC
Standards Review
Group
Yes and No
14.1 - R1 and R2 - The word "impacted" tends to broaden the requirements to have procedures,
processes and plans in place with each RC within the RC's Interconnection. We suggest the
phrasing should be tightened up to convey the original meaning that the team intended. For
example, does the team intend for the FRCC RC to have an agreement with the PJM or MISO RC?
14.2 - We suggest bringing R6 under R1 as subrequirement R1.7 and rewrite it as follows: R1 - The
Dispute Resolution process will be followed when the Reliability Coordinator issuing a mitigation plan
and the Reliability Coordinator(s) receiving a mitigation plan disagree on the proper steps to be taken.
14.3 - We suggest deleting R4.1 and adding a second sentence to R4: The frequency of these
communications shall be at least weekly.
14.4 - R4: The word "impacted" makes it sound like these calls are only to be made when problems
are expected or are occurring. If this requirement is intended more for operational awareness calls
(such as the daily SERC RC call), then the word "impacted" needs to be changed to "contiguous".
14.5 - We suggest rewriting R5 to read: In the event that an operating issue cannot be confirmed,
each Reliability Coordinator shall operate as though the problem exists.
Response: The RC SDT thanks you for your comment.
14.1: The RC SDT believes “impacted” directly relates to the purpose statement. The original wording of “one or more other” is vague and
difficult to measure. Using the word “other” presents a similar situation. The RCSDT chose to use the word “impacted” to tighten the
requirement and remove ambiguity. The RC SDT does not intend for non-contiguous reliability coordinators to have “RC agreements”, but to
have Procedures, Processes, or Plans with impacted reliability coordinators.
14.2: To address your comments on the process for resolution of disagreements and R5, the RC SDT proposes the 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
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Question 14:
Question 14 Comments:
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
14.3: The RC SDT deleted 4.1 modified R4 to: “The RC shall participate in agreed upon conference calls at least weekly and other
communication forums with impacted Reliability Coordinators.”
14.4: The RC SDT chose the word “impacted” after much discussion. Impacted has the implication that the RC is immediately impacted or the
RC may be impacted by a future situation. We feel that the requirement for weekly calls addresses your concern.
14.5: R5 was modified as above.
Buckeye Power,
Inc.
Yes and No
Entergy Services,
Inc
Yes
Salt River Project
Yes
US Bureau of
Reclamation
Yes
PJM
Interconnection
Yes
July 10, 2009
abstain
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Organization
Question 14:
Bonneville Power
Administration
Yes
Manitoba Hydro
Yes
NPCC
Yes
CU of Springfield
Yes
Ameren
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
AEP
Yes
American
Transmission
Company
July 10, 2009
Question 14 Comments:
Abstain
118
15. Do you agree with the revisions to the Measures in IRO-014-2 as shown in the posted Standard and Implementation Plan? If not,
please explain in the comment area.
Summary Consideration: The RC SDT received comments to revise M1 to remove “System operators” as it added to the
requirement and to remove “for real-time use”. The RC SDT agrees and has modified the measure as shown below:
M1.The Reliability Coordinator’s System Operators shall have available for Real-time use, the latest approved documented
version of Operating Procedures, Processes, or Plans that require notifications, information exchange or the coordination of
actions among impacted Reliability Coordinators. This documentation may include, but is not limited to, dated, current in
force documentation with the specified elements.
M1.1 These Operating Procedures, Processes, or Plans shall address:
M1.1.1
Communications and notifications, including the mutually agreed to conditions under which one Reliability
Coordinator notifies other Reliability Coordinators; the process to follow in making those notifications; and
the data and information to be exchanged with other Reliability Coordinators.
M1.1.2
Energy and capacity shortages.
M1.1.3
Planned or unplanned outage information.
M1.1.4
Voltage control, including the coordination of reactive resources for voltage control.
M1.1.5
Coordination of information exchange to support reliability assessments.
M1.1.6
Authority to act to prevent and mitigate instances of causing Adverse Reliability Impacts to other Reliability
Coordinator Areas.
Most oOther The measures were also revised to conform to changes in the requirements and to provide samples of acceptable
evidence.
Organization
Question 15:
Independent
Electricity
System
Operator -
No
July 10, 2009
Question 15 Comments:
Measure 1 actually contains a number of subrequirements that should be stipulated in R1, not M1. If
indeed these are required, they should be stipulated in the Requirement section, not the Measures
Section.
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Question 15:
Question 15 Comments:
Ontario
Response: The RC SDT thanks you for your comment. The RC SDT modified M1 deleting “System Operators” and the submeasures were
removed and included only in the requirement.
ISO/RTO
Council
Standards
Review
Subcommittee
No
Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about
System Operators yet the measurement does. The measurement should just be to verify that the RC
has have Operating Processes, Procedures, and Plans. The sub-measurements are not
measurements at all. There should be the single measurement to verify the Operating Processes,
Procedures, and Plans have been developed and address the sub-requirements. This really points
out the problem with making the criteria that must be considered in the Operating Processes,
Procedures, and Plans sub-requirements in the first place. They aren't requirements of any sort.
They represent criteria. The drafting team should consider making them a bulleted list without the
Rs, then the drafting team won't feel compelled to write sub-measures that don't measure anything.
Response: The RC SDT thanks you for your comment. . The RC SDT modified M1 deleting “System Operators” and the submeasures were
removed and included only in the requirement. As the list includes topics for every RC is required to address, these are mandatory and should
be numbered rather than bulleted.
MRO NERC
SDTandards
Review
Subcommittee
No
Measure 1 appears to add to the requirement. Requirement 1 does not mention anything about
System Operators yet the measurement does. The measurement should just be to verify that the RC
has have Operating Processes, Procedures, and Plans. The sub-measurements are not
measurements at all. There should be the single measurement to verify the Operating Processes,
Procedures, and Plans have been developed and address the sub-requirements. This really points
out the problem with making the criteria that must be considered in the Operating Processes,
Procedures, and Plans sub-requirements in the first place. They aren't requirements of any sort.
They represent criteria. The drafting team should consider making them a bulleted list without the
Rs, then the drafting team won't feel compelled to write sub-measures that don't measure anything.
We do not agree with M6 because we don't agree with R6.
Response: The RC SDT thanks you for your comment. The RC SDT modified M1 deleting “System Operators” and the submeasures were
removed and included only in the requirement.
R6: The RC SDT disagrees with your assertion that “RCs may have disagreements and there is no way to require a solution in these types of
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Organization
Question 15:
Question 15 Comments:
situations”. RC’s need to coordinate solutions and the revised wording of the requirements R5-R8 will require that.
Southern
Company
Transmission
No
15.1 - In M1, delete "for Real-time use".15.2 - Modify the measures to be consistent with changes
requested in R1, R2, R4, R4.1 and R5.
Response: The RC SDT thanks you for your comment. The RC SDT modified M1 and deleted “for Real-time use.”
The measures were revised based on revisions to the requirements (see response to Q14).
FirstEnergy
No
The measures should be modified per our suggested modifications in question 14.
Response: The RC SDT thanks you for your comment. The measures were revised based on revisions to the requirements (see response to
Q14).
Duke Energy
No
See comment #14 above. Also, Measure M5 is inconsistent with Requirement R5. It should mirror
the requirement. Also, need to add the requirement number at the end of each Measure.
Response: The RC SDT thanks you for your comment. See response to question 14. M5 was modified to reflect the entirety of R5 and new
R6/M6, R7/M7 and R8/M8 were written for clarity and completeness..
SERC OC
Standards
Review Group
Yes and No
15.1 - In M1, delete "System Operator" and "for real-time use".15.2 - Modify the measures to be
consistent with changes requested in R1, R2, R4, R4.1 and R5.
Response: The RC SDT thanks you for your comment. The RC SDT modified M1 and deleted both, “System Operators” and “for Real-time
use.”
The measures were revised based on revisions to the requirements (see response to Q14).
Buckeye Power,
Inc.
Yes and No
Manitoba Hydro
Yes
July 10, 2009
Abstain
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Organization
Question 15:
NPCC
Yes
Ameren
Yes
Reliability
Coordinator
Comment
Working Group
Yes
Northern
California Power
Agency
Yes
CU of
Springfield
Yes
Entergy
Services, Inc
Yes
Salt River
Project
Yes
US Bureau of
Reclamation
Yes
PJM
Interconnection
Yes
Bonneville
Power
Administration
Yes
July 10, 2009
Question 15 Comments:
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Question 15:
AEP
Yes
American
Transmission
Company
July 10, 2009
Question 15 Comments:
Abstain
123
16. Do you agree with the Violation Severity Levels proposed in IRO-014-2 as shown in the posted Standard and Implementation Plan?
If not, please explain in the comment area.
Summary Consideration: Several commenters suggested that the High and Severe VSLs for R2 contradicted the
requirement. The RC SDT agreed and removed the “nots” from the VSLs to correct this error.
The VSL for R4 was originally proposed as a binary requirement with only a Lower VSL – since that time, a determination was
made that noncompliance with any binary requirement must be classified a Severe VSL – thus the VSL for R4 was changed
from Lower to Severe.
Several commenters had suggested revisions for the VSLs for R6. This requirement was imported from IRO-016 and several
commenters suggested expanding the set of requirements regarding the Implementation Plan. The RC SDT expanded the
requirements to 4 separate requirements and developed VSLs for these requirements (R5-R8). This made some of the
comments on the VSLs moot.
Organization
Question 16:
Question 16 Comments:
Independent
Electricity System
Operator - Ontario
No
R2: the High and Severe VSLs contradict with the requirement. We believe all of the
"nots" should be removed.
R6: The Low VSL should be a High since not agreeing to a plan but implementing one that
has not been agreed to is a high violation of the requirement.
The VSLs for R1 may need to be revised if our comments on M1 are adopted.
Response: The RC SDT thanks you for your comment.
We have revised the VSL based on your comment.
R6 – The requirements were revised and additional requirements were added for clarity. The VSLs were written based on the
revised requirements.
The VSL for R1 was unchanged as R1 remained unchanged.
MRO NERC
SDTandards
Review
July 10, 2009
No
For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots" should be
removed. We don’t agree with the VSLs in R4 since we believe R4 should be struck.
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Question 16:
Subcommittee
Question 16 Comments:
The Lower VSL for R6 should not even be a violation unless the impact was negative. If the RC
implemented a different mitigation plan and resolved the issue, then the RC was likely correct to
disagree.
Response: The RC SDT thanks you for your comment.
We have revised the VSL for R2 per your suggestion.
R4 – R4 remains in the standard
R6 - The requirements were revised and additional requirements were added for clarity. The VSLs were written based on the revised
requirements.
Southern
Company
Transmission
No
16.1 - In R2, severe should be "... and no action was taken by the RC".
16.2 - In R5, severe should also include "... or that the RC failed to operate as though the problem
existed."
16.3 - Modify the VSLs to be consistent with changes requested in R1, R2, R4, R4.1 and R5.
Response: The RC SDT thanks you for your comment.
16.1 The requirement is to have agreed to plans and to distribute the plans. Other requirements address the actions to be taken.
16.2 The requirements were revised and additional requirements were added for clarity. The VSLs were written based on the revised
requirements.
16.3 The VSLs were revised based on stakeholder comments and revised requirements.
FirstEnergy
No
The VSL should be modified per our suggested modifications in question 14.
Response: The RC SDT thanks you for your comment. The VSLs were revised to reflect revisions to the requirements.
Duke Energy
No
See comments #14 and #15 above - VSLs need to be revised to correspond to the revised
Requirements and Measures.
Response: The RC SDT thanks you for your comment. Please see responses to comment 14 and 15 above. VSLs were revised to reflect
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Question 16:
Question 16 Comments:
No
For R2, the High and Severe VSLs contradict the requirement. We believe all of the "nots" should be
removed.
revised requirements.
ISO/RTO Council
Standards Review
Subcommittee
We don’t agree with the VSLs in R4 since we believe R4 should be struck.
The Lower VSL for R6 should not even be a violation unless the impact was negative. If the RC
implemented a different mitigation plan and resolved the issue, then the RC was likely correct to
disagree.
Response: The RC SDT thanks you for your comment.
The VSL for R2 was revised per your suggestion.
R4 – R4 remains in the standard. The VSLs were revised to reflect that noncompliance with a binary requirement is Severe.
R6 – The requirements were revised and additional requirements were added for clarity. The VSLs were written based on the revised
requirements.
SERC OC
Standards Review
Group
Yes and No
16.1 - In R2, severe should be "no action was taken by the RC".
16.2 - In R5, severe should also include that the RC failed to operate as though the problem existed.
16.3 - Modify the VSLs to be consistent with changes requested in R1, R2, R4, R4.1 and R5.
Response: The RC SDT thanks you for your comment.
16.1 - The requirement is to have agreed to plans and to distribute the plans. Other requirements address the actions to be taken.
16.2 - The requirements were revised and additional requirements were added for clarity. The VSLs were written based on the revised
requirements.
16.3 - The VSLs were revised based on stakeholder comments and revised requirements.
Buckeye Power,
Inc.
July 10, 2009
Yes and No
abstain
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Organization
Question 16:
US Bureau of
Reclamation
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
Bonneville Power
Administration
Yes
AEP
Yes
PJM
Interconnection
Yes
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
CU of Springfield
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
July 10, 2009
Question 16 Comments:
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American
Transmission
Company
July 10, 2009
Question 16:
Question 16 Comments:
Abstain
128
17. Do you agree with the RC SDT recommendation to retire IRO-015-1 and move the requirements into IRO-014-2? If not, please
explain in the comment area.
Summary Consideration: Stakeholders agree with the proposed revisions.
Organization
Question 17:
Question 17 Comments:
Buckeye Power,
Inc.
Yes and No
abstain
SERC OC
Standards Review
Group
Yes
17.1 - We agree with the recommendation to retire IRO-015-2
Response: The RC SDT thanks you for your comment.
Southern
Company
Transmission
Yes
17.1 - We agree with the recommendation to retire IRO-015-2.
Response: The RC SDT thanks you for your comment.
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
July 10, 2009
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Question 17:
CU of Springfield
Yes
Reliability
Coordinator
Comment Working
Group
Yes
Northern California
Power Agency
Yes
MRO NERC
SDTandards
Review
Subcommittee
Yes
ISO New England
Inc.
Yes
Entergy Services,
Inc
Yes
Salt River Project
Yes
US Bureau of
Reclamation
Yes
PJM
Interconnection
Yes
FirstEnergy
Yes
Bonneville Power
Yes
July 10, 2009
Question 17 Comments:
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Question 17:
Question 17 Comments:
Administration
Duke Energy
Yes
AEP
Yes
ISO/RTO Council
Standards Review
Subcommittee
Yes
American
Transmission
Company
July 10, 2009
Abstain
131
18. Do you agree with the revisions to IRO-016-1 as shown in the posted Standard and Implementation Plan? If not, please explain in
the comment area.
Summary Consideration: Stakeholders agree with the concept of moving the requirements of IRO-016-1 into IRO-014-2.
Some commenters did not agree with the wording of the new requirements in IRO-014 that were formerly in IRO-016. The RC
SDT reviewed the Implementation Plan for IRO-016 and its requirements and made some revisions to the requirements listed in
IRO-014-2. There are now 4 requirements formed to cover the intent of the requirement transferred from IRO-016:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability
Coordinators. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time
Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability
Impact cannot be agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same Day Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted
Reliability Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations
Planning, Same Day Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has
the identified Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan,
[Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Organization
Question 18:
Duke Energy
No
Question 18 Comments:
See comment #14 above regarding re-write needed for Requirement R6 of IRO-014-2.
Response: The RC SDT thanks you for your comment. Please see response in #14 above.
MRO NERC
SDTandards
Review
Subcommittee
July 10, 2009
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the wording
of the requirement. The new wording is much more confusing. Until we reviewed IRO-016-2, it was
not clear at all that R6 in IRO-014 was attempting to mimic R1 and its sub-requirements in IRO-0162.
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Question 18:
Question 18 Comments:
Response: The RC SDT thanks you for your comment. The RC SDT reviewed the Implementation Plan for IRO-016 and its requirements
and made some revisions to the requirements listed in IRO-014-2. There are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan,. [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Southern
Company
Transmission
Yes
18.1 - We agree with the recommendation to retire IRO-016-2.
Response: The RC SDT thanks you for your comment.
Buckeye Power,
Inc.
Yes and No
Abstain
SERC OC
Standards Review
Group
Yes
18.1 - We agree with the recommendation to retire IRO-016-2
Response: The RC SDT thanks you for your comment.
ISO/RTO Council
Standards Review
July 10, 2009
Yes
We do agree with moving the requirement. However, the drafting team needs to revisit the wording
of the requirement. The new wording is much more confusing. Until we reviewed IRO-016-2, it was
not clear at all that R6 in IRO-014 was attempting to mimic R1 and its sub-requirements in IRO-016-
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Question 18:
Subcommittee
Question 18 Comments:
2.
Response: The RC SDT thanks you for your comment. The RC SDT reviewed the Implementation Plan for IRO-016 and its requirements
and made some revisions to the requirements listed in IRO-014-2. There are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify impacted Reliability Coordinators. [Violation
Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the identified Adverse Reliability Impact cannot be
agreed to by the impacted Reliability Coordinators, [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan when the impacted Reliability
Coordinators can not agree that the problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified
Adverse Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan,. [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Manitoba Hydro
Yes
NPCC
Yes
Ameren
Yes
Independent
Electricity System
Operator - Ontario
Yes
CU of Springfield
Yes
Reliability
Coordinator
Comment Working
Yes
July 10, 2009
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Organization
Question 18:
Question 18 Comments:
Group
Northern California
Power Agency
Yes
ISO New England
Inc.
Yes
Entergy Services,
Inc
Yes
MEAG Power
Salt River Project
Yes
US Bureau of
Reclamation
Yes
PJM
Interconnection
Yes
FirstEnergy
Yes
Bonneville Power
Administration
Yes
AEP
Yes
American
Transmission
Company
July 10, 2009
Abstain
135
19. If you have any other comments, not expressed in questions above, on this set of revisions, please provide your comments here.
Summary Consideration: The RC SDT received comments that COM-001-2, R5 should be retired upon regulatory approval.
The RC SDT will propose the earliest possible retirement date – the first day of the first calendar quarter following applicable
regulatory approval, or in those jurisdictions where no regulatory approval is required, the first day of the first calendar quarter
following BOT adoption.
Organization
Question 19:
Southern Company Transmission
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the COM001-2 Standard should be effective immediately upon regulatory approval. As written, the Policy is
unenforceable, contains no measures and is not germane to BES Reliability.
Response: The RC SDT thanks you for your comment. We concur and will request an effective date as you suggest.
SERC OC Standards Review
Group
19.1 - We suggest the effective date for the retirement of R5 (NERC Net Security Policy) in the COM001-2 Standard should be effective immediately upon regulatory approval. As written, the Policy is
unenforceable, contains no measures and is not germane to BES Reliability
Response: The RC SDT thanks you for your comment. We concur and will request an effective date as you suggest.
Entergy Services, Inc
Overall, we think the coordinated set of standards being developed by the RTOSDT and IROLSDT are
good for reliability, crisp, and tightens up the reliability concepts.
Response: The RC SDT thanks you for your comment.
MEAG Power
My other concerns are addressed in the comments of the SERC OC Standards Review Group.
Response: The RC SDT thanks you for your comment.
Salt River Project
July 10, 2009
I appreciate the new comment form in Word version. his allows me to comment on each requirement
specifically addressing the requirement, measure or the VSL's
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Question 19:
Response: The RC SDT thanks you for your comment.
#2 Standards Interface
Subcommittee/Compliance
Elements Development Resource
Pool
Standard – COM-001-2 Telecommunications:
Requirement 1: Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
operationally test, on a quarterly basis at a minimum, alternative telecommunications facilities to ensure
the availability of their use when normal telecommunications facilities fail.
Proposed Measure: Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall provide evidence that it operationally tested, on a quarterly basis at a minimum, alternative
telecommunications facilities to ensure the availability of their use when normal telecommunications
facilities fail.
SDT Proposed Lower VSL The Reliability Coordinator, Transmission Operator, or Balancing Authority
failed to operationally test within the last quarter.
CEDRP Proposed Lower VSL:
The Reliability Coordinator, Balancing Authority or Transmission Operator performed operational
testing of alternative telecommunications, but did not perform a test in one of the previous four quarters.
SDT Proposed Moderate VSL:
The Reliability Coordinator, Transmission Operator, or Balancing Authority failed to operationally test
within the last 2 quarters.
CEDRP Proposed Moderate VSL:
The Reliability Coordinator, Balancing Authority or Transmission Operator performed operational
testing of alternative telecommunications, but did not perform a test in two of the previous four quarters.
SDT Proposed High VSL:
The Reliability Coordinator, Transmission Operator, or Balancing Authority failed to operationally test
within the last 3 quarters.
CEDRP Proposed High VSL:
The Reliability Coordinator, Balancing Authority or Transmission Operator performed operational
testing of alternative telecommunications, but did not perform a test in three of the previous four
quarters.
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Question 19:
SDT Proposed Severe VSL: The Reliability Coordinator, Transmission Operator, or Balancing
Authority failed to operationally test within the last 4 quarters.
CEDRP Proposed Severe VSL:
The Responsible Entity failed to operationally test alternative telecommunications every quarter on
more than three separate occasions (i.e. more than any three different quarters).
=========================================================================
Standard – COM-001-2 R2 Telecommunications
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted
entities of the failure of its normal telecommunications facilities, and shall verify that alternate means of
telecommunications are functional.
Proposed Measure: Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall provide evidence that it notified impacted entities of failure of their normal telecommunications
facilities, and verified the alternate means of telecommunications were functional.
Discussion - This requirement needs to be re-written to be more clearly define who the entities are
that are “impacted.” The key attributes appear to be notification of ALL (communication) impacted
entities (possible omission if some, but not all are not notified). The requirement does not give any
guidance on the “verification” side – this is a problem, one entity can interpret that to mean “we looked
and it was working”, another may be to verify with all impacted entities that alternate communication is
working. We suggest this requirement needs a little more clarification.
Response: The RC SDT believes that entities should contact others when their normal communication
capability is lost. For example, the normal phone line could be cut and someone trying to contact that
entity may only get a busy signal and have no idea that alternate communications is necessary.
We have revised the requirement to place time bounds on outages that require notification. The
requirement was rewritten to:
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted
entities within 60 minutes of the detection of a failure (30 minutes or longer) of its normal interpersonal
communications capabilities. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
The CEDRP does not feel it can write a valid VSL for this requirement as currently worded.
SDT Proposed Lower VSL:
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Question 19:
The Reliability Coordinator, Transmission Operator or Balancing Authority notified all impacted entities
of the failure of their normal telecommunications facilities, but failed to verify the alternate means of
telecommunications are functional.
CEDRP Proposed Lower VSL:
See Discussion
SDT Proposed Moderate VSL:
The Reliability Coordinator, Transmission Operator or Balancing Authority notified some, but not all,
impacted entities of the failure of their normal telecommunications facilities, and failed to verify the
alternate means of telecommunications are functional.
CEDRP Proposed Moderate VSL:
See Discussion:
SDT Proposed High VSL:
N/A
CEDRP Proposed High VSL:
See Discussion
SDT Proposed Severe VSL:
The Reliability Coordinator, Transmission Operator or Balancing Authority failed to notify any
impacted entities of the failure of their normal telecommunications facilities, and failed verify the alternate
means of telecommunications are functional.
CEDRP Proposed Severe VSL:
See Discussion
Standard – COM-001-2 R3 Telecommunications
Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator and Distribution Provider shall use English as the language for all inter-entity Bulk
Electric System (BES) reliability communications between and among operating personnel responsible
for the real-time generation control and operation of the interconnected BES. Transmission Operators
and Balancing Authorities may use an alternate language for internal operations.
Proposed Measure: The Reliability Coordinator, Transmission Operator or Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent, that will be used
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Question 19:
to determine that personnel used English as the language for all inter-entity BES reliability
communications between and among operating personnel responsible for the real-time generation
control and operation of the interconnected BES.
NOTE: OK with this as is because the requirement and VSLs have been re-written, will be removed
from this standard shortly, and included in the new COM-003-1 standard.
Response: Thank you for your comment.
SDT Proposed Severe VSL:
The Responsible Entity failed to provide evidence of concurrence to use a language other than
English for all communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System.
CEDRP Proposed Severe VSL:
The Responsible Entity failed to provide evidence of the concurrence to use a language other than
English for all communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System.
============================================================================
Standard – COM-001-2 R4 Telecommunications
Each Distribution Provider and Generation Operator shall have telecommunications facilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection and operating
information.
Proposed Measure: Each Distribution Provider and Generation Operator has telecommunications
facilities with its Transmission Operator and Balancing Authority for the exchange of Interconnection and
operating information.
“has” telecomm with TOP and BA
Discussion –
Telecommunication Facilities is ambiguous and is not included in the NERC glossary of terms – the
CEDRP recommend deleting the word “facilities” from the requirement and measure and leaving it just
as “telecommunications” with its TOP and BA .
Response: The term “telecommunications facilities” was replaced with “interpersonal communications
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Question 19:
capabilities” to clarify the intent of the requirement.
SDT Proposed High VSL: N/A
CEDRP Proposed High VSL:
The Responsible Entity failed to establish telecommunications with either their Balancing Authority OR
Transmission Operator for the exchange of Interconnection and operating information.
SDT Proposed Severe VSL: The Distribution Provider or Generation Operator failed to have
telecommunications facilities with its Transmission Operator and Balancing Authority
CEDRP Proposed Severe VSL:
The Responsible Entity failed to establish telecommunications with their Balancing Authority AND
Transmission Operator for the exchange of Interconnection and operating information.
5. Is the VSL language clear & measurable (ambiguity removed)? If no, does the requirement or
measure need to be revised?
Yes, considering the wording of the requirement as written. More specifically, the word “have” as used
in the requirement is a bit vague. A better choice could have been, “established and maintains.”
Response: Thank you for your comment.
============================================================================
Standard: COM-002-3 Communications and Coordination
Response: The RC SDT thanks you for your comments. Please see responses embedded above.
In the future, please do not submit comments in this format. It is extremely burdensome on the drafting team in trying to respond to the
comments. Please answer each question individually. If you encounter difficulty, please contact NERC for assistance.
Standards Interface
Subcommittee/Compliance
Elements Drafting
July 10, 2009
Standard – IRO-001 R1
The Reliability Coordinator shall act or direct actions to be taken by Transmission Operators,
Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities,
Distribution Providers and Purchasing-Selling Entities within its Reliability Coordinator Area to prevent or
mitigate the magnitude or duration of events that result in Adverse Reliability Impacts. [Violation Risk
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Question 19:
Factor: High] [Time Horizon: Real-time Operations and Same Day Operations]
Proposed Measure
Each Reliability Coordinator shall have evidence that it acted, or issued directives, to prevent or
mitigate the magnitude or duration of Adverse Reliability Impacts within its Reliability Coordinator Area
Discussion –
1. As currently worded it can be interpreted that any time an event occurs the RC would be in violation
of the standard simply because they had failed “to prevent” an event.
2. This requirement does not have a “timing” element included, although it implies timing based on the
“duration of the event”. Including that “duration of the event” is problematic – it appears to imply that
human intervention may provide a more timely response than relay operation, we would suggest more
clarification about what the “duration” element of the requirement is intended to address (e.g. generation
re-dispatch?).
3. There also appears to be a “quality” element included based on the mitigation of magnitude of the
event. As a result we believe that timeliness, effectiveness and communication should be the basis of
the VSLs.
4. The VSLs as differentiate between directing actions and acting. Practically, there is no difference.
The RC is still giving the directive. It is just a matter of who is carrying it out. This is not a valid basis for
differentiating between VSLs. We suggest the VSLs be defined based on actual system impact (i.e.
Was the RC acting or directing actions to prevent or to mitigate?) and to either modify the requirement to
remove timing aspects or to add the timing aspects to the VSLs.
Response:
1. The RC SDT does not agree that there would be a violation any time an event occurred. The RC
should always be looking ahead. Even though events can occur that were not foreseeable or due to
catastrophic failures of system equipment.
2. The intent of the phrase of “duration of the event” is to emphasize that there are actions that can be
taken to shorten the duration of an event. These include ordering redispatch and system reconfiguration
(including load shedding) to mitigate an Adverse Reliability Impact, thus shortening the event and its
impact on the interconnection.
3. The VSL has been re-written to include only a Severe VSL.
4. We agree and have revised the VSL to only have a Severe VSL.
SDT Proposed High VSL IRO-001 R1
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Question 19:
The Reliability Coordinator failed to act to prevent or mitigate the magnitude or duration of Adverse
Reliability Impacts.
CEDRP Proposed VSL
The Reliability Coordinator failed to act to prevent the magnitude or duration of Adverse Reliability
Impacts.
SDT Proposed Severe VSL IRO-001 R1
The Reliability Coordinator failed to act and direct actions to prevent or mitigate the magnitude or
duration of Adverse Reliability Impacts
CEDRP Proposed VSL
The Reliability Coordinator failed to act and direct actions to mitigate the magnitude or duration of
Adverse Reliability Impacts
CAE Resource Pool Comments
The Enforcement Authority Statement, “NERC shall be responsible for compliance monitoring of the
Regional Entity.” Is not clear, if it is intended to encompass Regional Entities that perform RC functions
is should be clearly stated, if not it should not be included in the Enforcement Authority section.
============================================================================
Standard – IRO-001 R2
Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, Distribution Providers, and Purchasing-Selling Entities shall act without
intentional delay to comply with Reliability Coordinator directives unless such actions would violate
safety, equipment, or regulatory or statutory requirements. [Violation Risk Factor: High] [Time Horizon:
Real-time Operations and Same Day Operations]
Proposed Measure
Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, or Purchasing-Selling Entity shall have evidence that it acted without
delay to comply with the Reliability Coordinator's directives unless such actions would violate safety,
equipment, or regulatory or statutory requirements.
Discussion - The team would suggest “intentional delay” be eliminated from the requirement – e.g.
“shall act to…”). To act with an intentional delay represents a willful act to disregard the requirement.
Willful disregard of requirements is one of the factors that the enforcement authority uses to magnify
penalties. Requirements should not include attempts to avoid willful disregard of the requirement.
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Question 19:
The measure and VSLs do not consider the exceptions for not following the RC objective. The drafting
team should consider combining requirements R2 and R3. Thus, one VSL would become failure to notify
the RC of the inability to comply. The drafting team could consider applying the numerical category of
VSLs for some directives such as an order to redispatch. Obviously, it would not work well if the directive
was to reconfigure the system.
Response:
The term “intentional delay” was eliminated from the standard as you suggested. The VSLs were
revised to reflect the requirement.
SDT Proposed Moderate High VSL
The responsible entity followed the Reliability Coordinators directive unless such actions would violate
safety, equipment, or regulatory or statutory requirements with a delay. not caused by equipment
problems.
CEDRP Proposed VSL IRO-001 R2
The team does not agree that this is a valid VSL.
SDT Proposed High VSL
The responsible entity followed the majority of the Reliability Coordinators directive but did not fully
follow the directive because it would violate safety, equipment, statutory or regulatory requirements.
CEDRP Proposed VSL IRO-001 R2
The team does not agree that this is a valid VSL. The word majority implies some ability to numerically
measure the response to the directive. Thus, the drafting team should consider applying the numerical
category of the VSL guidelines.
SDT Proposed Severe VSL
The responsible entity did not follow the Reliability Coordinators directive. The responsible entity did
not follow the Reliability Coordinators directive, the directive would not have violated safety, equipment,
regulatory, or statutory requirements, and responsible entity did not communicate the inability to follow
the directive to the Reliability Coordinator.
CEDRP Proposed VSL IRO-001 R2
The responsible entity did not follow the Reliability Coordinators directive, the directive would not have
violated safety, equipment, regulatory, or statutory requirements, and responsible entity did not
communicate the inability to follow the directive to the Reliability Coordinator.
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Question 19:
============================================================================
Standard - IRO-001 R3 The Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider or Purchasing-Selling Entity
shall immediately confirm the ability to comply with the directive or inform the Reliability Coordinator
upon recognition of the inability to perform the directive. [Violation Risk Factor: High] [Time Horizon:
Real-time Operations and Same Day Operations]
Proposed Measure
Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, or Purchasing-Selling Entity shall have evidence that it confirmed its
ability to comply with the Reliability Coordinator's directives, or if for safety, equipment, regulatory or
statutory requirements it could not comply, informed the Reliability Coordinator upon recognition of the
inability to comply.
Discussion – The requirement appears to be based on communication and can be problematic by
including the requirement to immediately confirm the ability to comply, a directive can be issued to one
entity or several entities at one time (e.g. conference call, all call, electronic notification) that may create
several issues when attempting to process all confirmations, the requirement language presents a risk of
being found out of compliance for following a directive but not providing an “immediate” confirmation to
the RC. The CEDRP believes it to be a reasonable expectation that all entities will comply with reliability
directives and notification should be made only on exception. The SDT should consider combining this
requirement with R2.
Response:
The phrase “immediately confirm the ability to comply” was removed from the requirement. The new
wording is:
R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, or Purchasing-Selling Entity shall inform its
Reliability Coordinator upon recognition of its inability to perform the directive. [Violation Risk Factor:
High] [Time Horizon: Real-time Operations and Same Day Operations]
SDT Proposed Lower VSL IRO-001 R3
The responsible entity failed to immediately confirm the ability to comply with the directive issued by
the Reliability Coordinator.
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CEDRP Proposed VSL
See above discussion note
============================================================================
Standard - IRO-001 R4
Each Reliability Coordinator that identifies an expected or actual threat with Adverse Reliability
Impacts within its Reliability Coordinator Area shall notify, without intentional delay, all impacted
Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. [Violation Risk
Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
Proposed Measure
Each Reliability Coordinator shall have evidence that it notified, without intentional delay, all impacted
Transmission Operators and balancing Authorities in its Reliability Coordinator Area when it identified a
real or potential threat with Adverse Reliability Impacts, within its Reliability Coordinator Area.
Discussion – To act with an intentional delay represents a willful act to disregard the requirement.
Willful disregard of requirements is one of the factors that the enforcement authority uses to magnify
penalties. Requirements should not include attempts to avoid willful disregard of the requirement. This
requirement appears to fit the numerical category of the VSL guidelines best.
Response:
The term “intentional delay” was eliminated from the standard as you suggested. The VSLs were
revised as you suggested.
SDT Proposed Lower VSL IRO-001 R4
N/A
CEDRP Proposed VSL
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify 25% or less of the Transmission Operators and
Balancing Authorities within its Reliability Coordination Area.
SDT Proposed Moderate VSL IRO-001 R4
N/A
CEDRP Proposed VSL
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Question 19:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 25% but less than or equal to 50% of the
Transmission Operators and Balancing Authorities within its Reliability Coordination Area.
SDT Proposed High VSL IRO-001 R4
N/A
CEDRP Proposed VSL
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 50% but less than or equal to 75% of the
Transmission Operators and Balancing Authorities within its Reliability Coordination Area.
SDT Proposed Severe VSL: IRO-001 R4
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to issue an alert to all impacted Transmission Operators and
Balancing Authorities in its Reliability Coordinator Area.
CEDRP Proposed Severe VSL:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 75% of the Transmission Operators and
Balancing Authorities within its Reliability Coordination Area.
============================================================================
Standard - IRO-001 R5
Each Reliability Coordinator who identifies an expected or actual threat with Adverse Reliability
Impacts, within its Reliability Coordinator Area shall notify, without intentional delay, all impacted
Transmission Operators and Balancing Authorities in its Reliability Coordinator Area when the
transmission problem has been mitigated. [Violation Risk Factor: High] [Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning]
Proposed Measure
Each Reliability Coordinator shall have evidence that it notified, without intentional delay, all impacted
Transmission Operators and balancing Authorities in its Reliability Coordinator Area when the real or
potential threat with Adverse Reliability Impacts within its Reliability Coordinator Area has been
mitigated.
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Discussion – To act with an intentional delay represents a willful act to disregard the requirement.
Willful disregard of requirements is one of the factors that the enforcement authority uses to magnify
penalties. Requirements should not include attempts to avoid willful disregard of the requirement.
Measure 5 is written implying that there is an Adverse Reliability Impact. The drafting team should
consider wording the measurement to consider that there may not be an Adverse Reliability Impact
requiring a directive. The Commission in paragraph 27 of the VSL order has stated that multiple VSLs
are preferable where possible. Suggest applying the numerical category of the VSL Guidelines based on
the number of entities notified.
Response:
The term “intentional delay” was eliminated from the standard as you suggested. The VSLs were
revised per your suggestion.
SDT Proposed Lower VSL: IRO-001 R5
N/A
CEDRP Proposed Lower VSL:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify 25% or less of the impacted Transmission Operators
and Balancing Authorities within its Reliability Coordination Area that the Adverse Reliability Impact had
been mitigated.
SDT Proposed Moderate VSL: IRO-001 R5
N/A
CEDRP Proposed Moderate VSL:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 25% but less than or equal to 50% of the
impacted Transmission Operators and Balancing Authorities within its Reliability Coordination Area that
the Adverse Reliability Impact had been mitigated.
SDT Proposed High VSL: IRO-001 R5
N/A
CEDRP Proposed High VSL:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 50% but less than or equal to 75% of the
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Question 19:
impacted Transmission Operators and Balancing Authorities within its Reliability Coordination Area that
the Adverse Reliability Impact had been mitigated.
SDT Proposed Severe VSL: IRO-001 R5
The Reliability Coordinator failed to notify all impacted Transmission Operators, Balancing Authorities,
when the transmission problem had been mitigated.
CEDRP Proposed Severe VSL:
The Reliability Coordinator who identified an expected or actual threat with Adverse Reliability Impacts
within its Reliability Coordinator Area failed to notify more than 75% of the impacted Transmission
Operators and Balancing Authorities within its Reliability Coordination Area that the Adverse Reliability
Impact had been mitigated.
============================================================================
Standard – IRO-002-2 R1
Each Reliability Coordinator shall determine the data requirements to support its reliability
coordination tasks and shall request such data from its Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and LoadServing Entities, or adjacent Reliability Coordinators. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations, Same Day Operations and Operations Planning]
Proposed Measure
Each Reliability Coordinator shall have and provide upon request evidence that could include,
but is not limited to, a letter to Transmission Operators, Balancing Authorities, Transmission
Owners, Generator Owners, Generator Operators, and Load-Serving Entities, or adjacent
Reliability Coordinators, or other equivalent evidence that will be used to confirm that the
Reliability Coordinator has requested the data required to support its reliability coordination
tasks.
Discussion – The VSLs attempt to measure the quality of the data requirements. They require the
compliance auditor to judge if another RC has material impact and what data is administrative and what
data is substantial. Given the typical length of a compliance audit, it is doubtful that the compliance
auditor can make these types of judgments about the quality of the data and the material impact of
another RC. The drafting team should consider applying numerical category of VSLs based on the
number of entities the data request is made from. It is interesting that the measure also does not require
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Question 19:
any documentation of a data specification.
Response:
The requirement was retired by the work of the IROLSDT. It is no longer in the standard.
SDT Proposed Lower VSL:
The Reliability Coordinator demonstrated that it
1) determined its data requirements and requested that data from its Transmission Operators,
Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and LoadServing Entities or Adjacent Reliability Coordinators with a material impact on the Bulk Electric System in
its Reliability Coordination Area but did not request the data from Transmission Operators, Balancing
Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving
Entities or Adjacent Reliability Coordinators with minimal impact on the Bulk Electric System in its
Reliability Coordination Area or
2) determined its data requirements necessary to perform its reliability functions with the exceptions of
data that may be needed for administrative purposes such as data reporting.
CEDRP Proposed Lower VSL: IRO-002-2 R1
The Reliability Coordinator failed to request data to support its reliability coordination tasks from 25%
or less of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners,
Generation Operators, and Load-Serving Entities, or adjacent Reliability Coordinators.
SDT Proposed Moderate VSL:
The Reliability Coordinator demonstrated that it determined the majority but not all of its data
requirements necessary to support its reliability coordination functions and requested that data from its
Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation
Operators, and Load-Serving Entities or Adjacent Reliability Coordinators.
CEDRP Proposed Moderate VSL: IRO-002-2 R1
The Reliability Coordinator failed to request data to support its reliability coordination tasks from more
than 25% but less than or equal to 50% of its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities, or
adjacent Reliability Coordinators.
SDT Proposed High VSL:
The Reliability Coordinator demonstrated that it determined
1) some but less than the majority of its data requirements necessary to support its reliability
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Question 19:
coordination functions and requested that data from its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators
Or
2) all of its data requirements necessary to support its reliability coordination functions but failed to
demonstrate that it requested data from two of its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators.
CEDRP Proposed High VSL: IRO-002-2 R1
The Reliability Coordinator failed to request data to support its reliability coordination tasks from more
than 50% but less than or equal to 75% of its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities, or
adjacent Reliability Coordinators.
SDT Proposed Severe VSL:
The Reliability Coordinator failed to demonstrate that it
1) determined its data requirements necessary to support its reliability coordination functions and
requested that data from its Transmission Operators, Balancing Authorities, Transmission Owners,
Generation Owners, Generation Operators, and Load-Serving Entities or Adjacent Reliability
Coordinators
Or
2) requested the data from three or more of its Transmission Operators, Balancing Authorities,
Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities or
Adjacent Reliability Coordinators.
CEDRP Proposed Severe VSL: IRO-002-2 R1
The Reliability Coordinator failed to request data to support its reliability coordination tasks from more
than 75% of its Transmission Operators, Balancing Authorities, Transmission Owners, Generation
Owners, Generation Operators, and Load-Serving Entities, or adjacent Reliability Coordinators,
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Question 19:
Or,
The Reliability Coordinator failed to determine data requirements to support its reliability coordination
tasks.
Standard – IRO-002-2 R2
Each Reliability Coordinator shall have the authority to veto planned outages to analysis tools, including
final approvals for planned maintenance. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations, Same Day Operations and Operations Planning]
Proposed Measure
Each Reliability Coordinator shall have and provide upon request evidence that could include, but is
not limited to, a documented procedure or equivalent evidence that will be used to confirm that the
Reliability Coordinator has the authority to veto planned outages to analysis tools, including final
approvals for planned maintenance as specified in Requirement 2.
Is this requirement needed? R1 IRO-001-2 requires the RC to mitigate Adverse Reliability Impacts. R2
IRO-001-2 requires responsible entities to comply with the RC directives. Wouldn’t the RC thus have the
right to cancel all types of outages (i.e. analysis tools, transmission equipment, etc). FERC has stated in
paragraph 112 of Order 693-A that an RC does not derive their authority from agreements but rather
from FERC’s approval of the standards.
Barring the team’s decision to remove this requirement, the Severe VSL is confusing. We have
suggested different wording.
Response:
While the RC SDT agrees that the other requirements should cover this subject, this is a direct response
to the 2003 blackout and is included here. We have revised the Severe VSL to reflect the revised
requirement.
SDT Proposed Severe VSL IRO-002-2 R2
Reliability Coordinator approval is not required for planned maintenance or planned outages.
CEDRP Proposed VSL
Reliability Coordinator does not approve planned maintenance or planned outages.
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Question 19:
============================================================================
Standard – IRO-014-2 R1 No comments
============================================================================
Standard – IRO-014-2 R2
R2. Each Reliability Coordinator’s Operating Procedure, Process, or Plan that requires one or more
other Reliability Coordinators to take action (e.g., make notifications, exchange information, or
coordinate actions) shall be: [Violation Risk Factor: Lower] [Time Horizon: Real-time Operations and
Operations Planning]
R2.1. Agreed to by all the Reliability Coordinators required to take the indicated action(s).
R2.2. Distributed to all Reliability Coordinators that are required to take the indicated action(s).
Proposed Measure
M2. The Reliability Coordinator shall have evidence that the Operating Procedures, Processes, or
Plans that require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were:
M2.1 Agreed to by all the Reliability Coordinators required to take the indicated action(s).
M2.2 Distributed to all Reliability Coordinators that are required to take the indicated action(s).
Discussion – The High and Severe VSLs appear to use “not” incorrectly.
Response:
We agree and have revised the VSLs.
SDT Proposed Moderate VSL: IRO-014-2 R2
The Reliability Coordinator failed to did not have evidence that the Operating Procedures, Processes,
or Plans that require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were distributed to all Reliability Coordinators that are
required to take action.
CEDRP Proposed Moderate VSL: IRO-014-2 R2
The Reliability Coordinator did not have evidence that the Operating Procedures, Processes, or Plans
that require one or more other Reliability Coordinators to take action (e.g., make notifications, exchange
information, or coordinate actions) were distributed to all Reliability Coordinators that are required to take
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Question 19:
action.
SDT Proposed High VSL:
The Reliability Coordinator failed to did not have evidence that the Operating Procedures, Processes,
or Plans that require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were not agreed to by all Reliability Coordinators that are
required to take action
CEDRP Proposed High VSL:
The Reliability Coordinator did not have evidence that the Operating Procedures, Processes, or Plans
that require one or more other Reliability Coordinators to take action (e.g., make notifications, exchange
information, or coordinate actions) were agreed to by all Reliability Coordinators that are required to take
action
SDT Proposed Severe VSL:
The Reliability Coordinator failed to did not have evidence that the Operating Procedures, Processes,
or Plans that require one or more other Reliability Coordinators to take action (e.g., make notifications,
exchange information, or coordinate actions) were not agreed to by all Reliability Coordinators that are
required to take action and were not distributed to all Reliability Coordinators that are required to take
action
CEDRP Proposed Severe VSL:
The Reliability Coordinator did not have evidence that the Operating Procedures, Processes, or Plans
that require one or more other Reliability Coordinators to take action (e.g., make notifications, exchange
information, or coordinate actions) were agreed to by all Reliability Coordinators that are required to take
action and were distributed to all Reliability Coordinators that are required to take action
============================================================================
Standard – IRO-014-2 R3 [Response: The SDT appreciates the comments. To better emphasize the
distinction, the SDT decided to underline the “and” and the “or”.]
Requirement (including sub-requirements)
R3. The Reliability Coordinator shall make notifications and exchange reliability–related information
with impacted Reliability Coordinators using its predefined Operating Procedures, Processes, or Plans
for conditions that may impact other Reliability Coordinator Areas or other means to accomplish the
notifications and exchange of reliability-related information. [Violation Risk Factor: Medium][Time
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Horizon: Real-time Operations and Operations Planning]
Proposed Measure
M3. The Reliability Coordinator shall have evidence it made notifications and exchanged reliability–
related information with impacted Reliability Coordinators using its predefined Operating Procedures,
Processes, or Plans for conditions that may impact other Reliability Coordinator Areas or other means to
accomplish the notifications and exchange of reliability-related information.
Discussion: The VSLs appear to be appropriate. Since the only difference is the use of the “and” and
“or”, we suggest emphasizing those words in bold. We read this more than once before we noticed the
difference.
Response:
We revised the VSL to emphasize the “OR” and “AND” parts.
SDT Proposed High VSL:
The Reliability Coordinator failed to make notifications or exchange reliability–related information with
impacted Reliability Coordinators.
CEDRP Proposed High VSL: IRO-014-2 R3
The Reliability Coordinator failed to make notifications or exchange reliability–related information with
impacted Reliability Coordinators.
SDT Proposed Severe VSL:
The Reliability Coordinator failed to make notifications and exchange reliability–related information
with impacted Reliability Coordinators.
CEDRP Proposed Severe VSL: IRO-014-2 R3
The Reliability Coordinator failed to make notifications and exchange reliability–related information
with impacted Reliability Coordinators.
============================================================================
Standard – IRO-014-2 R4
R4. The Reliability Coordinator shall participate in agreed upon conference calls and other
communication forums with impacted Reliability Coordinators. [Violation Risk Factor: Lower][Time
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Horizon: Real-time Operations]
The frequency of these conference calls shall be agreed upon by all involved Reliability Coordinators
and shall be at least weekly.
Proposed Measure
M4. The Reliability Coordinator shall have evidence it participated in agreed upon (at least weekly)
conference calls and other communication forums with impacted Reliability Coordinators.
Discussion – This requirement is purely administrative and probably does not rise to a level of a
reliability standard requirement.
It is in essence redundant, with R1.1 IRO-014-2? It appears R1.1 addresses the same information that
would be expected to be discussed in a weekly conference call. Should the drafting team disagree and
retain this requirement, please consider applying multiple VSLs based on how often the RC participates
in conference calls, how many they missed, or how many impacted RCs they participated in conference
calls with.
Response:
R1.1 is a sub-requirement of R1 which requires the reliability coordinator “to have” procedures,
processes, or plans, and R4 requires “participation.” R4 requires participation on calls. If the RC fails to
participate, that is a violation of the requirement, making it a binary requirement with only one VSL.
SDT Proposed Lower VSL:
The Reliability Coordinator failed to participate in agreed upon (at least weekly) conference calls and
other communication forums with impacted Reliability Coordinators.
CEDRP Proposed Lower VSL: IRO-014-2 R4
The Reliability Coordinator participated in agreed upon conference calls and other communication
forums with impacted Reliability Coordinators bi-weekly,
Or
the Reliability Coordinator failed to participate in one weekly conference call,
Or
the Reliability Coordinator agreed to participate in conference calls with 25% or less of the impacted
Reliability Coordinators.
SDT Proposed Moderate VSL:
N/A
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Organization
Question 19:
CEDRP Proposed Moderate VSL: IRO-014-2 R4
The Reliability Coordinator participated in agreed upon conference calls and other communication
forums with impacted Reliability Coordinators every third week,
Or
the Reliability Coordinator failed to participate in two weekly conference calls,
Or
the Reliability Coordinator agreed to participate in conference calls with more than 25% but less than
or equal to 50% of the impacted Reliability Coordinators.
SDT Proposed High VSL:
N/A
CEDRP Proposed High VSL: IRO-014-2 R4
The Reliability Coordinator participated in agreed upon conference calls and other communication
forums with impacted Reliability Coordinators fourth week,
Or
the Reliability Coordinator failed to participate in three weekly conference calls,
Or
the Reliability Coordinator agreed to participate in conference calls with more than 50% but less than
or equal to 75% of the impacted Reliability Coordinators.
SDT Proposed Severe VSL:
N/A
CEDRP Proposed Severe VSL: IRO-014-2 R4
The Reliability Coordinator participated in agreed upon conference calls and other communication
forums with impacted Reliability Coordinators at least every fifth week,
Or
the Reliability Coordinator failed to participate in four weekly conference calls,
Or
the Reliability Coordinator failed to agree to participate in any conference calls,
Or
the Reliability Coordinator agreed to participate in conference calls with more than 75% but less than
100% of the impacted Reliability Coordinators.
============================================================================
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Organization
Question 19:
Standard – IRO-014-2 R5
R5. When an expected or actual reliability issue is detected, the Reliability Coordinator shall confirm
the existence of the issue with the impacted Reliability Coordinators. Until In the event that the issue
cannot be has been proven to not exist, confirmed, each Reliability Coordinator shall operate as though
the problem exists. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day
Operations and Real-time Operations]
Proposed Measure
The Reliability Coordinator shall have evidence that, in cases when an expected or actual reliability
issue was detected, it has confirmed the existence of the issue with the impacted Reliability
Coordinators.
Discussion – This requirement is confusing in the way it is worded. We think it is trying to say that the
RC should operate as though the reliability issue (should this be Adverse Reliability Impact) is detected
until the issue is confirmed not to exist. The way it is worded might imply that if one doesn’t confirm it to
exist, operate as though it does. This leaves open the interpretation that a confirmation that it doesn’t
exist must still be operated to as though it does exist.
The drafting team should consider splitting operating to prevent from operating to mitigate an existing
event in the VSLs.
Response:
The RC SDT reviewed the Implementation Plan for IRO-016 and its requirements and made some
revisions to the requirements listed in IRO-014-2. There are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall notify
impacted Reliability Coordinators. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning,
Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when the
identified Adverse Reliability Impact cannot be agreed to by the impacted Reliability Coordinators,
[Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same Day Operations and Realtime Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation
plan when the impacted Reliability Coordinators can not agree that the problem exists. [Violation Risk
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Organization
Question 19:
Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the
Reliability Coordinator who has the identified Adverse Reliability Impact when the impacted Reliability
Coordinators can not agree on a mitigation plan,. [Violation Risk Factor: Medium][Time Horizon:
Operations Planning, Same Day Operations and Real-time Operations]
The RC SDT has revised / created VSLs based on the new requirements.
SDT Proposed Lower VSL
The Reliability Coordinator that detected an expected or actual reliability issue contacted the other
Reliability Coordinator(s) to confirm that there was a problem but could not confirm that the problem
existed and failed to operate as though the problem existed.
CEDRP Proposed VSL IRO-014-2 R5
N/A
SDT Proposed High VSL
N/A
CEDRP Proposed VSL IRO-014-2 R5
The Reliability Coordinator that detected an expected reliability issue failed to contact the other
Reliability Coordinator(s) to confirm that there was a problem.
SDT Proposed Severe VSL
The Reliability Coordinator that detected an expected or actual reliability issue failed to contact the
other Reliability Coordinator(s) to confirm that there was a problem.
CEDRP Proposed VSL IRO-014-2 R5
The Reliability Coordinator that detected an actual reliability issue failed to contact the other Reliability
Coordinator(s) to confirm that there was a problem.
============================================================================
Standard – IRO-014-2 R6
When an expected or actual reliability issue exists and the impacted Reliability Coordinators cannot
agree on a mitigation plan, all impacted Reliability Coordinators shall implement the mitigation plan
developed by the Reliability Coordinator who has the reliability issue. [Violation Risk Factor: Medium]
[Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Proposed Measure
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Comments for Set of Reliability Coordination Standards (Project 2006-06)
Organization
Question 19:
The affected Reliability Coordinators shall have evidence that, in cases when an expected or actual
reliability issue existed and the impacted Reliability Coordinators could not agree on a mitigation plan,
they implemented the mitigation plan developed by the Reliability Coordinator who has the reliability
issue.
Discussion: We are concerned the validity of this requirement, it may force an RC to implement a
solution that they don’t agree with and ultimately result in an Adverse Reliability Impact. The RC may not
agree with the solution because it may not be reliable for their footprint. They need to have the ability to
veto mitigation plans that cause Adverse Reliability Impacts in their footprint without incurring a
compliance violation.
Response:
R6 was brought into this standard from IRO-016, R1 and R2. The RC SDT removed the wording relating
to the “most conservative solution” because it can not be measured. We are proposing to use the
mitigation plan of the RC who is experiencing the issue in cases where an agreed to mitigation plan can
not be developed.
SDT Proposed Lower VSL
The Reliability Coordinator did not agree on a mitigation plan and implemented a plan other than the
one developed by the Reliability Coordinator who had the reliability issue.
CEDRP Proposed VSL IRO-014-2 R6
N/A
SDT Proposed Severe VSL
The Reliability Coordinator did not agree on a mitigation plan and did not implement a mitigation plan.
CEDRP Proposed VSL IRO-014-2 R6
What if the RC is correct in disagreeing and the mitigation plan would have caused an Adverse
Reliability Impact on their system?
Response: The RC SDT thanks you for your comments. Please see responses embedded above.
In the future, please do not submit comments in this format. It is extremely burdensome on the drafting team in trying to respond to the
comments. Please answer each question individually. If you encounter difficulty, please contact NERC for assistance.
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Standard COM-001-2 — Communications
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008 – May 26,
2009.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the first draft. The team is seeking
comments on the revised standards.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Second Posting of draft standards,
July-August 2009
2. Respond to comments on second posting
August 2009
3. Post Standards for pre-ballot period.
September 2009
4. Standards posted for initial and recirculation ballots.
October 2009
5. Standards sent to BOT for approval.
December 2009
6. Standards filed with regulatory authorities.
January 2010
Draft 2: July 10, 2009
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Standard COM-001-2 — Communications
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
Draft 2: July 10, 2009
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate interpersonal
communication capabilities.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
4.6. Transmission Service Providers.
4.7. Load-Serving Entities.
4.8. Purchasing-Selling Entities.
5.
Effective Date:
The first day of the first calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test, on a quarterly basis, alternative interpersonal communications capabilities used for
communicating real-time operating information. If the test is unsuccessful, the entity
shall develop a mitigation plan to restore its interpersonal communications capabilities.
[Violation Risk Factor: Lower][Time Horizon: Real-time Operations]
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities within 60 minutes of the detection of a failure (30 minutes or
longer) of its normal interpersonal communications capabilities. [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
R3. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator,
Balancing Authority, Generator Operator, Transmission Service Provider, LoadServing Entity, Purchasing-Selling Entity and Distribution Provider shall use English
as the language for all inter-entity Bulk Electric System (BES) reliability
communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected BES. [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations]
R4. Each Distribution Provider and Generation Operator shall have interpersonal
communications capabilities with its Transmission Operator and Balancing Authority
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Standard COM-001-2 — Communications
for the exchange of Interconnection and operating information. [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, it tested, on a quarterly basis, alternative
interpersonal communications capabilities used for communicating real-time operating
information. If the test was unsuccessful, the entity shall have and provide upon
request evidence that it developed a mitigation plan to restore the interpersonal
communications capabilities. (R1.)
M2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, it notified impacted entities within 60 minutes of the
detection of a failure (30 minutes or longer) of their normal communications
capabilities. (R2.)
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Purchasing-Selling
Entity, and Distribution Provider shall have and provide upon request evidence that
could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, that will be used to
determine that personnel used English as the language for all inter-entity Bulk Electric
System reliability communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected
Bulk Electric System. If a language other than English is used, each party shall have
and provide upon request evidence that could include, but is not limited to operator
logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent, of agreement to use the alternate language. (R3.)
M4. Each Distribution Provider and Generation Operator shall demonstrate the existence of
its interpersonal communications capabilities with its Transmission Operator and
Balancing Authority for the exchange of Interconnection and operating information.
(R4.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
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Standard COM-001-2 — Communications
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep the most recent three
years of historical data (evidence) for Requirement R1, Measure M1.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep the most recent twelve
months of historical data (evidence) for Requirement R2, Measure M2.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Purchasing-Selling Entity, and Distribution Provider shall keep evidence for
Requirement R3, Measure M3 for the most recent 3 months. If a Reliability
Coordinator, Transmission Operator, Balancing Authority, Distribution Provider
or Generator Operator is found non-compliant with a requirement, it shall keep
information related to the noncompliance until the Compliance Enforcement
Authority finds it compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 2: July 10, 2009
Page 5 of 7
2.
Violation Severity Levels
Requirement
R1
Lower VSL
Moderate VSL
Severe VSL
N/A
N/A
The responsible entity failed
to test the alternative
interpersonal communications
capabilities on a quarterly
basis.
N/A
The responsible entity failed
to notify any impacted
entities of the failure of their
normal interpersonal
communications capabilities
within 60 minutes.
N/A
The responsible entity failed
to provide evidence of
concurrence to use a language
other than English for
communications between and
among operating personnel
responsible for the real-time
generation control or
operation of the
interconnected BES when a
language other than English
was used.
The responsible entity failed
to have interpersonal
communications capabilities
with its Transmission
Operator or Balancing
Authority.
The responsible entity failed
to have interpersonal
communications capabilities
with its Transmission
Operator and Balancing
Authority.
R2
The responsible entity tested
alternative interpersonal
communications capabilities
but failed to develop a
mitigation plan when the test
failed.
N/A
R3
N/A
The responsible entity
notified at least one, but not
all, impacted entities of the
failure of its normal
interpersonal communications
capabilities within 60
minutes.
N/A
R4
N/A
N/A
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High VSL
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Standard COM-001-2 — Communications
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Standard COM-001-2 — Communications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RCSDT
Revised
Draft 2: July 10, 2009
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Standard COM-001-2 — CTelecommunications
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008 – May 26,
2009.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the first draft. The team is seeking
comments on the revised standards.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Second Posting of draft standards,
July-August 2009
2. Respond to comments on second posting
August 2009
3. Post Standards for pre-ballot period.
September 2009
4. Standards posted for initial and recirculation ballots.
October 2009
5. Standards sent to BOT for approval.
December 2009
6. Standards filed with regulatory authorities.
January 2010
Draft 21: July 1610, 20082009
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Standard COM-001-2 — CTelecommunications
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None
Draft 21: July 1610, 20082009
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Standard COM-001-2 — CTelecommunications
A. Introduction
1.
Title:
CTelecommunications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate interpersonal
communication capabilities.Each Reliability Coordinator, Transmission Operator and
Balancing Authority needs adequate and reliable telecommunications facilities
internally and with others for the exchange of Interconnection and operating
information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
4.6. Transmission Service Providers.
4.7. Load-Serving Entities.
4.8. Purchasing-Selling Entities.
5.
Effective Date:
TBDThe first day of the first calendar quarter following
applicable regulatory approval – or in those jurisdictions where no regulatory approval
is required, the first day of the first calendar quarter following Board of Trustees
adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
operationally test, on a quarterly basis at a minimum, alternative interpersonal
telecommunications capabilitfacilities used for communicating real-time operating
information to ensure the availability of their use when normal telecommunications
facilities fail. If the test is unsuccessful, the entity willshall develop a mitigation plan
to restore theits interpersonal communications capabilities. [Violation Risk Factor:
LowerMedium][Time Horizon: Real-time Operations]
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities within 60 minutes of the detection of a of failure (30 minutes
or longer) of theirits normal interpersonal communications capabilities. of their normal
telecommunications facilities, and verify the alternate means of telecommunications
are functional. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
R3. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator,
Balancing Authority, Generator Operator, Transmission Service Provider, LoadServing Entity, Purchasing-Selling Entity and Distribution Provider shall use English
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Standard COM-001-2 — CTelecommunications
as the language for all inter-entity Bulk Electric System (BES) reliability
communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric SystemBES.
Transmission Operators and Balancing Authorities may use an alternate language for
internal operations. [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
R4. Each Distribution Provider and Generation Operator shall have interpersonal
telecommunications capabilitfacilities with its Transmission Operator and Balancing
Authority for the exchange of Interconnection and operating information. [Violation
Risk Factor: High][Time Horizon: Real-time Operations and Operations Planning]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, it operationally tested, on a quarterly basis at
a minimum, alternative interpersonal telecommunications capabfacilities used for
communicating real-time operating information to ensure the availability of their use
when normal telecommunications facilities fail. If the test was unsuccessful, the entity
shall have and provide upon request evidence that it developed a mitigation plan to
restore the interpersonal communications capabilities. (R1.)
M2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent,that it notified impacted entities within 60 minutes of
the detection of a of failure (30 minutes or longer) of their normal telecommunications
capabilitiesfacilities, and verified the alternate means of telecommunications were
functional. (R2.)
M3. The Each Reliability Coordinator, Transmission Operator, or Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity, PurchasingSelling Entity, and Distribution Provider shall have and provide upon request evidence
that could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, that will be used to
determine that personnel used English as the language for all inter-entity Bulk Electric
System reliability communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected
Bulk Electric System. If a language other than English is used, both partieach partyes
shall have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, of agreement to use the alternate language. (R3.)
M4. Each Distribution Provider and Generation Operator shall demonstrate the existence of
itshas interpersonal telecommunications capabifacilities with its Transmission Operator
and Balancing Authority for the exchange of Interconnection and operating
information. (R4.)
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Standard COM-001-2 — CTelecommunications
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, and Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
For the Measures, eEach Reliability Coordinator, Transmission Operator, and
Balancing Authority, Distribution Provider, and Generator Operator shall each
keep the most recent three yearsmonths of historical data (evidence) for
Requirement R1, Measure M1.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep the most recent twelve
months of historical data (evidence) for Requirement R2, Measure M2.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Purchasing-Selling Entity, and Distribution Provider shall keep evidence for
Requirement R3, Measure M3 for the most recent 3 months.
If a Reliability Coordinator, Transmission Operator, and Balancing Authority,
Distribution pProvider andor Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliance until the
Compliance Enforcement Authority finds it ound compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
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Standard COM-001-2 — CTelecommunications
None
Draft 21: July 1610, 20082009
Page 6 of 9
2.
Violation Severity Levels
Requirement
R1
R2
Lower VSL
The responsible entity
tested alternative
interpersonal
communications
capabilities but failed to
develop a mitigation plan
when the test failed.
N/A
Draft 21: July 1610, 20082009
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The responsible entity
failed to test the alternative
interpersonal
communications
capabilities on a quarterly
basis.
The responsible entity
notified at least one, but
not all, impacted entities of
the failure of its normal
interpersonal
communications
capabilities within 60
minutes.
N/A
The responsible entity
failed to notify any
impacted entities of the
failure of their normal
interpersonal
communications
capabilities within 60
minutes.
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Standard COM-001-2 — CTelecommunications
R3
N/A
N/A
N/A
The responsible entity
failed to provide evidence
of concurrence to use a
language other than
English for all
communications between
and among operating
personnel responsible for
the real-time generation
control and or operation of
the interconnected Bulk
Electric SystemBES when
a language other than
English was used.
R4
N/A
N/A
The responsible entity
failed to have
interpersonal
communications
capabilities with its
Transmission Operator
ORor Balancing
Authority.N/A
The responsible
entityDistribution Provider
or Generation Operator
failed to have
interpersonal
communications
capabilities
telecommunications
facilities with its
Transmission Operator
and Balancing Authority.
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Standard COM-001-2 — CTelecommunications
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Standard COM-001-2 — CTelecommunications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RCSDT
Revised
Draft 21: July 1610, 20082009
Page 9 of 9
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UNOFFICIAL Comment Form for Reliability Coordination — Project 2006-06
Please DO NOT use this form. Please use the electronic comment form located at the link
below to submit comments on the proposed revisions to the standards for Project 2006-06:
Reliability Coordination. Comments must be submitted by August 9, 2009. If you have
questions please contact Stephen Crutchfield at [email protected] or by telephone
at 609-651-9455.
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Background Information:
The Reliability Coordination Standards Drafting Team (RC SDT) was tasked with 1) ensuring
that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable, 2) ensuring that this set of requirements is sufficient to
maintain reliability of the Bulk Electric System, and 3) revising the group of standards based
on FERC Order 693.
During the course of the project, the NERC standards staff revised the Reliability Standards
Development Plan and noted several areas of overlapping scope between certain projects. The
original SAR for Project 2006-06 called for revisions to PER-004 — Reliability Coordination –
Staffing and PRC-001 — System Protection Coordination. Based on scope overlap, it was
determined that PER-004 and PRC-001 would best be served by moving the proposed work to
Project 2006-01: System Personnel Training and Project 2007-06: System Protection,
respectively.
The RC SDT proposed revisions to the set of standards under the project in August and
September 2008. The RC SDT made revisions to the set of standards based on stakeholder
feedback and the results of the IROL Standards Drafting Team work. Since the inception of
this project, the IROL Standards Drafting Team has proposed, successfully balloted and
obtained NERC Board of Trustees approval for three new Standards which included revisions to
other IRO standards. With the approval of the IROL set of standards, certain requirements
were retired from other IRO standards (see below summaries for specific examples under the
RC SDT project).
Requirements, Measures and Violation Severity Levels in COM-001-2
Requirements: The RC SDT received several comments regarding the intent of the term
“telecommunications facilities”. For COM-001-2, the RC SDT envisions telecommunications to
be voice or message communication between operating personnel. The standard has been
renamed “Communications” and the term “telecommunications facilities” was replaced with
“interpersonal communications capabilities” throughout the standards to better reflect the
intent of the RC SDT.
We also received comments regarding the applicability of the standard that suggested adding
other entities listed in IRO-001 (LSE, PSE, and TSP). The RC SDT contends that, in order to
receive and carry out directives, an entity must be able to communicate with the RC…either
directly or through other entities (e.g. – a DP may receive the directive from the TOP who
received it from the RC). We have not expanded the applicability of Requirements R1 and R2
as suggested as we feel that this expands the standard beyond the reliability - it is not
necessary nor is it practical, for reliability purposes, for every entity to have normal and backup interpersonal communications capabilities with every other entity.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Unofficial Comment Form — Reliability Coordination Project 2006-06
Other commenters had concerns with regard to R2 and the intent with regard to length of
outages. The requirement was revised as:
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities within 60 minutes of the detection of a failure (30 minutes or
longer) of its normal interpersonal communications capabilities. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
R3 was expanded to include the Transmission Service Provider, Load-Serving Entity, and
Purchasing-Selling Entity – to ensure that they use the English language for inter-entity
communications. The informational (last) sentence of R3 was removed per stakeholder
suggestions.
Measures: Commenters suggested general as well as specific revisions to the measures.
One general comment suggested making the language consistent among the measures
regarding evidence. M1-M3 were revised to include the phrase “shall have and provide upon
request evidence that …”.
Several commenters suggested revisions to M3. The RC SDT revised M3 based on the
comments received suggesting that the applicability be expanded to include Generator
Operators, Distribution Providers, Transmission Service Providers, Purchasing-selling Entities
and Load-Serving Entities. Several entities commented that M3 did not match R3 which
included an explanatory sentence that allowed an entity to use a language other than English
for its internal communications. The informational second sentence was removed from
Requirement R3, thus eliminating the “disconnect” between the requirement and the measure.
All measures were revised as necessary to reflect revisions to requirements.
VSLs: The RC SDT made revisions to the VSLs based on the comments received and also to
reflect revisions to the associated requirements. We received comments that the VSLs for R1
and R2 were based on multiple violations. We agreed and revised the VSLs to reflect a single
violation.
Requirements, Measures and Violation Severity Levels in COM-002-3
The work of the IROL SDT resulted in the retirement of R1 from the standard. The RC SDT
received comments recommending expanding the applicability of the standard and separating
Requirement R1 into two distinct requirements. The applicability was expanded to include
Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and PurchasingSelling Entity. The requirements were revised to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues a directive associated with real-time operational emergency conditions shall require
the recipient of the directive to repeat the intent of the directive back; and shall
acknowledge the response as correct or repeat the original statement to resolve any
misunderstandings. [Violation Risk Factor: High][Time Horizon: Real-Time]
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity that is the recipient of a directive issued per Requirement R1
shall repeat the intent of the directive back to the issuer of the directive. [Violation Risk
Factor: High][Time Horizon: Real-Time]
The purpose statement was also revised to reflect the revisions to the standard:
To ensure communications by operating personnel are effective.
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Unofficial Comment Form — Reliability Coordination Project 2006-06
The RC SDT received comments recommending expanding the applicability of the standard
and separating Requirement R1 into two distinct requirements. The applicability was
expanded to include Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider,
and Purchasing-Selling Entity. The measures were revised to:
M1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
that issues a directive associated with real-time operational emergency conditions shall
have evidence such as voice recordings or transcripts of voice recordings to show that
it required the recipient of the directive to repeat the intent of the directive back; and
acknowledged the response as correct or repeated the original statement to resolve any
misunderstandings.
M2.
Each Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution
Provider, and Purchasing-Selling Entity that is the recipient of a directive issued per
Requirement R1 shall have evidence such as voice recordings or transcripts of voice
recordings to show that it repeated the intent of the directive back to the issuer of the
directive.
The RC SDT received comments recommending revisions to the VSLs based on revisions to the
requirements and measures. The RC SDT did this and created new VSLs for new Requirement
R2.
Requirements, Measures and Violation Severity Levels in IRO-001-2
The RC SDT has received a notable number of comments suggesting edits to the proposed
requirements and measures for the draft standard, particularly regarding the phrase “without
intentional delay.” The comments do not oppose the objective of the phrase, but often point
out the issues of measuring intent and measuring delay time.
To maintain the intent while improving the measurability of the requirement, the SDT
proposes to modify the standard as follows: delete the phrase ‘without intentional delay’ and
leave the obligation of response and timing an unstated requirement of R1 “The RC shall act or
direct actions…”
An RC that requires a given action in a given time will be expected to inform the impacted
entities of those actions and time requirements. This would obviate the need for providing a
measure for “intent”, but still maintain the reliability intent of the original requirement.
The VSLs were revised to reflect revisions to the requirements as well as the comments of
stakeholders. Several comments suggested that there was no fundamental difference
between the RC “acting” or “directing actions”. The RC SDT agreed and removed the High VSL
for R1 and revised the Severe VSL accordingly. Other commenters suggested removing the
High VSL from R2 as the VSL contradicted the requirement. The RC SDT agreed and removed
the VSL.
Requirements, Measures and Violation Severity Levels in IRO-002-2
Since the inception of this project (2006-06), the IROL Standards Drafting Team has
proposed, successfully balloted and obtained NERC Board of Trustees approval for a new
Standard IRO-010-1: Reliability Coordinator Data Specification and Collection. The work of
the IROL SDT retired IRO-002-2 Requirement R1. The team received comments expressing
concern about eliminating the requirement in IRO-002 to monitor frequency. While the
Standard Drafting Team (SDT) recognizes the concern raised, the SDT is even more concerned
with the subjectivity that any attempt to measure “Monitoring” can provide. It is the SDT’s
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Unofficial Comment Form — Reliability Coordination Project 2006-06
contention that adherence to reliability standards that require the said monitoring cannot be
demonstrated unless the entity is closely monitoring the system parameters. Furthermore, the
SDT contends that any requirements that describe the monitoring facilities needed to fulfill
fundamental duties should be embedded in entity certification requirements. With IRO-014
and IRO-001 R1 in place, the actual act of monitoring is a secondary task that is inherent in
responding to situations or events that could have an adverse impact on reliability. The team
declined to delete R2 (Reliability Coordinator veto over analysis tool outages) as it was a
specific recommendation from the 2003 Blackout report. This requirement was revised and
moved into IRO-001-2 as R6.
Stakeholders indicated that R6 (previously IRO-002 R2) is a “binary” requirement and the
Lower VSL was deleted and the Severe VSL was revised based on those comments.
Retirement of IRO-005-1
Several commenters had concerns around removing the requirement to monitor frequency
(IRO-005-1 R8). The intent of this monitoring activity was incorporated into IRO-002-2, R1.
Other commenters had concerns with the removal of other monitoring requirements in the
standard. While the Standard Drafting Team (SDT) recognizes the concern raised, the SDT is
even more concerned with the subjectivity associated with any attempt to measure
“Monitoring.” It is the SDT’s contention that adherence to reliability standards that require the
said monitoring cannot be demonstrated unless the entity is closely monitoring the system
parameters. Furthermore, the SDT contends that any requirements that describe the
monitoring facilities needed to fulfill fundamental duties should be embedded in entity
certification process requirements. With IRO-014 and IRO-001 R1 in place, the actual act of
monitoring is a secondary task that is inherent in responding to situations or events that could
have an adverse impact on reliability.
Requirements, Measures and Violation Severity Levels in IRO-014-2
Several commenters expressed concerns with the term “impacted” and suggested replacing
this with “other”. The RC SDT believes “impacted” directly relates to the purpose statement.
Additionally, replacing “one or more other” with “impacted” does tighten the requirement and
removes ambiguity. The RC SDT does not intend for non-contiguous Reliability Coordinators to
have “Reliability Coordinator Agreements”, but to have Procedures, Processes, or Plans with
impacted reliability coordinators. Other commenters suggested striking the term “as a
minimum” in R1 and the RC SDT agrees and has modified R1 accordingly. Some commenters
did not agree with the wording of the new requirements in IRO-014 that were formerly in IRO016. The RC SDT reviewed the Implementation Plan for IRO-016 and its requirements and
made some revisions to the requirements listed in IRO-014-2. There are now 4 requirements:
R5. Each Reliability Coordinator, upon identification of an Adverse Reliability Impact, shall
notify impacted Reliability Coordinators. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning, Same Day Operations and Real-time Operations]
R6. Each impacted Reliability Coordinator shall operate as though the problem exists when
the identified Adverse Reliability Impact cannot be agreed to by the impacted Reliability
Coordinators. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same
Day Operations and Real-time Operations]
R7. The Reliability Coordinator with the identified Adverse Reliability Impact shall develop
a mitigation plan when the impacted Reliability Coordinators can not agree that the
problem exists. [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same
Day Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed
by the Reliability Coordinator that has the identified Adverse Reliability Impact when the
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impacted Reliability Coordinators can not agree on a mitigation plan, [Violation Risk
Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time
Operations]
Several commenters suggested that the High and Severe VSLs for R2 contradicted the
requirement. The RC SDT agreed and removed the “nots” from the VSLs. Several
commenters had suggested revisions for the VSLs for R6. This requirement was imported
from IRO-016 and several commenters suggested expanding the set of requirements
regarding the mitigation plan. New VSLs were developed for these requirements.
Retirement of IRO-015-2
Stakeholders agreed with the proposed revisions and this is not being re-posted for comment.
Requirements of IRO-016-1
Stakeholders agreed with the concept of moving the requirements of IRO-016-1 into IRO-0142. Some commenters did not agree with the wording of the new requirements in IRO-014 that
were formerly in IRO-016 and the RC SDT revised these requirements in support of
stakeholder comments. There are now 4 requirements, rather than 2, that address Reliability
Coordinator actions when a Reliability Coordinator identifies an Adverse Reliability Impact.
New measures and VSLs were developed to support these revised requirements.
Proposed Effective Dates
The RC SDT received comments that COM-001-2, R5 should have an effective date
immediately upon regulatory approval. The RC SDT agrees and will request an effective date
that is the first possible effective date – the first day of the first calendar quarter following
applicable regulatory approval – or in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter following Board of Trustees adoption.
The Reliability Coordination Drafting Team would like to receive industry comments on these
changes. The RC SDT asks that you review the revised standards and answer the following
questions by August 9, 2009.
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Unofficial Comment Form — Reliability Coordination Project 2006-06
1. Do you agree with the revisions made to the Requirements in COM-001-2 as
shown in the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the revisions made to the Measures in COM-001-2 as shown in
the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
3. Do you agree with the revisions made to the Violation Severity Levels in COM001-2 as shown in the posted Standard? If not, please explain in the comment
area.
Yes
No
Comments:
4. Do you agree with the revisions made to the Requirements in COM-002-3 as
shown in the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
5. Do you agree with the revisions made to the Measures in COM-002-3 as shown in
the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
6. Do you agree with the revisions made to the Violation Severity Levels in COM002-3 as shown in the posted Standard? If not, please explain in the comment
area.
Yes
No
Comments:
7. Do you agree with the revisions to the definition of Adverse Reliability Impacts
(IRO-001-2)? If not, please explain in the comment area.
Yes
No
Comments:
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8. Do you agree with the revisions to the Requirements in IRO-001-2 as shown in
the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
9. Do you agree with the revisions to the Measures in IRO-001-2 as shown in the
posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
10.Do you agree with the revisions to the Violation Severity Levels in IRO-001-2 as
shown in the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
11.Do you agree with the revisions to the Requirements in IRO-014-2 as shown in
the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
12.Do you agree with the revisions to the Measures in IRO-014-2 as shown in the
posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
13.Do you agree with the revisions to the Violation Severity Levels in IRO-014-2 as
shown in the posted Standard? If not, please explain in the comment area.
Yes
No
Comments:
14.If you have any other comments, not expressed in questions above, for the RC
SDT on any of the other changes made to this set of standards and their
associated implementation plans, please provide them here.
Comments:
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Prerequisite Approvals
IRO-002-2
IRO-005-3
Conforming Changes to Requirements in Already Approved Standards
None
Revision Summary
The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
To be determined.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
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Implementation Plan for COM-001-2
Communications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
R1.4.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT contends that COM-001-1, R1 and its subrequirements are low
level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability
requirements for each entity throughout the body of standards. Examples
include:
IRO-001-1, R3 requires adequate telecommunication for the Reliability
Coordinator to direct actions of multiple entities, including TOPs and BAs.
TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to
the RC.
TOP-001-1, R3 requires adequate telecommunications facilities for the TOP,
BA, and GOP to be able to receive directives from the RC.
TOP-006-1, R1 requires adequate telecommunications for the GOP to inform
the BA and TOP of resources. The BA and TOP will then inform the RC,
other TOP and BAs of all transmission and generation available for use.
The retirement of this requirement also facilitates one of the FERC Order 693
directives for COM-001-1 to “includes adequate flexibility for compliance with
the Reliability Standard, adoption of new technologies and cost-effective
solutions”.
Notes: Based on the above information, the RC SDT recommends retiring R1 and its subrequirements.
July 10, 2009
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Implementation Plan for COM-001-2
Communications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R1. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall test, on a quarterly basis alternative
interpersonal communications capabilities used for communicating
real-time operating information. If the test is unsuccessful, the entity
shall develop a mitigation plan to restore its interpersonal
communications capabilities. [Violation Risk Factor: Lower][Time
Horizon: Real-time Operations]
Notes: The RC SDT contends that the first sentence of COM-001-1, R2 is a low level facilitating requirements that is more appropriately and
inherently monitored under various higher level performance-based reliability requirements for each entity throughout the body of standards as
described in R1 above. We propose revising R2 as shown above to focus on the testing of capabilities that are not used on a routine basis.
July 10, 2009
3
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
COM-001-2
R3.
R2. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60
minutes of the detection of a failure (30 minutes or longer) of its
normal interpersonal communications capabilities. [Violation
Risk Factor: Medium][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
July 10, 2009
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Implementation Plan for COM-001-2
Communications
Already Approved Standard
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2
R3. Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving
Entity, Purchasing-Selling Entity, and Distribution Provider
shall use English as the language for all inter-entity Bulk
Electric System (BES) reliability communications between
and among operating personnel responsible for the realtime generation control and operation of the interconnected
BES. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
Notes: COM-001 Requirement R3 is being incorporated into COM-003-1 by the Operations Personnel Communications Protocols SDT (Project
2007-02). It will be retired from this standard upon approval of COM-003-1. The RC SDT expanded the list of applicable entities to include the
TSP, LSE and PSE and to delete the explanatory sentence at the end of the requirement.
July 10, 2009
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Implementation Plan for COM-001-2
Communications
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Implementation Plan for COM-001-2
Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
July 10, 2009
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Implementation Plan for COM-001-2
Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the requirements
in Attachment 1-COM-001, “NERCNet Security Policy.” [Violation
Risk Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-2
R4. Each Distribution Provider and Generation Operator
shall have interpersonal communications capabilities
with its Transmission Operator and Balancing Authority
for the exchange of Interconnection and operating
information. [Violation Risk Factor: High][Time Horizon:
Real-time Operations and Operations Planning]
Notes: This is a new requirement based on the following FERC Order 693 directive:
“expands the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities”
July 10, 2009
7
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
Purchasing
Selling Entity
Transmission
Operator
Transmission
Service
Provider
Load Serving
Entity
Generator
Operator
Distribution
Provider
X
X
X
X
X
X
X
X
Communications
July 10, 2009
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Implementation Plan for COM-001-2
Communications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Prerequisite Approvals
IRO-002-2
IRO-005-3
Conforming Changes to Requirements in Already Approved Standards
None
Revision Summary
The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
To be determined.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
R1.4.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT contends that COM-001-1, R1 and its subrequirements are low
level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability
requirements for each entity throughout the body of standards. Examples
include:
IRO-001-1, R3 requires adequate telecommunication for the Reliability
Coordinator to direct actions of multiple entities, including TOPs and BAs.
TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to
the RC.
TOP-001-1, R3 requires adequate telecommunications facilities for the TOP,
BA, and GOP to be able to receive directives from the RC.
TOP-006-1, R1 requires adequate telecommunications for the GOP to inform
the BA and TOP of resources. The BA and TOP will then inform the RC,
other TOP and BAs of all transmission and generation available for use.
The retirement of this requirement also facilitates one of the FERC Order 693
directives for COM-001-1 to “includes adequate flexibility for compliance with
the Reliability Standard, adoption of new technologies and cost-effective
solutions”.
Notes: Based on the above information, the RC SDT recommends retiring R1 and its subrequirements.
July 30, 200810, 2009
2
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R1. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall operationally test, on a quarterly basis at a
minimum, alternative interpersonal telecommunications facilities
capabilities used for communicating real-time operating information.
If the test is unsuccessful, the entity shall develop a mitigation plan
to restore its interpersonal communications capabilities. to ensure
the availability of their use when normal telecommunications
facilities fail. manage, alarm, test and/or actively monitor vital
telecommunications facilities. Special attention shall be given to
emergency telecommunications facilities and equipment not used for
routine communications. [Violation Risk Factor: MediumLower][Time
Horizon: Real-time Operations]
Notes: The RC SDT contends that the first sentence of COM-001-1, R2 is a low level facilitating requirements that is more appropriately and
inherently monitored under various higher level performance-based reliability requirements for each entity throughout the body of standards as
described in R1 above. We propose revising R2 as shown above. to focus on the testing of capabilities that are not used on a routine basis.
July 30, 200810, 2009
3
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
COM-001-2
R3.
R2. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60
minutes of the detection of a of failure (30 minutes or longer) of
their its normal interpersonal communications capabilities.
telecommunications facilities, and verify the alternate means of
telecommunications are functional. provide a means to
coordinate telecommunications among their respective areas.
This coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas. [Violation Risk Factor: Medium
Lower][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
July 30, 200810, 2009
4
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2
R3. Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving
Entity, Purchasing-Selling Entity, and Distribution Provider
shall use English as the language for all inter-entity Bulk
Electric System (BES) reliability communications between
and among operating personnel responsible for the realtime generation control and operation of the interconnected
Bulk Electric SystemBES. Transmission Operators and
Balancing Authorities may use an alternate language for
internal operations. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
Notes: COM-001 Requirement R3 is being incorporated into COM-003-1 by the Operations Personnel Communications Protocols SDT (Project
2007-02). It will be retired from this standard upon approval of COM-003-1. The RC SDT expanded the list of applicable entities to include the
TSP, LSE and PSE and to delete the explanatory sentence at the end of the requirement.
July 30, 200810, 2009
5
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
July 30, 200810, 2009
6
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the requirements
in Attachment 1-COM-001, “NERCNet Security Policy.” [Violation
Risk Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-2
R4. Each Distribution Provider and Generation Operator
shall have interpersonal telecommunications facilities
capabilities with its Transmission Operator and
Balancing Authority for the exchange of Interconnection
and operating information. [Violation Risk Factor:
High][Time Horizon: Real-time Operations and
Operations Planning]
Notes: This is a new requirement based on the following FERC Order 693 directive:
“expands the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities”
July 30, 200810, 2009
7
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
Reliability
Coordinator
COM-001-2
X
Balancing
Authority
X
Purchasing
Selling
EntityInterc
hange
Authority
Transmission
Operator
X
X
Transmission
Service
ProviderOwn
er
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
Generator
Owner
X
Telecommuni
Communications
July 30, 200810, 2009
8
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Comment Period Open
July 10–August 9, 2009
Now available at:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Project Name
Project 2006-06 — Reliability Coordination
Due Date and Submittal Information
The comment period is open until 8 p.m. EDT on August 9, 2009. Please use this electronic form to
submit comments. If you experience any difficulties in using the electronic form, please contact
Lauren Koller at [email protected]. An off-line, unofficial copy of the comment form is posted
on the project page: http://www.nerc.com/filez/standards/Reliability_Coordination_Project_20066.html
Content for Comment Period
The Reliability Coordination Standards Drafting Team is seeking comments on its second drafts of the
following proposed standards:
COM-001-2 — Communications
COM-002-3 — Communications and Coordination
IRO-001-2 — Reliability Coordination – Responsibilities and Authorities
IRO-014-2 — Coordination Among Reliability Coordinators
The drafting team revised the proposed standards based on stakeholder feedback and the results of the
IROL Standards Drafting Team work.
Other Materials Posted
Revised implementation plans
The drafting team’s consideration of industry comments received during the first comment
period
Project Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measurable, unique, and
enforceable, 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System, and 3) revising the group of standards based on FERC Order 693.
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During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team, and two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope
overlap. Detailed information on these changes can be found in the comment form for this posting.
Applicability of Standards in Project
Reliability Coordinator
Balancing Authority
Transmission Service Provider
Transmission Operator
Distribution Provider
Generator Operator
Purchasing Selling Entity
Load Serving Entity
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on
stakeholder participation. We extend our thanks to all those who participate
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
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Individual or group. (29 Responses)
Name (19 Responses)
Organization (19 Responses)
Group Name (10 Responses)
Lead Contact (10 Responses)
Contact Organization (10 Responses)
Question 1 (23 Responses)
Question 1 Comments (29 Responses)
Question 2 (27 Responses)
Question 2 Comments (29 Responses)
Question 3 (25 Responses)
Question 3 Comments (29 Responses)
Question 4 (28 Responses)
Question 4 Comments (29 Responses)
Question 5 (24 Responses)
Question 5 Comments (29 Responses)
Question 6 (23 Responses)
Question 6 Comments (29 Responses)
Question 7 (23 Responses)
Question 7 Comments (29 Responses)
Question 8 (22 Responses)
Question 8 Comments (29 Responses)
Question 9 (23 Responses)
Question 9 Comments (29 Responses)
Question 10 (21 Responses)
Question 10 Comments (29 Responses)
Question 11 (18 Responses)
Question 11 Comments (29 Responses)
Question 12 (18 Responses)
Question 12 Comments (29 Responses)
Question 13 (18 Responses)
Question 13 Comments (29 Responses)
Question 14 (0 Responses)
Question 14 Comments (29 Responses)
Individual
Steve Alexanderson
Central Lincoln
Comments: The inclusion of load serving entities and distribution providers does not address any present reliability
gap. R4 is extremely vague, and is not likely to be interpreted consistently. What form of evidence will be acceptable?
Photos of telephones?
No
Comments: M4 is of little help regarding R4. How does an entity perform this demonstration, especially in the case of
an off-site audit? If left to the regions, there will be no consistency.
No
The severity levels have little or no relationship to reliability. Failure to provide a evidence of an agreement per R3, for
example, has no impact on reliability by itself; yet it carries the maximum VSL. In reality, the impact would only be
severe if the use of an alternate language resulted in a miscommunication.
No
The inclusion of load serving entities and distribution providers does not address any present BES reliability gap.
No
M2 goes beyond R2 in requiring recordings. This will be cost prohibitive for small entities that have little impact on the
BES. Telephone recording equipment will be needed on company phones, and some way to handle the recording of
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directives and responses that occur after hours on home or cell phones must be handled. Drafters seem to have
missed the fact that not all the applicable entities have 24/7 dispatch centers.
Individual
Virginia Cook
JEA
R2 I would suggest that R2 be clarified so that it is understood that the 60 minutes starts at the beginning of the outage
(or the end of the 30 minute period, if that was instead the intent) so that there can be no confusion about when the
clock starts for notification periods. Otherwise, the wording of these standards is clearer than the current version. R4 I
am concerned that with the word "capabilities" that the DP/GO's will be expected by the auditors to demonstrate that its
"capability" was working every single second of every day since their last audit, especially since you have not included
a data retention period(especially since this is rated a "high" VRF).
Yes
M1 - very nice, probably we will also be held responsible for completing the mitigation plans, so perhaps you should go
ahead and add that so no one gets caught without sufficient evidence in that regard M2 - fine M3 - this measure would
indicate that operators have the authority to agree among themselves to speak other languages, rather than a more
formal agreement between entities, which is how I read the language of the requirement. If that is not what is meant,
then I would suggest the examples include Memorandums of Agreement or Understanding, Contracts or other more
formal mechanisms. M4 - fine
Yes
No
R1: just to avoid possible auditor misunderstandings the SDT might consider replacing the words "or repeat the original
statement" to "reissue the directive" so that the RC does not get into trouble if the second statement is not verbatem of
the first. This also helps clarify that another statement is required from the recipient along with a final acknowledgement
from the RC that the intent is correct.
No
Not all entities have recorded lines. The standard does not directly require the to record their lines, but the measure
implies it. It seems that a written log should be sufficient. Since both sides of the conversation gets audited, the
auditors will have ample opportunity to check up on both sides.
Yes
Individual
Daniel Duff
Liberty Electric Power LLC
Yes
Yes
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No
The proposed standard does not require the RC, TO, or BA to declare an emergency to the GO when issuing a
directive. There has been confusion at times in the past as to whether the entity is issuing a directive based on
economics or due to an emergency. The standard should be amended to require the RC/TO/BA to state the directive is
due to a declared emergency. The GO is required to repeat back the intent of an emergency directive, but is not
required to repeat back the intent of economic directive. This can lead to a finding of a severe VSL non-compliance on
the part of the GO due to a failure of the RC/TO/BA to clearly state the nature of the directive.
Yes
Yes
Yes
No
Similar objection to COM-002-3: There should be a requirement to the RC to declare the nature of the directive,
emergency or economic.
Yes
No
The VSL's have a "Severe" VSL attached to a GO who fails to inform the RC when the Go becomes aware it is are
unable to fully comply with a directive. However, the RC failing to inform two TO's - who potentially could have many
GOs supplying power to their systems - of an emergency is only a "Moderate" VSL.
Yes
Yes
Yes
Group
Northwest LSE Group
Russell A. Noble
Cowlitz County PUD
No
The RC STD has done a commendable effort. However, it is questionable how expanding the applicability to include
LSEs, DPs, & PSEs that are non-scheduling/tagging entities will increase reliability of the BES. In fact, we believe that
increasing the applicability could do just the opposite. Many of these entities that are only registered as a LSE, DP,
and/or PSE do not have a 24/7 desk/dispatch facility to receive RC/BA/TOP reliability directives, and are too small (10s
of MW) to effectively assist during a reliability crisis. In addition, the Regional Entities (WECC in this case) are
overwhelmed as it is, asking them to take on even more audit responsibilities is unrealistic, and not worth the effort. In
addition, for the small Registered Entity, what would constitute compliance with R3 & R4 if no TOP/BA real-time
directives were received? Everyone employed speaks English and there is at least one phone on the premises? Will
the small DP and/or LSE be required to monitor its communication system 24/7 with competent personnel for an
unlikely TOP/BA directive?
No
To demonstrate compliance the small Registered Entities will be in the position of proving a negative: i.e., there is no
real-time BES operational communication from or to any other entity. Currently, for the smaller entities, communication
with the Transmission Operator or Balancing Authority is strictly for operational safety and local reliability of service, not
operational reliability for the BES as defined by NERC. It is not clear how the small entity will show compliance. If R4
requires the small load-only DP and/or LSE to have 24/7 monitoring of its phone, and contracted answering service is
unable to contact anyone, will this be a violation?
No
With the vague verbiage of R4 coupled with the High and Severe VSL, it is important to clarify R4 with the small DP in
mind, and possibly include Lower and Moderate VSLs for smaller load-only DP violations.
No
It would be advantageous to exempt certain smaller Registered Entities (LSE, DP, & PSE) that are nonscheduling/tagging entities. In addition to not having a scheduling/tagging desk, many of these entities do not have a
24/7 desk to receive RC/BA/TOP reliability directives/calls, and are too small (10s of MW) to even be substantially
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
significant in a reliability crisis. Instead of making this Standard applicable to all DPs, LSEs, and PSEs, we suggest that
the RC, BAs, and TOPs to yearly publish those LSEs, DPs, and PSEs responsible for responding to emergency
reliability directives. Also, it would be advisable for the RC, BA, and TOP giving a reliability directive to clearly preface
the instruction with “The following is an emergency reliability directive” to differentiate from normal operations
communications. Many smaller entities do not have the resources to install reliable voice recording equipment, but
having access to such recordings would be beneficial towards compliance documentation; thus, it would be helpful to
require the directive issuing RC, BA, or TOP to provide a digital copy of the voice recording, or transcript if available on
request to the recipient of the directive. Short of a recording or transcript of the recording, it will be difficult to determine
how a small entity without recorded line would show compliance other than writing down the directive as it is given and
reading it back to the issuer. If the directive is lengthy, this will slow down the process and probably defeat the purpose
and value of quick action. Further, there is no guarantee that the receiver will accurately retain a complicated directive if
not immediately documented in some way to allow review. Last of all, what is meant by the word “intent?” Must the
recipient understand and demonstrate the “why” the directive is given and the intended “outcome,” or merely
paraphrase the directive to demonstrate understanding? If the recipient repeats word for word the directive back to the
issuer without any other indication that the directive is understood, is this a violation??
No
Only in making the Measures agree with the suggested changes to the requirements above.
No
Only in making the Measures agree with the suggested changes to the requirements above.
Yes
No
To reduce the compliance burden on smaller entities that would never receive a Reliability Coordinator directive and
reduce needless Regional Entity auditing, it would be most helpful to require the RC to publish its list of entities
responsible for receiving reliability directives. Also, any Registered Entity should be able to request copies of digital
audio recordings or transcripts of the audio recordings if available from the RC.
No
Only in making the Measures agree with the suggested changes to the requirements above.
No
Only in making the Measures agree with the suggested changes to the requirements above.
Abstain
Abstain
Abstain
Group
WECC Reliability Coordinator
Mike Davis
WECC RC
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Interpersonal communication includes more than voice, such as instant messaging, text messaging and email. This
Standard needs a definition of interpersonal communication. Having alternative interpersonal communications should
be specified as a requirement. Work communication within Québec must be in French according to the law. It is
understood and agreed that communication outside Québec with adjacent entities would be, and in fact is already, in
English. Accordingly, R3 should be modify as the proposition below: R3. Unless dictated by law or otherwise agreed to,
…
No
See our comment for R3 in Q1. Accordingly, M3 should be modified as the proposition below: M3. … that will be used
to determine that personnel used English «or another language» as the language for all inter-entity Bulk Electric
System reliability communications between and among operating personnel responsible for the real-time generation
control and operation of the interconnected Bulk Electric System. If a language other than English is used, both
partieach partyes shall have and provide upon request, evidence that could include, but is not limited to operator logs,
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
voice recordings or transcripts of voice recordings, electronic communications, or equivalent, of agreement shall be
provided to explain the use of the alternate language. (R3.) M3 allows a language other than English. Must the
agreement for non-English be in place in advance of the call?
No
see M3 comment for question 2
No
Support the intent but not the existing language. Do not support Requirements that include some examples since the
examples can be confused with the Requirement. Do not support one written Requirement that has two requirements.
Recommend the following Requirements A new R1 - Each Entity shall have Operational Procedure requiring that
communications directives be repeated back to the issuer R2 – leave as is A new R3 – If not repeated, then issuer
shall request the receiving Entity to repeat the communication directive A new R4 – The issuer will acknowledge the
correctness of the repetition of the communications directive
No
Addressed the new proposed Requirements above in Question 4.
No
Address the new proposed Requirements.
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive issued Dec. 27,
2007.
No
Add “an issued” to the wording as shown following: The Each Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, andor Purchasing-Selling Entity
shall immediately confirm the ability to comply with the directive or inform the its Reliability Coordinator upon
recognition of itshe inability to perform thean issued directive.
Yes
No
(i) R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to issue
an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High VSL to:
“…failed to issue an alert to three, but not all, impacted….” and the Severe VSL to: “…failed to issue an alert to any or
more than three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. Some
examples may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were alerted, this would be a
“Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be a “High” violation. In this last
case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation. (ii) R5: Similar changes as in R4 should
also apply to High and Severe in R5.
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
No
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are
graded according to the number of impacted RCs that need to be notified. For example, Low for missing one, Moderate
for missing two, High for missing three, Severe for missing four or more. (ii) We do not have any issue with the binary
nature of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on
the SDT’s response to our comments under Q11.
NPCC appreciates the work of the Drafting Team. No additional comments.
Individual
Brent Hebert
Calpine Corporation
Yes
Yes
Yes
Yes
Calpine supports three part communications when verbal directives are issued during real-time operational emergency
conditions. Calpine believes all issued directives should be explicitly identified as such.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Brandy A. Dunn
Western Area Power Administration
Yes
R4 should say "Generator Operator" rather than "Generation Operator"
Yes
M4 should say "Generator Operator" rather than "Generation Operator"
Yes
Yes
This is a very good improvement. Some Regional Entities were interpreting every communication from a control room
as a ‘directive’ and stating that ‘directives’ were equal to any ‘normal instruction’ that related to operations of the power
system. Making it clear that the directives are associated with emergency conditions is a big improvement. The drafting
team may wish to consider additional clarification, such as, “The entity that issues a verbal directive shall make it
known during the communication that, ‘This is a directive…’ ”. All parties to the communication would be clear that the
real-time situation was an emergency condition, and that the requirements for repeating the intent were in effect.
Yes
Yes
Yes
Yes
Suggest changing the word "complying" to "compliance" in the purpose statement.
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Group
Southern Company
Hugh Francis
Southern Company Services, Inc.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
IRO-001-1 Requirement 3 states that, “The Reliability Coordinator shall have clear decision-making authority to act and
to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing- Selling Entities within its Reliability Coordinator Area to
preserve the integrity and and reliability of the Bulk Electric System.” This does not give one RC the authority to direct
another RC. Requirement 7 and 8 would allow one RC to give a directive to another RC if they disagree. This would
allow an RC with bad information to require another RC to carry out a mitigation plan that could degrade system
reliability. For example, RC1 identifies a possible SOL violation in RC2’s reliability area due to RC1’s generation
pattern. RC1 and RC2 can’t agree that there is a problem. In order to mitigate the SOL a mitigation plan is developed
by RC1 that requires RC2 to redispatch generation and reconfigure transmission in RC2’s area so that the generation
and transmission in RC1’s area won't have to be redispatched or reconfigured. Suggested rewording of R7 and R8 R7.
When Reliability Coordinators can not agree that a problem exists a mitigation plan will be developed by each
Reliability Coordinator that will restore system reliability in their respective reliability areas. [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations] R8. Each impacted
Reliability Coordinator shall implement the mitigation plan developed to relieve the identified Adverse Reliability Impact
in their reliability area when the impacted Reliability Coordinators can not agree that a problem exists. [Violation Risk
Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Yes
No
Reliability problems identified in other reliability areas are based on modeling information obtained from another
reliability region. The fact that one RC will not agree that the model of an adjacent RC's reliability area may be more
accurate than their model of the adjacent reliability area is no reason to impose a severe violation on the RC with the
more accurate model of their own reliability region. Example: RC1 identifies a contingency overload of a transformer
bank in an adjacent reliability area. The transformer bank was replaced the week before with a larger bank. When RC1
contacts RC2, RC2 explains that the bank overload is not valid because of the replacement. RC2 does not identify a
problem due to the fact that the model RC2 is using has been updated with the new transformer bank. RC1 will not
agree and requires RC2 to open a tie line with another reliability area to relieve the contingency overload. If RC2 does
not follow the instructions of RC1, making the interconnection weaker to relieve a problem that does not exists, RC2 is
out of compliance and a severe violation will be imposed.
Individual
Rao Somayajula
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ReliabilityFirst Corporation
No
FERC 693 excludes distribution providers if they are not a user, owner or operator of BES. This should be reflected in
R4 of the standard
No
No measures are posted for R4 of the revised standard
Yes
No
FERC 693 excludes distribution providers if they are not a user, owner or operator of BES. This should be reflected in
R2 of the standard
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Individual
James H. Sorrels, Jr.
American Electric Power
Yes
AEP does generally agree with the revisions, but the use of the term “interpersonal communication capabilities” needs
a NERC-approved definition. Otherwise, what is in scope? Are e-mail or text messages acceptable, and, if so, what
type of guaranteed delivery is necessary?
Yes
Yes
Yes
AEP does generally agree with the revisions, but we have concerns with the much wider scope of three part
communications that expand the required voice or transcript evidence. There is no rational provided for changing the
text in R1 and M1, and adding a the new R2 and M2. We would recommend that these items remain as stated in
Version 2.
Yes
As described in the question 4 response, there is no rational provided for changing the text in R1 and M1, and adding a
the new R2 and M2. We would recommend that these items remain as stated in Version 2.
No
AEP is concerned that the severe VSL assigned to Requirement 2 is excessive and should be reconsidered.
Yes
Yes
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Yes
Yes
Not applicable.
Not applicable.
Not applicable.
Group
SERC OC Standards Review Group
Jim Case
Entergy
No
The STD should clarify what types of communications are considered in the standard – is it voice or data
communications or both?
Yes
Yes
No
The term “emergency” has a broad definition and other standards use “adverse conditions” or “adverse reliability
impact”. There should be a consistency of terms when describing a system condition. The STD should include a
definition of “directive” that includes more than “Emergency’ operational conditions. Should this requirement be
modified to include the term “Reliability Directive” and the definition of this term added to the NERC Glossary?
Yes
Yes
If R1 changes as suggested in Question 4, the VSLs will need to be changed also.
No
What is the difference between “Adverse Reliability Impacts” and the definition of an IROL? Is this going to replace an
IROL?
No
If R2 of IRO-001-1 is retired, what process is in place to ensure that reliability plans are kept up to date and are
reviewed to approve footprint changes?
No
The measures should indicate how long records should be kept to verify compliance with the requirements.
Yes
No
Does the STD intend to give a Reliability Coordinator the authority to direct reliability outside their reliability area? This
appears to be in conflict with IRO-001.
Yes
Yes
“The comments expressed herein represent a consensus of the views of the above named members of the SERC OC
Standards Review group only and should not be construed as the position of SERC Reliability Corporation, its board or
its officers.”
Group
Bonneville Power Administration
Denise Koehn
BPA Transmission Reliability Program
Yes
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No
Issue #1: Measure M3 The measure states that entities “shall have and provide” evidence that “personnel used English
as the language for all” communications. This infers that all communications must be documented in some form or
fashion and that any outage of the normal communication system must be met with alternative processes which will
meet this measure, even if the alternative is the preparation of handwritten notes of each person’s conversations,
noting that the communications occurred in English. Unfortunately, there have been times where our Dictaphone
stopped recording phone calls, and nobody knew it for days! This measure sets us up for a violation! It’s just a matter of
time.
Yes
Yes
Yes
No
Comments: Issue #1: Violation Severity Level The Moderate and Severe VSLs for Requirement R1 can lead to
confusion. For instance, the Moderate VSL states that the responsible entity ‘did not acknowledge the recipient was
correct in the repeated directive OR (emphasis theirs) failed to repeat the intent of the original statement to resolve any
misunderstandings.’ What is it saying here? Is it dinging the responsible entity for making no response at all to the
recipient after they repeated the intent of the message? Or is that what the Severe VSL is dinging for when it includes
an AND rather than an OR in the statement? I can’t tell what the drafting team was intending with their statements, but
one of the statements seem to infer that the responsible entity can actually be dinged for not doing both,
acknowledging the recipient as being correct in their response and at the very same time repeating the intent of the
original statement to resolve any misunderstandings because the recipient was incorrect in their response. This then
argues that the recipient can be both correct and incorrect at the same time. I didn’t think that was possible…similar to
binary code…either you get a one or a zero, but not both and never neither! I would argue that the drafting team should
rewrite their VSLs to succinctly state that the responsible entity failed to respond after the recipient repeated the intent
of the message. With that in mind, either the Moderate or the Severe VSL will be rewritten in an understandable way
and the other VSL will disappear in the realms of impossible things.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Issue #2: Data Retention Why would the Distribution Provider and Generator Operator be required to store historical
data (three years in the case of Requirement R1 and Measure M1; twelve months in the case of Requirement R2 and
Measure M2) to show that these requirements and measures have been successfully implemented when these two
entities (Distribution Provider and Generator Operator) aren’t even included either in Requirements R1 and R2 or in
Measure M1 and M2? It would appear that they should only have to provide historical data for three months as required
by the data retention time for Requirement 3 and Measure 3. Issue #1: Data Retention The first bullet in this section
states that all entities are responsible for retaining documents associated with all Requirements and Measures
associated with this standard. In reality, Requirements R1, R4, R5 and R6 and the corresponding Measures are the
responsibility of the Reliability Coordinator. Requirements R2 and R3 and their corresponding Measures are
implemented by the Transmission Operator, Balancing Authority, Generator Operator, Distribution Provider,
Transmission Service Provider, Purchasing-Selling Entity and the Load Serving Entity. The Data Retention section
should be rewritten to reflect this so that entities are not required to maintain documents that they aren’t suppose to
even possess in some cases.
Individual
Brent ingebrigtson
E.ON U.S.
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No
E.ON U.S. suggests deleting “interpersonal” from the term “interpersonal communications capabilities”. The need for
and meaning of the term “interpersonal” isn’t clear. Does it infer communications must be to/from a specific individual
rather then to/from another reliability entity? Verbal vs electronic communications? All non-data communications? E.ON
U.S. believes that the term “interpersonal" must be clarified if it is to remain in the standard. In the proposed R1 – how
extensive must the quarterly testing be – establish contact or verify all functions? Does the term “alternative” include
the "normal" communication medium or only the “backup” mediums? Does the alternative imply ALL possible
communication alternatives? E.ON U.S. suggests replacing the term “alternative” wtth “planned backup” or similar.
Quarterly testing needs to be limited to only established/planned backup communication methods not any potential
"alternative" communication method.
No
E.ON U.S. believes that he M1 must be clarified to address whether the testing entity is responsible to develop and
implement a mitigation plan when a test is unsuccessful due to an issue at the other end (i.e. non-testing entity).
No
E.ON U.S. suggests that R1 be modified to include the language that when an RC, BA and/or TOP issue a directive it
must state: ”This is a directive” and the entity receiving the directive must state: "I understand this is a directive”. E.ON
U.S. also requests that language be added to the requirement that states that this communication protocol is only for
reliability related directives and not for other operational directives.
No
E.ON U.S. suggests that the VSL for R4 should be binary with the Severe VSL for failing to notify all entities as per R4.
Partially meeting R4 in not consistent with the language in R4. E.ON U.S. also suggests that the VSL for R5 should be
binary with the Severe VSL for failing to notify all entities as per R5. Partially meeting R5 is not consistent with the
language in R5 but the reliability impact of partially meeting R5 is low.
COM-001-2 R1 and R2 and the associated M1 and M2 are only applicable to the RC, TOP and BA but the “Data
Retention” for R1/R2 and M1/M2 require the DP and GOP to retain data for the Requirements and Measures. E.ON
U.S. suggests that the requirement for data retention of the DP and GOP be eliminated from the standard.
Individual
Kasia Mihalchuk
Manitoba Hydro
No
do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the
quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary as it would
delay repairing the interpersonal communication capability. R2 assumed that the 30 minutes or longer in parenthesis is
intended to describe the length of the outage. We think this would be clearer if the requirement were revised to: “Each
Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes
of the detection of a failure of its normal interpersonal communications capabilities lasting longer than 30 minutes.” R3
is not necessary as it would be impossible to meet many other requirements if a common language such as English
was not used. This requirement results in the waste of compliance resources managing and auditing documentation
associated with it.
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in
question 1.
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
In addition, since R2 has a time component in the requirement four VSLs could be written based on the timeliness of
the notification.
Yes
For the most part agree with the changes to the requirements and believe it goes a long way towards resolving the
issue NERC has created recently with interpreting operating instructions as directives. This makes it clear that only
directives that are required for operating emergencies require three way communication. The SDT could further support
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resolution to this directive issue by developing a definition for directive. In requirement 1, I would use another word than
“require”. Consider using “request”. An RC, BA, and TOP can’t force the recipient of the directive to repeat it back.
They can ask or request it be repeated back though.
Yes
For the most part agree with the measures with the exception that a conforming change needs to be made to M1 if the
suggestion regarding “require” in Q4 is accepted.
No
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally,
believe the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In
most cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent
of Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the directive was correct and the
repeat was correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not acknowledge the
repeat of the directive was correct but the repeat was incorrect. We agree that these distinctions make sense but offer
the following changes to clarify the intent. Moderate VSL: The responsible entity issued a verbal directive associated
with real-time operating emergency conditions and the recipient repeated the intent of the directive correctly, but the
responsible entity did not acknowledge the recipient was correct. Severe VSL: The responsible entity issued a verbal
directive associated with real-time operating emergency conditions and the recipient repeated the intent of the directive
incorrectly, but the responsible entity failed to repeat the intent of the original statement to resolve any
misunderstandings.
Yes
No
R5 does not make sense as it doesn’t create an adverse reliability impact should the RC fail to notify impacted entities.
No
Measure for R5 would need to be struck should R5 be struck as per question 8.
No
Believe two VSLs are possible for R1 based on whether the RC is acting or directing actions to prevent versus mitigate.
Failure to mitigate should be Severe. Failure to prevent should be High because if the RC fails to act or direct action to
prevent, the Adverse Reliability Impact may still not happen if system conditions change. For the Moderate VSL of R2,
please remove the clause “but not all”. It is not necessary.
No
Requirements R2 and R8 need additional work. R2 appropriately requires the RC experiencing the Adverse Reliability
Impact to distribute its Operating Procedure, Process or Plan to other RCs required to take action. However, it
inappropriately places the burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to
agree. Rather R2 should remove the bullet to require agreement from the impacted RC and a new requirement should
be written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement or
disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable actions
should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This contributes to
reliability by forcing the impacted RC to take action if the action is reasonable. Further, the drafting team needs to
clarify that R2 also applies to the mitigation plan in R7. Because R7 requires the RC experiencing the Adverse
Reliability Impact to develop the mitigation plan, the mitigation plan may not be agreed to by the impacted RC. The
impacted RC may have a perfectly valid reliability, statutory, legal, or regulatory reason for not agreeing to the
mitigation plan. R8 still obligates the RC to implement the mitigation plan developed in R7 though it may be contrary to
reliability. R8 needs to allow the RC to refuse to implement the mitigation plan if the impacted RC has a reliability,
statutory, legal or regulatory reason. Further the drafting team should consider if the impacted RC could refuse
because the RC experiencing the Adverse Reliability Impact has not implemented comparable measures in their own
area. R8 as written could allow an RC to simply pass cost on to the neighboring RC in the name of reliability. For
example, the RC may not want to order a unit to be committed to avoid certain startup costs but they ask the
neighboring RC to start up a unit in their footprint.
No
Conforming changes to the Measurements will be required for accepted changes from question 11.
No
Believe that four VSLs could be written for R4 based on the number of conference calls that are participated in. Four
VSLs should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is redundant
with the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any.
Individual
Troy Willis
Georgia Transmission Corporation
No
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Per the NERC Reliability Standards Development Procedure, under the definition of a Reliability Standard; “The
obligations or requirements must be material to reliability and measurable.” With regards to R3. - It goes without saying
that inter-entity BES reliability communications must be in a common language between the entities for understanding
operation instructions. From an audit/measurability standpoint, the evidence to the requirement would not converge to
a finite amount of material. The amount of evidence required to demonstrate compliance of this requirement would be a
huge administrative burden. It seems this concept (for use of the English language) could be captured under the “Entity
Tasks and Interrelationships” section of the NERC Reliability Functional Model which defines the set of functions that
must be performed to ensure the reliability of the bulk electric system. It also explains the relationship between and
among the entities responsible for performing the tasks within each function. Additionally, this concept (for use of the
English language) could further be explained under each applicable registration type (BA, GOP, TSP, LSE, PSE, and
DP) in the NERC Reliability Functional Model. The Second option for R3 is to remove the Requirement from the
continent wide Standards and have the effected entities/regions create a “Regional Standard” where entities involved in
inter-entity BES reliability communications have a history of language barrier concerns. As a separate issue to R3, it
also seems conflicting that a written requirement would provide the option of “Unless agreed to otherwise”. This option
described in the language of the requirement implies that it is not a requirement but an option which further supports
the suggestions above.
No
See comments to Question 1 in regards to measurability.
No
Again, Requirement 3 seems to be an option.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
N/A
N/A
N/A
Individual
Bob Thomas
Illinois Municipal Electric Agency
No
The IMEA supports comments submitted by the MISO Standards Collaboration Group indicating R3 is not necessary.
Similarly, IMEA questions the necessity of R4. Therefore, we question the need to expand the applicability of COM-001
to DP, LSE, and PSE since R3 and R4 are the only two Requirements applicable to those functions.
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in
Quesion 1.
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in Quesion 1.
No
IMEA questions the necessity of expanding the applicability of COM-002 as proposed in R2, particularly to the DP,
LSE, and PSE functions. IMEA recommends accomplishing the intent of COM-002-3 R2 by simply refering to COM002-3 R1 in IRO-001-2 R2 which requires those entities to comply with the RC directive. Thus it would be understood
that the functional entity had repeated the directive in order to comply with it; thereby avoiding the necessity of
expanding applicability to another reliability standard.
Conforming changes are required to the Measures based on the suggested modifications to the requirements in
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Question 4.
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in Question 4.
Yes
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group. In addition, while we agree with
the proposed revisions to IRO-001-2 R2, IMEA recommends (as indicated in our comments to Question 4) that a
reference be made to COM-002-3 R1 in IRO-001-2 R2. By including this reference, it is understood the applicable
entities successfully repeated the directive in order to comply with the directive.
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group.
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group.
In order to minimize the number of reliability standards and the details covered in requirements - particularly those
dealing with communications - it is recommended that an up-front provision/requirement be included as part of the
compliance registration process that certain functional entities (e.g., DP, LSE, PSE, etc.) shall be responsible for
providing the necessary information to transact services and for complying with the directives/requests of certain
functional authorities (e.g., BA, PC, RC, etc.) in order to maintain/enhance reliability of the BES.
Individual
Chris Scanlon
Exelon
No
Agree with the revisions with the following exception/recommendation: COM-001: purpose is to address
communication facilities / capabilities (technical/hardware). COM-002: purpose is to address effectiveness (protocols).
COM-001: R.1-3 address telecommunication facility requirements. R4 requires English use. Recommend the drafting
team move COM-001 R4 (use English) to COM-002 where effectiveness of communications (protocols) between
entities is addressed.
No
See answer to #1
No
See answer # 1
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
Yes
We agree with many of the changes made to the standard including the change of title to reflect communications (voice
and text messages). The parenthesis around 30 minutes or longer should be removed as parenthesis by definition
mean a word, phrase, or sentence inserted in a passage to explain or modify the thought. This phrase is more than an
explanation of the term failure. It sets forth a time requirement that is an integral part of R1. We suggest rewording the
requirement as "Each RC, TOP, and BA shall notify impacted entities within 60 minutes of a failure of its normal
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interpersonal communications capabilities that lasts 30 minutes or longer."
Yes
However, it is not clear whether to show compliance the voice recordings and associated transcripts are of the test
done or of the conversations across those facilities.
Yes
Yes
1. We agree with the clarification in R1 that a directive per COM-002-3 is a "verbal directive associated with real-time
operational emergency conditions". We understand this to be a "Reliability" directive used during times of emergency or
in situations where reliability may be an issue. Also, with this clarification, it confirms that the term "directive", as used
in this standard, does not include "Operational" directives issued by System Operators during normal system conditions
to change the status of an element such as a circuit breaker. 2. The industry does not appear to have a clear,
consistent definition of what constitutes a directive. We suggest the standard require the person issuing a directive to
use the phrase "I am directing you to …", "I am ordering you to …" or something similar to invoke the three part
communication requirement. 3. Since this standard deals with communications and coordination during emergency
conditions, it may be helpful to change the title of the standard to "Communications and Coordination – Emergency
Conditions". 4. The phrase "the intent of the directive" could be difficult to comply with and measure. The words "the
intent of" should be removed from Requirements R1 and R2.
Yes
Yes
Yes
If the term "cascading" used in the definition is referring to the NERC-defined term, it should be capitalized.
No
Regarding the retirement of IRO-001-1 R7 – We are not convinced that this requirement is redundant with IRO-014-1
R1. The existing requirement requires the RC to "have clear, comprehensive coordination agreements with adjacent
RCs to ensure that SOL or IROL violation mitigation requiring actions in adjacent RC areas are coordinated". IRO-0141 R1 requires agreements for coordination of actions between RCs to support Interconnection reliability, but it does not
specifically require "clear" and "comprehensive" agreements to mitigate SOL or IROL violations. For IRO-001-1 R7 to
be properly retired, the "mitigation of SOL and IROL violations" should be explicitly stated in IRO-014-2 R1 as one of
the items to be addressed in the RC's Operating Procedure, Process, or Plan.
Yes
Yes
No
See our comments from Questions 8. If IRO-001 R7 is retired and deemed covered by IRO-014 R1, then IRO-014 R1
should include the "mitigation of SOL and IROL violations" as one of the items to be addressed in the RC's Operating
Procedure, Process, or Plan.
Yes
Yes
Individual
Roger Champagne
Hydro-Québec TransÉnergie (HQT)
No
Interpersonal communication includes more than voice, such as instant messaging, text messaging and email. This
Standard needs a definition of interpersonal communication. Having alternative interpersonal communications should
be specified as a requirement since there is actually no requirement to have that alternative way of communication in
the first place. Work communication within Québec must be in French according to the law. It is understood and agreed
that communication outside Québec with adjacent entities would be, and is in fact already, in English. Accordingly, R3
should be modify as the proposition below: R3. Unless determined by law or otherwise agreed to, …
No
Comments: See our comment for R3 in Q1. Accordingly, M3 should be modify to read as the proposition below: M3. …
that will be used to determine that personnel used English «or another language determine otherwise» as the language
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for all inter-entity Bulk Electric System reliability communications between and among operating personnel responsible
for the real-time generation control and operation of the interconnected Bulk Electric System. If a language other than
English is used, upon request, evidence shall be provided to explain the use of the alternate language. (R3.) M3 allows
a language other than English. Must the agreement for non-English be in place in advance of the call?
No
see M3 comment for question 2
No
Support the intent but not the existing language. Do not support Requirements that include some examples since the
examples can be confused with the Requirement. Do not support one written Requirement that has two requirements.
Recommend the following Requirements A new R1 - Each Entity shall have Operational Procedure requiring that
communications directives be repeated back to the issuer R2 – leave as is A new R3 – If not repeated, then issuer
shall request the receiving Entity to repeat the communication directive A new R4 – The issuer will acknowledge the
correctness of the repetition of the communications directive
No
Address the new proposed Requirements above in Question 4.
No
address the new proposed Requirements.
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive issued Dec. 27,
2007.
No
Add “an issued” to the wording as shown following: Each Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity
shall inform its Reliability Coordinator upon recognition of its inability to perform «an issued» directive.
Yes
No
(i) R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to issue
an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High VSL to:
“…failed to issue an alert to three, but not all, impacted….” and the Severe VSL to: “…failed to issue an alert to any or
more than three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. Some
examples may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were alerted, this would be a
“Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be a “High” violation. In this last
case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation. (ii) R5: Similar changes as in R4 should
also apply to High and Severe in R5.
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
No
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are
graded according to the number of impacted RCs that need to be notified. For example, Low for missing one, Moderate
for missing two, High for missing three, Severe for missing four or more. (ii) We do not have any issue with the binary
nature of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on
the SDT’s response to our comments under Q11.
Individual
Scott Berry
Indiana Municipal Power Agency
No
The requirements do not consider a pre-recorded communication that might be sent out from the Transmission
Operator to Generator Operators or any other entity. If this communication is a directive associated with a real-time
opeational emergency condition (depending on the judgement used by an entity or auditor), it does not make sense to
repeat back a pre-recorded message on the phone. It might be good to clearly state in the standard that pre-recorded
messages do not need to be repeated back.
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Individual
Greg Rowland
Duke Energy
No
R1 requires an entity to “develop a mitigation plan” if a test of alternative communications capabilities is unsuccessful.
We believe that this phrase should be changed to “take action”, reflecting that an entity’s response to an unsuccessful
test may be to simply call or email a repair order. The phrase “develop a mitigation plan” implies that an entity must
establish a backup to the alternative communications capabilities rather than just restore the alternative
communications capabilities.
No
Replace the phrase “develop a mitigation plan” with the phrase “take action” per our comment on Requirement R1
above. Also, the DP and GOP should be deleted from the Data Retention section requirements for R1/M1 and R2/M2.
Need to add a Data Retention requirement for R4/M4 for the DP and GOP.
No
Replace the phrase “develop a mitigation plan” with the phrase “take action to restore the capabilities” per our comment
on Requirement R1 above.
No
We agree with adding the clarification that these requirements refer to “emergency” communications, but we think the
word “Emergency” should be capitalized to further clarify that it is a defined term in the NERC Glossary. Also, the
phrase “require the recipient of the verbal directive to repeat the intent of the directive back” should be changed to
“have the recipient of the verbal directive repeat the intent of the directive back”. This avoids making the issuer of the
directive make a statement requiring a repeat back unless the recipient actually fails to repeat back as normally
expected.
No
Change “emergency” to “Emergency” per comment on R1 above. Also change the phrase “required the recipient of the
verbal directive to repeat” to “had the recipient of the verbal directive repeat” per our comment on R1 above.
No
Change “emergency” to “Emergency” in the VSLs per our comment on R1 above. Also, we don’t see a tangible
difference between the Moderate and Severe VSLs, and the High VSL should really be the Severe VSL. We suggest
having just a High and a Severe VSL as follows: • High VSL: “The responsible entity issued a verbal directive
associated with real-time operating Emergency conditions and had the recipient repeat back the intent of the directive,
but did not either acknowledge the recipient was correct in the repeated directive or failed to repeat the intent of the
original statement to resolve any misunderstandings.” • Severe VSL: “The responsible entity issued a verbal directive
associated with real-time operating Emergency conditions, but did not have the recipient repeat back the intent of the
directive.”
Yes
Yes
Yes
Yes
No
• R1 introduces the concept of “impacted Reliability Coordinators” which is unclear. Revise R1 as follows: R1. For
conditions or activities that may impact other Reliability Coordinator Areas, each Reliability Coordinator shall have
Operating Procedures, Processes, or Plans for notification, exchange of information or coordination of actions with
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those impacted Reliability Coordinators to support Interconnection reliability. These Operating Procedures, Processes,
or Plans shall collectively address the following: • R2 Time Horizon should not include Long-term Planning. • R3 is
unclear. Revise R3 as follows: R3. For conditions or activities that may impact other Reliability Coordinator Areas, each
Reliability Coordinator shall make notifications and exchange reliability-related information with those impacted
Reliability Coordinators using its predefined Operating Procedures, Processes, or Plans, or other available means to
accomplish the notifications and exchange of reliability-related information. • R4 could be interpreted to require a
weekly conference call even if there is no need for a call. Revise R4 as follows: R4. When there are conditions or
activities that may impact other Reliability Coordinator areas, each Reliability coordinator shall participate in agreed
upon conference calls, at least weekly, and other communication forums with those impacted Reliability Coordinators. •
R5 – Insert the word “all” before impacted Reliability Coordinators for clarity. • R6, R7 and R8 are interrelated and
unclear. Combine these three requirements into one clear requirement as follows: R6. When the identified Adverse
Reliability Impact cannot be agreed to by the impacted Reliability Coordinators, the Reliability Coordinator with the
identified Adverse Reliability Impact shall develop a mitigation plan and each impacted Reliability Coordinator shall
implement the plan.
No
Need to revise the Measures to coincide with the recommended changes to the requirements in #11 above. Also under
Data Retention, 12 months of evidence is needed for R3, R4 and M3, M4. However 3 years plus the current year is
required for R5 through R8 and M5 through M8. We see no reason the data requirements to be different and believe 12
months is the proper amount of data retention.
No
Need to revise the VSLs to coincide with recommended changes to the requirements in #11 above.
Individual
Jianmei Chai
Consumers Energy Company
No
COM-002 R2 specifies the Generator Operator that receives a directive from the Transmission Operator, Reliability
Coordinator or Balancing Authority must repeat the intent of the directive back to the Transmission Operator. COM-002
M2 specifies that evidence must be retained in the form of either voice recordings or transcripts by the generator
operator. Since the Transmission Operator, Reliability Coordinator and Balancing Authority already have voice
recording capability (centrally located), it is not necessary for the Generator to also install voice recording capability at
each generating station. We suggest the wording of COM-002 be changed such that only the Transmission Operator,
Reliability Coordinator and Balancing Authority be required to keep voice recordings or transcripts.
Group
IRC Standards Review Committee
Ben Li
IESO
No
(1) We do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the
quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary and will
only delay repairing the interpersonal communication capability as it would have to be completed first before fixing the
system. If repairing the system would be a lengthy process, then a mitigation plan may be developed to document that
the entity is in process to fix the system. There is no associated requirement to have an alternate interpersonal
communication capability along with R1 to test it. Thus, if a responsible entity did not have an alternate interpersonal
communication capability, R1, in essence, does not apply. We suggest adding a requirement to have an alternate
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interpersonal communication capability to address this gap. Alternatively, the requirement to have an alternate
interpersonal communication capability along with requirements to test and fix it could be stipulated in the Organization
Certification Requirements. (2) In R2, we assume that the 30 minutes or longer in parenthesis is intended to describe
the length of the outage. We think this would be clearer if the requirement were revised to: “Each Reliability
Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the
detection of a failure of its normal interpersonal communications capabilities lasting longer than 30 minutes.” (3) R3 is
not necessary. This requirement results in the waste of compliance resources managing and auditing documentation
associated with it with no measurable improvement to reliability.
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in
question 1.
No
(1) Conforming changes are required to the VSLs based on the suggested modifications to the requirements in
question 1. (2) FERC expressed its desire in the June 2008 order on VSLs to have as many VSLs as possible. We
suggest since R2 also has a time component in the requirement four VSLs could be written based on the timeliness of
the notification as well as the number of impacted entities that were not notified. The VSLs should reflect both
components.
Yes
(1) We largely agree with the changes to the requirements and believe it goes a long way towards resolving the issue
NERC has created recently with interpreting operating instructions as Reliability Directives. This makes it clear that only
Reliability Directives that are required for operating emergencies require three way communication. We believe that the
SDT could further support resolution to this Reliability Directive issue by developing a definition for Reliability Directive.
We propose the following definition: Reliability Directive – A verbal communication by a Reliability Coordinator,
Transmission Operator, or Balancing Authority that requires action by the recipient to prevent or mitigate an Adverse
Reliability Impact. Please note that AESO already has this term defined. The above suggested definition may be
different from the AESO’s definition. (2) In requirement 1, we do believe that another word than “require” should be
used. Consider using “request”. An RC, BA, and TOP can’t force the recipient of the Reliability Directive to repeat it
back. They can ask or request it be repeated back though.
Yes
We largely agree with the measures with the exception that a conforming change needs to be made to M1 if the
suggestion regarding “require” in Q4 is accepted.
No
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, we
believe the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In
most cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent
of Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the Reliability Directive was
correct and the repeat was correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not
acknowledge the repeat of the Reliability Directive was correct but the repeat was incorrect. We agree that these
distinctions make sense but offer the following changes to clarify the intent. Moderate VSL: The responsible entity
issued a verbal Reliability Directive associated with real-time operating emergency conditions and the recipient
repeated the intent of the Reliability Directive correctly, but the responsible entity did not acknowledge the recipient was
correct. Severe VSL: The responsible entity issued a verbal Reliability Directive associated with real-time operating
emergency conditions and the recipient repeated the intent of the Reliability Directive incorrectly, but the responsible
entity failed to repeat the intent of the original statement to resolve any misunderstandings.
Yes
The drafting team should consider that NERC is moving away from using the term "cascading outages". FERC has
directed NERC to rescind this definition, and use the defined term "cascading" instead.
Yes
No
(1) R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating Procedure,
Process or Plan to other RCs required to take action. However, placing the burden on the same RC to obtain the
agreement of impacted RCs may not be appropriate since the RC experiencing the Adverse Reliability Impact may not
be able to force impacted RC to concur. We suggest the SDT to consider: a. Remove the bullet to require agreement
from the impacted RC; b. Add a new requirement that the impacted RC shall acknowledge the Operating Procedure,
Process or Plan with agreement or disagreement. In the event of disagreement, a reliability or legal reason or failure to
implement comparable actions should be given. (2) We realize that R7 implies that the RC experiencing the Adverse
Reliability Impact has come up with an alternative plan when its initial plan was not agreed to, but the alternative may
still be disagreed by the impacted RC. Simply implementing the alternative plan, as stipulated in R8, could expose the
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impacted RC to operate in an unreliable or unsafe domain. We therefore request the SDT to assess if any
requirements need to be introduced to resolve this difference with due regard to reliability concerns in both RC areas
when agreement cannot be reached even on the alternative plan.
No
Conforming changes to the Measurements will be required if changes as suggested in Question 11 are introduced.
No
(1) In the Commission’s June 2008 order on VSLs, they expressed their preference for having as many VSLs as
possible. We believe that four VSLs could be written for R4 based on the number of conference calls that are
participated in. We also believe this would be consistent with the Commission’s guideline 4 because the requirement is
written in the plural, that is conference calls, so all conference calls must be considered in aggregate. Thus, failure to
participate in more than one conference call does not represent distinct violations but a single violation. (2) Four VSLs
should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is redundant with
the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any. Note: CAISO abstains
from these comments.
AESO abstains from commenting on VSLs. VSLs for Alberta will be developed by provincial authorities.
Individual
Michael R. Lombardi
Northeast Utilities
No
It is understood that the use of the term "interpersonal communications" and "interpersonal communications
capabilities" were selected by the RC SDT to better reflect the intent of the Standard. However, NU reviewers are
concerned over the new terminology and believe that it is unclear and not universally accepted to mean the same thing
to all parties. NU's belief is that the original use of the terms "telecommunications" and "telecommunications facilities"
are clearer and universally understood. NU recommends that the original terms be re-instated or the term
"interpersonal communications" be replaced to reflect the intent of the Standard is to ensure "voice and text equipment"
is adequate for communicating real-time operating information. R1 – the requirement has evolved to test alternative
equipment, versus a requirement to have primary and alternative equipment. Standard should require entities to have
the equipment such as in the -1 version. R2 is to notify impacted entities in the event of a loss of normal
communications. With backup communications operating correctly do we assume there is no impact and therefore
notification is not required? This is unclear from a compliance perspective and unnecessary if backup communications
are available. Alternative communications often go several layers deep including cell phones, satellite phones, radio,
etc.
Yes
Yes
Yes
No
NU agrees with expanding the applicability of the Standard beyond the Reliability Coordinators, Balancing Authorities
and Transmission Operators to ensure that the recipient of a verbal directive repeats back the directive to the issuer
(R2). Despite NU's agreement with R2, NU believes that M2 is duplicative to the intent of M1 and unnecessarily
requires the installation of voice recording capabilities at the entities other than a RC, BA or TOP. It is our belief that the
voice recordings of the RC, BA and TOP (M1) provide the evidentiary support required by all applicable entities.
Yes
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive issued Dec. 27,
2007.
No
The intent of R3 is not clear - i.e., "… shall inform its Reliability Coordinator upon recognition of its inability to perform a
directive". Does this requirement pre-suppose a directive has been given? Suggest adding clarifying language that
indicates that the requirement is applicable subsequent to a directive being received. It is our belief that the wording of
Measure M3 supports the suggested changes to R3.
Yes
No
(i) R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to issue
an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High VSL to:
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“…failed to issue an alert to three, but not all, impacted….” and the Severe VSL to: “…failed to issue an alert to any or
more than three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. Some
examples may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were alerted, this would be a
“Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be a “High” violation. In this last
case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation. (ii) R5: Similar changes as in R4 should
also apply to High and Severe in R5.
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
No
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are
graded according to the number of impacted RCs that need to be notified. For example, Low for missing one, Moderate
for missing two, High for missing three, Severe for missing four or more. (ii) We do not have any issue with the binary
nature of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on
the SDT’s response to our comments under Q11.
Northeast Utilities appreciates the work of the Drafting Team. No additional comments.
Individual
Dan Rochester
Independent Electricity System Operator
No
We suggest the SDT review the applicability to Transmission Service Providers, Load-Serving Entities and Purchasing
Entities from a real time operating perspective. We do not believe they are active participants in real time operation for
which they require to have the same communication capability as the RCs, TOPs, BAs and DPs. Interpersonal
communication includes more than voice, such as instant messaging, text messaging and email. This Standard needs
a definition of interpersonal communication. Having alternative interpersonal communications should also be specified
as a requirement. Work communication within Québec must be in French according to the law. It is understood and
agreed that communication outside Québec with adjacent entities would be, and already is, in English. Accordingly, R3
should be modified as proposed below: R3. Unless dictated by law or otherwise agreed to, … R4: We believe
“Interconnection” should be replaced by “interconnection” since the former is not a defined term.
No
M3 and M4 may need to be revised depending on the response to our comments under Q1, above.
No
The VSLs for R3 may have to be changed based on the outcome of our comments in Q2 regarding the language of
communication.
No
(i) We suggest the word “emergency” be capitalized since it is a defined term which generally covers the conditions
under which directives are issued. (ii) We further suggest that to avoid confusion between operating instructions and
directives, the term directive should be defined as suggested below: Directive or Reliability Directive – A verbal
communication by a Reliability Coordinator, Transmission Operator, or Balancing Authority that requires complying
action by the recipient to prevent or mitigate an Adverse Reliability Impact. (iii) Since R1 contains two requirements,
there may be some benefit in separating these since that would make the VSLs clearer, i.e. separate the requirements
placed on the issuer of the directive to (a) request the recipient to repeat the intent of the directive and (b) to
acknowledge the response of the recipient as correct.
No
Comments: Some changes may be necessary based on the SDT’s response to our suggestion in Q4.
No
The sequence of communication required under R1 is intended to ensure that directives from the issuing entities are
clearly understood. The earlier this sequence is broken, the greater the uncertainty that this goal is achieved and the
greater should be the severity level. Thus, failure to request that the recipient entity repeat the intent of the directive –
the earliest step in the sequence - should attract the “Severe” VSL. Also, failing to repeat the original directive when
there is any misunderstanding, again, in our view, leaves the intent of the directive equally unclear and should also
attract a “Severe” VSL. Failing to acknowledge the recipient was correct in the repeating the intent of the directive – the
last step in the sequence – is already assigned a “Moderate” VSL and this should not be repeated in the “Severe” VSL.
We therefore suggest that the two conditions under “High” and “Severe” in R1 be combined as one under “Severe” as
follows: The responsible entity issued a verbal directive associated with real-time operating emergency conditions but
did not require the recipient to repeat the intent of the directive; OR The responsible entity issued a verbal directive
associated with real-time operating emergency conditions and required the recipient to repeat the intent of the directive,
but failed to repeat the intent of the original statement to resolve any misunderstandings.
No
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Comments: Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive
issued Dec. 27, 2007.
No
Comments: Change “…inability to perform a directive.” to “…inability to perform an issued directive.”
Yes
No
(i) R1: For clarity, we suggest changing “it” to “that”. R4: Since failing to issue an alert to 3 entities already attracts a
“High” VSL, not doing so for ANY (i.e. failing to issue an alert to all entities) or more than three should attract a “Severe”
VSL. We suggest to change the High VSL to: “…failed to issue an alert to three, but not all, impacted….” and the
Severe VSL to: “…failed to issue an alert to any or more than three impacted Transmission Operators and Balancing
Authorities in its Reliability Coordinator Area. Some examples may help to make our intent clearer: If there were 3 BAs,
TOPs etc. and none were alerted, this would be a “Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not
alerted, this would be a “High” violation. In this last case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe”
violation. (ii) R5: Similar changes as in R4 should also apply to High and Severe in R5.
No
(i) Definition of Adverse Reliability Impact is duplicated as it is already defined in IRO-001-2. (ii) We do not see the
need for R7 and R8 since R6 already stipulates the necessary actions to be taken, it is not necessary for the Reliability
Coordinator with the identified Adverse Reliability Impact to develop (re-develop?) a mitigation plan when the impacted
Reliability Coordinators did not agree that the problem exists. What may be needed is the insertion of “shall develop a
mitigation plan” before “notify impacted Reliability Coordinators” in R5. We suggest removing these requirements (R7
and R8).
No
Depending on the response of the SDT, changes to M5 to M8 may be required.
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe if the VSLs are
graded according to then number of impacted RCs that need to be notified. For example, Low for missing one,
Moderate for missing two, High for missing three, Severe for missing four or more. (ii) We do not have any issue with
the binary nature of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal)
depending on the SDT’s response to our comments under Q11.
In our comments on the previous posting, we expressed a disagreement with a proposed to remove IRO-005, in
particular the latter part of R13, which stipulated that: In instances where there is a difference in derived limits, the
Reliability Coordinator and its Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities shall always operate the Bulk Electric System
to the most limiting parameter. Our rationale was that The FAC standards cover the methodology used in calculating
SOLs and IROLs. Regardless of how these limits are calculated, in practice there always exists the possibility that
different entities may come up with SOLs/IROLs, especially of the inter-ties, that could be different. Operating to the
lowest SOLs/IROLs when more than one set exists is a necessary requirement for reliable operation. The SDT
responded by suggesting that this requirement is redundant with FAC-014 which -014 states the requirement for
developing and sharing SOL and IROL between the RC, PA, TP and TOP in both the planning and operating time
frames. However, this response fails to address the situation where during operation, the situation of disagreeing SOLs
or IROLs does arise. FAC-014 or any other standards do not currently have a requirement to ensure that all entities
operate to the lower limit before the difference is resolved. This leaves room for unreliable operation. We suggest the
SDT to consider restating this requirement somewhere. Note that this requirement is similar to R6 of IRO-014 that
when in doubt, the more conservative approach should be taken. If it is necessary to have an R6 to deal with an
uncertain identification/notification of an Adverse Reliability Impact, we don’t see why it is not necessary to operate to a
lower SOL or IROL when there is an unresolved difference.
Individual
Jason Shaver
American Transmission Company
No
We believe that the team needs to define the term “interpersonal communications capabilities”. It’s our understanding
that the term refers to how entities will communicate (i.e. phone, cell phone, video conferencing, email or satellite
phone) with each other, but that is not being clearly communicated by the requirement. A clear definition of the term
“interpersonal communication capabilities” will likely provide needed clarity to the requirement. Requirement 1 seems to
imply that an entity will be judge based on a single test of its alternative communication system within any given
quarter, and if that test fails they must develop a mitigation plan. Our concern is that the requirement should allow for
multiple testing and only if all or a reoccurring issue is found should you document and fix the issue. (Example: An
entity performs weekly tests of its alternative communication system. One of the test’s fails. All other tests, following the
failed test, are successful. Would the entity have to develop a mitigation plan based on the one failure, or are the other
successful tests sufficient to show compliance?) In R2, we assume that the 30 minutes or longer in parenthesis is
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intended to describe the length of the outage. To clarify, we suggest that the language be changed to: “Each RC, TOP
and BA shall notify impacted entities within 60 minutes of the detection of a failure of its normal interpersonal
communication systems lasting longer than 30 minutes.”
No
See our comment to question 1
No
are supportive of the language regarding “directives” which clarifies that directives are those which involve operating
emergencies. However, in R1, we believe that the word “requires” should be changed to “request”. An entity can
request that another entity repeat back a directive but we cannot “require” it.
No
See our comments to question 4
Yes
Yes
Yes
Group
Midwest ISO Standards Collaborators
Jason L. Marshall
Midwest ISO
No
We do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the
quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary and will
only delay repairing the interpersonal communication capability as it would have to be completed first before fixing the
system. In R2, we assume that the 30 minutes or longer in parenthesis is intended to describe the length of the outage.
We think this would be clearer if the requirement were revised to: “Each Reliability Coordinator, Transmission Operator
and Balancing Authority shall notify impacted entities within 60 minutes of the detection of a failure of its normal
interpersonal communications capabilities lasting longer than 30 minutes.” R3 is not necessary as it would be
impossible to meet many other requirements if a common language such as English was not used. This requirement
results in the waste of compliance resources managing and auditing documentation associated with it.
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in
question 1.
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
In addition, we suggest since R2 has a time component in the requirement, four VSLs could be written based on the
timeliness of the notification. This would be consistent with the FERC’s expressed desire in the June 2008 order on
VSLs in which they stated that as many VSLs should be developed as possible.
Yes
We largely agree with the changes to the requirements and believe it goes a long way towards resolving the issue
NERC has created recently with interpreting operating instructions as directives. This makes it clear that only directives
that are required for operating emergencies require three way communication. We believe that the SDT could further
support resolution to this directive issue by developing a definition for directive. We propose the following definition:
Directive or Reliability Directive – A verbal communication by a Reliability Coordinator, Transmission Operator, or
Balancing Authority that requires action by the recipient to prevent or mitigate an Adverse Reliability Impact. In
requirement 1, we do believe that another word than “require” should be used. Consider using “request”. An RC, BA,
and TOP can’t force the recipient of the directive to repeat it back. They can ask or request it be repeated back though.
Yes
We largely agree with the measures with the exception that a conforming change needs to be made to M1 if the
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suggestion regarding “require” in Q4 is accepted.
No
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, we
believe the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In
most cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent
of Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the directive was correct and the
repeat was correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not acknowledge the
repeat of the directive was correct but the repeat was incorrect. We agree that these distinctions make sense but offer
the following changes to clarify the intent. Moderate VSL: The responsible entity issued a verbal directive associated
with real-time operating emergency conditions and the recipient repeated the intent of the directive correctly, but the
responsible entity did not acknowledge the recipient was correct. Severe VSL: The responsible entity issued a verbal
directive associated with real-time operating emergency conditions and the recipient repeated the intent of the directive
incorrectly, but the responsible entity failed to repeat the intent of the original statement to resolve any
misunderstandings.
Yes
No
We agree with many of the changes. However, we believe R5 is not necessary for reliability. We agree the RC should
notify impacted entities when the transmission problem has been mitigated; however, if the RC fails to notify the
impacted entities, it will not result in an Adverse Reliability Impact. Thus, it is not necessary as a sanctionable
requirement.
No
Measurement 5 needs to be struck if R5 is struck per question 8.
No
The Commission stated in their order on VSLs in June of 2008 their preference for as many VSLs as possible. We
believe two VSLs are possible for R1 based on whether the RC is acting or directing actions to prevent versus mitigate.
Failure to mitigate should be Severe. Failure to prevent should be High because if the RC fails to act or direct action to
prevent, the Adverse Reliability Impact may still not happen if system conditions change. For the Moderate VSL of R2,
please remove the clause “but not all”. It is not necessary.
No
Requirements R2 and R8 need additional work. R2 appropriately requires the RC experiencing the Adverse Reliability
Impact to distribute its Operating Procedure, Process or Plan to other RCs required to take action. However, it
inappropriately places the burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to
agree. Rather R2 should remove the bullet to require agreement from the impacted RC and a new requirement should
be written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement or
disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable actions
should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This contributes to
reliability by forcing the impacted RC to take action if the action is reasonable. Further, the drafting team needs to
clarify that R2 also applies to the mitigation plan in R7. Because R7 requires the RC experiencing the Adverse
Reliability Impact to develop the mitigation plan, the mitigation plan may not be agreed to by the impacted RC. The
impacted RC may have a perfectly valid reliability, statutory, legal, or regulatory reason for not agreeing to the
mitigation plan. R8 still obligates the RC to implement the mitigation plan developed in R7 though it may be contrary to
reliability. R8 needs to allow the RC to refuse to implement the mitigation plan if the impacted RC has a reliability,
statutory, legal or regulatory reason. Further the drafting team should consider if the impacted RC could refuse
because the RC experiencing the Adverse Reliability Impact has not implemented comparable measures in their own
area. R8 as written could allow an RC to simply pass cost on to the neighboring RC in the name of reliability. For
example, the RC may not want to order a unit to be committed to avoid certain startup costs but they ask the
neighboring RC to start up a unit in their footprint.
No
Conforming changes to the Measurements will be required for accepted changes from question 11.
No
In the Commission’s June 2008 order on VSLs, they expressed their preference for having as many VSLs as possible.
We believe that four VSLs could be written for R4 based on the number of conference calls that are participated in. We
also believe this would be consistent with the Commission’s guideline 4 because the requirement is written in the
plural, that is conference calls, so all conference calls must be considered in aggregate. Thus, failure to participate in
more than one conference call does not represent distinct violations but a single violation. Four VSLs should be written
for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is redundant with the Moderate VSL.
Failure to notify one RC meets both VSL since Severe uses the word any.
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Consideration of Comments on Reliability Coordination — Project 2006-06
The Reliability Coordination Standard Drafting Team (RC SDT) thanks all commenters who
submitted comments proposed revisions to the standards for Project 2006-06: Reliability
Coordination. These standards were posted for a 30-day public comment period from July
10, 2009 through August 9, 2009. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 31 sets of comments,
including comments from more than 87 different people from over 62 companies
representing 8 of the 10 Industry Segments as shown in the table on the following pages.
All comments received have been reformatted so that all comments received in response to
the first question appear following the first question, etc. All comments have been posted
at the following site:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Changes to Requirements, Measures and Violation Severity Levels in COM-001-2:
Stakeholders suggested that there is a need to define Interpersonal Communications for this
standard. The RC SDT is proposing the following definitions:
Interpersonal Communication: Any method that allows two or more individuals
to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any method that is able to serve as
a substitute for and is redundant to normal Interpersonal Communication and does
not utilize the same infrastructure (medium) as normal Interpersonal
Communications.
Other stakeholders suggested edits to the requirements. The RC SDT revised the wording
of R2 to add clarity and revised R3 to include the phrase “unless dictated by law…” to
address legal requirements in some areas.
Several stakeholders suggested removing the mitigation plan from R1 and M1. The RC SDT
agreed and made revisions to other measures to reflect changes to the requirements.
Stakeholders suggested adding more VSLs for R2. The RC SDT agreed and drafted
additional VSLs reflecting timing and the number of entities notified. Other changes to the
VSLs were made based on revisions to the requirements.
Stakeholders suggested removing the Distribution Provider and Generator Operator from
the Data Retention section for R1 of COM-001. Since these are not applicable entities in R1,
they were removed from Data Retention for the requirement.
The standard and the proposed definitions will be posted for an additional comment period.
Changes to Requirements, Measures and Violation Severity Levels in COM-002-3
Stakeholder consensus has been achieved with respect to the retirement of R1 and M1 from
the last approved version of the standard. In response to the majority of the comments,
the drafting team has modified and rearranged the order of the remaining requirements,
and coined a definition for “Reliability Directive”. The drafting team is also coordinating with
the RTO SDT (Project 2007-03) and the OPCP SDT (Project 2007-02) on the definition and
usage of the term “Reliability Directive”.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Reliability Directive: A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.
As a reference, we have included the existing definition of Emergency:
Emergency: Any abnormal system condition that requires automatic or immediate
manual action to prevent or limit the failure of transmission facilities or generation
supply that could adversely affect the reliability of the Bulk Electric System.
In accord with the majority of commenters, the drafting team made changes to the
Measures to bring them into conformance with the adopted suggestions from question 4 for
improving the Requirements.
Changes to Requirements, Measures and Violation Severity Levels in IRO-001-2
Stakeholders generally agreed with the revisions to the requirements. Several stakeholders
suggested adding the words “an issued” before “directive” in R3. The RC SDT agreed and
made the change. No further revisions were made to the requirements. The proposed
revisions to the definition of Adverse Reliability Impacts is being posted for comment.
Stakeholders agreed with the measures for IRO-001-2. The measure M3 was revised to
reflect the revision to R3. No other revisions were suggested for the measures.
The VLS for R3 was revised to add the word “issued” before directive to match the revised
requirement. Stakeholders suggested minor revisions to the VSLs for R4 and R5. The RC
SDT agreed and made the revisions.
The RC SDT believes that stakeholder consensus has been achieved on IRO-001-2. The
definition of Adverse Reliability Impacts is included in this posting for comment.
Changes to Requirements, Measures and Violation Severity Levels in IRO-014-2
Stakeholders suggested revising R8 to include provisions for avoiding implementing actions
that would violate safety, equipment or regulatory or statutory requirements. The RC SDT
agreed and added this to the requirement. Other stakeholders suggested adding “For
conditions or activities that impact other Reliability Coordinator Areas,…” at the beginning
of R1 and R3. The RC SDT agreed and added this to the requirements. The Time Horizons
for R2 were revised as suggested to “Same Day Operations and Operations Planning”.
Several stakeholders expressed concerns regarding having R6-R8 as separate requirements.
The intent of R6, R7, and R8 is to handle those things that arise that may not have had a
plan identified in advance. The RC SDT contends the requirements should be separate
requirements as they identify distinctly different actions and are adequate as written.
Stakeholders agreed with the Measures, except to make conforming changes for revisions to
the requirements. The RC SDT has revised the measures based on the new requirements.
One stakeholder suggested revision to the Data Retention for R5-R8. Data Retention was
revised for R5 to 12 months, however the RC SDT believes that three years is the correct
period for R6-R8.
Several stakeholders suggested developing four VSLs for R5. Typically, in the course of BES
operations, the number of impacted Reliability Coordinators will be a small number. The
SDT effort in this regard was to write the VSLs to represent both the large and small
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
scenarios containing an Adverse Reliability Impact. The essence of the severe VSL is that
the RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The
essence of the moderate VSL is that the RC notified one other RC, however did not notify
the remaining impacted RC’s. The SDT felt the VSL’s appropriately addressed the large and
small scenarios. Other stakeholders suggested four VSLs for R4. The essence of R4 is
written to require impacted RC’s to talk at least weekly and is singular in nature. VSL’s can
not be written for conference calls that exceed the singular requirement.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Index to Questions, Comments, and Responses
1.
Do you agree with the revisions made to the Requirements in COM-001-2 as shown in
the posted Standard? If not, please explain in the comment area. ..........................10
2.
Do you agree with the revisions made to the Measures in COM-001-2 as shown in the
posted Standard? If not, please explain in the comment area.................................23
3.
Do you agree with the revisions made to the Violation Severity Levels in COM-001-2 as
shown in the posted Standard? If not, please explain in the comment area. .............29
4.
Do you agree with the revisions made to the Requirements in COM-002-3 as shown in
the posted Standard? If not, please explain in the comment area. ..........................33
5.
Do you agree with the revisions made to the Measures in COM-002-3 as shown in the
posted Standard? If not, please explain in the comment area.................................45
6.
Do you agree with the revisions made to the Violation Severity Levels in COM-002-3 as
shown in the posted Standard? If not, please explain in the comment area. .............49
7.
Do you agree with the revisions to the definition of Adverse Reliability Impacts (IRO001-2)? If not, please explain in the comment area. .............................................55
8.
Do you agree with the revisions to the Requirements in IRO-001-2 as shown in the
posted Standard? If not, please explain in the comment area.................................58
9.
Do you agree with the revisions to the Measures in IRO-001-2 as shown in the posted
Standard? If not, please explain in the comment area. ..........................................63
10. Do you agree with the revisions to the Violation Severity Levels in IRO-001-2 as shown
in the posted Standard? If not, please explain in the comment area. .......................66
11. Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the
posted Standard? If not, please explain in the comment area.................................70
12. Do you agree with the revisions to the Measures in IRO-014-2 as shown in the posted
Standard? If not, please explain in the comment area. ..........................................79
13. Do you agree with the revisions to the Violation Severity Levels in IRO-014-2 as shown
in the posted Standard? If not, please explain in the comment area. .......................82
14. If you have any other comments, not expressed in questions above, for the RC SDT on
any of the other changes made to this set of standards and their associated
implementation plans, please provide them here. ..................................................88
December 30, 2009
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Russell A. Noble
Additional Member
1. Rick Paschall
2.
Group
2
4
5
6
7
8
9
10
X
Northwest LSE Group
Additional Organization
3
Region Segment Selection
Pacific Northwest Generating Cooperative WECC 3
Guy Zito
Additional Member
Additional Organization
Region Segment Selection
1. Ralph Rufrano
New York Power Authority
NPCC 5
2. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
3. Paul Kiernan
New York Independent System Operator
NPCC 2
4. Roger Champagne
Hydro-Quebec TransEnergie
NPCC 2
5. Kurtis Chong
Independent Electricy System Operator
NPCC 2
6. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
7. Edward Dahill
National Grid
NPCC 1
8. Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC NA
9. Chris de Graffenried
Consolidated Edison Co. of New York
NPCC 1
10. Brian D. Evans-Mongeon Utility Services
December 30, 2009
X
Northeast Power Coordinating Council
NPCC 8
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Commenter
Organization
Industry Segment
1
11. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
12. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
13. Kathleen Goodman
ISO - New England
NPCC 2
14. David Kiguel
Hydro One Networks Inc.
NPCC 1
15. Michael R. Lombardi
Northeast Utilities
NPCC 1
16. Randy MacDonald
New Brunswick System Operator
NPCC 2
17. Greg Mason
Dynegy Generation
NPCC 5
18. Bruce Metruck
New York Power Authority
NPCC 6
19. Chris Orzel
FPL/NextEra Energy
NPCC 5
20. Robert Pellegrini
The United Illuminating Company
NPCC 1
21. Michael Schiavone
National Grid
NPCC 1
22. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
23. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
24. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
25. Gregory Campoli
New York Independent System Operator
NPCC 2
3.
Group
Jim Case
Additional Member
SERC OC Standards Review Group
Additional Organization
X
Dominion Virginia Power
SERC
1, 3
2. Steve Fritz
ACES Power Marketing
SERC
6
3. Joel Wise
Tennessee Valley Authority
SERC
1, 3, 5, 9
4. Hugh Francis
Southern Co.
SERC
1, 3, 5
5. Alan Jones
Alcoa Power Generation
SERC
1, 5
6. Scott McGough
Oglethorpe Power Corporation
SERC
5
7. Keith Steinmetz
E.ON US Services
SERC
1, 3, 5
8. Mike Hardy
Southern Co.
SERC
1, 3, 5
9. Steve McElhaney
South Mississippi Electric Membership Corp. SERC
1, 3, 5
10. Gary Hutson
South Mississippi Electric Membership Corp. SERC
1, 3, 5
11. John Rembold
Southern Illinois Power Cooperative
1, 3, 5
SERC
3
X
Region Segment Selection
1. Jack Kerr
December 30, 2009
2
6
4
5
6
7
8
9
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Commenter
Organization
Industry Segment
1
12. Timmy LeJeune
Louisiana Generating, LLC
SERC
1, 3, 5
13. Wayne Pourciau
Georgia System Operations Corp.
SERC
3
14. Tim Hattaway
PowerSouth Energy Cooperative
SERC
1, 3, 5
15. Tony Halcomb
Cogentrix Energy, LLC
SERC
5, 6
16. Robert Thomasson Big Rivers Electric Cooperative
SERC
1, 3, 5
17. Wes Davis
SERC Reliability Corp.
SERC
10
18. John Troha
SERC Reliability Corp.
SERC
10
4.
Group
Denise Koehn
Bonneville Power Administration
2
3
X
X
X
X
4
5
6
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Steven Davis
5.
Group
Generation Support
Sam Ciccone
WECC 1
FirstEnergy
Additional Member Additional Organization Region Segment Selection
1. Dave Folk
FE
RFC
2. Doug Hohlbaugh
FE
RFC
3. John Martinez
FE
RFC
4. Kevin Querry
FE
RFC
6.
Group
Ben Li
Additional Member
IRC Standards Review Committee
Additional Organization Region Segment Selection
1. Patrick Brown
PJM
RFC
2
2. James Castle
NYISO
NPCC
2
3. Anita Lee
AESO
WECC 2
4. Bill Phillips
MISO
MRO
5. Steve Myers
ERCOT
ERCOT 2
2
6. Lourdes Estrada-Salinero CAISO
WECC 2
7. Charles Yeung
SPP
SPP
2
8. Matt Goldberg
ISO-NE
NPCC
2
December 30, 2009
X
7
X
7
8
9
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Commenter
Organization
Industry Segment
1
7.
Group
Jason L. Marshall
Midwest ISO Standards Collaborators
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Joe Knight
Great River Energy
MRO
1
2. Bob Thomas
IMEA
SERC
4
3. Barb Kedrowski
We Energies
RFC
3, 4, 5
4. Jim Cyrulewski
JDRJC Associates
RFC
8
8.
Individual
Steve Alexanderson
Central Lincoln
9.
Individual
Virginia Cook
JEA
10.
Individual
Daniel Duff
Liberty Electric Power LLC
11.
Individual
Mike Davis
WECC Reliability Coordinator
12.
Individual
Sandra Shaffer
PacifiCorp
13.
Individual
Brent Hebert
Calpine Corporation
14.
Individual
Brandy A. Dunn
Western Area Power Administration
X
15.
Individual
Hugh Francis
Southern Company
X
16.
Individual
Rao Somayajula
ReliabilityFirst Corporation
17.
Individual
James H. Sorrels, Jr.
American Electric Power
X
X
X
X
18.
Individual
Brent Ingebrigtson
E.ON U.S.
X
X
X
X
19.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
X
X
20.
Individual
Troy Willis
Georgia Transmission Corporation
X
December 30, 2009
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Commenter
Organization
Industry Segment
1
21.
Individual
Bob Thomas
Illinois Municipal Electric Agency
22.
Individual
Chris Scanlon
Exelon
X
23.
Individual
Roger Champagne
Hydro-Québec TransEnergie (HQT)
X
24.
Individual
Scott Berry
Indiana Municipal Power Agency
25.
Individual
Greg Rowland
Duke Energy
26.
Individual
Jianmei Chai
Consumers Energy Company
27.
Individual
Michael R. Lombardi
Northeast Utilities
28.
Individual
Dan Rochester
Independent Electricity System
Operator
29.
Group
Carol Gerou
MRO NSRS
30.
Individual
Alice Murdock
Xcel Energy
31.
Individual
Jason Shaver
American Transmission Company
December 30, 2009
2
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
9
X
X
X
7
8
9
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
1. Do you agree with the revisions made to the Requirements in COM-001-2 as shown in the posted Standard? If
not, please explain in the comment area.
Summary Consideration: Most stakeholders agreed with the requirements in COM-001. Stakeholders suggested that
there is a need to define Interpersonal Communications for this standard. The RC SDT is proposing the following definitions:
Interpersonal Communication: Any method that allows two or more individuals to interact, consult, or exchange
information.
Alternative Interpersonal Communication: Any method that is able to serve as a substitute for and is redundant to normal
Interpersonal Communication and does not utilize the same infrastructure (medium) as normal Interpersonal Communications.
Other stakeholders suggested edits to the requirements. The RC SDT revised the wording of R2 to add clarity, revised R3 to
include the phrase “unless dictated by law…” to address legal requirements in some areas, and removed references to the
mitigation plan in R1.
Organization
Yes or No
Central Lincoln
Question 1 Comment
Comments: The inclusion of load serving entities and distribution providers does not address any present reliability gap. R4
is extremely vague, and is not likely to be interpreted consistently. What form of evidence will be acceptable? Photos of
telephones?
Response: The RC SDT thanks you for your comment. The LSE and DP were added as applicable entities to R3 as a result of stakeholder comments
during the previous posting. The DP and GOP were added as applicable entities in R4 per FERC Order 693 directives. The Measure M4 for Requirement
R4 was revised to:
M4. Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but is not limited to operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or equivalent that it had Interpersonal Communications capabilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection and operating information. (R4.)
JEA
R2 I would suggest that R2 be clarified so that it is understood that the 60 minutes starts at the beginning of the outage (or
the end of the 30 minute period, if that was instead the intent) so that there can be no confusion about when the clock
starts for notification periods. Otherwise, the wording of these standards is clearer than the current version.
R4 I am concerned that with the word "capabilities" that the DP/GO's will be expected by the auditors to demonstrate that
its "capability" was working every single second of every day since their last audit, especially since you have not included a
data retention period(especially since this is rated a "high" VRF).
December 30, 2009
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
Response: The RC SDT thanks you for your comment.
R2: We have revised the wording to clarify the intent:
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of a failure of its
normal Interpersonal Communications capabilities that lasts 30 minutes or longer. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
R4: The Measure 4 for Requirement R4 was revised to:
M4. Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but is not limited to operator logs,
voice recordings or transcripts of voice recordings, electronic communications, or equivalent that it had Interpersonal Communications capabilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection and operating information. (R4.)
Data retention for R4, M4 was added to the revised standard.
Northwest LSE Group
No
The RC STD has done a commendable effort. However, it is questionable how expanding the applicability to include LSEs,
DPs, & PSEs that are non-scheduling/tagging entities will increase reliability of the BES. In fact, we believe that increasing
the applicability could do just the opposite. Many of these entities that are only registered as a LSE, DP, and/or PSE do not
have a 24/7 desk/dispatch facility to receive RC/BA/TOP reliability directives, and are too small (10s of MW) to effectively
assist during a reliability crisis. In addition, the Regional Entities (WECC in this case) are overwhelmed as it is, asking
them to take on even more audit responsibilities is unrealistic, and not worth the effort.
In addition, for the small Registered Entity, what would constitute compliance with R3 & R4 if no TOP/BA real-time
directives were received? Everyone employed speaks English and there is at least one phone on the premises? Will the
small DP and/or LSE be required to monitor its communication system 24/7 with competent personnel for an unlikely
TOP/BA directive?
Response: The RC SDT thanks you for your comment. The LSE, DP and PSE were added as applicable entities to R3 as suggested by other
stakeholders in the last posting. The Distribution Provider and Generator Operator are in R4 per FERC Order 693 directives.
The measures for the requirements specify what would constitute evidence needed to demonstrate compliance. Note that R3 and R4 are not focused
solely on communication related to “directives.” Requirement R3 is focused on all “. . . inter-entity Bulk Electric System (BES) reliability communications . . .
“ The drafting team feels that R4 as written allows flexibility to the entities in meeting the performance requirement. Note that R4 only applies to
Distribution Providers and Generator Operators, not to LSEs.
American
Transmission
Company
No
December 30, 2009
We believe that the team needs to define the term “interpersonal communications capabilities”. It’s our understanding that
the term refers to how entities will communicate (i.e. phone, cell phone, video conferencing, email or satellite phone) with
each other, but that is not being clearly communicated by the requirement. A clear definition of the term “interpersonal
communication capabilities” will likely provide needed clarity to the requirement.
11
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
Requirement 1 seems to imply that an entity will be judge based on a single test of its alternative communication system
within any given quarter, and if that test fails they must develop a mitigation plan. Our concern is that the requirement
should allow for multiple testing and only if all or a reoccurring issue is found should you document and fix the issue.
(Example: An entity performs weekly tests of its alternative communication system. One of the test’s fails. All other tests,
following the failed test, are successful. Would the entity have to develop a mitigation plan based on the one failure, or are
the other successful tests sufficient to show compliance?)
In R2, we assume that the 30 minutes or longer in parenthesis is intended to describe the length of the outage. To clarify,
we suggest that the language be changed to: Each RC, TOP and BA shall notify impacted entities within 60 minutes of the
detection of a failure of its normal interpersonal communication systems lasting longer than 30 minutes.
Response: The RC SDT thanks you for your comment. Several stakeholders have expressed a concern with the definition of interpersonal
communications capabilities. The RC SDT concurs and has drafted a definition that will be posted for comment.
R1: Other stakeholders also expressed concern with developing a mitigation plan in this requirement. The RC SDT has revised the requirement to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
The RC SDT feels that this will address your comment.
R2: We concur and have revised the requirement as you suggest.
Northeast Power
Coordinating Council
No
Interpersonal communication includes more than voice, such as instant messaging, text messaging and email. This
Standard needs a definition of interpersonal communication.
Having alternative interpersonal communications should be specified as a requirement.
Work communication within Québec must be in French according to the law. It is understood and agreed that
communication outside Québec with adjacent entities would be, and in fact is already, in English. Accordingly, R3 should
be modified as the proposition below: R3. Unless dictated by law or otherwise agreed to,
Response: The RC SDT thanks you for your comment. The RC SDT agrees that there is a need for a definition of Interpersonal Communications
Capability. We have developed a draft definition that will be posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
The RC SDT agrees with your comment regarding the alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
December 30, 2009
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
We concur with your suggestion regarding R3 and have made the suggested revision.
SERC OC Standards
Review Group
No
The STD should clarify what types of communications are considered in the standard is it voice or data communications or
both?
Response: The RC SDT thanks you for your comment. Interpersonal communication does not include data (see IRO-010-1) and includes more than
voice, such as instant messaging, text messaging and email. The RC SDT has developed a draft definition of interpersonal communications
capabilities that will be posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
IRC Standards
Review Committee
No
(1) We do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the
quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary and will only
delay repairing the interpersonal communication capability as it would have to be completed first before fixing the system.
If repairing the system would be a lengthy process, then a mitigation plan may be developed to document that the entity is
in process to fix the system. There is no associated requirement to have an alternate interpersonal communication
capability along with R1 to test it. Thus, if a responsible entity did not have an alternate interpersonal communication
capability, R1, in essence, does not apply. We suggest adding a requirement to have an alternate interpersonal
communication capability to address this gap. Alternatively, the requirement to have an alternate interpersonal
communication capability along with requirements to test and fix it could be stipulated in the Organization Certification
Requirements.
(2) In R2, we assume that the 30 minutes or longer in parenthesis is intended to describe the length of the outage. We
think this would be clearer if the requirement were revised to: “Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60 minutes of the detection of a failure of its normal interpersonal
communications capabilities lasting longer than 30 minutes.”
(3) R3 is not necessary. This requirement results in the waste of compliance resources managing and auditing
documentation associated with it with no measurable improvement to reliability.
Response: The RC SDT thanks you for your comment. 1) The RC SDT agrees with your comment regarding the mitigation plan and the requirement
for alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
December 30, 2009
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
2) We concur with your comment and have revised the requirement accordingly.
3) The RC SDT does not agree with your assertion regarding R3. There is a reliability need to speak a common language, especially in issuing and
receiving directives. There are several areas of the continent where this could be a reliability gap if there is no requirement.
Midwest ISO
Standards
Collaborators
No
We do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the
quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary and will only
delay repairing the interpersonal communication capability as it would have to be completed first before fixing the system.
In R2, we assume that the 30 minutes or longer in parenthesis is intended to describe the length of the outage. We think
this would be clearer if the requirement were revised to: “Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60 minutes of the detection of a failure of its normal interpersonal
communications capabilities lasting longer than 30 minutes.”
R3 is not necessary as it would be impossible to meet many other requirements if a common language such as English
was not used. This requirement results in the waste of compliance resources managing and auditing documentation
associated with it.
Response: The RC SDT thanks you for your comment. 1) The RC SDT agrees with your comment regarding the mitigation plan and the requirement
for alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
2)
We concur with your comment and have revised the requirement accordingly.
3) The RC SDT does not agree with your assertion regarding R3. There is a reliability need to speak a common language, especially in issuing and
receiving directives. There are several areas of the continent where this could be a reliability gap if there is no requirement.
ReliabilityFirst
Corporation
No
FERC 693 excludes distribution providers if they are not a user, owner or operator of BES. This should be reflected in R4
of the standard
Response: The RC SDT thanks you for your comment. FERC Order 693 endorses the NERC Statement of Compliance Registry criteria (paragraph 512)
and also adopted the proposal to require the ERO to modify COM-001 to apply to distribution providers and generator operators (paragraph 493).
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
E.ON U.S.
Yes or No
No
Question 1 Comment
E.ON U.S. suggests deleting “interpersonal” from the term “interpersonal communications capabilities”. The need for and
meaning of the term “interpersonal” isn’t clear. Does it infer communications must be to/from a specific individual rather
then to/from another reliability entity? Verbal vs electronic communications? All non-data communications? E.ON U.S.
believes that the term “interpersonal" must be clarified if it is to remain in the standard.
In the proposed R1 “how extensive must the quarterly testing be “ establish contact or verify all functions? Does the term
“alternative” include the "normal" communication medium or only the “backup” mediums? Does the alternative imply ALL
possible communication alternatives? E.ON U.S. suggests replacing the term “alternative” with “planned backup” or similar.
Quarterly testing needs to be limited to only established/planned backup communication methods not any potential
"alternative" communication method.
Response: The RC SDT thanks you for your comment. The RC SDT agrees with several stakeholders that there is a need for a definition of
Interpersonal Communications Capability. We have developed a draft definition that will be posted for comment which meets the FERC Order 693
directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
The testing requirement is to ensure that the alternative (not “normal”) interpersonal communications capability works as a minimum. Entities may go
above and beyond the requirement if they desire. The requirement was edited to identify the alternative and test it.
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its alternative Interpersonal
Communication capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: Lower][Time Horizon: Realtime Operations]
Manitoba Hydro
No
do not believe a mitigation plan is necessary in R1. If the interpersonal communication capability fails during the quarterly
test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is unnecessary as it would delay
repairing the interpersonal communication capability.
R2 assumed that the 30 minutes or longer in parenthesis is intended to describe the length of the outage. We think this
would be clearer if the requirement were revised to: Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall notify impacted entities within 60 minutes of the detection of a failure of its normal interpersonal
communications capabilities lasting longer than 30 minutes?
R3 is not necessary as it would be impossible to meet many other requirements if a common language such as English
was not used. This requirement results in the waste of compliance resources managing and auditing documentation
associated with it.
Response: The RC SDT thanks you for your comment. 1) The RC SDT agrees with your comment regarding the mitigation plan and the requirement
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
for alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
2) We concur with your comment and have revised the requirement accordingly.
3) The RC SDT does not agree with your assertion regarding R3. There is a reliability need to speak a common language, especially in issuing and
receiving directives. There are several areas of the continent where this could be a reliability gap if there is no requirement.
Georgia Transmission
Corporation
No
Per the NERC Reliability Standards Development Procedure, under the definition of a Reliability Standard? The
obligations or requirements must be material to reliability and measurable? With regards to R3. - It goes without saying
that inter-entity BES reliability communications must be in a common language between the entities for understanding
operation instructions. From an audit/measurability standpoint, the evidence to the requirement would not converge to a
finite amount of material. The amount of evidence required to demonstrate compliance of this requirement would be a
huge administrative burden. It seems this concept (for use of the English language) could be captured under the “Entity
Tasks and Interrelationships” section of the NERC Reliability Functional Model which defines the set of functions that must
be performed to ensure the reliability of the bulk electric system. It also explains the relationship between and among the
entities responsible for performing the tasks within each function. Additionally, this concept (for use of the English
language) could further be explained under each applicable registration type (BA, GOP, TSP, LSE, PSE, and DP) in the
NERC Reliability Functional Model. The Second option for R3 is to remove the Requirement from the continent wide
Standards and have the effected entities/regions create a “Regional Standard” where entities involved in inter-entity BES
reliability communications have a history of language barrier concerns.
As a separate issue to R3, it also seems conflicting that a written requirement would provide the option of “Unless agreed
to otherwise”. This option described in the language of the requirement implies that it is not a requirement but an option
which further supports the suggestions above.
Response: The RC SDT thanks you for your comment. The RC SDT does not agree with your assertion regarding R3. There is a reliability need to
speak a common language, especially in issuing and receiving directives. There are several areas of the continent where this could be a reliability gap
if there is no requirement. The Reliability Functional Model is not an enforceable standard.
Illinois Municipal
Electric Agency
No
December 30, 2009
The IMEA supports comments submitted by the MISO Standards Collaboration Group indicating R3 is not necessary.
Similarly, IMEA questions the necessity of R4. Therefore, we question the need to expand the applicability of COM-001 to
DP, LSE, and PSE since R3 and R4 are the only two Requirements applicable to those functions.
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
Response: The RC SDT thanks you for your comment. The RC SDT does not agree with your assertion regarding R3. There is a reliability need to
speak a common language, especially in issuing and receiving directives. There are several areas of the continent where this could be a reliability gap
if there is no requirement. R4 is included per FERC Order 693 directive.
Exelon
No
Agree with the revisions with the following exception/recommendation: COM-001: purpose is to address communication
facilities / capabilities (technical/hardware). COM-002: purpose is to address effectiveness (protocols).COM-001: R.1-3
address telecommunication facility requirements. R4 requires English use. Recommend the drafting team move COM-001
R4 (use English) to COM-002 where effectiveness of communications (protocols) between entities is addressed.
Response: The RC SDT thanks you for your comment. COM-001 Requirement R3 (English use) is being incorporated into COM-003-1 by the Operations
Personnel Communications Protocols SDT (Project 2007-02). It will be retired from this standard upon approval of COM-003-1. We see no benefit to
moving it to COM-002 at this time.
Hydro-Québec
TransEnergie (HQT)
No
Interpersonal communication includes more than voice, such as instant messaging, text messaging and email. This
Standard needs a definition of interpersonal communication.
Having alternative interpersonal communications should be specified as a requirement since there is actually no
requirement to have that alternative way of communication in the first place.
Work communication within Québec must be in French according to the law. It is understood and agreed that
communication outside Québec with adjacent entities would be, and is in fact already, in English. Accordingly, R3 should
be modified as the proposition below: R3. Unless determined by law or otherwise agreed to,
Response: The RC SDT thanks you for your comment. The RC SDT agrees that there is a need for a definition of Interpersonal Communications
Capability. We have developed a draft definition that will be posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
The RC SDT agrees with your comment regarding the alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
We concur with your suggestion regarding R3 and have made the suggested revision.
Duke Energy
No
December 30, 2009
R1 requires an entity to “develop a mitigation plan” if a test of alternative communications capabilities is unsuccessful. We
believe that this phrase should be changed to “take action”, reflecting that an entity’s response to an unsuccessful test may
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
be to simply call or email a repair order. The phrase “develop a mitigation plan” implies that an entity must establish a
backup to the alternative communications capabilities rather than just restore the alternative communications capabilities.
Response: The RC SDT thanks you for your comment. We concur with your comment regarding the mitigation plan and have revised the requirement
to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its alternative Interpersonal
Communication capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: Lower][Time Horizon: Realtime Operations]
Northeast Utilities
No
It is understood that the use of the term "interpersonal communications" and "interpersonal communications capabilities"
were selected by the RC SDT to better reflect the intent of the Standard. However, NU reviewers are concerned over the
new terminology and believe that it is unclear and not universally accepted to mean the same thing to all parties. NU's
belief is that the original use of the terms "telecommunications" and "telecommunications facilities" are clearer and
universally understood. NU recommends that the original terms be re-instated or the term "interpersonal communications"
be replaced to reflect the intent of the Standard is to ensure "voice and text equipment" is adequate for communicating
real-time operating information.
R1 ? the requirement has evolved to test alternative equipment, versus a requirement to have primary and alternative
equipment. Standard should require entities to have the equipment such as in the -1 version.R2 is to notify impacted
entities in the event of a loss of normal communications. With backup communications operating correctly do we assume
there is no impact and therefore notification is not required? This is unclear from a compliance perspective and
unnecessary if backup communications are available. Alternative communications often go several layers deep including
cell phones, satellite phones, radio, etc.
Response: The RC SDT thanks you for your comment. Several stakeholders have expressed a concern about the definition of interpersonal
communications. The RC SDT is proposing a definition that will be posted for comment to address those concerns as well as your comment.
R1: The intent of the requirement is as you suggest. This requirement has been revised to:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
Notification of a failure of the normal interpersonal communications is still required by R2. The testing requirement is for one designated alternative.
No notification is required for the failure of a non-designated alternative.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Independent
Electricity System
Operator
Yes or No
No
Question 1 Comment
We suggest the SDT review the applicability to Transmission Service Providers, Load-Serving Entities and Purchasing
Entities from a real time operating perspective. We do not believe they are active participants in real time operation for
which they require to have the same communication capability as the RCs, TOPs, BAs and DPs.
Interpersonal communication includes more than voice, such as instant messaging, text messaging and email. This
Standard needs a definition of interpersonal communication.
Having alternative interpersonal communications should also be specified as a requirement.
Work communication within Quebec must be in French according to the law. It is understood and agreed that
communication outside Québec with adjacent entities would be, and already is, in English. Accordingly, R3 should be
modified as proposed below: R3. Unless dictated by law or otherwise agreed to,
R4: We believe “Interconnection” should be replaced by “interconnection” since the former is not a defined term.
Response: The RC SDT thanks you for your comment. TSP, LSE and PSE are not required to have the same Interpersonal communication as RC, TOP
or BA. The only requirement applicable to TSP, LSE and PSE is R3 (English language).
The RC SDT agrees that there is a need for a definition of Interpersonal Communications Capability. We have developed a draft definition that will be
posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
The RC SDT agrees with your comment regarding the alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
We concur with your suggestion regarding R3 and have made the suggested revision.
R4: Interconnection is a defined term in the NERC Glossary of Terms (Updated on April 20, 2009).
MRO NSRS
No
(1) The MRO NSRS does not believe a mitigation plan is necessary in R1. If the interpersonal communication capability
fails during the quarterly test, the entity simply needs to fix it, document the fix and re-test. A mitigation plan is
unnecessary and will only delay repairing the interpersonal communication capability as it would have to be completed first
before fixing the system. Please create a definition for the interpersonal communication capability (or systems) term used
in the response to comments to draft 1 in the summary of consideration for question 1.
(2) In R2, MRO NSRS assumes that the 30 minutes or longer in parenthesis is intended to describe the length of the
outage. MRO NSRS thinks this would be clearer if the requirement were revised to: “Each Reliability Coordinator,
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
Transmission Operator and Balancing Authority shall notify impacted entities within 60 minutes of the detection of a failure
of its normal interpersonal communications capabilities lasting longer than 30 minutes.”
(3) R3 is not necessary as it would be impossible to meet many other requirements if a common language such as English
was not used. This requirement results in the waste of compliance resources managing and auditing documentation
associated with it.
Response: The RC SDT thanks you for your comment. 1) The RC SDT agrees with your comment regarding the mitigation plan and the requirement
for alternate interpersonal communications capability and has revised the requirement to read:
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly basis, its Alternative Interpersonal
Communications capability used for communicating real-time operating information. If the test is unsuccessful, the entity shall take action within 60 minutes to
restore the identified alternative or identify a substitute Alternative Interpersonal Communications capability. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
The team has drafted a definition for both the term “Interpersonal Communication” and the term, “Alternative Interpersonal Communication.”
2) We concur with your comment and have revised the requirement accordingly.
3) The RC SDT does not agree with your assertion regarding R3. There is a reliability need to speak a common language, especially in issuing and
receiving directives. There are several areas of the continent where this could be a reliability gap if there is no requirement.
Xcel Energy
No
(1) While an improvement from the terminology used in version 1, the term "interpersonal communications" is still vague.
We feel the intent of the drafting team was to include non-verbal communication as well, like email. However, as drafted,
this point is not clear. We feel a definition is needed in order avoid disparity in its interpretation.
(2) It appears that the requirement for RCs, TOPs and BAs to have communication capabilities (whether primary or
backup/alternative) was removed from the standard. Yet, R1 requires the RC, TOP and BA to test alternative
communications capabilities. Requirements to have primary and backup/alternative communication capabilities should be
explicitly stated.
(3) Additionally, we feel that the DP and GOP should have testing requirements for their communication capabilities with
their TOP and BA.
Response: The RC SDT thanks you for your comment. 1) The RC SDT agrees that there is a need for a definition of Interpersonal Communications
Capability. We have developed a draft definition that will be posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
2) The RC SDT does not agree with your assertion regarding R1. The requirement for alternate interpersonal communications capability implies that
primary interpersonal communications are in place.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 1 Comment
3) The DP and GOP were added as applicable entities in R4 per FERC Order 693 directives. The RC SDT does not agree with your assertion regarding
the need for testing requirements. However, your concerns may be addressed in the Measure 4 revision:
M4. Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent that it had Interpersonal Communications capabilities with its Transmission
Operator and Balancing Authority for the exchange of Interconnection and operating information. (R4.)
Western Area Power
Administration
Yes
R4 should say "Generator Operator" rather than "Generation Operator"
Response: The RC SDT thanks you for your comment. We have made this revision.
American Electric
Power
Yes
AEP does generally agree with the revisions, but the use of the term “interpersonal communication capabilities” needs a
NERC-approved definition. Otherwise, what is in scope? Are e-mail or text messages acceptable, and, if so, what type of
guaranteed delivery is necessary?
Response: The RC SDT thanks you for your comment. The RC SDT agrees that there is a need for a definition of Interpersonal Communications
Capability. We have developed a draft definition that will be posted for comment which meets the FERC Order 693 directive to:
Includes adequate flexibility for compliance with the reliability standard, adoption of new technologies and cost-effective solutions.
FirstEnergy
Yes
We agree with many of the changes made to the standard including the change of title to reflect communications (voice
and text messages). The parenthesis around 30 minutes or longer should be removed as parenthesis by definition mean a
word, phrase, or sentence inserted in a passage to explain or modify the thought. This phrase is more than an explanation
of the term failure. It sets forth a time requirement that is an integral part of R1. We suggest rewording the requirement as
"Each RC, TOP, and BA shall notify impacted entities within 60 minutes of a failure of its normal interpersonal
communications capabilities that lasts 30 minutes or longer."
Response: The RC SDT thanks you for your comment. We concur with your comment and have revised the requirement accordingly.
Bonneville Power
Administration
Yes
PacifiCorp
Yes
Southern Company
Yes
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Calpine Corporation
Yes or No
Question 1 Comment
Yes
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
2. Do you agree with the revisions made to the Measures in COM-001-2 as shown in the posted Standard? If not,
please explain in the comment area.
Summary Consideration: Most commenters agreed with the measures for COM-001. The measures were revised based on
revisions to the requirements as well as comments received below. Several stakeholders suggested removing the mitigation
plan from R1 and M1. The RC SDT agreed and made the revision. M3 and M4 were revised as:
M3.
Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Purchasing-Selling Entity, and Distribution Provider shall have and provide upon request
evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, that will be used to determine that its personnel used English as the language for all inter-entity
BES reliability communications between and among operating personnel responsible for the real-time generation control or
operation of the interconnected BES. If a language other than English is used, each party shall have and provide upon request
evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, of agreement to use the alternate language or the law that requires the use of an alternate
language. (R3.)
M4.
Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but
is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent that
it had Interpersonal Communications capabilities with its Transmission Operator and Balancing Authority for the exchange of
Interconnection and operating information (R4).
Organization
Yes or No
Question 2 Comment
Northwest LSE
Group
No
To demonstrate compliance the small Registered Entities will be in the position of proving a negative: i.e., there is no realtime BES operational communication from or to any other entity. Currently, for the smaller entities, communication with the
Transmission Operator or Balancing Authority is strictly for operational safety and local reliability of service, not operational
reliability for the BES as defined by NERC. It is not clear how the small entity will show compliance. If R4 requires the small
load-only DP and/or LSE to have 24/7 monitoring of its phone, and contracted answering service is unable to contact anyone,
will this be a violation?
Response: The RC SDT thanks you for your comment. R4 is applicable only to registered Distribution Providers and Generator Operators. The RC SDT
has revised the measure to prevent having to prove a negative:
M4. Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent that it had Interpersonal Communications capabilities with its Transmission
Operator and Balancing Authority for the exchange of Interconnection and operating information
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 2 Comment
There is no 24/7 monitoring requirement in R4.
Northeast Power
Coordinating
Council
No
See our comment for R3 in Q1.Accordingly, M3 should be modified as the proposition below:M3. “ that will be used to
determine that personnel used English “or another language” as the language for all inter-entity Bulk Electric System
reliability communications between and among operating personnel responsible for the real-time generation control and
operation of the interconnected Bulk Electric System. If a language other than English is used, both parties shall have and
provide upon request, evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or equivalent, of agreement shall be provided to explain the use of the alternate
language. (R3.)M3 allows a language other than English. Must the agreement for non-English be in place in advance of the
call?
Response: The RC SDT thanks you for your comment. The RC SDT has revised the measure to conform to revisions in the requirement:
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, and Distribution Provider shall have and provide upon request
evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent, that will
be used to determine that personnel used English as the language for all inter-entity BES reliability communications between and among operating personnel
responsible for the real-time generation control and operation of the interconnected BES. If a language other than English is used, both parties shall have and
provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications,
or equivalent, of agreement to use the alternate language or the law that requires the use of an alternate language.
The RC SDT feels that agreement is not required prior to the call, but only prior to the conversation using the alternate language.
Bonneville Power
Administration
No
Issue #1: Measure M3 The measure states that entities “shall have and provide” evidence that “personnel used English as
the language for all” communications. This infers that all communications must be documented in some form or fashion and
that any outage of the normal communication system must be met with alternative processes which will meet this measure,
even if the alternative is the preparation of handwritten notes of each person’s conversations, noting that the communications
occurred in English. Unfortunately, there have been times where our Dictaphone stopped recording phone calls, and nobody
knew it for days! This measure sets us up for a violation! It’s just a matter of time.
Response: The RC SDT thanks you for your comment. The measure as written is consistent with the requirement. The RC SDT did not receive any
other comments to modify this measure.
IRC Standards
Review Committee
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in question 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Midwest ISO
Standards
Collaborators
No
Question 2 Comment
Conforming changes are required to the Measures based on the suggested modifications to the requirements in question 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
Central Lincoln
No
Comments: M4 is of little help regarding R4. How does an entity perform this demonstration, especially in the case of an offsite audit? If left to the regions, there will be no consistency.
Response: The RC SDT thanks you for your comment. Based on comments received on R4 and M4, the RC SDT has revised M4 to:
M4. Each Distribution Provider and Generator Operator shall have and provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent that it had Interpersonal Communications capabilities with its Transmission
Operator and Balancing Authority for the exchange of Interconnection and operating information. (R4.)
ReliabilityFirst
Corporation
No
No measures are posted for R4 of the revised standard
Response: The RC SDT thanks you for your comment. A measure M4 is in both the redline and clean version of the posted standard.
E.ON U.S.
No
E.ON U.S. believes that he M1 must be clarified to address whether the testing entity is responsible to develop and
implement a mitigation plan when a test is unsuccessful due to an issue at the other end (i.e. non-testing entity).
Response: The RC SDT thanks you for your comment. We have removed the mitigation plan from the requirement and measure.
Manitoba Hydro
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in question 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
Georgia
Transmission
Corporation
No
See comments to Question 1 in regards to measurability.
Response: The RC SDT thanks you for your comment. Please see response to question 1.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Illinois Municipal
Electric Agency
Yes or No
No
Question 2 Comment
Conforming changes are required to the Measures based on the suggested modifications to the requirements in Quesion 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
Exelon
No
See answer to #1
Response: The RC SDT thanks you for your comment. See response to question 1.
Hydro-Québec
TransEnergie (HQT)
No
Comments: See our comment for R3 in Q1.Accordingly, M3 should be modify to read as the proposition below:M3. “ that will
be used to determine that personnel used English “or another language determine otherwise” as the language for all interentity Bulk Electric System reliability communications between and among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System. If a language other than English is used, upon
request, evidence shall be provided to explain the use of the alternate language. (R3.)M3 allows a language other than
English. Must the agreement for non-English be in place in advance of the call?
Response: The RC SDT thanks you for your comment. The RC SDT has revised the measure to conform to revisions in the requirement:
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, and Distribution Provider shall have and provide upon request
evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent, that will
be used to determine that its personnel used English as the language for all inter-entity BES reliability communications between and among operating personnel
responsible for the real-time generation control or operation of the interconnected BES. If a language other than English is used, both parties shall have and provide
upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent, of agreement to use the alternate language or the law that requires the use of an alternate language.
The RC SDT feels that agreement is not required prior to the call, but only prior to the conversation using the alternate language.
Duke Energy
No
Replace the phrase “develop a mitigation plan” with the phrase “take action” per our comment on Requirement R1 above.
Also, the DP and GOP should be deleted from the Data Retention section requirements for R1/M1 and R2/M2. Need to add
a Data Retention requirement for R4/M4 for the DP and GOP.
Response: The RC SDT thanks you for your comment. The measure M1 was revised to conform to suggested revisions to R1. We have also revised
the Data Retention section.
Independent
Electricity System
No
December 30, 2009
M3 and M4 may need to be revised depending on the response to our comments under Q1, above.
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 2 Comment
Operator
Response: The RC SDT thanks you for your comment. Conforming revisions were made to the measures based on revisions to the requirements.
MRO NSRS
No
Conforming changes are required to the Measures based on the suggested modifications to the requirements in question 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
Xcel Energy
No
Measures should be modified to reflect changes to requirements suggested in question 1.
Response: The RC SDT thanks you for your comment. Changes were made to the Measures to conform to revisions of the requirements.
American
Transmission
Company
No
See our comment to question 1
Response: The RC SDT thanks you for your comment. See response to question 1.
JEA
Yes
M1 - very nice, probably we will also be held responsible for completing the mitigation plans, so perhaps you should go ahead
and add that so no one gets caught without sufficient evidence in that regard
M2 – fine
M3 - this measure would indicate that operators have the authority to agree among themselves to speak other languages,
rather than a more formal agreement between entities, which is how I read the language of the requirement. If that is not what
is meant, then I would suggest the examples include Memorandums of Agreement or Understanding, Contracts or other more
formal mechanisms.
M4 - fine
Response: The RC SDT thanks you for your comment. M1: We removed the mitigation plan from R1 and M1.
M3: The requirement does not preclude individuals from using an alternate language as long as they agree to do so prior to the conversation.
FirstEnergy
Yes
However, it is not clear whether to show compliance the voice recordings and associated transcripts are of the test done or of
the conversations across those facilities.
Response: The RC SDT thanks you for your comment. Since the requirement is to test, the evidence provided should be sufficient to show that the test
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 2 Comment
was performed and any appropriate follow up actions taken (in case of failure).
Western Area
Power
Administration
Yes
M4 should say "Generator Operator" rather than "Generation Operator"
Response: The RC SDT thanks you for your comment. We have made this revision.
SERC OC
Standards Review
Group
Yes
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine Corporation
Yes
Southern Company
Yes
American Electric
Power
Yes
Northeast Utilities
Yes
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
3. Do you agree with the revisions made to the Violation Severity Levels in COM-001-2 as shown in the posted
Standard? If not, please explain in the comment area.
Summary Consideration: Stakeholders suggested adding more VSLs for R2. The RC SDT agreed and drafted additional VSLs
reflecting time and the number of entities notified. Other changes to the VSLs were made based on revisions to the
requirements.
Organization
Yes or No
Northwest LSE Group
No
Question 3 Comment
With the vague verbiage of R4 coupled with the High and Severe VSL, it is important to clarify R4 with the small DP in
mind, and possibly include Lower and Moderate VSLs for smaller load-only DP violations.
Response: The RC SDT thanks you for your comment. Based on the requirement, the RC SDT does not feel that additional VSLs can be written for R4.
The intent of the requirement is missed if the responsible entity does not have Interpersonal Communication Capabilities with both its TOP or its BA.
Northeast Power
Coordinating Council
No
see M3 comment for question 2
Response: The RC SDT thanks you for your comment. See response to question 2.
IRC Standards
Review Committee
No
(1) Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
(2) FERC expressed its desire in the June 2008 order on VSLs to have as many VSLs as possible. We suggest since R2
also has a time component in the requirement four VSLs could be written based on the timeliness of the notification as well
as the number of impacted entities that were not notified. The VSLs should reflect both components.
Response: The RC SDT thanks you for your comment. 1) Conforming changes were made to the VSLs based on the modifications to the requirements.
2) We have added VSLs based on the time requirements.
Midwest ISO
Standards
Collaborators
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
In addition, we suggest since R2 has a time component in the requirement, four VSLs could be written based on the
timeliness of the notification. This would be consistent with the FERC’s expressed desire in the June 2008 order on VSLs
in which they stated that as many VSLs should be developed as possible.
Response: The RC SDT thanks you for your comment. Conforming changes were made to the VSLs based on the modifications to the requirements.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 3 Comment
We have added VSLs based on the time requirements.
Central Lincoln
No
The severity levels have little or no relationship to reliability. Failure to provide a evidence of an agreement per R3, for
example, has no impact on reliability by itself; yet it carries the maximum VSL. In reality, the impact would only be severe if
the use of an alternate language resulted in a miscommunication.
Response: The RC SDT thanks you for your comment. The VSLs are a metric applied after a requirement has been violated. The intent is to provide a
relative measure of how far the action or inaction was from the threshold set in the requirement. Some requirements lend themselves to a relative
measure of meeting the threshold (i.e. “almost met”, 12 minutes when the requirement was 10 minutes, etc), and some do not. Those that do not are
often termed “binary” requirements (either you meet the threshold or you do not). The relative risk to the bulk electric system of not meeting a
requirement is specifically reflected in the requirement’s VRF. The relative size of a registered entity is beyond the scope of the standard drafting team
and is addressed through the NERC Statement of Compliance Registry Criteria or taken into account as a mitigating factor through the Regional
compliance enforcement programs.
E.ON U.S.
No
E.ON U.S. suggests that R1 be modified to include the language that when an RC, BA and/or TOP issue a directive it must
state: “This is a directive” and the entity receiving the directive must state: "I understand this is a directive”. E.ON U.S. also
requests that language be added to the requirement that states that this communication protocol is only for reliability
related directives and not for other operational directives.
Response: The RC SDT thanks you for your comment. The RC SDT does not agree with your assertion regarding R1. The purpose of R1 is to ensure
that operating entities have adequate Interpersonal Communications capabilities.
Manitoba Hydro
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
In addition, since R2 has a time component in the requirement four VSLs could be written based on the timeliness of the
notification.
Response: The RC SDT thanks you for your comment. Conforming changes were made to the VSLs based on the modifications to the requirements.
We have also added VSLs based on the time requirements.
Georgia Transmission
Corporation
No
Again, Requirement 3 seems to be an option.
Response: The RC SDT thanks you for your comment. The RC SDT does not agree with your assertion regarding R3. There is a reliability need to
speak a common language, especially in issuing and receiving directives.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Illinois Municipal
Electric Agency
No
Question 3 Comment
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in Quesion 1.
Response: The RC SDT thanks you for your comment. Conforming changes were made to the VSLs based on the modifications to the requirements.
Hydro-Québec
TransEnergie (HQT)
No
see M3 comment for question 2
Response: The RC SDT thanks you for your comment. See response to question 2.
Duke Energy
No
Replace the phrase “develop a mitigation plan” with the phrase “take action to restore the capabilities” per our comment on
Requirement R1 above.
Response: The RC SDT thanks you for your comment. Mitigation plan was removed from the requirement.
Independent
Electricity System
Operator
No
The VSLs for R3 may have to be changed based on the outcome of our comments in Q2 regarding the language of
communication.
Response: The RC SDT thanks you for your comment. Conforming changes were made to the VSLs based on the modifications to the requirements.
MRO NSRS
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in question 1.
In addition, the MRO NSRS suggests since R2 has a time component in the requirement four VSLs could be written based
on the timeliness of the notification. This would be consistent with the FERC’s expressed desire in the June 2008 order on
VSLs in which they stated that as many VSLs should be developed as possible.
Response: The RC SDT thanks you for your comment. Conforming changes were made to the VSLs based on the modifications to the requirements.
We have also added VSLs based on the time requirements.
SERC OC Standards
Review Group
Yes
Bonneville Power
Administration
Yes
December 30, 2009
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Organization
Yes or No
FirstEnergy
Yes
JEA
Yes
Liberty Electric Power
LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine Corporation
Yes
Western Area Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
American Electric
Power
Yes
Northeast Utilities
Yes
December 30, 2009
Question 3 Comment
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Consideration of Comments on Project 2006-06 Reliability Coordination
4. Do you agree with the revisions made to the Requirements in COM-002-3 as shown in the posted Standard? If
not, please explain in the comment area.
Summary Consideration: Stakeholder consensus has been achieved with respect to the retirement of R1 (the requirement for
the TOP and BA to each have data and voice communication with RCs, BAs and TOPs). In response to the majority of the
comments, the drafting team has added a new R1 to require that “Reliability Directives” be identified as such, revised and
rearranged the two requirements from the last posting so that the new R2 focuses on repeating the intent of a reliability
directive and the new R3 focuses on responding to that repeated directive. The drafting team is also coordinating with the
RTO SDT and the OPCP SDT (Project 2007-02) on the definition and usage of the term “Reliability Directive”.
The new R1 through R3 are:
R1.
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a
Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a
Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
R2.
Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a Reliability Directive
issued per Requirement R1, shall repeat the intent of the Reliability Directive back to the issuer of the Reliability Directive.
[Violation Risk Factor: High][Time Horizon: Real-Time]
R3.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority that identifies an action as a Reliability
Directive shall acknowledge the response from the recipient of the Reliability Directive in R2 as correct or reissue the Reliability
Directive to resolve any misunderstandings. [Violation Risk Factor: High][Time Horizon: Real-Time]
The proposed definition for Reliability Directive is:
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where
action by the recipient is necessary to address an actual or expected Emergency.
Organization
Yes or No
Northwest LSE
Group
No
Question 4 Comment
It would be advantageous to exempt certain smaller Registered Entities (LSE, DP, & PSE) that are non-scheduling/tagging
entities. In addition to not having a scheduling/tagging desk, many of these entities do not have a 24/7 desk to receive
RC/BA/TOP reliability directives/calls, and are too small (10s of MW) to even be substantially significant in a reliability crisis.
Instead of making this Standard applicable to all DPs, LSEs, and PSEs, we suggest that the RC, BAs, and TOPs to yearly
publish those LSEs, DPs, and PSEs responsible for responding to emergency reliability directives.
Also, it would be advisable for the RC, BA, and TOP giving a reliability directive to clearly preface the instruction with “The
following is an emergency reliability directive” to differentiate from normal operations communications. Many smaller entities
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 4 Comment
do not have the resources to install reliable voice recording equipment, but having access to such recordings would be
beneficial towards compliance documentation; thus, it would be helpful to require the directive issuing RC, BA, or TOP to
provide a digital copy of the voice recording, or transcript if available on request to the recipient of the directive. Short of a
recording or transcript of the recording, it will be difficult to determine how a small entity without recorded line would show
compliance other than writing down the directive as it is given and reading it back to the issuer. If the directive is lengthy, this
will slow down the process and probably defeat the purpose and value of quick action. Further, there is no guarantee that the
receiver will accurately retain a complicated directive if not immediately documented in some way to allow review.
Last of all, what is meant by the word “intent”? Must the recipient understand and demonstrate the “why” the directive is given
and the intended “outcome,” or merely paraphrase the directive to demonstrate understanding? If the recipient repeats word
for word the directive back to the issuer without any other indication that the directive is understood, is this a violation??
Response: The RC SDT thanks you for your comment. The requirements of COM-002 for LSE, DP and PSE simply state that the entity has to repeat the
intent of the directive back. The issue you raise concerning smaller entities is valid, but this standard is not the venue at which to make this argument.
Registration criteria are outside the scope of this project.
We have included a new requirement R1:
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor:
High][Time Horizon: Real-Time]
The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is coordinating with that team.
The word “intent” was chosen so that the recipient did not have to repeat the directive verbatim and to also indicate an understanding of the directive. If
a recipient repeats the directive verbatim, it is not a violation of the requirement, as it would also capture the intent.
Northeast Power
Coordinating
Council
No
Support the intent but not the existing language. Do not support Requirements that include some examples since the
examples can be confused with the Requirement. Do not support one written Requirement that has two requirements.
Recommend the following Requirements: A new R1 - Each Entity shall have Operational Procedure requiring that
communications directives be repeated back to the issuer. R2 leave as is. A new R3 If not repeated, then issuer shall request
the receiving Entity to repeat the communication directive. A new R4 The issuer will acknowledge the correctness of the
repetition of the communications directive.
Response: The RC SDT thanks you for your comment. The RC SDT does not see a reliability benefit to having an Operational Procedure requirement, as
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 4 Comment
it would be redundant since the standard COM-002 would be mandatory and enforceable and requires the actions in the Operational Procedure that you
suggest. The RC SDT feels that we have the same requirements that you suggest but in a different arrangement.
SERC OC
Standards Review
Group
No
The term “emergency” has a broad definition and other standards use “adverse conditions” or “adverse reliability impact”.
There should be a consistency of terms when describing a system condition. The STD should include a definition of “directive”
that includes more than “Emergency” operational conditions. Should this requirement be modified to include the term
“Directive” and the definition of this term added to the NERC Glossary?
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal
operations communications. The RC SDT appreciates the baggage that comes with the defined term “Emergency”. However, it is the best fit with the
normal messaging that has historically occurred in the bulk electric reliability community. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an
actual or expected Emergency.
This term has been included in the requirements of COM-002. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team.
Midwest ISO
Standards
Collaborators
Yes
We largely agree with the changes to the requirements and believe it goes a long way towards resolving the issue NERC has
created recently with interpreting operating instructions as directives. This makes it clear that only directives that are required
for operating emergencies require three way communication. We believe that the SDT could further support resolution to this
directive issue by developing a definition for directive. We propose the following definition: Directive or Directive A verbal
communication by a Reliability Coordinator, Transmission Operator, or Balancing Authority that requires action by the recipient
to prevent or mitigate an Adverse Reliability Impact.
In requirement 1, we do believe that another word than “require” should be used. Consider using “request”. An RC, BA, and
TOP can’t force the recipient of the directive to repeat it back. They can ask or request it be repeated back though.
Response: The RC SDT thanks you for your comment. 1) The RC SDT is proposing a new definition for Reliability Directive to differentiate it from
normal operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team.
2) The RC SDT has revised the requirement to remove that part since original R2 required the recipient to repeat the intent of the directive.
December 30, 2009
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Organization
Yes or No
Central Lincoln
No
Question 4 Comment
The inclusion of load serving entities and distribution providers does not address any present BES reliability gap.
Response: The RC SDT thanks you for your comment. Loads are under the direct control of Load Serving Entities while underfrequency relays are often
under the direct control of distribution providers. Current NERC standards do not address the possibility that a Reliability Directive may be issued to
either of these entities. The requirements of COM-002 for LSE and DP simply state that the entity has to repeat the intent of the directive back since
these entities may receive reliability directives.
JEA
No
R1: just to avoid possible auditor misunderstandings the SDT might consider replacing the words "or repeat the original
statement" to "reissue the directive" so that the RC does not get into trouble if the second statement is not verbatem of the
first. This also helps clarify that another statement is required from the recipient along with a final acknowledgement from the
RC that the intent is correct.
Response: The RC SDT appreciates your comment. You have identified a potential problem; the RC SDT agrees with your comment and has replaced
the words “repeat the original statement” with “reissue the Reliability Directive”.
Liberty Electric
Power LLC
No
The proposed standard does not require the RC, TO, or BA to declare an emergency to the GO when issuing a directive.
There has been confusion at times in the past as to whether the entity is issuing a directive based on economics or due to an
emergency. The standard should be amended to require the RC/TO/BA to state the directive is due to a declared emergency.
The GO is required to repeat back the intent of an emergency directive, but is not required to repeat back the intent of
economic directive. This can lead to a finding of a severe VSL non-compliance on the part of the GO due to a failure of the
RC/TO/BA to clearly state the nature of the directive.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal
operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTOSDT (Project 2007-03) is also working on a similar path and the RC SDT are
coordinating with that team. A new R1 has been developed that states:
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: RealTime]
ReliabilityFirst
No
December 30, 2009
FERC 693 excludes distribution providers if they are not a user, owner or operator of BES. This should be reflected in R2 of
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Corporation
Question 4 Comment
the standard
Response: The RC SDT thanks you for your comment. Any distribution provider excluded by FERC Order 693 would not be held to the standard since
standards only apply to registered entities. FERC Order 693 endorses the NERC Statement of Compliance Registry criteria (paragraph 512) and also
adopted their proposal to require the ERO to modify COM-002 to apply to distribution providers and generator operators (paragraph 512). The Functional
Model describes the real-time relationships between entities. Among those relationships, the DP:
Implements voltage reduction and sheds load as directed by the Transmission Operator or Balancing Authority
Such directives fall under COM-002 requirements.
Illinois Municipal
Electric Agency
No
IMEA questions the necessity of expanding the applicability of COM-002 as proposed in R2, particularly to the DP, LSE, and
PSE functions. IMEA recommends accomplishing the intent of COM-002-3 R2 by simply referring to COM-002-3 R1 in IRO001-2 R2 which requires those entities to comply with the RC directive. Thus it would be understood that the functional entity
had repeated the directive in order to comply with it; thereby avoiding the necessity of expanding applicability to another
reliability standard.
Response: The RC SDT thanks you for your comment. The RC SDT feels that there is a difference between complying with a directive and
communicating the directive effectively. The requirements of COM-002 for LSE, PSE and DP simply state that the entity has to repeat the intent of the
directive back since these entities may receive reliability directives. The drafting team feels that the current draft adds clarity to the requirements.
Exelon
No
See answer # 1
Response: The RC SDT thanks you for your comment. See response to answer #1.
Hydro-Québec
TransEnergie
(HQT)
No
Support the intent but not the existing language. Do not support Requirements that include some examples since the
examples can be confused with the Requirement. Do not support one written Requirement that has two requirements.
Recommend the following Requirements A new R1 - Each Entity shall have Operational Procedure requiring that
communications directives be repeated back to the issuerR2 leave as is. A new R3 If not repeated, then issuer shall request
the receiving Entity to repeat the communication directive. A new R4 The issuer will acknowledge the correctness of the
repetition of the communications directive
Response: The RC SDT thanks you for your comment. There are no examples in any of the requirements of COM-002-3 as posted. There are no
compound requirements remaining in COM-002-3 as posted. The RC SDT does not see a reliability benefit to having an Operational Procedure
requirement, as it would be redundant since the standard COM-002 would be mandatory and enforceable and requires the actions in the Operational
Procedure that you suggest. The RC SDT feels that we have the same requirements that you suggest but in a different arrangement that is internally
consistent.
December 30, 2009
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Organization
Yes or No
Indiana Municipal
Power Agency
No
Question 4 Comment
The requirements do not consider a pre-recorded communication that might be sent out from the Transmission Operator to
Generator Operators or any other entity. If this communication is a directive associated with a real-time operational
emergency condition (depending on the judgment used by an entity or auditor), it does not make sense to repeat back a prerecorded message on the phone. It might be good to clearly state in the standard that pre-recorded messages do not need to
be repeated back.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal
operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RC SDT can not envision a situation, regardless of the technology, where a Reliability
Directive would be issued without confirmation from the recipient and acknowledgement of accuracy. However, even if there were an occasion as
suggested by your comment, the bulk electric system can only remain reliable by coordinating actions between reliability entities. A pre-recorded
communication is a broadcast, not a coordinating activity. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT are
coordinating with that team.
Duke Energy
No
We agree with adding the clarification that these requirements refer to “emergency” communications, but we think the word
“Emergency” should be capitalized to further clarify that it is a defined term in the NERC Glossary.
Also, the phrase “require the recipient of the verbal directive to repeat the intent of the directive back” should be changed to
“have the recipient of the verbal directive repeat the intent of the directive back”. This avoids making the issuer of the directive
make a statement requiring a repeat back unless the recipient actually fails to repeat back as normally expected.
Response: The RC SDT thanks you for your comment. We have removed the word “emergency” and are proposing a definition of Reliability Directive
which includes the defined term “Emergency” and which is being posted for comment.
The RC SDT agrees with the intent of your comment. The phrase you mention has been removed from R1 as it is required by R2. We have made other
edits to tighten the requirements as well.
Consumers Energy
Company
No
December 30, 2009
COM-002 R2 specifies the Generator Operator that receives a directive from the Transmission Operator, Reliability
Coordinator or Balancing Authority must repeat the intent of the directive back to the Transmission Operator. COM-002 M2
specifies that evidence must be retained in the form of either voice recordings or transcripts by the generator operator. Since
the Transmission Operator, Reliability Coordinator and Balancing Authority already have voice recording capability (centrally
located), it is not necessary for the Generator to also install voice recording capability at each generating station. We suggest
the wording of COM-002 be changed such that only the Transmission Operator, Reliability Coordinator and Balancing
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
Question 4 Comment
Authority be required to keep voice recordings or transcripts.
Response: The RC SDT thanks you for your comment. While recordings may be available from other entities, a Generator Operator has mandatory
requirements with which it must comply. Generator Operators must have evidence that they complied with the requirement. The evidence mentioned in
the measures is a suggestion of possible methods of evidence. We have revised the measure to include “…which could include, but is not limited to, voice
recordings, transcripts of voice recordings or operator logs…”.
Independent
Electricity System
Operator
No
(i)
We suggest the word “emergency” be capitalized since it is a defined term which generally covers the conditions under
which directives are issued.
(ii)
We further suggest that to avoid confusion between operating instructions and directives, the term directive should be
defined as suggested below: Directive or Directive A verbal communication by a Reliability Coordinator, Transmission
Operator, or Balancing Authority that requires complying action by the recipient to prevent or mitigate an Adverse
Reliability Impact.
(iii)
Since R1 contains two requirements, there may be some benefit in separating these since that would make the VSLs
clearer, i.e. separate the requirements placed on the issuer of the directive to (a) request the recipient to repeat the
intent of the directive and (b) to acknowledge the response of the recipient as correct.
Response: The RC SDT thanks you for your comment.
i) We have removed the word “emergency” and are proposing a definition of Reliability Directive which includes the defined term “Emergency” and
which is being posted for comment.
ii)
The RC SDT is proposing a definition of Reliability Directive that will be posted for comment. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
iii) The RC SDT agrees and has modified R1. Since R2 requires the recipient to repeat the intent of the directive, we have removed the part of R1 that
states the issues shall require the recipient to repeat the directive. This removed the compound requirement.
MRO NSRS
No
The MRO NSRS largely agrees with the changes to the requirements and believes it goes a long way towards resolving the
issue NERC has created recently with interpreting operating instructions as directives. This makes it clear that only directives
that are required for operating emergencies require three way communication. MRO NSRS believes that the SDT could
further support resolution to this directive issue by developing a definition for directive. MRO NSRS proposes the following
definition:
Directive or Directive – A verbal communication by a Reliability Coordinator, Transmission Operator, or Balancing Authority
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Organization
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Question 4 Comment
that requires action by the recipient to prevent or mitigate an Adverse Reliability Impact.
In requirement 1, MRO NSRS does believe that another word than “require” should be used. Consider using “request”. An
RC, BA, and TOP can’t force the recipient of the directive to repeat it back. They can ask or request it be repeated back
though.
Response: The RC SDT thanks you for your comment. 1) The RC SDT is proposing a new definition for Reliability Directive to differentiate it from
normal operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTOSDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team.
We have removed the “require” part of R1 since R2 is an enforceable requirement for repeating the directive.
American
Transmission
Company
No
are supportive of the language regarding “directives” which clarifies that directives are those which involve operating
emergencies. However, in R1, we believe that the word “requires” should be changed to “request”. An entity can request that
another entity repeat back a directive but we cannot “require” it.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a definition of Reliability Directive that will be posted for comment. Our
proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
We have removed the “require” part of R1 since R2 is an enforceable requirement for repeating the directive.
IRC Standards
Review Committee
Yes
(1) We largely agree with the changes to the requirements and believe it goes a long way towards resolving the issue NERC
has created recently with interpreting operating instructions as Directives. This makes it clear that only Directives that are
required for operating emergencies require three way communication. We believe that the SDT could further support
resolution to this Directive issue by developing a definition for Directive. We propose the following definition: Directive A
verbal communication by a Reliability Coordinator, Transmission Operator, or Balancing Authority that requires action by the
recipient to prevent or mitigate an Adverse Reliability Impact. Please note that AESO already has this term defined. The
above suggested definition may be different from the AESO’s definition.
(2) In requirement 1, we do believe that another word than “require” should be used. Consider using “request”. An RC, BA,
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Yes or No
Question 4 Comment
and TOP can’t force the recipient of the Directive to repeat it back. They can ask or request it be repeated back though.
Response: The RC SDT thanks you for your comment.
1) The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal operations communications. Our proposed definition
is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team.
2) The RC SDT has revised the requirement to remove that part since original R2 required the recipient to repeat the intent of the directive.
Calpine
Corporation
Yes
Calpine supports three part communications when verbal directives are issued during real-time operational emergency
conditions. Calpine believes all issued directives should be explicitly identified as such.
Response: The RC SDT thanks you for your comment. A new R1 has been developed that states:
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
Western Area
Power
Administration
Yes
This is a very good improvement. Some Regional Entities were interpreting every communication from a control room as a
“directive” and stating that “directives” were equal to any “normal instruction” that related to operations of the power system.
Making it clear that the directives are associated with emergency conditions is a big improvement. The drafting team may wish
to consider additional clarification, such as, “The entity that issues a verbal directive shall make it known during the
communication that, “This is a directive”? . All parties to the communication would be clear that the real-time situation was an
emergency condition, and that the requirements for repeating the intent were in effect.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal
operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team. A new R1 has been developed that states:
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Question 4 Comment
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
American Electric
Power
Yes
AEP does generally agree with the revisions, but we have concerns with the much wider scope of three part communications
that expand the required voice or transcript evidence. There is no rationale provided for changing the text in R1 and M1, and
adding a new R2 and M2. We would recommend that these items remain as stated in Version 2.
Response: The RC SDT thanks you for your comment. The RC SDT’s intent was to create a consistent set of noncompound requirements and to provide
clarity according to the scope of the drafting team.
Manitoba Hydro
Yes
For the most part agree with the changes to the requirements and believe it goes a long way towards resolving the issue
NERC has created recently with interpreting operating instructions as directives. This makes it clear that only directives that
are required for operating emergencies require three way communication. The SDT could further support resolution to this
directive issue by developing a definition for directive.
In requirement 1, I would use another word than “require”. Consider using “request”. An RC, BA, and TOP can’t force the
recipient of the directive to repeat it back. They can ask or request it be repeated back though.
Response: The RC SDT thanks you for your comment.
1) The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal operations communications. Our proposed definition
is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTOSDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team. 2) The RC SDT has revised the requirement to remove that part since original R2 required the recipient to repeat the intent
of the directive.
FirstEnergy
Yes
1. We agree with the clarification in R1 that a directive per COM-002-3 is a "verbal directive associated with real-time
operational emergency conditions". We understand this to be a "Reliability" directive used during times of emergency or in
situations where reliability may be an issue. Also, with this clarification, it confirms that the term "directive", as used in this
standard, does not include "Operational" directives issued by System Operators during normal system conditions to change
the status of an element such as a circuit breaker.
2. The industry does not appear to have a clear, consistent definition of what constitutes a directive. We suggest the standard
require the person issuing a directive to use the phrase "I am directing you to ?", "I am ordering you to ?" or something similar
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Yes or No
Question 4 Comment
to invoke the three part communication requirement.
3. Since this standard deals with communications and coordination during emergency conditions, it may be helpful to change
the title of the standard to "Communications and Coordination Emergency Conditions".
4. The phrase "the intent of the directive" could be difficult to comply with and measure. The words "the intent of" should be
removed from Requirements R1 and R2.
Response: The RC SDT thanks you for your comment. 1) The RC SDT is proposing a new definition for Reliability Directive to differentiate it from
normal operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
This term has been included in the requirements of COM-002. The RTO SDT (Project 2007-03) is also working on a similar path and the RC SDT is
coordinating with that team.
2) We agree and have included a new R1 that states:
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
3) The RC SDT disagrees. This standard covers all interpersonal communications, not just emergency communications. The title stays as is.
4) The phrase was included so that the recipient did not have to repeat the directive verbatim and to also indicate an understanding of the directive. If a
recipient repeats the directive verbatim, it is not a violation of the requirement, as it would also capture the intent. The goal of the RC SDT is to assure
continued reliability without creating a trap by requiring word-for-word repetition.
Northeast Utilities
Yes
Xcel Energy
Yes
Bonneville Power
Administration
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
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Yes or No
Southern Company
Yes
Georgia
Transmission
Corporation
Yes
December 30, 2009
Question 4 Comment
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5.
Do you agree with the revisions made to the Measures in COM-002-3 as shown in the posted Standard? If not,
please explain in the comment area.
Summary Consideration: Stakeholder consensus has been achieved with respect to the retirement of R1 and M1 from the
last approved version of this standard. In accord with the majority of commenters, the drafting team made changes to the
Measures to bring them into conformance with the adopted suggestions from question 4 for improving the Requirements.
Specifically, a new R1 was added to require that reliability directives be identified as such – and the two requirements from the
last posting were rephrased and rearranged for clarity. The Measures were changed to match the revised requirements.
Organization
Yes or No
Illinois Municipal
Electric Agency
Question 5 Comment
Conforming changes are required to the Measures based on the suggested modifications to the requirements in Question 4.
Response: The RC SDT thanks you for your comment. The measures were revised to reflect changes to the requirements.
Hydro-Québec
TransEnergie (HQT)
No
Address the new proposed Requirements above in Question 4.
Northeast Power
Coordinating Council
No
Addressed the new proposed Requirements above in Question 4.
Response: The RC SDT thanks you for your comment. The measures were revised to reflect changes to the requirements.
Duke Energy
No
Change “emergency” to “Emergency” per comment on R1 above. Also change the phrase “required the recipient of the
verbal directive to repeat” to “had the recipient of the verbal directive repeat” per our comment on R1 above.
Response: The RC SDT thanks you for your comment. We have removed the word “emergency” and are proposing a definition of Reliability Directive
which includes the defined term “Emergency” and which is being posted for comment.
Northwest LSE
Group
No
Only in making the Measures agree with the suggested changes to the requirements above.
Response: The RC SDT thanks you for your comment. See response to Question 4. The measures have been revised to reflect changes to the
requirements.
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Yes or No
Central Lincoln
No
Question 5 Comment
M2 goes beyond R2 in requiring recordings. This will be cost prohibitive for small entities that have little impact on the BES.
Telephone recording equipment will be needed on company phones, and some way to handle the recording of directives
and responses that occur after hours on home or cell phones must be handled. Drafters seem to have missed the fact that
not all the applicable entities have 24/7 dispatch centers.
Response: The RC SDT thanks you for your comment. The measure lists possible examples of evidence to prove compliance with the requirement. It
does not impose any additional requirements or the purchase of recording systems. We have revised the measure to include “…which could include, but
is not limited to, voice recordings, transcripts of voice recordings or operator logs…”.
JEA
No
Not all entities have recorded lines. The standard does not directly require the to record their lines, but the measure implies
it. It seems that a written log should be sufficient. Since both sides of the conversation gets audited, the auditors will have
ample opportunity to check up on both sides.
Response: The RC SDT thanks you for your comment. The measure lists possible examples of evidence to prove compliance with the requirement. It
does not impose any additional requirements or the purchase of recording systems. We have revised the measure to include “…which could include, but
is not limited to, voice recordings, transcripts of voice recordings or operator logs…”.
Northeast Utilities
No
NU agrees with expanding the applicability of the Standard beyond the Reliability Coordinators, Balancing Authorities and
Transmission Operators to ensure that the recipient of a verbal directive repeats back the directive to the issuer (R2).
Despite NU's agreement with R2, NU believes that M2 is duplicative to the intent of M1 and unnecessarily requires the
installation of voice recording capabilities at the entities other than a RC, BA or TOP. It is our belief that the voice
recordings of the RC, BA and TOP (M1) provide the evidentiary support required by all applicable entities.
Response: The RC SDT thanks you for your comment. The measure lists possible examples of evidence to prove compliance with the requirement. It
does not impose any additional requirements or the purchase of recording systems. We have revised the measure to include “…which could include, but
is not limited to, voice recordings, transcripts of voice recordings or operator logs…”.
Independent
Electricity System
Operator
No
Comments: Some changes may be necessary based on the SDT’s response to our suggestion in Q4.
Response: The RC SDT thanks you for your comment. See response to your comments on question 4.
MRO NSRS
No
December 30, 2009
MRO NSRS largely agrees with the measures with the exception that a conforming change needs to be made to M1 if the
suggestion regarding “require” in Q4 is accepted.
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Question 5 Comment
Response: The RC SDT thanks you for your comment. “Require” was removed from the requirement and the measure edited appropriately.
American
Transmission
Company
No
See our comments to question 4
Response: The RC SDT thanks you for your comment. See response to your comments on question 4.
IRC Standards
Review Committee
Yes
We largely agree with the measures with the exception that a conforming change needs to be made to M1 if the suggestion
regarding “require” in Q4 is accepted.
Midwest ISO
Standards
Collaborators
Yes
We largely agree with the measures with the exception that a conforming change needs to be made to M1 if the suggestion
regarding “require” in Q4 is accepted.
Response: The RC SDT thanks you for your comment. “Require” was removed from the requirement and the measure edited appropriately.
American Electric
Power
Yes
As described in the question 4 response, there is no rationale provided for changing the text in R1 and M1, and adding a the
new R2 and M2. We would recommend that these items remain as stated in Version 2.
Response: The RC SDT thanks you for your comment. See response to question 4.
Manitoba Hydro
Yes
For the most part agree with the measures with the exception that a conforming change needs to be made to M1 if the
suggestion regarding “require” in Q4 is accepted.
Response: The RC SDT thanks you for your comment. “Require” was removed from the requirement and the measure edited appropriately.
SERC OC Standards
Review Group
Yes
Bonneville Power
Administration
Yes
FirstEnergy
Yes
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Yes or No
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine Corporation
Yes
Western Area Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
Georgia
Transmission
Corporation
Yes
December 30, 2009
Question 5 Comment
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Consideration of Comments on Project 2006-06 Reliability Coordination
6. Do you agree with the revisions made to the Violation Severity Levels in COM-002-3 as shown in the posted
Standard? If not, please explain in the comment area.
Summary Consideration: Several stakeholders suggested revisions to the VSLs based on suggested revisions to the
requirements. The RC SDT made changes to the VSLs to conform to revisions to the requirements.
Organization
Yes or No
Northwest LSE
Group
No
Question 6 Comment
Only in making the Measures agree with the suggested changes to the requirements above.
Response: The RC SDT thanks you for your comment. The Measures have been revised to reflect changes to the requirements.
Northeast Power
Coordinating Council
No
Address the new proposed Requirements.
Response: The RC SDT thanks you for your comment. The RC SDT feels that we have the same requirements that you suggest but in a different
arrangement. The new proposed Requirements have been addressed.
Bonneville Power
Administration
No
Comments: Issue #1: Violation Severity Level. The Moderate and Severe VSLs for Requirement R1 can lead to confusion.
For instance, the Moderate VSL states that the responsible entity “did not acknowledge the recipient was correct in the
repeated directive OR (emphasis theirs) failed to repeat the intent of the original statement to resolve any
misunderstandings. ”What is it saying here? Is it dinging the responsible entity for making no response at all to the recipient
after they repeated the intent of the message? Or is that what the Severe VSL is dinging for when it includes an AND rather
than an OR in the statement? I can’t tell what the drafting team was intending with their statements, but one of the
statements seem to infer that the responsible entity can actually be dinged for not doing both, acknowledging the recipient as
being correct in their response and at the very same time repeating the intent of the original statement to resolve any
misunderstandings because the recipient was incorrect in their response. This then argues that the recipient can be both
correct and incorrect at the same time. I didn’t think that was possible ”similar to binary code” either you get a one or a zero,
but not both and never neither!
I would argue that the drafting team should rewrite their VSLs to succinctly state that the responsible entity failed to respond
after the recipient repeated the intent of the message. With that in mind, either the Moderate or the Severe VSL will be
rewritten in an understandable way and the other VSL will disappear in the realms of impossible things.
Response: The RC SDT thanks you for your comment. We have eliminated the Moderate VSL and only have the Severe.
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IRC Standards
Review Committee
No
Question 6 Comment
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, we
believe the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In most
cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent of
Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the Directive was correct and the repeat
was correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not acknowledge the repeat of
the Directive was correct but the repeat was incorrect. We agree that these distinctions make sense but offer the following
changes to clarify the intent. Moderate VSL: The responsible entity issued a verbal Directive associated with real-time
operating emergency conditions and the recipient repeated the intent of the Directive correctly, but the responsible entity did
not acknowledge the recipient was correct. Severe VSL: The responsible entity issued a verbal Directive associated with
real-time operating emergency conditions and the recipient repeated the intent of the Directive incorrectly, but the
responsible entity failed to repeat the intent of the original statement to resolve any misunderstandings.
Response: The RC SDT thanks you for your comment. We have modified all the requirements in a way that addresses your comments. Conforming
changes to the VSLs have been made.
Midwest ISO
Standards
Collaborators
No
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, we
believe the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In most
cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent of
Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the directive was correct and the repeat
was correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not acknowledge the repeat of
the directive was correct but the repeat was incorrect. We agree that these distinctions make sense but offer the following
changes to clarify the intent. Moderate VSL: The responsible entity issued a verbal directive associated with real-time
operating emergency conditions and the recipient repeated the intent of the directive correctly, but the responsible entity did
not acknowledge the recipient was correct. Severe VSL: The responsible entity issued a verbal directive associated with
real-time operating emergency conditions and the recipient repeated the intent of the directive incorrectly, but the
responsible entity failed to repeat the intent of the original statement to resolve any misunderstandings.
Response: The RC SDT thanks you for your comment. We have modified all the requirements in a way that addresses your comments. Conforming
changes to the VSLs have been made.
American Electric
Power
No
AEP is concerned that the severe VSL assigned to Requirement 2 is excessive and should be reconsidered.
Response: The RC SDT thanks you for your comment. We believe that R2 is a binary requirement which results in a Severe VSL. The entity either
performed the requirement or did not.
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Manitoba Hydro
No
Question 6 Comment
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, believe
the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement. In most cases,
repeating the language of the requirement is best but we believe a deviation is warranted here. The intent of Moderate
appears to be that the RC, TOP or BA did not acknowledge the repeat of the directive was correct and the repeat was
correct. In the Severe, we believe the intent appears to be that the RC, TOP or BA did not acknowledge the repeat of the
directive was correct but the repeat was incorrect. We agree that these distinctions make sense but offer the following
changes to clarify the intent. Moderate VSL: The responsible entity issued a verbal directive associated with real-time
operating emergency conditions and the recipient repeated the intent of the directive correctly, but the responsible entity did
not acknowledge the recipient was correct. Severe VSL: The responsible entity issued a verbal directive associated with
real-time operating emergency conditions and the recipient repeated the intent of the directive incorrectly, but the
responsible entity failed to repeat the intent of the original statement to resolve any misunderstandings.
Response: The RC SDT thanks you for your comment. We have modified all the requirements in a way that addresses your comments. Conforming
changes to the VSLs have been made.
Illinois Municipal
Electric Agency
No
Conforming changes are required to the VSLs based on the suggested modifications to the requirements in Question 4.
Response: The RC SDT thanks you for your comment. The RC SDT feels that there is a difference between complying with a Reliability Directive and
communicating the Reliability Directive effectively. The requirements of COM-002 for LSE, PSE and DP simply state that the entity has to repeat the
intent of the directive back since these entities may receive Reliability Directives. The drafting team feels that the current draft adds clarity to the
requirements. The VSLs were revised to match the revised requirements.
Hydro-Québec
TransEnergie (HQT)
No
address the new proposed Requirements.
Response: The RC SDT thanks you for your comment. The RC SDT does not see a reliability benefit to having an Operational Procedure requirement,
as it would be redundant since the Standard COM-002 would be mandatory and enforceable and requires the actions in the Operational Procedure that
you suggest. The RC SDT feels that we have the same requirements that you suggest but in a different arrangement.
Duke Energy
No
December 30, 2009
Change “emergency” to “Emergency” in the VSLs per our comment on R1 above. Also, we don’t see a tangible difference
between the Moderate and Severe VSLs, and the High VSL should really be the Severe VSL. We suggest having just a
High and a Severe VSL as follows:” High VSL: “The responsible entity issued a verbal directive associated with real-time
operating Emergency conditions and had the recipient repeat back the intent of the directive, but did not either acknowledge
the recipient was correct in the repeated directive or failed to repeat the intent of the original statement to resolve any
misunderstandings.” Severe VSL: “The responsible entity issued a verbal directive associated with real-time operating
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Question 6 Comment
Emergency conditions, but did not have the recipient repeat back the intent of the directive.”
Response: The RC SDT thanks you for your comment. We have removed the word “emergency” and are proposing a definition of Reliability Directive
which will be posted for comment. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
We have removed the “require” part of R1 since R2 is an enforceable requirement for repeating the directive. Conforming changes to the VSLs have
been modified.
Independent
Electricity System
Operator
No
The sequence of communication required under R1 is intended to ensure that directives from the issuing entities are clearly
understood. The earlier this sequence is broken, the greater the uncertainty that this goal is achieved and the greater should
be the severity level. Thus, failure to request that the recipient entity repeat the intent of the directive “ the earliest step in the
sequence - should attract the “Severe” VSL.Also, failing to repeat the original directive when there is any misunderstanding,
again, in our view, leaves the intent of the directive equally unclear and should also attract a “Severe” VSL.Failing to
acknowledge the recipient was correct in the repeating the intent of the directive “ the last step in the sequence “ is already
assigned a “Moderate” VSL and this should not be repeated in the “Severe” VSL.We therefore suggest that the two
conditions under “High” and “Severe” in R1 be combined as one under “Severe” as follows: The responsible entity issued a
verbal directive associated with real-time operating emergency conditions but did not require the recipient to repeat the intent
of the directive;ORThe responsible entity issued a verbal directive associated with real-time operating emergency conditions
and required the recipient to repeat the intent of the directive, but failed to repeat the intent of the original statement to
resolve any misunderstandings.
Response: The RC SDT thanks you for your comment. In the revised standard, R2 requires the recipient to repeat the intent of the directive. We have
removed the part of R1, (now R3), that states the issuer shall “require” the recipient to repeat the directive. We have made revisions to the VSLs to
match the requirements.
MRO NSRS
No
If the suggestion regarding “require” in Q4 is accepted, conforming changes to the VSL need to made. Additionally, MRO
NSRS believes the Moderate and Severe VSLs are confusing based on repeating the language exactly in the requirement.
In most cases, repeating the language of the requirement is best but we believe a deviation is warranted here. The intent of
Moderate appears to be that the RC, TOP or BA did not acknowledge the repeat of the directive was correct and the repeat
was correct. In the Severe, MRO NSRS believes the intent appears to be that the RC, TOP or BA did not acknowledge the
repeat of the directive was correct but the repeat was incorrect. MRO NSRS agrees that these distinctions make sense but
offer the following changes to clarify the intent.
Moderate VSL: The responsible entity issued a verbal directive associated with real-time operating emergency conditions
and the recipient repeated the intent of the directive correctly, but the responsible entity did not acknowledge the recipient
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Organization
Yes or No
Question 6 Comment
was correct.
Severe VSL: The responsible entity issued a verbal directive associated with real-time operating emergency conditions and
the recipient repeated the intent of the directive incorrectly, but the responsible entity failed to repeat the intent of the original
statement to resolve any misunderstandings.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a definition of Reliability Directive that will be posted for comment.
Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
We have removed the “require” part of R1 since R2 is an enforceable requirement for repeating the directive. Conforming changes to the VSLs have
been modified.
SERC OC
Standards Review
Group
Yes
If R1 changes as suggested in Question 4, the VSLs will need to be changed also.
Response: The RC SDT thanks you for your comment. The RC SDT is proposing a new definition for Reliability Directive to differentiate it from normal
operations communications. Our proposed definition is:
A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual
or expected Emergency.
The VSLs have been revised to reflect the proposal.
FirstEnergy
Yes
JEA
Yes
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
December 30, 2009
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Organization
Yes or No
PacifiCorp
Yes
Calpine Corporation
Yes
Western Area Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
Georgia
Transmission
Corporation
Yes
Northeast Utilities
Yes
December 30, 2009
Question 6 Comment
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Consideration of Comments on Project 2006-06 Reliability Coordination
7. Do you agree with the revisions to the definition of Adverse Reliability Impacts (IRO-001-2)? If not, please
explain in the comment area.
Summary Consideration: Stakeholders suggested removing the word “outages” after “cascading” as per the NERC Glossary
of Terms and a FERC Directive issued December 27, 2007. The RC SDT made the revision. There were no other suggested
revisions to the definition.
Organization
Yes or No
Question 7 Comment
Northeast Power
Coordinating Council
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive ssued Dec. 27,
2007.
Hydro-Québec
TransEnergie (HQT)
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive issued Dec. 27,
2007.
Northeast Utilities
No
Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive issued Dec. 27,
2007.
Independent
Electricity System
Operator
No
Comments: Remove the word “outages” that appears after “cascading” as per NERC Glossary and FERC Directive
issued Dec. 27, 2007.
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has removed “outages”. We have also capitalized “Cascading”
FirstEnergy
Yes
If the term "cascading" used in the definition is referring to the NERC-defined term, it should be capitalized.
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has capitalized “Cascading”
IRC Standards
Review Committee
Yes
The drafting team should consider that NERC is moving away from using the term "cascading outages". FERC has
directed NERC to rescind this definition, and use the defined term "cascading" instead.
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has removed “outages”. We have also capitalized “Cascading”
SERC OC
Standards Review
Group
No
December 30, 2009
What is the difference between “Adverse Reliability Impacts” and the definition of an IROL? Is this going to replace an
IROL?
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Yes or No
Question 7 Comment
Response: The RC SDT thanks you for your comment. Adverse Reliability Impacts is already a defined term that the RC SDT is proposing to revise.
IROL is a limit, while ARI is the impact of events. ARI will not replace IROL.
Northwest LSE
Group
Yes
Bonneville Power
Administration
Yes
Midwest ISO
Standards
Collaborators
Yes
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine Corporation
Yes
Western Area Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
American Electric
Power
Yes
December 30, 2009
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Organization
Yes or No
Manitoba Hydro
Yes
Georgia
Transmission
Corporation
Yes
Illinois Municipal
Electric Agency
Yes
Duke Energy
Yes
MRO NSRS
Yes
Xcel Energy
Yes
American
Transmission
Company
Yes
December 30, 2009
Question 7 Comment
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Consideration of Comments on Project 2006-06 Reliability Coordination
8.
Do you agree with the revisions to the Requirements in IRO-001-2 as shown in the posted Standard? If not,
please explain in the comment area.
Summary Consideration: Stakeholders generally agreed with the revisions to the requirements. Several stakeholders
suggested adding the words “an issued” before “directive in R3. The RC SDT agreed and made the change. No further
revisions were made to the requirements.
Organization
Yes or No
Northwest LSE
Group
No
Question 8 Comment
To reduce the compliance burden on smaller entities that would never receive a Reliability Coordinator directive and reduce
needless Regional Entity auditing, it would be most helpful to require the RC to publish its list of entities responsible for
receiving reliability directives.
Also, any Registered Entity should be able to request copies of digital audio recordings or transcripts of the audio recordings
if available from the RC.
Response: The RC SDT thanks you for your comment. An RC may issue a directive to any registered entity within its footprint. The burden of
compliance is assigned by the NERC registration process and is outside of the scope of this drafting team.
The requirements of IRO-001 do not preclude an entity from requesting copies of digital audio recordings or transcripts from the RC.
Northeast Power
Coordinating
Council
No
Add “an issued” to the wording as shown following: The Each Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and/or Purchasing-Selling Entity shall
immediately confirm the ability to comply with the directive or inform the its Reliability Coordinator upon recognition of its
inability to perform the issued directive.
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has added “an issued” before directive. We have also changed
directive to Reliability Directive and included the definition at the beginning of IRO-001 and COM-002
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.
SERC OC
Standards
Review Group
No
If R2 of IRO-001-1 is retired, what process is in place to ensure that reliability plans are kept up to date and are reviewed to
approve footprint changes?
Response: The RC SDT thanks you for your comment. As stated in the posted implementation of IRO-001, this is covered in NERC Rules of
Procedure, Section 503, item 2.2:
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Organization
Yes or No
Question 8 Comment
“Regional entities shall verify that all balancing authorities and transmission operators are under the responsibility of a reliability coordinator”.
The RC SDT proposed retiring R2 and R5 as the regional reliability plan is a “how” document that shows how an RC will comply with all other NERC
Standards, making this requirement redundant.
FirstEnergy
No
Regarding the retirement of IRO-001-1 R7 We are not convinced that this requirement is redundant with IRO-014-1 R1. The
existing requirement requires the RC to "have clear, comprehensive coordination agreements with adjacent RCs to ensure
that SOL or IROL violation mitigation requiring actions in adjacent RC areas are coordinated". IRO-014-1 R1 requires
agreements for coordination of actions between RCs to support Interconnection reliability, but it does not specifically require
"clear" and "comprehensive" agreements to mitigate SOL or IROL violations. For IRO-001-1 R7 to be properly retired, the
"mitigation of SOL and IROL violations" should be explicitly stated in IRO-014-2 R1 as one of the items to be addressed in
the RC's Operating Procedure, Process, or Plan.
Response: The RC SDT thanks you for your comment. The RC SDT believes that R1.6 of IRO-014-2 addresses your concern as the procedures,
processes or plans include:
Authority to act to prevent and mitigate conditions which could cause Adverse Reliability Impacts to other Reliability Coordinator Areas.
The definitions of each are:
IROL: A System Operating Limit that, if violated, could lead to instability, uncontrolled separation, or Cascading Outages that adversely impact the
reliability of the Bulk Electric System.
Adverse Reliability Impacts: The impact of an event that results in Bulk Electric System instability; uncontrolled separation or Cascading.
Midwest ISO
Standards
Collaborators
No
We agree with many of the changes. However, we believe R5 is not necessary for reliability. We agree the RC should notify
impacted entities when the transmission problem has been mitigated; however, if the RC fails to notify the impacted entities,
it will not result in an Adverse Reliability Impact. Thus, it is not necessary as a sanctionable requirement.
Response: The RC SDT thanks you for your comment. The RC SDT concurs that Adverse Reliability Impacts will not result from an RC not notifying
impacted entities when a problem has been mitigated. However, impacted entities may have taken actions when the problem arose. These entities
need to be informed that the problem has been mitigated so that they can return to normal operations. R5 notifies entities when the system is in a
stable state and facilitates Interpersonal Communication between entities.
Liberty Electric
Power LLC
No
Similar objection to COM-002-3: There should be a requirement to the RC to declare the nature of the directive, emergency
or economic.
Response: The RC SDT thanks you for your comment. The reliability standards do not address economic issues. The RC SDT has developed a
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Yes or No
Question 8 Comment
proposed definition of Reliability Directive that should address your concern.
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.
Manitoba Hydro
No
R5 does not make sense as it doesn’t create an adverse reliability impact should the RC fail to notify impacted entities.
Response: The RC SDT thanks you for your comment. The RC SDT concurs that Adverse Reliability Impacts will not result from an RC not notifying
impacted entities when a problem has been mitigated. However, impacted entities may have taken actions when the problem arose. These entities
need to be informed that the problem has been mitigated so that they can return to normal operations. R5 let’s entities know when the system is in a
stable state and facilitates Interpersonal Communication between entities.
Illinois Municipal
Electric Agency
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group.
In addition, while we agree with the proposed revisions to IRO-001-2 R2, IMEA recommends (as indicated in our comments
to Question 4) that a reference be made to COM-002-3 R1 in IRO-001-2 R2. By including this reference, it is understood the
applicable entities successfully repeated the directive in order to comply with the directive.
Response: The RC SDT thanks you for your comment. The RC SDT concurs that Adverse Reliability Impacts will not result from an RC not notifying
impacted entities when a problem has been mitigated. However, impacted entities may have taken actions when the problem arose. These entities
need to be informed that the problem has been mitigated so that they can return to normal operations. R5 notifies entities when the system is in a
stable state and facilitates Interpersonal Communication between entities.
We have included our proposed definition of Reliability Directive in both COM-002 and IRO-001 and used the term in the appropriate requirements.
This will provide the linkage you suggest.
Hydro-Québec
TransEnergie
(HQT)
No
Add “an issued” to the wording as shown following: Each Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall inform its
Reliability Coordinator upon recognition of its inability to perform “an issued” directive.
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has added “an issued” before directive. We have also changed
directive to Reliability Directive and included the definition at the beginning of IRO-001 and COM-002.
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.
Northeast Utilities
No
December 30, 2009
The intent of R3 is not clear - i.e., " shall inform its Reliability Coordinator upon recognition of its inability to perform a
directive". Does this requirement pre-suppose a directive has been given? Suggest adding clarifying language that
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Organization
Yes or No
Question 8 Comment
indicates that the requirement is applicable subsequent to a directive being received. It is our belief that the wording of
Measure M3 supports the suggested changes to R3.
Response: The RC SDT thanks you for your comment. R3 has been revised to add clarity per your comment:
R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity shall inform its Reliability Coordinator upon recognition of its inability to perform an issued Reliability Directive. [Violation Risk Factor:
High] [Time Horizon: Real-time Operations and Same Day Operations]
Independent
Electricity System
Operator
No
Comments: Change “inability to perform a directive.” to “inability to perform an issued directive.”
Response: The RC SDT thanks you for your comment. The RC SDT agrees and has added “an issued” before directive. We have also changed
directive to Reliability Directive and included the definition at the beginning of IRO-001 and COM-002.
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency
MRO NSRS
No
MRO NSRS agrees with many of the changes. However, we believe R5 is not necessary for reliability. MRO NSRS agrees
the RC should notify impacted entities when the transmission problem has been mitigated; however, if the RC fails to notify
the impacted entities, it will not result in an Adverse Reliability Impact. Thus, it is not necessary as a sanctionable
requirement.
Response: The RC SDT thanks you for your comment. The RC SDT concurs that Adverse Reliability Impacts will not result from an RC not notifying
impacted entities when a problem has been mitigated. However, impacted entities may have taken actions when the problem arose. These entities
need to be informed that the problem has been mitigated so that they can return to normal operations. R5 notifies entities when the system is in a
stable state and facilitates Interpersonal Communication between entities.
Xcel Energy
No
R6 – while this requirement has merits, it does not appear to fall under the stated purpose of the standard “To establish
requirements for issuance of and complying with Reliability
Coordinator directives or notification within the Reliability Coordinator Areas.”. Either the purpose should be modified or this
requirement should be placed in a more appropriate location, e.g. IRO-002-2 (along with R8).
Response: The RC SDT thanks you for your comment. The RC SDT moved this requirement into IRO-001 from IRO-002 rather than have a single
requirement standard.
December 30, 2009
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Organization
Yes or No
Western Area
Power
Administration
Yes
Question 8 Comment
Suggest changing the word "complying" to "compliance" in the purpose statement.
Response: The RC SDT thanks you for your comment. The RC SDT had made the suggested edit.
Bonneville Power
Administration
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine
Corporation
Yes
Southern
Company
Yes
ReliabilityFirst
Corporation
Yes
American Electric
Power
Yes
Georgia
Transmission
Corporation
Yes
Duke Energy
Yes
American
Transmission
Company
Yes
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
9. Do you agree with the revisions to the Measures in IRO-001-2 as shown in the posted Standard? If not, please
explain in the comment area.
Summary Consideration: Stakeholders agreed with the measures for IRO-001-2. The measure M3 was revised to reflect the
revision to R3 and the word, “directive” was changed to the defined term, “Reliability Directive” in M1 through M3. No other
revisions were suggested for the measures.
Organization
Yes or No
Northwest LSE
Group
No
Question 9 Comment
Only in making the Measures agree with the suggested changes to the requirements above.
Response: The RC SDT thanks you for your comment. The measures were revised as appropriate to reflect revisions to the requirements.
SERC OC
Standards Review
Group
No
The measures should indicate how long records should be kept to verify compliance with the requirements.
Response: The RC SDT thanks you for your comment. This is covered in the Data Retention section of the Standard.
Midwest ISO
Standards
Collaborators
No
Measurement 5 needs to be struck if R5 is struck per question 8.
Response: The RC SDT thanks you for your comment. The RC SDT retained R5 and M5. Please see discussion above in Q8.
Manitoba Hydro
No
Measure for R5 would need to be struck should R5 be struck as per question 8.
Response: The RC SDT thanks you for your comment. The RC SDT retained R5 and M5. Please see discussion above in Q8.
Illinois Municipal
Electric Agency
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group.
Response: The RC SDT thanks you for your comment. The RC SDT retained R5 and M5. Please see discussion above in Q8.
December 30, 2009
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Organization
Yes or No
MRO NSRS
No
Question 9 Comment
Measurement 5 needs to be struck if R5 is struck per question 8.
Response: The RC SDT thanks you for your comment. The RC SDT retained R5 and M5. Please see discussion above in Q8.
Northeast Power
Coordinating
Council
Yes
Bonneville Power
Administration
Yes
FirstEnergy
Yes
IRC Standards
Review Committee
Yes
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine
Corporation
Yes
Western Area
Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Yes
December 30, 2009
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Organization
Yes or No
Question 9 Comment
Corporation
American Electric
Power
Yes
Georgia
Transmission
Corporation
Yes
Hydro-Québec
TransEnergie
(HQT)
Yes
Duke Energy
Yes
Northeast Utilities
Yes
Independent
Electricity System
Operator
Yes
American
Transmission
Company
Yes
December 30, 2009
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10.Do you agree with the revisions to the Violation Severity Levels in IRO-001-2 as shown in the posted Standard?
If not, please explain in the comment area.
Summary Consideration: Several stakeholders suggested revisions to the VSLs for R4 and R5. The RC SDT concurs that
improvements are warranted for the VSLs for R4 and R5. The VSLs have been changed accordingly. The VLS for R3 was
revised to add the word “issued” before Reliability Directive to match the revised requirement. The VSLs for R4 and R5 were
modified to clarify that if the responsible entity did not notify any others, then this is a Severe VSL.
Organization
Yes or No
Northwest LSE Group
No
Question 10 Comment
Only in making the Measures agree with the suggested changes to the requirements above.
Response: The RC SDT thanks you for your comment. The measures were revised to reflect changes to the requirements as necessary.
Northeast Power
Coordinating Council
No
(i)
R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to
issue an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High
VSL to: “failed to issue an alert to three, but not all, impacted”. and the Severe VSL to: “failed to issue an alert to
any or more than three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area. Some examples may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were
alerted, this would be a “Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be
a “High” violation. In this last case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation.
(ii)
(ii) R5: Similar changes as in R4 should also apply to High and Severe in R5.
Response: The RC SDT thanks you for your comment. We concur that improvements are warranted for the VSLs for R4 and R5. The VSLs have been
revised per your suggestion accordingly.
Midwest ISO Standards
Collaborators
No
The Commission stated in their order on VSLs in June of 2008 their preference for as many VSLs as possible. We
believe two VSLs are possible for R1 based on whether the RC is acting or directing actions to prevent versus mitigate.
Failure to mitigate should be Severe. Failure to prevent should be High because if the RC fails to act or direct action to
prevent, the Adverse Reliability Impact may still not happen if system conditions change. For the Moderate VSL of R2,
please remove the clause “but not all”. It is not necessary.
Response: The RC SDT thanks you for your comment. The VSL for R1 was revised as recommended. There is not a Moderate VSL for R2.
Liberty Electric Power
LLC
No
December 30, 2009
The VSL's have a "Severe" VSL attached to a GO who fails to inform the RC when the Go becomes aware it is are
unable to fully comply with a directive. However, the RC failing to inform two TO's - who potentially could have many
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Organization
Yes or No
Question 10 Comment
GOs supplying power to their systems - of an emergency is only a "Moderate" VSL.
Response: The RC SDT thanks you for your comment. The VSLs for R4 and R5 have been revised to more closely fit the intent of the requirements.
E.ON U.S.
No
E.ON U.S. suggests that the VSL for R4 should be binary with the Severe VSL for failing to notify all entities as per R4.
Partially meeting R4 in not consistent with the language in R4. E.ON U.S. also suggests that the VSL for R5 should be
binary with the Severe VSL for failing to notify all entities as per R5. Partially meeting R5 is not consistent with the
language in R5 but the reliability impact of partially meeting R5 is low.
Response: The RC SDT thanks you for your comment. The requirements R4 and R5 are not binary in nature and therefore do not meet the VSL
guideline for binary. We have revised the High and Severe VSLs for R4 and R5 (see comment of NPCC above).
Manitoba Hydro
No
Believe two VSLs are possible for R1 based on whether the RC is acting or directing actions to prevent versus mitigate.
Failure to mitigate should be Severe. Failure to prevent should be High because if the RC fails to act or direct action to
prevent, the Adverse Reliability Impact may still not happen if system conditions change. For the Moderate VSL of R2,
please remove the clause “but not all”. It is not necessary.
Response: The RC SDT thanks you for your comment. We concur with your suggestion to split the single VSL into two separate VSLs, one addressing
prevention and one mitigation. The VSLs for R1 have been changed accordingly.
Illinois Municipal Electric
Agency
No
IMEA supports the comments submitted by the MISO Standards Collaboration Group.
Response: The RC SDT thanks you for your comment. Please review the response to MISO SCG comments.
Hydro-Québec
TransEnergie (HQT)
No
(i)
R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to
issue an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High
VSL to: “failed to issue an alert to three, but not all, impacted”. and the Severe VSL to: “failed to issue an alert to
any or more than three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area. Some examples may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were
alerted, this would be a “Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be
a “High” violation. In this last case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation.
(ii)
R5: Similar changes as in R4 should also apply to High and Severe in R5.
Response: The RC SDT thanks you for your comment. We concur that improvements are warranted for the VSLs for R4 and R5. The VSLs have been
December 30, 2009
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Organization
Yes or No
Question 10 Comment
revised as you suggest.
Northeast Utilities
No
(i) R4: Since failing to issue an alert to 3 entities already attracts a “High” VSL, not doing so for ANY (i.e. failing to issue
an alert to all entities) or more than three should attract a “Severe” VSL. We suggest to change the High VSL to: “failed
to issue an alert to three, but not all, impacted”. and the Severe VSL to: “failed to issue an alert to any or more than
three impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. Some examples
may help to make our intent clearer: If there were 3 BAs, TOPs etc. and none were alerted, this would be a “Severe”
violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this would be a “High” violation. In this last case, if 4
BAs, TOPs etc. were not alerted, this would be a “Severe” violation.(ii) R5: Similar changes as in R4 should also apply
to High and Severe in R5.
Response: The RC SDT thanks you for your comment. We concur that improvements are warranted for the VSLs for R4 and R5. The VSLs have been
revised as you suggested.
Independent Electricity
System Operator
No
(i) R1: For clarity, we suggest changing “it” to “that”.R4: Since failing to issue an alert to 3 entities already attracts a
“High” VSL, not doing so for ANY (i.e. failing to issue an alert to all entities) or more than three should attract a “Severe”
VSL. We suggest to change the High VSL to: “failed to issue an alert to three, but not all, impacted”. and the Severe
VSL to: “failed to issue an alert to any or more than three impacted Transmission Operators and Balancing Authorities in
its Reliability Coordinator Area. Some examples may help to make our intent clearer: If there were 3 BAs, TOPs etc.
and none were alerted, this would be a “Severe” violation. If there were 6 BAs, TOPs etc. and 3 were not alerted, this
would be a “High” violation. In this last case, if 4 BAs, TOPs etc. were not alerted, this would be a “Severe” violation.(ii)
R5: Similar changes as in R4 should also apply to High and Severe in R5.
Response: The RC SDT thanks you for your comment. We concur that improvements are warranted for the VSLs for R4 and R5. The VSLs have been
revised as you suggested.
MRO NSRS
No
The Commission stated in their order on VSLs in June of 2008 their preference for as many VSLs as possible. MRO
NSRS believes two VSLs are possible for R1 based on whether the RC is acting or directing actions to prevent versus
mitigate. Failure to mitigate should be Severe. Failure to prevent should be High because if the RC fails to act or direct
action to prevent, the Adverse Reliability Impact may still not happen if system conditions change.
For the Moderate VSL of R2, please remove the clause “but not all”. It is not necessary.
Response: The RC SDT thanks you for your comment. We concur with your suggestion to split the single VSL into two separate VSLs, one addressing
prevention and one mitigation. The VSLs for R1 have been changed accordingly.
There is not a Moderate VSL for R2.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
Organization
Yes or No
SERC OC Standards
Review Group
Yes
Bonneville Power
Administration
Yes
FirstEnergy
Yes
PacifiCorp
Yes
Calpine Corporation
Yes
Western Area Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
American Electric Power
Yes
Georgia Transmission
Corporation
Yes
Duke Energy
Yes
December 30, 2009
Question 10 Comment
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Consideration of Comments on Project 2006-06 Reliability Coordination
11.Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the posted Standard? If not,
please explain in the comment area.
Summary Consideration: Stakeholders suggested revising R8 to include provisions for avoiding implementing actions that
would violate safety, equipment or regulatory or statutory requirements. The RC SDT agreed and added this to the
requirement. Other stakeholders suggested adding “For conditions or activities that impact other Reliability Coordinator
Areas,…” at the beginning of R1 and R3. The RC SDT agreed and added this to the requirements. The Time Horizons for R2
were revised as suggested to “Same Day Operations and Operations Planning”. Several stakeholders expressed concerns
regarding having R6-R8 as separate requirements. The intent of R6, R7, and R8 is to handle those things that arise that may
not have had a plan identified in advance. The RC SDT contends the requirements are adequate as written.
Organization
Yes or No
Northwest LSE
Group
Northeast Power
Coordinating
Council
Question 11 Comment
Abstain
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
Response: The RC SDT thanks you for your comment. The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to
eliminate a compound requirement (a requirement that contained multiple separate requirements). Each requirement is different and requires
different specific actions. Please see the posted implementation plan for IRO-014 for details.
http://www.nerc.com/docs/standards/sar/IRO-014-2_Implementation_Plan_Clean_2009July9.pdf
SERC OC
Standards Review
Group
No
Does the STD intend to give a Reliability Coordinator the authority to direct reliability outside their reliability area? This
appears to be in conflict with IRO-001.
Response: The RC SDT thanks you for your comment. IRO-014 deals with coordinating plans, processes and procedures ahead of time. The
requirements state that RCs will follow these agreed to plans, processes or procedures.
FirstEnergy
No
December 30, 2009
See our comments from Questions 8. If IRO-001 R7 is retired and deemed covered by IRO-014 R1, then IRO-014 R1
should include the "mitigation of SOL and IROL violations" as one of the items to be addressed in the RC's Operating
Procedure, Process, or Plan.
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Organization
Yes or No
Question 11 Comment
Response: The RC SDT thanks you for your comment. Please see response to question 8. The RC SDT did not make any revisions as this issue is
covered by R1.6 relating to Adverse Reliability Impacts.
IRC Standards
Review Committee
No
(1) R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating Procedure,
Process or Plan to other RCs required to take action. However, placing the burden on the same RC to obtain the
agreement of impacted RCs may not be appropriate since the RC experiencing the Adverse Reliability Impact may not be
able to force impacted RC to concur. We suggest the SDT to consider: a. Remove the bullet to require agreement from
the impacted RC; b. Add a new requirement that the impacted RC shall acknowledge the Operating Procedure, Process
or Plan with agreement or disagreement. In the event of disagreement, a reliability or legal reason or failure to implement
comparable actions should be given.
(2) We realize that R7 implies that the RC experiencing the Adverse Reliability Impact has come up with an alternative
plan when its initial plan was not agreed to, but the alternative may still be disagreed by the impacted RC. Simply
implementing the alternative plan, as stipulated in R8, could expose the impacted RC to operate in an unreliable or unsafe
domain. We therefore request the SDT to assess if any requirements need to be introduced to resolve this difference with
due regard to reliability concerns in both RC areas when agreement cannot be reached even on the alternative plan.
Response: The RC SDT thanks you for your comment.
1) R2 deals with procedures, processes and plans identified and developed ahead of time. If the plan of one RC requires action from another RC,
the RC SDT feels it is necessary to get agreement from the second RC to take action, otherwise the plan is not a plan that will maintain reliability.
The intent of R6, 7, and 8 is to handle those things that arise that may not have had a plan identified in advance. The RC SDT believes the
requirements are adequate as written.
2) We have modified R8 to allow RCs to avoid implementing actions that violate safety, equipment or regulatory or statutory requirement.
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified Adverse
Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan unless such actions would violate safety, equipment, or
regulatory or statutory requirements. . [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations
Midwest ISO
Standards
Collaborators
No
December 30, 2009
Requirements R2 and R8 need additional work. R2 appropriately requires the RC experiencing the Adverse Reliability
Impact to distribute its Operating Procedure, Process or Plan to other RCs required to take action. However, it
inappropriately places the burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to
agree. Rather R2 should remove the bullet to require agreement from the impacted RC and a new requirement should be
written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement or
disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable actions
should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This contributes to
reliability by forcing the impacted RC to take action if the action is reasonable.
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Organization
Yes or No
Question 11 Comment
Further, the drafting team needs to clarify that R2 also applies to the mitigation plan in R7. Because R7 requires the RC
experiencing the Adverse Reliability Impact to develop the mitigation plan, the mitigation plan may not be agreed to by the
impacted RC. The impacted RC may have a perfectly valid reliability, statutory, legal, or regulatory reason for not
agreeing to the mitigation plan. R8 still obligates the RC to implement the mitigation plan developed in R7 though it may
be contrary to reliability. R8 needs to allow the RC to refuse to implement the mitigation plan if the impacted RC has a
reliability, statutory, legal or regulatory reason. Further the drafting team should consider if the impacted RC could refuse
because the RC experiencing the Adverse Reliability Impact has not implemented comparable measures in their own
area. R8 as written could allow an RC to simply pass cost on to the neighboring RC in the name of reliability. For
example, the RC may not want to order a unit to be committed to avoid certain startup costs but they ask the neighboring
RC to start up a unit in their footprint.
Response: The RC SDT thanks you for your comment.
R2 deals with procedures, processes and plans identified and developed ahead of time. If the plan of one RC requires action from another RC, the
RC SDT feels it is necessary to get agreement from the second RC to take action, otherwise the plan is not a plan that will maintain reliability. The
intent of R6, R7, and R8 is to handle those things that arise that may not have had a plan identified in advance. The RC SDT believes the
requirements are adequate as written.
R7/R8: We have modified R8 to allow RCs to avoid implementing actions that violate safety, equipment or regulatory or statutory requirement.
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified Adverse
Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan unless such actions would violate safety, equipment, or
regulatory or statutory requirements. . [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
The second comment deals with economic issues and not with reliability. We cannot address economic issues, but it would be reasonable to
expect that plans developed in advance could include equity considerations. Also, it is possible to postulate a scenario where the RC experiencing
the Adverse Reliability Impact may not have actions to take that are effective and the other impacted RC could have very effective actions to take
and should take them regardless of whether the RC developing the mitigation plan has taken comparable measures in its own area.
Southern
Company
No
December 30, 2009
IRO-001-1 Requirement 3 states that, “The Reliability Coordinator shall have clear decision-making authority to act and to
direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, and Purchasing- Selling Entities within its Reliability Coordinator Area to preserve the
integrity and reliability of the Bulk Electric System.” This does not give one RC the authority to direct another RC.
Requirement 7 and 8 would allow one RC to give a directive to another RC if they disagree. This would allow an RC with
bad information to require another RC to carry out a mitigation plan that could degrade system reliability. For example,
RC1 identifies a possible SOL violation in RC2s reliability area due to RC1s generation pattern. RC1 and RC2 can’t agree
that there is a problem. In order to mitigate the SOL a mitigation plan is developed by RC1 that requires RC2 to redispatch
generation and reconfigure transmission in RC2’s area so that the generation and transmission in RC1’s area won't have
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Organization
Yes or No
Question 11 Comment
to be redispatched or reconfigured. Suggested rewording of R7 and R8
R7. When Reliability Coordinators can not agree that a problem exists a mitigation plan will be developed by each
Reliability Coordinator that will restore system reliability in their respective reliability areas. [Violation Risk Factor:
Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed to relieve the identified Adverse
Reliability Impact in their reliability area when the impacted Reliability Coordinators can not agree that a problem exists.
[Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Response: The RC SDT thanks you for your comment. IRO-014 deals with coordinating plans, processes and procedures ahead of time. The
requirements state that RCs will follow these plans processes or procedures. We have modified R8 to allow RCs to avoid implementing actions that
violate safety, equipment or regulatory or statutory requirement. The intent of R6, R7, and R8 is to handle those things that arise that may not have
had a plan identified in advance.
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified Adverse Reliability
Impact when the impacted Reliability Coordinators can not agree on a mitigation plan unless such actions would violate safety, equipment, or regulatory or
statutory requirements. . [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
Manitoba Hydro
No
Requirements R2 and R8 need additional work. R2 appropriately requires the RC experiencing the Adverse Reliability
Impact to distribute its Operating Procedure, Process or Plan to other RCs required to take action. However, it
inappropriately places the burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to
agree. Rather R2 should remove the bullet to require agreement from the impacted RC and a new requirement should be
written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement or
disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable actions
should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This contributes to
reliability by forcing the impacted RC to take action if the action is reasonable.
Further, the drafting team needs to clarify that R2 also applies to the mitigation plan in R7. Because R7 requires the RC
experiencing the Adverse Reliability Impact to develop the mitigation plan, the mitigation plan may not be agreed to by the
impacted RC. The impacted RC may have a perfectly valid reliability, statutory, legal, or regulatory reason for not
agreeing to the mitigation plan. R8 still obligates the RC to implement the mitigation plan developed in R7 though it may
be contrary to reliability. R8 needs to allow the RC to refuse to implement the mitigation plan if the impacted RC has a
reliability, statutory, legal or regulatory reason. Further the drafting team should consider if the impacted RC could refuse
because the RC experiencing the Adverse Reliability Impact has not implemented comparable measures in their own
area. R8 as written could allow an RC to simply pass cost on to the neighboring RC in the name of reliability. For
example, the RC may not want to order a unit to be committed to avoid certain startup costs but they ask the neighboring
RC to start up a unit in their footprint.
December 30, 2009
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Organization
Yes or No
Question 11 Comment
Response: The RC SDT thanks you for your comment.
R2 deals with procedures, processes and plans identified and developed ahead of time. If the plan of one RC requires action from another RC, the
RC SDT feels it is necessary to get agreement from the second RC to take action, otherwise the plan is not a plan that will maintain reliability. The
intent of R6, R7, and R8 is to handle those things that arise that may not have had a plan identified in advance. The RC SDT contends the
requirements are adequate as written.
R8: We have modified R8 to allow RCs to avoid implementing actions that violate safety, equipment or regulatory or statutory requirement.
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified Adverse
Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan unless such actions would violate safety, equipment, or
regulatory or statutory requirements. . [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations
The second comment deals with economic issues and not with reliability. We cannot address economic issues, but it would be reasonable to
expect that plans developed in advance could include equity considerations. Also, it is possible to postulate a scenario where the RC experiencing
the Adverse Reliability Impact may not have actions to take that are effective and the other impacted RC could have very effective actions to take
and should take them regardless of whether the RC developing the mitigation plan has taken comparable measures in its own area.
Hydro-Québec
TransEnergie
(HQT)
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
Response: The RC SDT thanks you for your comment. The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to
eliminate a compound requirement. Each requirement is different and requires different specific actions. Please see the posted implementation
plan for IRO-014 for details.
http://www.nerc.com/docs/standards/sar/IRO-014-2_Implementation_Plan_Clean_2009July9.pdf
Duke Energy
No
R1 introduces the concept of “impacted Reliability Coordinators” which is unclear. Revise R1 as follows: R1. For
conditions or activities that may impact other Reliability Coordinator Areas, each Reliability Coordinator shall have
Operating Procedures, Processes, or Plans for notification, exchange of information or coordination of actions with those
impacted Reliability Coordinators to support Interconnection reliability. These Operating Procedures, Processes, or Plans
shall collectively address the following:
R2 Time Horizon should not include Long-term Planning.
R3 is unclear. Revise R3 as follows:R3. For conditions or activities that may impact other Reliability Coordinator Areas,
each Reliability Coordinator shall make notifications and exchange reliability-related information with those impacted
Reliability Coordinators using its predefined Operating Procedures, Processes, or Plans, or other available means to
December 30, 2009
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Organization
Yes or No
Question 11 Comment
accomplish the notifications and exchange of reliability-related information.
R4 could be interpreted to require a weekly conference call even if there is no need for a call. Revise R4 as follows:R4.
When there are conditions or activities that may impact other Reliability Coordinator areas, each Reliability coordinator
shall participate in agreed upon conference calls, at least weekly, and other communication forums with those impacted
Reliability Coordinators.”
R5 “ Insert the word “all” before impacted Reliability Coordinators for clarity.”
R6, R7 and R8 are interrelated and unclear. Combine these three requirements into one clear requirement as follows:
R6. When the identified Adverse Reliability Impact cannot be agreed to by the impacted Reliability Coordinators, the
Reliability Coordinator with the identified Adverse Reliability Impact shall develop a mitigation plan and each impacted
Reliability Coordinator shall implement the plan.
Response: The RC SDT thanks you for your comment.
R1: We have revised R1 to include the phrase “For conditions or activities that impact other Reliability Coordinator Areas,…” We removed the
word “may” to tighten up the requirement.
R2: The RC SDT removed Long term Planning and revised the Time Horizon of R2 to match that of R1: Same Day Operations and Operations Planning
R3: We have revised R3 to include the phrase “For conditions or activities that impact other Reliability Coordinator Areas,…” We removed the
word “may” to tighten up the requirement.
R4: The collective experience of the RC SDT members indicates a clear need to have at least weekly conference calls among impacted Reliability
Coordinators among impacted Reliability Coordinators.
R5: The RC SDT agrees and added the word “all” as suggested.
R6-8: These requirements were developed from IRO-016, R1 which was a compound requirement (it contained multiple requirements for different
actions in a single requirement). The RC SDT separated these into distinct requirements for clarity and measurability.
Northeast Utilities
No
The intents of Requirements R7 and R8 are addressed in R6, and do not add anything. Suggest removing R7 and R8.
Response: The RC SDT thanks you for your comment. The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to
eliminate a compound requirement (it contained multiple requirements for different actions in a single requirement. Each requirement is different
and requires different specific actions. Please see the posted implementation plan for IRO-014 for details.
http://www.nerc.com/docs/standards/sar/IRO-014-2_Implementation_Plan_Clean_2009July9.pdf
December 30, 2009
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Organization
Yes or No
Independent
Electricity System
Operator
No
Question 11 Comment
(i)
Definition of Adverse Reliability Impact is duplicated as it is already defined in IRO-001-2
(ii)
We do not see the need for R7 and R8 since R6 already stipulates the necessary actions to be taken, it is not
necessary for the Reliability Coordinator with the identified Adverse Reliability Impact to develop (re-develop?) a
mitigation plan when the impacted Reliability Coordinators did not agree that the problem exists. What may be
needed is the insertion of “shall develop a mitigation plan” before “notify impacted Reliability Coordinators” in R5.
We suggest removing these requirements (R7 and R8).
Response: The RC SDT thanks you for your comment. i)…The SDT acknowledges that the definition of Adverse Reliability Impact is duplicated in
IRO-001-2 and in IRO-014-2. The SDT repeated it in the two standards to facilitate review and consistency. When the standards are approved, the
definition will be moved into the NERC Glossary of Terms…only once.
ii) The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to eliminate a compound requirement (it contained multiple
requirements for different actions in a single requirement. Each requirement is different and requires different specific actions. Please see the
posted implementation plan for IRO-014 for details.
http://www.nerc.com/docs/standards/sar/IRO-014-2_Implementation_Plan_Clean_2009July9.pdf
MRO NSRS
No
In bullet 2.1 of Requirement R2, what does the requirement that all RCs that are required to take action must agree to it
really mean? Does this mean that if the RCs don’t agree that in reality an Operating Procedure, Process or Plan doesn’t
really exist and thus is not subject to R2? Further, how can one RC require another RC to agree with an Operating
Procedure, Process or Plan? Either they agree or they don’t. Isn’t what is really needed is a requirement for the impacted
RC to review and acknowledge the plan? That is give it a thumbs up or a thumbs down?
In requirement R4, the clause “at least weekly” should be struck. If the RCs agree that a bi-weekly call is sufficient unless
conditions change significantly why must they be held to a weekly standard. Our experience has been that most RCs
participate in daily calls anyway based on an agreed need.
Please strike IRO-014-2 R7 as it is redundant with IRO-001-2 R1. IRO-001-2 R1 already requires that RC with the
identified Adverse Reliability Impact to act or direct actions to prevent or mitigate the magnitude or duration of the event.
MRO NSRS does not believe IRO-014-2 R8, yet properly considers why the RCs may not agree on a mitigation plan. If
RC A develops a mitigation plan for an identified Adverse Reliability Impact on their system and RC B does not agree with
RC A’s mitigation plan, RC B will be in violation of R8 if they do not follow the mitigation plan. What if the mitigation plan
has an Adverse Reliability Impact on RC B’s footprint? They should not have to follow the mitigation plan.
Response: The RC SDT thanks you for your comment. Requirement R2 addresses processes, procedures, and plans developed in advance. Such
plans reasonably can be expected to contain agreement. The goal is to ensure reliability; refusal to agree based upon equity issues is
unacceptable. If inability to agree is based upon differing opinions as to whether the problem exists, then the coordination requirements are out of
December 30, 2009
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Organization
Yes or No
Question 11 Comment
compliance. Technical assessments reasonably can be expected to predict the same effects upon the system.
The collective experience of the RC SDT members indicates a clear need to have at least weekly conference calls.
IRO-014-2 R7 applies to scenarios and coordination between RCs. IRO-001-2 R1 applies to scenarios and coordination between an RC and TOPs,
BAs, GOPs, TSPs, LSEs, DPs, and PSEs within its RC Area. The SDT believes it is appropriate to leave both requirements in place.
R8: We have modified R8 to allow RCs to avoid implementing actions that violate safety, equipment or regulatory or statutory requirement.
R8. Each impacted Reliability Coordinator shall implement the mitigation plan developed by the Reliability Coordinator who has the identified Adverse
Reliability Impact when the impacted Reliability Coordinators can not agree on a mitigation plan unless such actions would violate safety, equipment, or
regulatory or statutory requirements. . [Violation Risk Factor: Medium][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations
Bonneville Power
Administration
Yes
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine
Corporation
Yes
Western Area
Power
Administration
Yes
ReliabilityFirst
Corporation
Yes
American Electric
Power
December 30, 2009
Not applicable.
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Organization
Yes or No
Georgia
Transmission
Corporation
Question 11 Comment
N/A
Response: The RC SDT thanks you for your comment.
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
12.Do you agree with the revisions to the Measures in IRO-014-2 as shown in the posted Standard? If not, please
explain in the comment area.
Summary Consideration: Stakeholders agreed with the Measures, except to make conforming changes for revisions to the
requirements (M1, M3 and M8). The RC SDT has revised the measures based on the new requirements. One stakeholder
suggested revision to the Data Retention for R5-R8. Data Retention was revised for R5 to 12 months, however the RC SDT
believes that three years is the correct period for R6-8.
Organization
Yes or No
Northwest LSE
Group
Northeast Power
Coordinating
Council
Question 12 Comment
Abstain
No
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
Response: The RC SDT thanks you for your comment. R7 and R8 were not removed, therefore the measures will remain in place.
IRC Standards
Review Committee
No
Conforming changes to the Measurements will be required if changes as suggested in Question 11 are introduced.
Response: The RC SDT thanks you for your comment. The measures were revised to conform to the revised requirements.
Midwest ISO
Standards
Collaborators
No
Conforming changes to the Measurements will be required for accepted changes from question 11.
Manitoba Hydro
No
Conforming changes to the Measurements will be required for accepted changes from question 11.
Response: The RC SDT thanks you for your comment. The measures were revised to conform to the revised requirements.
Hydro-Québec
TransEnergie
(HQT)
No
December 30, 2009
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
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Organization
Yes or No
Question 12 Comment
Response: The RC SDT thanks you for your comment. R7 and R8 were not removed, therefore the measures will remain in place
Duke Energy
No
Need to revise the Measures to coincide with the recommended changes to the requirements in #11 above. Also under
Data Retention, 12 months of evidence is needed for R3, R4 and M3, M4. However 3 years plus the current year is
required for R5 through R8 and M5 through M8. We see no reason the data requirements to be different and believe 12
months is the proper amount of data retention.
Response: The RC SDT thanks you for your comment. The measures were revised to conform to the revised requirements. The RC SDT concurs
with the suggested revision to Data Retention for R5. The infrequency of occurrences of R6-8 clearly support a 3 year retention period.
Northeast Utilities
No
The intents of Measures M7 and M8 are addressed in M6, and do not add anything. Suggest removing M7 and M8.
Response: The RC SDT thanks you for your comment. R7 and R8 were not removed, therefore the measures will remain in place
Independent
Electricity System
Operator
No
Depending on the response of the SDT, changes to M5 to M8 may be required.
Response: The RC SDT thanks you for your comment. The measures were revised to conform to the revised requirements
MRO NSRS
No
Conforming changes to the Measurements will be required for accepted changes from question 11.
Response: The RC SDT thanks you for your comment. The measures were revised to conform to the revised requirements
SERC OC
Standards Review
Group
Yes
Bonneville Power
Administration
Yes
FirstEnergy
Yes
Liberty Electric
Power LLC
Yes
December 30, 2009
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Organization
Yes or No
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine
Corporation
Yes
Western Area
Power
Administration
Yes
Southern Company
Yes
ReliabilityFirst
Corporation
Yes
Question 12 Comment
American Electric
Power
Not applicable.
Georgia
Transmission
Corporation
N/A
December 30, 2009
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13.Do you agree with the revisions to the Violation Severity Levels in IRO-014-2 as shown in the posted Standard?
If not, please explain in the comment area.
Summary Consideration: Several stakeholders suggested developing four VSLs for R5. Typically, in the course of BES
operations, impacted Reliability Coordinators will be a small number. The SDT effort in this regard, was to write the VSLs to
represent both the large and small scenario containing an Adverse Reliability Impact. The essence of the severe VSL is that the
RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of the moderate VSL is that the
RC notified one other RC, however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately addressed
the large and small scenarios. Other stakeholders suggested four VSLs for R4. The essence of R4 is written to require
impacted RC’s to talk at least weekly and is singular in nature. VSL’s can not be written for conference calls that exceed the
singular requirement.
Organization
Yes or No
Northwest LSE
Group
Northeast Power
Coordinating
Council
Question 13 Comment
Abstain
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are graded
according to the number of impacted RCs that need to be notified. For example, Low for missing one, Moderate for
missing two, High for missing three, Severe for missing four or more. (ii) We do not have any issue with the binary nature
of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on the
SDT’s response to our comments under Q11.
Response: The RC SDT thanks you for your comment. Typically, in the course of BES operations, impacted Reliability Coordinators will be a
small number. The SDT effort in this regard, was to write the VSLs to represent both the large and small scenario containing an Adverse Reliability
Impact. The essence of the severe VSL is that the RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of
the moderate VSL is that the RC notified one other RC, however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately
addressed the large and small scenarios.
The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to eliminate a compound requirement (a single requirement that
contained multiple requirements). Each requirement is different and requires different specific actions. Please see the posted implementation plan
for IRO-014 for details; as such, the VSL’s remain.
IRC Standards
Review
Committee
No
December 30, 2009
(1) In the Commission’s June 2008 order on VSLs, they expressed their preference for having as many VSLs as possible.
We believe that four VSLs could be written for R4 based on the number of conference calls that are participated in. We
also believe this would be consistent with the Commission’s guideline 4 because the requirement is written in the plural,
that is conference calls, so all conference calls must be considered in aggregate. Thus, failure to participate in more than
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Organization
Yes or No
Question 13 Comment
one conference call does not represent distinct violations but a single violation.
(2) Four VSLs should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is
redundant with the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any. Note:
CAISO abstains from these comments.
Response: The RC SDT thanks you for your comment.
1) The Commission’s June 2008 stated a preference for as many as possible, however the SDT believes the essence of this statement was to write
multiple VSLs only where appropriate, not to do so simply because it is possible. Further, the essence of R4 is written to require impacted RC’s to
talk at least weekly and is singular in nature. VSL’s can not be written for conference calls that exceed the singular requirement.
2) Typically, in the course of BES operations, impacted Reliability Coordinators will be a small number. The SDT effort in this regard, was to write
the VSLs to represent both the large and small scenario containing an Adverse Reliability Impact. The essence of the severe VSL is that the RC did
not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of the moderate VSL is that the RC notified one other RC,
however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately addressed the large and small scenarios.
Midwest ISO
Standards
Collaborators
No
In the Commission’s June 2008 order on VSLs, they expressed their preference for having as many VSLs as possible.
We believe that four VSLs could be written for R4 based on the number of conference calls that are participated in. We
also believe this would be consistent with the Commission’s guideline 4 because the requirement is written in the plural,
that is conference calls, so all conference calls must be considered in aggregate. Thus, failure to participate in more than
one conference call does not represent distinct violations but a single violation.
Four VSLs should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is
redundant with the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any.
Response: The RC SDT thanks you for your comment. The Commission’s June 2008 stated a preference for as many as possible, however the
SDT believes the essence of this statement was to write multiple VSLs only where appropriate, not to do so simply because it is possible. Further,
the essence of R4 is that it is written to require impacted RC’s to talk at least weekly and is singular in nature. VSL’s can not be written for
conference calls that exceed the singular requirement.
Typically, in the course of BES operations, impacted Reliability Coordinators will be a small number. The SDT effort in this regard, was to write the
VSsL to represent both the large and small scenario containing an Adverse Reliability Impact. The essence of the severe VSL is that the RC did not
notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of the moderate VSL is that the RC notified one other RC,
however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately addressed the large and small scenarios.
Southern
Company
No
December 30, 2009
Reliability problems identified in other reliability areas are based on modeling information obtained from another reliability
region. The fact that one RC will not agree that the model of an adjacent RC's reliability area may be more accurate than
their model of the adjacent reliability area is no reason to impose a severe violation on the RC with the more accurate
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Organization
Yes or No
Question 13 Comment
model of their own reliability region.
Example: RC1 identifies a contingency overload of a transformer bank in an adjacent reliability area. The transformer
bank was replaced the week before with a larger bank. When RC1 contacts RC2, RC2 explains that the bank overload is
not valid because of the replacement. RC2 does not identify a problem due to the fact that the model RC2 is using has
been updated with the new transformer bank. RC1 will not agree and requires RC2 to open a tie line with another
reliability area to relieve the contingency overload. If RC2 does not follow the instructions of RC1, making the
interconnection weaker to relieve a problem that does not exists, RC2 is out of compliance and a severe violation will be
imposed.
Response: The RC SDT thanks you for your comment. The scenario you describe is essentially a modeling problem, as such the discrepancy
would be vetted and corrected during the discovery phase. Further, an RC1 cannot tell RC2 how to rate facilities owned by entities within the RC2
area. The SDT believes that your scenario would play out like this: RC1 calls RC2 and says, “we show an overload on transformer bank X.” RC2
says, “we do not, what rating are you using?” RC1 replies with the old rating, RC2 states that it is wrong, and here is the correct rating, which RC1
implements, problem solved. RC1 cannot come back and say the rating that you have for transformer bank X is incorrect. Each entity within the
RC Area (TO or GO) is responsible for the rating of the facilities it owns. (Taking the scenario even farther, if RC1 believes that the TO or GO has
an incorrect rating, then RC1 can challenge the rating methodology of that TO or GO under the FAC standards.)
Manitoba Hydro
No
Believe that four VSLs could be written for R4 based on the number of conference calls that are participated in. Four
VSLs should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is redundant
with the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any.
Response: The RC SDT thanks you for your comment. In regards to R4: The essence of R4 is that it is written to require impacted RC’s to talk at
least weekly and is singular in nature. VSL’s can not be written for conference calls that exceed the singular requirement.
In regards to R5: Typically, in the course of BES operations, impacted Reliability Coordinators will be a small number. The SDT effort in this
regard, was to write the VSL to represent a typical scenario containing an Adverse Reliability Impact. The essence of the severe VSL is that the RC
did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of the moderate VSL is that the RC notified one other
RC, however did not notify the remaining impacted RC’s.
Hydro-Québec
TransEnergie
(HQT)
No
(i)
Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are
graded according to the number of impacted RCs that need to be notified. For example, Low for missing one,
Moderate for missing two, High for missing three, Severe for missing four or more.
(ii)
We do not have any issue with the binary nature of the VSLs for R6, R7 and R8, but they may need to be revised
(wording change and/or removal) depending on the SDT’s response to our comments under Q11.
Response: The RC SDT thanks you for your comment. Typically, in the course of BES operations, impacted Reliability Coordinators will be a
December 30, 2009
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Organization
Yes or No
Question 13 Comment
small number. The SDT effort in this regard, was to write the VSL to represent both the large and small scenario containing an Adverse Reliability
Impact. The essence of the severe VSL is that the RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of
the moderate VSL is that the RC notified one other RC, however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately
addressed the large and small scenarios.
The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to eliminate a compound requirement (a single requirement that
contained multiple requirements). Each requirement is different and requires different specific actions. Please see the posted implementation plan
for IRO-014 for details; as such, the VSL’s remain.
Duke Energy
No
Need to revise the VSLs to coincide with recommended changes to the requirements in #11 above.
Response: The RC SDT thanks you for your comment. The VSLs were modified to align with changes made to the requirements. Please see the
response to #11. The SDT adopted several, but not all of your suggestions.
Northeast Utilities
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe, if the VSLs are graded
according to the number of impacted RCs that need to be notified. For example, Low for missing one, Moderate for
missing two, High for missing three, Severe for missing four or more.(ii) We do not have any issue with the binary nature
of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on the
SDT’s response to our comments under Q11.
Response: The RC SDT thanks you for your comment. Typically, in the course of BES operations, impacted Reliability Coordinators will be a
small number. The SDT effort in this regard, was to write the VSL to represent both the large and small scenario containing an Adverse Reliability
Impact. The essence of the severe VSL is that the RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of
the moderate VSL is that the RC notified one other RC, however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately
addressed the large and small scenarios.
The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to eliminate a compound requirement (a single requirement that
contained multiple requirements). Each requirement is different and requires different specific actions. Please see the posted implementation plan
for IRO-014 for details; as such, the VSL’s remain.
Independent
Electricity System
Operator
No
(i) Arguably, all four VSLs could be developed as opposed to just having the Moderate and Severe if the VSLs are graded
according to then number of impacted RCs that need to be notified. For example, Low for missing one, Moderate for
missing two, High for missing three, Severe for missing four or more.(ii) We do not have any issue with the binary nature
of the VSLs for R6, R7 and R8, but they may need to be revised (wording change and/or removal) depending on the
SDT’s response to our comments under Q11.
Response: The RC SDT thanks you for your comment. Typically, in the course of BES operations, impacted Reliability Coordinators will be a
December 30, 2009
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Organization
Yes or No
Question 13 Comment
small number. The SDT effort in this regard, was to write the VSL to represent both the large and small scenario containing an Adverse Reliability
Impact. The essence of the severe VSL is that the RC did not notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of
the moderate VSL is that the RC notified one other RC, however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately
addressed the large and small scenarios.
The RC SDT developed R5-R8 of IRO-014 from original IRO-016, R1. This was done to eliminate a compound requirement (a single requirement that
contained multiple requirements). Each requirement is different and requires different specific actions. Please see the posted implementation plan
for IRO-014 for details; as such, the VSL’s remain.
MRO NSRS
No
In the Commission’s June 2008 order on VSLs, they expressed their preference for having as many VSLs as possible.
The MRO NSRS believes that four VSLs could be written for R4 based on the number of conference calls that are
participated in. We also believe this would be consistent with the Commission’s guideline 4 because the requirement is
written in the plural, that is conference calls, so all conference calls must be considered in aggregate. Thus, failure to
participate in more than one conference call does not represent distinct violations but a single violation.
Four VSLs should be written for R5 based on the number of RCs notified. Furthermore, the current Severe VSL is
redundant with the Moderate VSL. Failure to notify one RC meets both VSL since Severe uses the word any.
Response: The RC SDT thanks you for your comment. The Commission’s June 2008 stated a preference for as many as possible, however the SDT
believes the essence of this statement was to write multiple VSLs only where appropriate, not to do so simply because it is possible. Further, the
essence of R4 is written to require impacted RC’s to talk at least weekly and is singular in nature. VSL’s can not be written for conference calls that
exceed the singular requirement.
Typically, in the course of BES operations, impacted Reliability Coordinators will be a small number. The SDT effort in this regard, was to write the
VSLs to represent both the large and small scenario containing an Adverse Reliability Impact. The essence of the severe VSL is that the RC did not
notify any (as in no one) impacted RC’s. As such, it should be severe. The essence of the moderate VSL is that the RC notified one other RC,
however did not notify the remaining impacted RC’s. The SDT felt the VSL’s appropriately addressed the large and small scenarios.
SERC OC
Standards
Review Group
Yes
Bonneville Power
Administration
Yes
FirstEnergy
Yes
December 30, 2009
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Organization
Yes or No
Liberty Electric
Power LLC
Yes
WECC Reliability
Coordinator
Yes
PacifiCorp
Yes
Calpine
Corporation
Yes
Western Area
Power
Administration
Yes
ReliabilityFirst
Corporation
Yes
Question 13 Comment
American Electric
Power
Not applicable.
Georgia
Transmission
Corporation
N/A
December 30, 2009
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Consideration of Comments on Project 2006-06 Reliability Coordination
14.If you have any other comments, not expressed in questions above, for the RC SDT on any of the other changes
made to this set of standards and their associated implementation plans, please provide them here.
Summary Consideration: Stakeholders suggested removing the Distribution provider and Generator Operator from the Data
Retention section for R1 of COM-001. Since these are not applicable entities in R1, they were removed from Data Retention for
the requirement.
Organization
Northeast Power Coordinating
Council
Question 14 Comment
NPCC appreciates the work of the Drafting Team. No additional comments.
Response: The RC SDT thanks you for your comment.
SERC OC Standards Review
Group
“The comments expressed herein represent a consensus of the views of the above named members of the SERC OC
Standards Review group only and should not be construed as the position of SERC Reliability Corporation, its board or its
officers.”
Response: The RC SDT thanks you for your comment.
Bonneville Power
Administration
Issue #2: Data Retention Why would the Distribution Provider and Generator Operator be required to store historical data
(three years in the case of Requirement R1 and Measure M1; twelve months in the case of Requirement R2 and Measure M2)
to show that these requirements and measures have been successfully implemented when these two entities (Distribution
Provider and Generator Operator) aren’t even included either in Requirements R1 and R2 or in Measure M1 and M2?It would
appear that they should only have to provide historical data for three months as required by the data retention time for
Requirement 3 and Measure 3.
Issue #1: Data Retention: The first bullet in this section states that all entities are responsible for retaining documents
associated with all Requirements and Measures associated with this standard. In reality, Requirements R1, R4, R5 and R6
and the corresponding Measures are the responsibility of the Reliability Coordinator. Requirements R2 and R3 and their
corresponding Measures are implemented by the Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider, Transmission Service Provider, Purchasing-Selling Entity and the Load Serving Entity. The Data
Retention section should be rewritten to reflect this so that entities are not required to maintain documents that they aren’t
suppose to even possess in some cases.
Response: The RC SDT thanks you for your comment. COM-001 removed DP and GOP from the data retention section regarding R1 and R2. IRO001-2 changed “all” to “applicable.”
December 30, 2009
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Organization
IRC Standards Review
Committee
Question 14 Comment
AESO abstains from commenting on VSLs. VSLs for Alberta will be developed by provincial authorities.
Response: The RC SDT thanks you for your comment.
E.ON U.S.
COM-001-2 R1 and R2 and the associated M1 and M2 are only applicable to the RC, TOP and BA but the “Data Retention”
for R1/R2 and M1/M2 require the DP and GOP to retain data for the Requirements and Measures. E.ON U.S. suggests that
the requirement for data retention of the DP and GOP be eliminated from the standard.
Response: The RC SDT thanks you for your comment. COM-001 removed DP and GOP from the data retention section regarding R1 and R2.
Illinois Municipal Electric
Agency
In order to minimize the number of reliability standards and the details covered in requirements - particularly those dealing with
communications - it is recommended that an up-front provision/requirement be included as part of the compliance registration
process that certain functional entities (e.g., DP, LSE, PSE, etc.) shall be responsible for providing the necessary information
to transact services and for complying with the directives/requests of certain functional authorities (e.g., BA, PC, RC, etc.) in
order to maintain/enhance reliability of the BES.
Response: The RC SDT thanks you for your comment. The registration process is not in the scope of this SDT project
Northeast Utilities
Northeast Utilities appreciates the work of the Drafting Team. No additional comments.
Response: The RC SDT thanks you for your comment.
Independent Electricity
System Operator
December 30, 2009
In our comments on the previous posting, we expressed a disagreement with a proposed to remove IRO-005, in particular the
latter part of R13, which stipulated that: In instances where there is a difference in derived limits, the Reliability Coordinator
and its Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving
Entities, and Purchasing-Selling Entities shall always operate the Bulk Electric System to the most limiting parameter. Our
rationale was that The FAC standards cover the methodology used in calculating SOLs and IROLs. Regardless of how these
limits are calculated, in practice there always exists the possibility that different entities may come up with SOLs/IROLs,
especially of the inter-ties, that could be different. Operating to the lowest SOLs/IROLs when more than one set exists is a
necessary requirement for reliable operation. The SDT responded by suggesting that this requirement is redundant with FAC014 which -014 states the requirement for developing and sharing SOL and IROL between the RC, PA, TP and TOP in both
the planning and operating time frames. However, this response fails to address the situation where during operation, the
situation of disagreeing SOLs or IROLs does arise. FAC-014 or any other standards do not currently have a requirement to
ensure that all entities operate to the lower limit before the difference is resolved. This leaves room for unreliable operation.
We suggest the SDT to consider restating this requirement somewhere. Note that this requirement is similar to R6 of IRO-014
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Organization
Question 14 Comment
that when in doubt, the more conservative approach should be taken. If it is necessary to have an R6 to deal with an uncertain
identification/notification of an Adverse Reliability Impact, we don’t see why it is not necessary to operate to a lower SOL or
IROL when there is an unresolved difference.
Response: The RC SDT thanks you for your comment. The SDT team still feels this is covered in FAC-010, 011, and 14. For real-time operations, as
you mention, this is covered with IRO-014, R6
December 30, 2009
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard COM-001-2 — Communications
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the first draft. The team is seeking
comments on the revised standards.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments on third posting
March 2010
2. Post Standards for pre-ballot period.
April 2010
3. Standards posted for initial and recirculation ballots.
May 2010
4. Standards sent to BOT for approval.
July 2010
5. Standards filed with regulatory authorities.
September 2010
Draft 3:
December 30, 2009
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Standard COM-001-2 — Communications
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any method that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any method that is able to serve as a substitute
for and is redundant to normal Interpersonal Communication and does not utilize the same
infrastructure (medium) as normal Interpersonal Communications.
Draft 3:
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate Interpersonal
Communication capabilities.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
4.6. Transmission Service Providers.
4.7. Load-Serving Entities.
4.8. Purchasing-Selling Entities.
5.
Effective Date:
The first day of the first calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
identify and test, on a quarterly basis, its Alternative Interpersonal Communications
capability used for communicating real-time operating information. If the test is
unsuccessful, the entity shall take action within 60 minutes to restore the identified
alternative or identify a substitute Alternative Interpersonal Communications
capability. [Violation Risk Factor: High][Time Horizon: Real-time Operations]
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities within 60 minutes of the detection of a failure of its normal
Interpersonal Communications capabilities that lasts 30 minutes or longer. [Violation
Risk Factor: Medium][Time Horizon: Real-time Operations]
R3. Unless dictated by law or otherwise agreed to, each Reliability Coordinator,
Transmission Operator, Balancing Authority, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Purchasing-Selling Entity and Distribution
Provider shall use English as the language for all inter-entity Bulk Electric System
(BES) reliability communications between and among operating personnel responsible
for the real-time generation control or operation of the interconnected BES. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]
R4. Each Distribution Provider and Generator Operator shall have Interpersonal
Communications capability with its Transmission Operator and Balancing Authority
Draft 3:
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Standard COM-001-2 — Communications
for the exchange of Interconnection and operating information. [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, that it identified and tested, on a quarterly
basis, alternative Interpersonal Communications capabilities used for communicating
real-time operating information. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it took action within 60 minutes to restore the
identified alternative or identified a substitute Interpersonal Communications
capability. (R1.)
M2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, it notified impacted entities within 60 minutes of the
detection of a failure of its normal communications capabilities that lasted 30 minutes
or longer. (R2.)
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Purchasing-Selling
Entity, and Distribution Provider shall have and provide upon request evidence that
could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, that will be used to
determine that its personnel used English as the language for all inter-entity BES
reliability communications between and among operating personnel responsible for the
real-time generation control or operation of the interconnected BES. If a language
other than English is used, each party shall have and provide upon request evidence
that could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, of agreement to use the
alternate language or the law that requires the use of an alternate language. (R3.)
M4. Each Distribution Provider and Generator Operator shall have and provide upon
request evidence that could include, but is not limited to operator logs, voice recordings
or transcripts of voice recordings, electronic communications, or equivalent that it had
Interpersonal Communications capabilities with its Transmission Operator and
Balancing Authority for the exchange of Interconnection and operating information.
(R4.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Draft 3:
December 30, 2009
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Standard COM-001-2 — Communications
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall keep the most recent three years of historical data (evidence) for
Requirement R1, Measure M1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall keep the most recent twelve months of historical data (evidence) for
Requirement R2, Measure M2.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Purchasing-Selling Entity, and Distribution Provider shall keep evidence for
Requirement R3, Measure M3 for the most recent 3 months. If a Reliability
Coordinator, Transmission Operator, Balancing Authority, Distribution Provider
or Generator Operator is found non-compliant with a requirement, it shall keep
information related to the noncompliance until the Compliance Enforcement
Authority finds it compliant.
Each Distribution Provider and Generator Operator shall keep the most recent
three years of historical data (evidence) for Requirement R4, Measure M4.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 3:
December 30, 2009
Page 5 of 8
2.
R#
R1
Violation Severity Levels
Lower VSL
The responsible entity tested
Alternative Interpersonal
Communications capability but failed
to take action within 60 minutes to
restore the identified alternative
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The responsible entity failed to test
its Alternative Interpersonal
Communications capability on a
quarterly basis.
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its normal
Interpersonal Communications
capabilities within 60 minutes.
The responsible entity failed to notify
the impacted entities in more than 80
minutes but less than or equal to 90
minutes.
The responsible entity failed to notify
any impacted entities of the failure of
its normal Interpersonal
Communications capabilities within
60 minutes.
OR
Failed to identify a substitute
Alternative Interpersonal
Communications capability
R2
R3
The responsible entity failed to notify
the impacted entities in more than 60
minutes but less than or equal to 70
minutes.
N/A
Draft 3: December 30, 2009
OR
OR
The responsible entity failed to notify
the impacted entities in more than 70
minutes but less than or equal to 80
minutes.
The responsible entity failed to notify
the impacted entities in more than 90
minutes.
N/A
N/A
The responsible entity failed to
provide evidence of legal
requirements or concurrence to use a
language other than English for
communications between and among
operating personnel responsible for
the real-time generation control or
operation of the interconnected BES
when a language other than English
was used.
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Standard COM-001-2 — Communications
R#
R4
Lower VSL
N/A
Draft 3: December 30, 2009
Moderate VSL
N/A
High VSL
The responsible entity failed to have
Interpersonal Communications
capability with its Transmission
Operator or Balancing Authority.
Page 7 of 8
Severe VSL
The responsible entity failed to have
Interpersonal Communications
capability with its Transmission
Operator and Balancing Authority.
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Standard COM-001-2 — Communications
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Standard COM-001-2 — Communications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
Draft 3: December 30, 2009
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Standard COM-001-2 — Communications
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008 – May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9 – November 20, 2009.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the first draft. The team is seeking
comments on the revised standards.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments on third posting
March 2010
2. Post Standards for pre-ballot period.
April 2010
3. Standards posted for initial and recirculation ballots.
May 2010
4. Standards sent to BOT for approval.
July 2010
5. Standards filed with regulatory authorities.
September 2010
Draft 32: July 12 December 30, 2009
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Standard COM-001-2 — Communications
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any method that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any method that is able to serve as a substitute
for and is redundant to normal Interpersonal Communication and does not utilize the same
infrastructure (medium) as normal Interpersonal Communications.
None
Draft 32: July 12 December 30, 2009
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate iInterpersonal
Ccommunication capabilities.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators.
4.6. Transmission Service Providers.
4.7. Load-Serving Entities.
4.8. Purchasing-Selling Entities.
5.
Effective Date:
The first day of the first calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
identify and test, on a quarterly basis, its Aalternative iInterpersonal Ccommunications
capabilityies used for communicating real-time operating information. If the test is
unsuccessful, the entity shall take action within 60 minutes develop a mitigation plan to
restore the identified alternative or identify a substitute Alternative its iInterpersonal
Ccommunications capabilityies. [Violation Risk Factor: LowerHigh][Time Horizon:
Real-time Operations]
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify impacted entities within 60 minutes of the detection of a failure (30 minutes or
longer) of its normal iInterpersonal Ccommunications capabilities that lasts 30 minutes
or longer. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
R3. Unless dictated by law or otherwise agreed to otherwise, each Reliability Coordinator,
Transmission Operator, Balancing Authority, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Purchasing-Selling Entity and Distribution
Provider shall use English as the language for all inter-entity Bulk Electric System
(BES) reliability communications between and among operating personnel responsible
for the real-time generation control and or operation of the interconnected BES.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
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Standard COM-001-2 — Communications
R4. Each Distribution Provider and Generatiorn Operator shall have Iinterpersonal
cCommunications capabilityies with its Transmission Operator and Balancing
Authority for the exchange of Interconnection and operating information. [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, that it identified and tested, on a quarterly
basis, alternative Iinterpersonal Ccommunications capabilities used for communicating
real-time operating information. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it took action within 60 minutes developed a
mitigation plan to restore the identified alternative or identified a substitute
iInterpersonal Ccommunications capabilityies. (R1.)
M2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to
operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, it notified impacted entities within 60 minutes of the
detection of a failure (30 minutes or longer) of their its normal communications
capabilities that lasted 30 minutes or longer. (R2.)
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Purchasing-Selling
Entity, and Distribution Provider shall have and provide upon request evidence that
could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, that will be used to
determine that its personnel used English as the language for all inter-entity Bulk
Electric SystemBES reliability communications between and among operating
personnel responsible for the real-time generation control and or operation of the
interconnected Bulk Electric SystemBES. If a language other than English is used,
each party shall have and provide upon request evidence that could include, but is not
limited to operator logs, voice recordings or transcripts of voice recordings, electronic
communications, or equivalent, of agreement to use the alternate language or the law
that requires the use of an alternate language. (R3.)
M4. Each Distribution Provider and Generatorion Operator shall have and provide upon
request evidence that could include, but is not limited to operator logs, voice recordings
or transcripts of voice recordings, electronic communications, or equivalent that it had
demonstrate the existence of its iInterpersonal Ccommunications capabilities with its
Transmission Operator and Balancing Authority for the exchange of Interconnection
and operating information. (R4.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
Draft 32: July 12 December 30, 2009
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Standard COM-001-2 — Communications
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority ,
Distribution Provider, and Generator Operator shall keep the most recent three
years of historical data (evidence) for Requirement R1, Measure M1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority,
Distribution Provider, and Generator Operator shall keep the most recent twelve
months of historical data (evidence) for Requirement R2, Measure M2.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Purchasing-Selling Entity, and Distribution Provider shall keep evidence for
Requirement R3, Measure M3 for the most recent 3 months. If a Reliability
Coordinator, Transmission Operator, Balancing Authority, Distribution Provider
or Generator Operator is found non-compliant with a requirement, it shall keep
information related to the noncompliance until the Compliance Enforcement
Authority finds it compliant.
Each Distribution Provider and Generator Operator shall keep the most recent
three years of historical data (evidence) for Requirement R4, Measure M4.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 32: July 12 December 30, 2009
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Standard COM-001-2 — Communications
2.
Violation Severity Levels
Draft 32: December 30July 10, 2009
Page 6 of 9
R1
The responsible entity tested
Aalternative iInterpersonal
Ccommunications
capabilityies but failed to take
action within 60 minutes to
restore the identified
alternative
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The responsible entity failed
to test the its Aalternative
Iinterpersonal
cCommunications
capabilityies on a quarterly
basis.
The responsible entity
notified at least one, but not
all, impacted entities of the
failure of its normal
Iinterpersonal
Ccommunications capabilities
within 60 minutes.
The responsible entity failed
to notify the impacted entities
in more than 80 minutes but
less than or equal to 90
minutes.N/A
The responsible entity failed
to notify any impacted
entities of the failure of their
its normal Iinterpersonal
Ccommunications capabilities
within 60 minutes.
OR
R2
Failed to identify a substitute
Alternative Interpersonal
Communications
capabilitydevelop a
mitigation plan when the test
failed.
The responsible entity failed
to notify the impacted entities
in more than 60 minutes but
less than or equal to 70
minutes.N/A
OR
OR
R3
N/A
Draft 32: December 30July 10, 2009
The responsible entity failed
to notify the impacted entities
in more than 70 minutes but
less than or equal to 80
minutes.
N/A
The responsible entity failed
to notify the impacted entities
in more than 90 minutes.
N/A
The responsible entity failed
to provide evidence of legal
requirements or concurrence
to use a language other than
English for communications
between and among operating
personnel responsible for the
real-time generation control
or operation of the
Page
7 of a9
interconnected BES
when
language other than English
was used.
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Standard
COM-001-2 —Lower
Communications
Requirement
VSL
R4
N/A
Draft 32: December 30July 10, 2009
N/A
The responsible entity failed
to have Iinterpersonal
Ccommunications
capabilityies with its
Transmission Operator or
Balancing Authority.
The responsible entity failed
to have Iinterpersonal
Ccommunications
capabilityies with its
Transmission Operator and
Balancing Authority.
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Standard COM-001-2 — Communications
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Standard COM-001-2 — Communications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1,
2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
Draft 32: July 10December 30, 2009
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Implementation Plan for COM-001-2 — Communications
Defined Terms in the NERC Glossary:
The Reliability Coordination Standard Drafting Team proposes the following new definitions:
Interpersonal Communication: Any method that allows two or more individuals to
interact, consult, or exchange information.
Alternative Interpersonal Communication: Any method that is able to serve as a
substitute for and is redundant to normal Interpersonal Communication and does not
utilize the same infrastructure (medium) as normal Interpersonal Communications.
Prerequisite Approvals:
None
Conforming Changes to Requirements in Already Approved Standards:
None
Revision Summary:
The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to
align with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates:
The first day of the first calendar quarter following applicable regulatory approval – or in those
jurisdictions where no regulatory approval is required, the first day of the first calendar quarter
following Board of Trustees adoption.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
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Implementation Plan for COM-001-2 — Communications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
R1.4.
Where applicable, these facilities shall
be redundant and diversely routed.
[Violation Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT contends that COM-001-1, R1 and its subrequirements are low
level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability
requirements for each entity throughout the body of standards. Examples
include:
IRO-001-1, R3 requires adequate telecommunication for the Reliability
Coordinator to direct actions of multiple entities, including TOPs and BAs.
TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to
the RC.
TOP-001-1, R3 requires adequate telecommunications facilities for the TOP,
BA, and GOP to be able to receive directives from the RC.
TOP-006-1, R1 requires adequate telecommunications for the GOP to inform
the BA and TOP of resources. The BA and TOP will then inform the RC,
other TOP and BAs of all transmission and generation available for use.
The retirement of this requirement also facilitates one of the FERC Order 693
directives for COM-001-1 to “includes adequate flexibility for compliance with
the Reliability Standard, adoption of new technologies and cost-effective
solutions”.
Notes: Based on the above information, the RC SDT recommends retiring R1 and its subrequirements.
Already Approved Standard
December 30, 2009
Proposed Replacement Requirement(s)
2
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Implementation Plan for COM-001-2 — Communications
COM-001-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
COM-001-2:
R1. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall identify and test, on a quarterly basis its
Alternative Interpersonal Communications capability used for
communicating real-time operating information. If the test is
unsuccessful, the entity shall take action within 60 minutes to restore
the identified alternative or identify a substitute Alternative
Interpersonal Communications capability [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
Notes: The RC SDT contends that the first sentence of COM-001-1, R2 is a low level facilitating requirements that is more appropriately and
inherently monitored under various higher level performance-based reliability requirements for each entity throughout the body of standards as
described in R1 above. We propose revising R2 as shown above to focus on the testing of capabilities that are not used on a routine basis.
December 30, 2009
3
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Implementation Plan for COM-001-2 — Communications
Already Approved Standard
COM-001-1
R3. Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
December 30, 2009
Proposed Replacement Requirement(s)
COM-001-2
R2. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60
minutes of the detection of a failure of its normal Interpersonal
Communications capabilities that lasts 30 minutes or longer.
[Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
4
Already Approved Standard
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2
R3. Unless dictated by law or otherwise agreed to, each
Reliability Coordinator, Transmission Operator, Balancing
Authority, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Purchasing-Selling Entity,
and Distribution Provider shall use English as the language
for all inter-entity Bulk Electric System (BES) reliability
communications between and among operating personnel
responsible for the real-time generation control and
operation of the interconnected BES. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
Notes: COM-001 Requirement R3 is being incorporated into COM-003-1 by the Operations Personnel Communications Protocols SDT (Project
2007-02). It will be retired from this standard upon approval of COM-003-1. The RC SDT expanded the list of applicable entities to include the
TSP, LSE and PSE and to delete the explanatory sentence at the end of the requirement.
December 30, 2009
5
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Implementation Plan for COM-001-2 — Communications
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Implementation Plan for COM-001-2 — Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
December 30, 2009
6
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Implementation Plan for COM-001-2 — Communications
Already Approved Standard
None - retire
COM-001-1
R6.
Proposed Replacement Requirement(s)
Each NERCNet User Organization shall adhere to the requirements
in Attachment 1-COM-001, “NERCNet Security Policy.” [Violation
Risk Factor: Lower]
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-2
R4. Each Distribution Provider and Generation Operator
shall have Interpersonal Communications capability
with its Transmission Operator and Balancing Authority
for the exchange of Interconnection and operating
information. [Violation Risk Factor: High][Time Horizon:
Real-time Operations and Operations Planning]
Notes: This is a new requirement based on the following FERC Order 693 directive:
“expands the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities”
December 30, 2009
7
Functions that Must Comply with the Requirements in the Standards:
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
X
X
X
X
X
X
Communication
December 30, 2009
8
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Implementation Plan for COM-001-2 — Communications
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Implementation Plan for COM-001-2
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any method that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any method that is able to serve as a substitute for
and is redundant to normal Interpersonal Communication and does not utilize the same infrastructure
(medium) as normal Interpersonal Communications.
Prerequisite Approvals
None
Conforming Changes to Requirements in Already Approved Standards
None
Revision Summary
The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
The first day of the first calendar quarter following applicable regulatory approval – or in those jurisdictions
where no regulatory approval is required, the first day of the first calendar quarter following Board of
Trustees adoption. To be determined.
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
R1.4.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT contends that COM-001-1, R1 and its subrequirements are low
level facilitating requirements that are more appropriately and inherently
monitored under various higher level performance-based reliability
requirements for each entity throughout the body of standards. Examples
include:
IRO-001-1, R3 requires adequate telecommunication for the Reliability
Coordinator to direct actions of multiple entities, including TOPs and BAs.
TOP-005-1, R1 and R3 require adequate telecommunications for BAs and
TOPs to provide each other with operating data as well as providing data to
the RC.
TOP-001-1, R3 requires adequate telecommunications facilities for the TOP,
BA, and GOP to be able to receive directives from the RC.
TOP-006-1, R1 requires adequate telecommunications for the GOP to inform
the BA and TOP of resources. The BA and TOP will then inform the RC,
other TOP and BAs of all transmission and generation available for use.
The retirement of this requirement also facilitates one of the FERC Order 693
directives for COM-001-1 to “includes adequate flexibility for compliance with
the Reliability Standard, adoption of new technologies and cost-effective
solutions”.
Notes: Based on the above information, the RC SDT recommends retiring R1 and its subrequirements.
July 30, 200810December 30, 2009
2
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R1. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall identify and operationally test, on a
quarterly basis its Aat a minimum, alternative Iinterpersonal
Ctelecommunications facilities capability ies used for communicating
real-time operating information. If the test is unsuccessful, the entity
shall take action within 60 minutes develop a mitigation plan to
restore the identified alternative or identify a substitute its Alternative
iInterpersonal Ccommunications capability ies. to ensure the
availability of their use when normal telecommunications facilities
fail. manage, alarm, test and/or actively monitor vital
telecommunications facilities. Special attention shall be given to
emergency telecommunications facilities and equipment not used for
routine communications. [Violation Risk Factor:High
MediumLower][Time Horizon: Real-time Operations]
Notes: The RC SDT contends that the first sentence of COM-001-1, R2 is a low level facilitating requirements that is more appropriately and
inherently monitored under various higher level performance-based reliability requirements for each entity throughout the body of standards as
described in R1 above. We propose revising R2 as shown above. to focus on the testing of capabilities that are not used on a routine basis.
July 30, 200810December 30, 2009
3
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
COM-001-2
R3.
R2. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall notify impacted entities within 60
minutes of the detection of a of failure (30 minutes or longer) of
their its normal Iinterpersonal Ccommunications capabilities
that lasts 30 minutes or longer. telecommunications facilities,
and verify the alternate means of telecommunications are
functional. provide a means to coordinate telecommunications
among their respective areas. This coordination shall include
the ability to investigate and recommend solutions to
telecommunications problems within the area and with other
areas. [Violation Risk Factor: Medium Lower][Time Horizon:
Real-time Operations]
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
July 30, 200810December 30, 2009
4
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2
R3. Unless dictated by law or otherwise agreed to otherwise,
each Reliability Coordinator, Transmission Operator, and
Balancing Authority, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Purchasing-Selling
Entity, and Distribution Provider shall use English as the
language for all inter-entity Bulk Electric System (BES)
reliability communications between and among operating
personnel responsible for the real-time generation control
and operation of the interconnected Bulk Electric
SystemBES. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations]
Notes: COM-001 Requirement R3 is being incorporated into COM-003-1 by the Operations Personnel Communications Protocols SDT (Project
2007-02). It will be retired from this standard upon approval of COM-003-1. The RC SDT expanded the list of applicable entities to include the
TSP, LSE and PSE and to delete the explanatory sentence at the end of the requirement.
July 30, 200810December 30, 2009
5
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
July 30, 200810December 30, 2009
6
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the requirements
in Attachment 1-COM-001, “NERCNet Security Policy.” [Violation
Risk Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-2
R4. Each Distribution Provider and Generation Operator
shall have Interpersonal Communications capability
with its Transmission Operator and Balancing Authority
for the exchange of Interconnection and operating
information. [Violation Risk Factor: High][Time Horizon:
Real-time Operations and Operations Planning]
Notes: This is a new requirement based on the following FERC Order 693 directive:
“expands the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities”
July 30, 200810December 30, 2009
7
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
X
Balancing
Authority
X
Purchasing
Selling
EntityInterc
hange
Authority
Transmission
Operator
X
X
Transmission
Service
ProviderOwn
er
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
Generator
Owner
X
Telecommuni
Communications
July 30, 200810December 30, 2009
8
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Implementation Plan for COM-001-2
TelecommunicationsCommunications
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Unofficial Comment Form for Reliability Coordination – Project 2006-06
Please DO NOT use this form. Please use the electronic comment form at the link below to
submit comments on the proposed revisions to the standards for Project 2006-06 —
Reliability Coordination. Comments must be submitted by February 3, 2010. If you have
questions please contact Stephen Crutchfield at [email protected] or by
telephone at 609-651-9455.
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Background Information:
The Reliability Coordination Standards Drafting Team (RC SDT) was tasked with 1) ensuring
that the reliability-related requirements applicable to the Reliability Coordinator are clear,
measurable, unique and enforceable; 2) ensuring that this set of requirements is sufficient
to maintain reliability of the Bulk Electric System; and 3) revising the group of standards
based on FERC Order 693.
During the course of the project, the NERC standards staff revised the Reliability Standards
Development Plan and noted several areas of overlapping scope between certain projects.
The original SAR for Project 2006-06 called for revisions to PER-004 — Reliability
Coordination – Staffing and PRC-001 — System Protection Coordination. Based on scope
overlap, it was determined that PER-004 and PRC-001 would best be served by moving the
proposed work to Project 2006-01: System Personnel Training and Project 2007-06: System
Protection, respectively.
The RC SDT proposed revisions to the set of standards under the project in August and
September 2008. The RC SDT made revisions to the set of standards based on stakeholder
feedback and the results of the IROL Standards Drafting Team work. Since the inception of
this project, the IROL Standards Drafting Team has proposed, successfully balloted and
obtained NERC Board of Trustees approval for three new Standards which included revisions
to other IRO standards. With the approval of the IROL set of standards, certain
requirements were retired from other IRO standards (see below summaries for specific
examples under the RC SDT project).
116-390 Village Blvd.
Princeton, NJ 08540
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Unofficial Comment Form — Reliability Coordination Project 2006-6
1. Do you agree with the proposed definition of Interpersonal Communication
(COM-001-2)? If not, please explain in the comment area.
Yes
No
Comments:
2. Do you agree with the proposed definition of Alternative Interpersonal
Communication (COM-001-2)? If not, please explain in the comment area.
Yes
No
Comments:
3. Do you agree with the revisions made to Requirement 1 in COM-001-2 as
shown in the posted Standard and Implementation Plan? If not, please explain
in the comment area.
Yes
No
Comments:
4. Do you agree with the definition of Reliability Directive (COM-002-2)? If not,
please explain in the comment area.
Yes
No
Comments:
5. Do you agree with the revisions to the Requirements in COM-002-3 as shown in
the posted Standard and Implementation Plan? If not, please explain in the
comment area.
Yes
No
Comments:
6. Do you agree with the use of the defined term “Reliability Directive” in
revisions to the Requirements in IRO-001-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area.
Yes
No
Comments:
7. Do you agree with the revisions to the Requirements in IRO-014-2 as shown in
the posted Standard and Implementation Plan? If not, please explain in the
comment area.
Yes
No
Comments:
8. Do you have any other comment, not expressed in questions above, for the RC
SDT?
Comments:
2
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Standards Announcement
Comment Period Open
January 4–February 3, 2010
Now available at: http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Project 2006-06: Reliability Coordination
The Reliability Coordination Standards Drafting Team is seeking comments on the following standards and
associated implementation plans until 8 p.m. EST on February 3, 2010:
COM-001-2 — Communications
COM-002-3 — Communications and Coordination
IRO-001-2 — Reliability Coordination – Responsibilities and Authorities
IRO-014-2 — Coordination Among Reliability Coordinators
This is the third comment period for the proposed standards and implementation plans. The drafting team has
made revisions to the documents based on stakeholder feedback. Explanations of the changes are included in
the comment form. The drafting team has also posted its consideration of industry comments received during
the previous comment period.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Next Steps
The drafting team will draft and post responses to comments received during this period. The drafting team will
also determine whether to post the standards for an additional comment period or seek approval from the
Standards Committee to proceed to balloting.
Project Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team, and two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap.
Applicability of Standards in Project
Reliability Coordinator
Balancing Authority
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Purchasing Selling Entity
Transmission Service Provider
Transmission Operator
Distribution Provider
Generator Operator
Load Serving Entity
Proposed Glossary of Terms Changes
New terms:
Reliability Directive
Interpersonal Communication
Alternative Interpersonal Communication
Modified term:
Adverse Reliability Impact
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Comment Period Extension
Project 2006-06: Reliability Coordination
The comment period for this project has been extended until 8 p.m. EDT on February 18, 2010. The
extension provides a 45-day period to review the definition of Reliability Directive, which was not part of the
previous comment periods for this project.
Project page: http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (69 Responses)
Name (51 Responses)
Organization (51 Responses)
Group Name (18 Responses)
Lead Contact (18 Responses)
Question 1 (62 Responses)
Question 1 Comments (69 Responses)
Question 2 (63 Responses)
Question 2 Comments (69 Responses)
Question 3 (65 Responses)
Question 3 Comments (69 Responses)
Question 3.1 (64 Responses)
Question 3.1 Comments (69 Responses)
Question 3.2 (64 Responses)
Question 3.2 Comments (69 Responses)
Question 3.3 (65 Responses)
Question 3.3 Comments (69 Responses)
Question 3.4 (58 Responses)
Question 3.4 Comments (69 Responses)
Question 4 (64 Responses)
Question 4 Comments (69 Responses)
Question 5 (0 Responses)
Question 5 Comments (69 Responses)
Question 6 (51 Responses)
Question 6 Comments (69 Responses)
Question 7 (53 Responses)
Question 7 Comments (69 Responses)
Individual
Ray Mason
ReliabilityFirst
No
TPL-001-2 Draft 5 is much better than Draft 4. There is still one significant concern, that I
do not believe the drafting team adequately addressed. It is unclear as to what ―Planning
Assessment results‖ and ―results of its Planning Assessment‖ entail. The Draft 5 response
that ―Planning Assessment‖ is a defined term does not fully address this concern. ―Planning
Assessment results‖ or ―results of its Planning Assessment‖ is not necessarily the same
thing as ―Planning Assessment‖. As written, ―Planning Assessment results‖ or ―results of its
Planning Assessment‖ could be anything from a single sentence, to a few brief high level
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
paragraphs, to a detailed and technically complete Planning Assessment. The Standard
needs to more clearly state what is required in the report to other entities. Based on the
drafting team response in Draft 4, it seems that replacement of ―Planning Assessment
results‖ or ―results of its Planning Assessment‖ with the term ―Planning Assessment‖ or ―its
Planning Assessment‖ would be appropriate. Violation Severity Levels: R8 The failure to
provide documented responses to documented comments to ―Planning Assessment results‖
is deemed to be a higher severity level than failing to distribute ―results of its Planning
Assessment‖. Failure to distribute denies functional entities an opportunity to comment,
and could prevent coordinated planning, and thus should be deemed to be more severe
than failing to provide documented responses to documented comments.
Individual
Greg Rowland
Duke Energy
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
We support the changes.
Yes
Yes
Individual
Catherine Mathews
NorthWestern Energy (NWMT)
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖
No
Measure M6 is too vague. It is unclear how to identify the conditions of Cascading, voltage
instability, or uncontrolled islanding. The Glossary of Terms defines Cascading as ―The
uncontrolled successive loss of system elements triggered by an incident at any location.
Cascading results in widespread electric service interruption that cannot be restrained from
sequentially spreading beyond an area predetermined by studies.‖ Does the loss of system
elements have to extend beyond the Control Area to be considered ―Cascading‖? Is there a
Megawatt threshold that must be satisfied? Is there a time duration involved? Also,
―cascading outages‖ needs to be defined. In addition, ―voltage instability‖ and ―uncontrolled
islanding‖ should both be defined.
Yes
Individual
Phuong Tran
Lakeland Electric
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Shouldn‘t the ―Implementation Plan for TPL-001-1‖ document be for TPL-001-2? Also, ―TPL001-1‖ is referenced throughout the document.
No
―the latest‖ is not needed from the second sentence of R1, since the sentence already
ended with ―..shall represent projected System conditions‖. R1 Part 1.1.2 Suggest adding
this clarification at the end ―… six months during the period under study‖. This language
addition helps clarify the point that if an outage occurs during the summer and the entity‘s
system peak occurs in the winter, then the system peak Load study case (model) does not
have to include this particular outage.
No
Please consider removing R.2.6.2
No
A ―measureable change in performance‖ can be interpreted as not meeting one of the
performance requirements as specified in Table 1 in order for the condition to be selected
as a sensitivity. This will cause utilities to perform sensitivity analysis for all system
conditions listed in R2.1.4 to determine which one fails to meet one of the performance
requirements in Table 1, as one may not be able to tell performance impact until after the
studies are performed. Suggested change: ―…one of the following conditions by a sufficient
amount…system conditions that may demonstrate a measurable change in system
response.‖
Yes
No
Please consider removing R2.6.2. The ―any material change‖ language can cause utilities
perform studies due to material changes outside of and remote to its system.
Yes
The performance requirements of Table 1 do not allow the loss of non-consequential load
for single and multiple contingency events. The disallowance of load loss does not provide
any real benefit to the reliability of the BES and is an unnecessary overreach into local
quality of service issues that are best addressed by State, Provincial or Municipal
authorities. There may be circumstances such as high local transmission costs or local
opposition to transmission construction where prohibition of non-consequential load loss
represents a poor cost/benefit or quality of life tradeoff. Having a provision at the regional
level that a PA or TP can have a certain amount of non-consequential load loss designed or
planned in to its system that would be reasonable if it is acceptable to the RE and does not
have an adverse impact on the remaining BES. In lieu of such a RE provision, providing a
quantitative cap in non-consequential load loss such as 100 MW may be rationale
compromise in the goal of limiting load loss for the more probable outage events. Our
preference would be to retain the capability of limited non-consequential load loss.It is our
understanding that footnote 9 is under consideration as part of Project 2010-11 and should
be noted as such for clarification.
No
please consider remove ―the latest‖ from M1
No
The requirement to distribute the Planning Assessment should be more flexible and allow
for making the Planning Assessment available, such that those entities that desire the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
information can have it readily available. R8 should be modified as follows: Each Planning
Coordinator and Transmission Planner shall make available its Planning Assessment results
to adjacent Planning Coordinators and Transmission Planners and to any functional entity
that indicates a reliability related need for the Planning Assessment results.
Individual
Tom Duane
PNM
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Group
NERC Staff
Mallory Huggins
Yes
NERC staff supports the change to allow Corrective Action Plans to include tripping of NonConsequential Load and curtailment of Firm Transmission Service for 7 years. This seems
long, but staff understands the stakeholder concern that it could take that long to plan,
site, and construct facilities required for compliance with the standard.
Yes
NERC staff supports the revisions to the definition of Year One. However, we believe an
associated change should be made where this term is used in part 2.1.1 of Requirement 2
which requires modeling of ―System peak Load for either Year One or year two, and for
year five.‖ It seems the new definition of Year One would negate the need to refer to year
two. NERC staff recommends that part 2.1.1 be changed to ―System peak Load for Year
One and for year five.‖
No
NERC staff suggests that the added sentence in R1 be deleted and ―Normal System‖ in
Table 1 be replaced with ―No unplanned Element outages.‖ We have a problem with R1
establishing ―normal system condition.‖ ―Normal‖ is not defined, but the system condition
that most people would define as ―normal‖ is the System operating within its limits. There
are no checks required on the projected system conditions to guarantee ―operation within
limits.‖ Staff realizes that if this were the case, the categories tested would all pass their
respective tests. (In other words, the category tests may define operating limits that in turn
define ―normal‖ from a planning perspective.) Thus, the added sentence in R1 should be
deleted. In Table 1, the use of the term ―Normal System‖ in the column ―Initial System
Condition‖ really means ―No unplanned Element outages.‖ All Elements that do not have a
planned outage are assumed in-service (for transmission Elements) or available for
dispatch (for generators). Contrast the term ―Normal System‖ with categories P3 and P6,
which have the loss of an Element (which is unplanned) followed by the loss of a second
Element (also unplanned). ―Normal System‖ should be replaced with ―No unplanned
Element outages.‖
Yes
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NERC staff supports the use of qualified past studies for the Near Term horizon.
Yes
NERC staff supports removing the phrase ―not already included in the studies‖ from the
parts 2.1.4 and 2.4.3 of Requirement R2. We believe that the requirement is more clear
and less subject to interpretation without this phrase.
No
NERC staff understands why the SDT has inserted the word ―expected‖ before ―dynamic
behavior of Loads,‖ but we have concerns with this addition. We understand that a PC or TP
that models the best current industry understanding of load behavior should not need to
worry about compliance if that model does not match actual load response for all possible
system conditions. However, we are concerned that this change to part 2.4.1 of
Requirement R2 may be too accommodating. If a PC or TP has unrealistic expectations
about load behavior, would this permit the use of unrealistic models? While we have
struggled to develop an alternative proposal, we hope that the SDT will identify a way to
address this concern.
Yes
NERC staff supports inserting the word ―material‖ in the reference to assessing the impact
of proposed generation. We have some concern that this change leaves this part of the
requirement open to interpretation, but we also understand the need to permit some
degree of engineering judgment to be applied. It would not be appropriate to require that
every potential generation addition be included in the assessment where some proposed
additions may by inspection be deemed to be immaterial due to size and/or interconnection
location.
Yes
NERC staff supports the changes to the header notes in Table 1.
NERC staff is concerned with P5 and footnote 9 and thus cannot support these changes in
their entirety. First, a revision to the Draft 4 definition of P5 should be used in lieu of the
current Draft 5 version: ―Loss of multiple elements caused by the Fault clearing consistent
with failure of a single Protection System while clearing a fault on one of the following: . . .‖
After reviewing the P5 contingency throughout various drafts of this standard, along with
existing Table 1 for TPL-001 through TPL-004, NERC staff‘s primary concern is that this
most recent version is going in the wrong direction by becoming too limiting regarding
which Protection System component failures are covered. Draft 5 is an improvement
because it removes the reference to loss of multiple elements in Draft 4 (which defined P5
as ―Loss of multiple elements caused by the failure of a single Protection System while
clearing a fault on one of the following: . . .‖). Draft 5 takes a step backward, however, by
referring to Delayed Fault Clearing. The advantage of not referring to Delayed Fault
Clearing is that for cases where redundant protection systems are provided, the fault
clearing may not be delayed even when a single Protection System failure occurs. Ideally,
NERC staff believes that P5 should refer to ―failure of any component of a Protection
System,‖ but NERC staff recognizes that we cannot get there until the term Protection
System is redefined and Project 2009-07—Reliability of Protection Systems is underway.
Until that change is possible, NERC staff encourages the SDT to use the revised version of
P5 proposed above. A second concern is with footnote 9, which is used numerous times in
Table 1. System adjustments may be used in two different settings: the first is to address
the aftermath of a particular Contingency; the second is to prepare for the next
Contingency. Staff suggests that the current footnote 9 have this language added: ―PostContingency Ccurtailment of Firm Transmission Service to address the simulated
contingency, when coupled with ….‖ Footnote 9 is used in the column labeled ―Interruption
of Firm Transmission Service Allowed‖ whenever a ―No‖ is provided. The footnote 9 in this
column has to do with System adjustments that address the aftermath of the Contingency
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that is being simulated. Therefore, no footnote 9 appears appropriate for category P0 (No
Contingency). The reference in footnote 9 to no load loss and staying within applicable
Facility rating, including those on a neighboring system, is sufficient for addressing the
aftermath of the Contingency being simulated. To address next Contingency, an additional
footnote is needed in the ―Initial System Condition‖ column for category P3 and category
P6. The following is suggested: ―System adjustments to prepare for the next Contingency
must be completed within 30 minutes.‖ Footnote 9 is used in the column labeled ―Initial
System Condition‖ for category P3 and category P6, and these two categories define the
loss of an Element ―followed by System adjustments‖ and then followed by the loss of a
second Element. It is unclear whether the intent in footnote 9 in these two cases is meant
to address the same issue referenced above (i.e. the aftermath of the Contingency being
simulated) or whether it is intended to address the next Contingency. Thus, both situations
need to be addressed using the suggestions indicated above.
Yes
NERC staff supports the changes to the Measures.
Yes
NERC staff supports the changes to the VSL for Requirement R8.
Individual
Doug Hohlbaugh
FirstEnergy
Yes
We appreciate the effort of the standard drafting team and the changes reflected in the
current draft of the TPL-001-1 standard. The changes are improvements that should move
the standard towards greater industry consensus. The extended Implementation Plan aligns
with suggestions in FE‘s prior ballot comments. We support the Implementation Plan
change made by the team.
Yes
The change in the Year One definition provides greater flexibility for the industry and also
addresses a prior FE comment during the 1st ballot. We appreciate the team‘s careful
consideration of the industry feedback and support the change.
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay (footnote 13) protecting the Faulted element to operate as designed‖. To the extent
fully redundant relaying exists with no expected delay in Fault Clearing its understood that
the P5 event would not be a concern for the redundant system design. The drafting team
has taken appropriate steps within the TPL standard to focus on relaying failures to provide
clarity in what is required for P5 planning event.
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Yes
Yes
Individual
John Collins
Platte River Power Authority
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
No
I like that you have requirements for qualifying past studies, but Part 2.6.2 is confusing.
Please change Part 2.6.2 to read something like: ―For steady state, short circuit or Stability
analysis: no material changes have occurred to the System represented in the study or, if
material changes have occurred, a technical rationale can be provided to explain that the
changes do not impact the performance results in the study area.‖
Yes
Yes
For consistency, use the qualifier ―expected‖ in the second sentence of Part 2.4.1 also, such
that it reads ―…represents the overall expected dynamic behavior…‖
Yes
I like the flexibility you give the PC and TP to define what ‗material‘ means in their
‗documentation to support the technical rationale for determining material changes.‘ In Part
2.5 this rationale will decide whether or not any Long-Term Stability studies are required
for the Planning Assessment. And in Part 2.6.2 this rationale will be a factor in qualifying a
past study.
Yes
I like the flexibility you give the PC and TP in Requirements R3 and R4 to develop their
rationale for the Contingencies they select for evaluation.
No. Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure
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of a relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue). In Table 1 –
Planning Events – Suggest changing the description for Events P2-3, P2-4, P4 and P4-6 to
use the term ‗Bus-tie Breaker‘ or ‗non-Bus-tie Breaker‘ as applicable. In Table 1 – Extreme
Events – Stability – Items 2a-2d, do you mean ‗Protection System failure‘ here, or do you
want to change to ‗relay failure‘ to be consistent with changes in P5?
Yes
Yes
Group
SERC Planning Standards Subcommittee
Philip Kleckley
Yes
Yes
No
The definition does not adequately address normal (pre-contingency) operating procedures
or system configurations. Language should be added to the requirement (perhaps as
R1.1.7) to include normal operating procedures or system configurations in place prior to
any contingency occurring.
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Comments: We wish to make a comment on R4.3.1: it appears that this requires stability
simulations of both successful and unsuccessful high-speed reclosing for all contingency
simulations regardless of whether high-speed reclosing is used on the faulted line. We
suggest the following wording be used to replace the first bullet: ―Successful high-speed
reclosing and unsuccessful high-speed reclosing onto a fault, where such reclosing is
applied, and where such additional simulations are deemed appropriate by the PC or TP.‖
We wish to make a comment on the stability extreme event table: Changes were made in
planning event P5 to narrow the focus to specific relay failures. The same changes are
needed for stability extreme event 2a, 2b, 2c, and 2d.
Individual
Aaron Staley
Orlando Utilities Commission
Yes
Yes
Yes
No
Allowing the use of past studies in lieu of new studies for part or all of an assessment when
the underlying system hasn't changed in a signficant change if very prudent. However the
wording in 2.6.2 of "unless a technical rationale can be provided to demonstrate that
System changes do not impact the performance results in the study area" is of concern. By
this wording is it intended that the planner must demonstrate that every material change
has no impact? In essence doing more work to prove that a study isn't required then the
study would take? Or that the planner must essentially have a technical rationale
(overarching) for determining when a material change is "material enough" to impact
system perofrmance?
No
What is meant by "measurable change in performance"? Is this a measure that the
sensistivty should move the system from meeting the performance requirements to not
meeting the performance requirements? Or just a measurable change in system response,
IE the loading was 45% on this corridor but is now 76%.
Yes
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No
I agree with what I think is the intent. The word "Material" is meant to allow for changes in
model to occur that are "small" relative to the TP/PC. For example the 400 MW generator
that might be built in 10 years by another utility over a hundred miles, several dozen buses
and generators away to not force new study work. However as written in 2.5 it requires you
to define what a material change is, and could be applied to mean every change must be
identified and explained rather then an overarching rationale that would only have you
looking for changes that meet the material criteria. But then in 2.6.2 the word material is
used with no obligation to explain what material is, only to explain if a material change
would not impact the results in a study area. I recommend leaving the term material, but
setting a requirement, measure, or definition that requires the TP/PC to define what they
consider material specific to their system and circumstance. Since this will by the
hetreogenous nature of the grid be different for each it may not be reasonable to pre-define
what is realibale. Just as was done with many items in the ATC (MOD) standards, require
that it be documented and questions on that rationale be answered. If a specific level of
technical oversight is desired, consider requiring that description to be on file with the
regional entity and approved by their planning committee. I think the team is heading in a
good direction, it's just how the words will be applied that concern me. This may be a case
where an Example or two would go a long way towards providing guidance to entities and
auditors.
Yes
I am assuming you mean the header notes on the performance table
I generally agree with the direction the team has gone. Footnote 9 should also be
highlighted as being part of the project 2010-11 discussion just as footnote 12 is.
Yes
No
R8 should require that the PC and TP make available it's planning assessment results when
requested, rather then requring the preemptive transmittal. There is no reliablity purpose
served by providing unsolicited information.
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
No
The last two sentences ―System peak Load levels shall include a Load model which
represents the expected dynamic behavior of Loads that could impact the study area,
considering the behavior of induction motor Loads. An aggregate System Load model which
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represents the overall dynamic behavior of the Load is acceptable.‖ belong in the MOD
standards. They are not required in TPL-001-2.
No
Adding the word ―material‖ does not clarify Part 2.5. The word ―material‖ can be interpreted
in many ways and is subjective. In order to have a consistent approach by all TPs, the
drafting team should add a definition of the term ―material‖. One TP may consider a new
200 MW unit as not being material because there are several larger units in the TPs system.
Yes
In point g, violations are noted in terms of post-Contingency voltage deviations rather than
post-Contingency voltage limits. This may lead to confusion, as some utilities evaluate
performance based on a post-Contingency voltage deviation criterion while other utilities
evaluate performance based on post-Contingency voltage limits. This same comment
applies to Requirement R5. Suggested rewording for point g: System steady state voltages
and post-Contingency voltages or voltage deviations shall be within acceptable limits as
established by the Planning Coordinator and the Transmission Planner. Suggested
rewording for the first sentence in Requirement R5: Each Transmission Planner and
Planning Coordinator shall have criteria for acceptable System steady state voltage limits,
post-Contingency voltages or voltage deviations, and the transient voltage response for its
System. Note 12 states that an outstanding issue related to non-consequential load loss is
being discussed. This will create a lot of uncertainty. Manitoba Hydro could not support this
standard unless the resolution of Note B is known.
Yes
Yes
Individual
Randi Woodward
Minnesota Power
Yes
Yes
Yes
No
Requirement 2 - This requirement states that Stability analyses be performed as part of the
annual Planning Assessments. Minnesota Power would like to see the term "Stability
analysis" more clearly defined as there are several different types of stability related
analysis that can be performed for power systems including: transient stability, voltage
stability and small signal stability.
Yes
Yes
Yes
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Yes
None.
Yes
Yes
Group
Northeast Power Coordinating Council
Guy Zito
No
Requirement R1 Part 1.1 and following states ―System models shall represent:… 1.1.5.
Known commitments for firm Transmission Service and Interchange. It was commented
during a previous posting that 1.1.5 should be reworded to read: Known commitments for
Firm Transmission Service, and, additionally, other types of transactions provided they
have been demonstrated to not violate existing reliability constraints. The response was
that ―The SDT believes that the defined term ‗Interchange‘ covers other transfers as
described in your comment. No change made.‖ It is agreed that known Interchanges should
be modeled. However, it is imperative that existing reliability constraints not be violated in
the process. That is, Interchange relating to economic transactions should not drive
planning studies. Reliability related investments should not be driven by congestion related
to economic transactions incorporated into planning models. Following is a
preferred/revised wording: • 1.1.5. Known commitments for firm Transmission Service and
Interchange. Interchange is meant to refer to energy transactions other than firm
Transmission Service. While rigorous planning studies have been conducted to permit the
uninterrupted implementation of firm Transmission Service without jeopardizing the reliable
operation of the Interconnected System, other types of energy transaction only take place
whenever system conditions permit them. They are usually of very short duration relative
to planning assessment periods (usually spanning for a few hours to a few days) and
deemed highly interruptible subject to reliability issues that may arise during operation of
the system. In other words, the term Interchange refers to economic transactions that are
permitted when the system is secure and there are reasonable reliability margins to effect
dispatch changes to lower operating costs. As such, Interchange should not be reflected in
system representation meant to assess system reliability in adherence to reliability criteria
delineated in documents such as TPL-001.
No
The definition of Year One could be eliminated, and its wording used in place of Year One
within the text of the requirement. The proposed definition has now added ambiguity with
respect to ―year two‖ and ―year five‖ which are not defined. Year two could be deleted and
R.2.1.1 modified as follows: System peak Load representing a point in time 12-24 months
and another point in time 48-65 months into the future from the time the study is initiated.
Define Year Five as the twelve month period 4 to 6 calendar years from the date of the
Planning Assessment.
Yes
No
The revisions made to Requirement R2 Part 2.1 appear to resolve the concern that past
studies could not be used to comply with the short-term steady state study requirements.
This revision must be carried through to other sections (R2.2, 2.2.1). However, the
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language of Requirement R2 Part 2.2 still seems to suggest that current annual studies are
always required for the long-term steady state assessment to be compliant. This may have
been an oversight, for consistency Requirement R2 Part 2.2 should be modified to similarly
read as Requirement R2, Part 2.1. Regarding R2.2, the language should be consistent with
2.1. For example, use "current or qualified past studies" instead of "the following annual
current study". Revisions made to Requirement R2.1.5 have made it worse than was
originally drafted. This would require the PC & TP to study (meaning performing a technical
analysis) of the impact and probability of the possible unavailability of any piece of
equipment with a lead time of one year or more. Such an evaluation of spare equipment
strategies would require significant additional resources and data, but provide no benefit to
system reliability, as it is redundant to the existing N-1-1 contingency requirement (P6).
R2.7 requires that Corrective Action Plans are included in each Planning Assessment and
states ―Such actions may include…‖ followed by a list of actions. Restricting allowable
actions, and excluding runback/tripping of HVDC would have a direct impact on multiple
existing facilities in New York and would adversely impact the reliability planning of the
NYCA. Runback/tripping of HVDC must be added to the list, and also suggest revising to
―Such actions may include but not be limited to:‖.
No
Part 2.1.4, requires an entity to vary one or more conditions to demonstrate a change in
performance. If the cases were initially stressed, this may force an entity to simulate
conditions with less severe stresses. At this point, there is limited to no value to this
additional workload. Having a requirement to test at least one sensitivity as a blanket
requirement may not be informative by itself and is more unclear since sensitivities are
being required on an undefined base set of conditions. If an entity does a case with a
stressed set of assumptions, is it necessary to do a non-stressed case? Additionally, our
concern involves wording under 2.1.4 and 2.4.3 that sensitivities are required varying one
or more conditions. Subsequently, in requirement 2.7.2 corrective action plans need to be
developed to resolve performance deficiencies ―only‖ if identified in multiple conditions or
require a rationalization why no corrective action plan is necessary. Multiple conditions
sensitivities under 2.1.4 and 2.4.3 are necessary to satisfy requirement 2.7.2. Requirement
2.7.2 adds ambiguity and should be removed. If not, a suggested revision to Requirement
2.7.2 as follows: 2.7.2. Corrective Action Plans are not required for performance
deficiencies identified in a sensitivity analysis. In general, the scope of this requirement is
too broad and non-specific, and only results in undue study burden. Is it necessary for
sensitivity analysis to be included in requirements since in accordance with good
engineering practices a conservative approach should be used in studies? The standard is
referring to requirements for sensitivity and other issues without a reference to base
assumptions as commented in issue #3. The standard must describe base assumptions. To
define a sensitivity condition, NERC must define base assumptions.
No
There is insufficient information and experience regarding dynamic load modeling. It may
also be included as a ―sensitivity‖ analysis in 3.2, rather than requiring and expecting
accurate representation of a dynamic load model. If this requirement is kept, a modeling
standard must be written that is specific to dynamic loads. Change belongs in a modeling
standard, not in TPL-001.
Yes
No
Header note (i) in the first Table 1 (p. 10) could imply that voltage-varying load shall not be
used to meet steady state performance requirements. Steady state load models in use
include voltage-varying loads. The explicit representation of (voltage-dependent) load
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models is perfectly consistent with the requirements defined in R1 (which calls for a
comprehensive representation of system components and their expected operating status in
the planning assessment period) and the impetus to the creation of more specific load
models in dynamic assessments found Requirement 2.4 of this draft of TPL-001-2. It is a
known that depressed voltage conditions cause certain system elements to perform below
their rated capacity. For example, capacitors provide less voltage support and voltage
controlling transformers are impeded by their finite tap range to direct VAR flow into areas
affected by low voltage conditions. Certain load types, on the other hand, provide a selfcompensating relief to depressed voltage by naturally decreasing demand in a manner
proportional to their characteristics, without operator intervention. Choosing to negate the
voltage-dependence of one of these system elements (load, in our case) results in an
inaccurate system representation that, in turn, may lead to erroneous assessments of the
reliability state of the interconnected system and, potentially, to the implementation of
unwarranted system upgrades. This note should be revised to only reference loads which
are disconnected due to voltage.
To support the change to P5, other items need to also be modified. In Table 1 - Steady
State & Stability Performance Extreme Events (p. 12), in the Stability Section, the language
should be made similar to wording in P5. Protection System should be removed and
replaced with the words ―relay failure‖. This change should be made for 2a through 2d: 2.
Local or wide area events affecting the Transmission System such as: a. 3Ø fault on
generator with stuck breaker10 or a relay failure resulting in Delayed Fault Clearing. b. 3Ø
fault on Transmission circuit with stuck breaker10 or a relay failure resulting in Delayed
Fault Clearing. c. 3Ø fault on transformer with stuck breaker10 or a relay failure resulting in
Delayed Fault Clearing. d. 3Ø fault on bus section with stuck breaker10 or a relay failure
resulting in Delayed Fault Clearing. Note 11 (p. 14) needs clarification as shown: Excludes
circuits that share a common structure (Planning event P7, Extreme event steady state 2a)
or common Right-of-Way (Extreme event, steady state 2b) for a total of 1 mile or less.
There are two tables labeled ―Table 1‖. Suggest that the extreme events table be renamed
―Table 2‖.
Yes
No
Requirement 8 is an administrative burden to TPs and PCs that adds no value to Bulk Power
System reliability. PCs should be including TPs, neighboring PCs and interested parties in its
planning processes when developing the Planning Assessments. Therefore, the inclusion of
a set of VSLs for Requirement 8 is unnecessary. Should the VSLs for Requirement 8 remain,
Requirement 8.1 should be revised to reflect that comments only to the final Assessment
(not drafts developed during a process) need a response as follows: If a recipient of the
planning assessment final results provides documented comments on the results, the
respective Planning Coordinator or Transmission Planner shall provide a documented
response to such recipient within 90 calendar days of receipt of those comments. If
Requirement 8 and 8.1 are retained, they should be revised to reflect that comments only
to the final Assessment (not drafts developed during a process) need a response and there
should be a limit on the comment period as follows: If a recipient of the planning
assessment final results provides documented comments on the results within 90 days of
receipt, the respective Planning Coordinator or Transmission Planner shall provide a
documented response to such recipient within 90 calendar days of receipt of those
comments. Other comments not addressed by this Comment Form as follows: Section 3.3 The last sentence of 3.3.1 should be removed. This is addressed in PRC-023. Line ratings
are addressed in PRC-023. PRC-023 requires coordination with the Reliability Coordinator.
Remove ―Tripping of Transmission elements where relay loadability limits are exceeded.‖
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Section 4.3 - High speed reclosing is not defined, and to help eliminate any confusion that it
may introduce into the standard it will be worthwhile for the SDT to define this term.
Several specific examples from previous comments on sensitivity analysis and guidance for
base case assumptions: The requirements for sensitivity analysis already address issues
going beyond what is expected to meet reliability requirements. Requiring extreme event
analysis is requiring two layers of event analysis beyond what is required and there is no
requirement for corrective action if anything is identified. The standard is referring to
requirements for sensitivity and other issues without a reference to base assumptions. The
standard must describe base assumptions. To define a sensitivity condition, NERC must
define base assumptions. As for allowing con-consequential load loss for Categories P1
through P5, suggest approval at the Regional level, with a concept of allowing it in a ―local
area‖ that does not impact BPS reliability. All references to 300 kV in document should be
replaced with EHV (for example in the Introduction, Section 5). The first phrase of Note 3
on p. 14 should be revised as follows: ―Bulk Electric System (BES) level references include
extra-high voltage (EHV) Facilities defined as those representing the backbone of the
System, generally at voltage greater than 300 kV, and high voltage (HV) Facilities defined
as those not representing the backbone of the System, as determined by the Planning
Coordinator and approved by Regional Entity.‖
Individual
Martin Bauer
US Bureau of Reclamation
Yes
With exception of the definitions.
No
The language implies a requirement. The language "Year One must include the forecasted
peak Load period for one of the following two calendar years" is a requirement and not a
statement of clarification. If the definition is that ―Year One‖ can also be the period used for
forecast peak load, then it should be stated so. It is suggested that either the language in
the definition is modified or the language is deleted from the definition and moved to the
body of the standard.
Yes
No
The question is misleading in that R2 also include current studies. The overall structure of
the standard could be greatly improved if the standard were segmented into Near Term and
Long Term with sub segments for each specific type of analysis to be performed. Second,
the standard does not use consistent terms. The Planning Assessment is to include Near
Term and Long Term portions which must have steady state analysis, short circuit analysis,
and stability analysis (ref. R2). Requirement R 2.1 introduces sensitivity analysis for the
Near Term portion, and then refers to the Planning Analysis which is in reality both Near
Term and Long Term portions. That implies that sensitivity analysis must be required for
both? The standard repeats the requirement for annual stability studies in 2.4 which was
already a requirement for Planning Assessments. The requirement 2.1.5 is one the most
problematic requirements in this standard. This requirement implies that an entity must
have spare equipment and a strategy to employ it. That is beyond the scope of the Energy
Policy Act 2005. Spare equipment is not on-line and does not contribute to the reliability of
the existing system. The Energy Policy Act of 2005 specifically prohibits the requirement to
enhance or modify the system. The use, application, or requirement to have spare
equipment violates that prohibition. This section should be removed. In addition, this
requirement suffers from an ability to implement. In the first case, the requirement is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
invoked if the spare equipment strategy could result in unavailability of transmission
equipment. How is that determined? There is no nexus to that determination. The
unavailability may have already occurred once the transmission equipment has failed. The
only way to avoid unavailability if the transmission equipment that fails has a hot stand-by
with automatic fail-over. The presence or not of a suitable replacement will still result in
unavailability by virtue of the failure o the first piece of transmission equipment. Next
problem, who will second guess the owner of the replacement. Where is the requirement to
make the replacement strategy available? The standard should focus on system
performance with existing equipment to meet current and future loads.
No
Sensitivity analysis is not included in R2. This gets back to the structure of the standard.
There should a clear indication of the studies that are to be included in the Near-Term and
Long-Term portions of the Planning Assessments.
No
Not included in R2. See response to Question 3.2
No
The term "material" is arbitrary. It is suggested that a specific value be used to trigger the
assessment.
No
The language implies that the responsible entity may choose to not distribute it is feels the
entity making the request does not have a "reliability related need". It is not clear why that
distinction is being made?
Group
Exelon Transmission Planning
Eric Mortenson
Yes
Yes
Yes
Yes
Yes
No
There is not an industry consensus around best practices for modeling the dynamic
behavior or characteristics of load. It is premature to make this a requirement in an
enforceable standard which would be held to this degree of subjective auditing.
No
The term ‗material changes‘ is subjective. It is very difficult to determine a base case to
study combinations of generator additions on a changing transmission network in the 6 to
10 year time period to be used for dynamic simulations. Dynamic studies should be
performed whenever new generator interconnections are proposed and it is at that time
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where meaningful calculations can be performed. The long term six to ten year out dynamic
studies for groupings of potential units should be done at a high level, if at all.
Yes
Comments: The term ‗HV‘ in the performance table should be defined as ‗Bulk Electric
System elements up to 300 kV, not simply all elements ‗below 300 kV‘. Footnote 12 should
be clarified to specifically state the requirements before voting takes place. The
performance criteria should be based on the voltage level of the element experiencing
stress due to the contingency, not based on the voltage level of the outaged element. It
does not seem to make sense that the loss of a 500 kV bus would not allow for any nonconsequential load shedding unless the bus contained a 500 to 230 kV transformer, in
which case additional load shedding would be allowed. If outages on a 230 kV system, such
as bus fault with stuck breaker, were to cause overloads on a 500 kV network it is
acceptable to shed load, but if the outages were on the 500 kV system originally it would
not be acceptable to shed additional load. It seems as if it should be the severity of the
situation and the elements involved that would dictate allowable remedial actions and not
the initial cause of the disturbance. If, for example, there was a 500 kV contingency outage
that caused problems on the 230 kV system there would be a problem that may require
load shedding on the 230 kV system. If there were a 230 kV contingency or series of
contingencies that caused overloads on the 500 kV system, it would be more difficult to find
enough lower voltage load to shed to bring the 500 kV system back to applicable ratings or
conditions. The inability to shed non-consequential load could theoretically be resolved by
hanging a small EHV / HV transformer on a particular bus, or by tapping a EHV line with an
auto transformer.
Yes
Yes
Individual
Paul Rocha
CenterPoint Energy
No
The SDT did not incorporate CenterPoint Energy's
therefore, CenterPoint Energy's concerns remain.
No
The SDT did not incorporate CenterPoint Energy's
therefore, CenterPoint Energy's concerns remain.
No
The SDT did not incorporate CenterPoint Energy's
therefore, CenterPoint Energy's concerns remain.
No
The SDT did not incorporate CenterPoint Energy's
therefore, CenterPoint Energy's concerns remain.
No
The SDT did not incorporate CenterPoint Energy's
therefore, CenterPoint Energy's concerns remain.
previous comment regarding R1;
previous comments regarding R2;
previous comments regarding R2;
previous comments regarding R2;
previous comments regarding R2;
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Yes
CenterPoint Energy appreciates the effort put forth by the SDT in revising the performance
table. The current draft of P5 is preferable to previous versions.
Individual
Tim Ponseti, VP
TVA Transmission Planning & Compliance
Yes
TVA supports the change from five years to seven years for the implementation plan period.
Yes
TVA supports the change in the Year One definition - but would suggest that the word
―started‖ should be changed to ―completed‖ since a Planning Assessment may be started in
one calendar year and finished in the next calendar year.
Yes
Yes
Yes
Yes
Yes
Yes
TVA is concerned about footnote 12 (known as footnote b in existing TPL standards). TVA
believes that utilities should be given some freedom in dropping local load in response to N1 events as long as overall BES reliability is not impacted. Otherwise significant capital
improvements will be required that will have no overall reliability gain for the Bulk Electric
System. TVA does agree with the revisions made specifically to the P5 event. TVA wishes to
make a comment on the stability extreme event table: Changes were made in planning
event P5 to narrow the focus to specific relay failures. The same changes are needed for
stability extreme event 2a, 2b, 2c, and 2d.
Yes
Yes
Additional TVA comments: TVA wishes to make a comment on R4.3.1: it appears that this
requires stability simulations of both successful and unsuccessful high-speed reclosing for
all contingency simulations. Does high speed reclosing occur in less than 60 cycles or 60
seconds? If a utility does not have reclosing on a transmission line - then must the utility
still perform stability studies assuming that there is reclosing? TVA suggests the following
wording be used to replace the first bullet: ―Successful high-speed reclosing and
unsuccessful high-speed reclosing onto a fault, where such reclosing is applied, and where
such additional simulations are deemed appropriate by the PC or TP.‖ In R4.1.1, TVA is
concerned that no generating unit shall pull out of synchronism in a local area only (thus
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not impacting the overall reliability of the BES) for Planning Event P1, while the standard
does allow generator runback/tripping for the same event. Thus the generating unit may be
tripped by a special protection scheme - but may not be tripped by an out of step relay.
TVA believes that out of step relaying should be allowed for this unit tripping as long as this
does not affect the overall reliability of the BES.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
We agree with this change. We further suggest that this change and the additional wording:
―or in those jurisdictions where no regulatory approval is required on the first day of the
first calendar quarter, 84 months after Board of Trustees adoption‖ be added to P. 3 of the
standard that starts with ―For 84 calendar months…‖ to be totally consistent.
Yes
Yes
Yes
Yes
Yes
Yes
We do not have a concern with this change but we don‘t think it is necessary. It is not a
requirement, and appropriate wording in the Measures can take care of it.
Yes
Yes
Yes
Group
Southern Company
Andy Tillery
Yes
Yes
No
The definition does not adequately address normal (pre-contingency) operating procedures
or system configurations. Language should be added to the requirement (perhaps as
R1.1.7) to include normal operating procedures or system configurations in place prior to
any contingency occurring.
Yes
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Yes
Yes
Yes
Yes
NO We wish to make a comment on the stability extreme event table: Changes were made
in planning event P5 to narrow the focus to specific relay failures. The same changes are
needed for stability extreme event 2a, 2b, 2c, and 2d.
Yes
No
We wish to make a comment on R4.3.1: it appears that this requires stability simulations of
both successful and unsuccessful high-speed reclosing for all contingency simulations
regardless of whether high-speed reclosing is used on the faulted line. We suggest the
following wording be used to replace the first bullet: ―Successful high-speed reclosing and
unsuccessful high-speed reclosing onto a fault, where such reclosing is applied, and where
such additional simulations are deemed appropriate by the PC or TP.‖ Also, we wish to
make a comment on footnote #13 of Table 1. 13. Applies to any of the following relay
functions or types: pilot (#85), distance (#21), differential (#87), current (#50, 51, & 67),
voltage (#27 & 59), directional (#32 & 67), and associated tripping (#86 & 94) relays.
Group
Hydro One Networks Inc.
David Kiguel
Yes
Yes
Yes
Yes
No
The scope of this requirement is too broad and non-specific and only results in undue study
burden.
No
There is insufficient information and experience regarding dynamic load modeling. Hence,
this should not be a requirement but a guide or an item to be considered to the extent
possible. It may also be included as a ―sensitivity‖ analysis in 3.2, rather than requiring and
expecting accurate representation of dynamic load model.
Yes
Yes
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No selection boxes in this question. Yes, we support.
Yes
Yes
Requirement 8 is an administrative burden and adds little or no value to the BPS reliability.
Therefore, the inclusion of a set of VSLs for Requirement 8 is unnecessary.
Group
jWestern Electricity Coordinating Council
Steve Rueckert
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on various requirements not
identified in the questions below; therefore, we have included our comments here:
Requirement and 2.6 and 2.6.1: A study that is five years old is very likely to be out of
date. The entity's BES may have not changed much in five years but the entity cannot be
certain whether or not their neighbor‘s system may have changed. Changes outside the
immediate entity's system can impact results of studies within their system. Suggest that
two years is a maximum that past studies should be allowed. Requirement 3.4.1 and 4.4.1
require PCs and TPs to coordinate with adjacent PCs and TPs to ensure that Contingencies
on adjacent Systems which may impact their Systems are included in the Contingency list.
Please clarify whether this means that a PC or TP must coordinate with others to identify
contingencies on other Systems that the PC or TP must now include on their Contingency
list to simulate and address any performance violations on their own System, or does it
mean that the PC or TP must coordinate with others to identify contingencies on their
System that the PC or TP must now include on their Contingency list to simulate and
address any performance violations on other Systems. In either case, the standard does
not seem to clearly state what must be done, or whose responsibility it is to mitigate, if a
contingency in one System causes a performance violation in another System. Requirement
R4.3.1, bullet point 3 requires the stability analyses to include the impact of subsequent
―[t]ripping of Transmission lines and transformers where transient swings cause Protection
System operation based on generic or actual relay models‖. As written, this bullet could be
interpreted as requiring the inclusion of these relay models in stability data bases. We do
not have generic or actual relay models in our dynamics data bases for tripping line faults
on lines and transformers represented. We represent actual relay response and tripping
times of relays, communications, and breakers to faults in tripping transmission lines and
transformers. Requiring the inclusion of generic or actual relay models for all relays that
can trip lines and transformers would add a large burden to the development and
maintenance of accurate dynamics model files that would add little or no benefit. Please
change this bullet to read: ―Tripping of Transmission lines and transformers where transient
swings cause Protection System operation based on known Protection System response‖.
No
We recognize that the drafting team made changes to the definition of Year One based on
industry comments. However, we believe that the revised language could allow for a
situation where an entity could use its next season‘s operating study as its Year One
planning study. For example, if the entity does its study in the fall of 2011, the proposed
definition would allow the entity to use its summer 2012 operating study as its Year One
study. This is a very short period to address any issued identified. Suggest working into the
requirement that Planning Studies must look out at least 12 months beyond when the study
is performed. This would still allow for the provision in the current definition example (―if a
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Planning Assessment was started in 2011, then Year One must include the forecasted peak
Load period for either 2012 or 2013) because the entity would be able to use their 2013
Load period, but it would prevent the entity from using the 2012 Load period if they started
the assessment late in 2011.
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
Dilip Mahendra
SMUD
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
R2.7.1, last bullet: Please provide specifics on the types of acceptable ‗Corrective Actions‘
covered by ‗rate applications and DSM‘ and the planning horizon for which they are
considered acceptable. As an alternative, NERC should develop a process by which what is
considered acceptable is published and continuously updated. (With due apologies for not
raising this point earlier).
What is the significance of changing the wording for section R2.1.5 from ‗assessed‘ to
‗studied‘ and ‗Planning Assessments‘ to ‗studies‘?
For the Western Interconnection, the performance level for a Bus-tie breaker fault under
TPL-001-2, Table 1, Item P2-4, Notes (a) and (f), requires no thermal overloads and no
cascading. While, FAC-010-2.1, R1.2, R2.5-R2.6, as modified by E1.1, E1.1.7, E1.3, and
E1.3.1 requires a different performance level of no cascading. Please explain why this
regional variance is not included under TPL-001-2, Item E.
Group
Arizona Public Service Company
Jana Van Ness, Director Regulatory Compliance
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
RoLynda Shumpert
South Carolina and Gas
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
We wish to make a comment on the revisions to R4.3.1. We believe that the analysis of
both successful and unsuccessful high speed reclosing for all cases is not justified and
should be left to the discretion of the Transmission Planner.
Individual
Brian Keel
SRP
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
Darcy O'Connell
California ISO
Yes
Yes
Yes
Yes
No
Requirement 2.7.2 could be revised as follows: 2.7.2. Corrective Action Plans are not
required for performance deficiencies identified in a sensitivity analysis. If a Planning
Coordinator includes Corrective Action Plans to resolve performance deficiencies identified
in multiple sensitivity analysis, the Planning Coordinator shall provide documentation to
support those Plans.
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
We support these changes, although we suggest that the proposed footnote 12 include an
interim provision to default to the existing footnote ―b‖ in TPL-002-0 until Project 2010-11
is decided. Please revise footnote 12 to read, ―Note: Non-Consequential Load Loss is being
decided in Project 2010-11. When that project is finalized, the resolution will be copied
here. In the interim, planned or controlled interruption of electric supply to radial customers
or some local Network customers, connected to or supplied by the Faulted element or by
the affected area, may occur in certain areas without impacting the overall reliability of the
interconnected transmission systems. To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers.‖
Yes
No
Requirement 8 is an administrative burden to TPs and PCs that adds no value to reliability.
PCs should be including TPs, neighboring PCs and interested parties in its planning
processes when developing the Planning Assessments. Therefore, the inclusion of a set of
VSLs for Requirement 8 is unnecessary. Should the SDT decide to leave the VSLs for
Requirement 8, Requirement 8.1 should be revised to reflect that comments only to the
final Assessment (not drafts developed during a process) need a response as follows: 8.1 If
a recipient of the planning assessment final results provides documented comments on the
results, the respective Planning Coordinator or Transmission Planner shall provide a
documented response to such recipient within 90 calendar days of receipt of those
comments. For a Planning Coordinator (PC) who distributes the Planning Assessment to
many different entities (to adjacent PCs, TPs, and other functional entities), a concern
regarding the Requirement R8 VSL is that it is overly restrictive to apply a violation for
failing to distribute the results of its Planning Assessment to only one PC, TP, or functional
entity (and to apply a High VSL for failing to distribute to more than one entity), particularly
since an entity‘s contact is subject to change over time, and since Measure M8 allows for
publicly posting the results of its Planning Assessment to its website. Should the SDT decide
to include the VSLs for Requirement 8, would recommend revising to use a percentage
approach rather than applying a violation to a Planning Coordinator who fails to provide the
results of its Planning Assessment to one PC, TP, or other functional entity (or applying a
High VSL for failing to distribute to more than one entity.) Recommend applying a similar
percentage approach to the VSLs drafted by NERC Staff for Project #2007-23 VSLs (e.g.,
for FAC-013-1) to be considered for the TPL-001-2 R8 VSLs. For example, • Lower VSL: The
responsible entity failed to provide the Planning Assessment final results to 5% or less of
the required entities. • Moderate VSL: The responsible entity failed to provide the Planning
Assessment final results to more than 5% up to (and including) 10% of the required
entities. • High VSL: The responsible entity failed to provide the Planning Assessment final
results to more than 10% up to (and including) 15% of the required entities. • Severe VSL:
The responsible entity failed to provide the Planning Assessment final results to more than
15% of the required entities OR [the existing language for the Severe VSL]. Explanation:
The VSLs were modified for consistency with other standards and VSLs. Reference: Link to
VSLs drafted by NERC Staff for Project #2007-23 VSLs (e.g., for FAC-013-1):
http://www.nerc.com/docs/standards/sar/Staff_Proposed_VSLs_2010July27.pdf
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Scott Inglebritson
Seattle City Light
Yes
No
The definition of Year One is now too flexible and does not meet the intent of the standard.
For example, our system peak is generally in January of the year. If I perform TPL studies
in November 2011, studying the peak in January 2012 is acceptable according to the new
definition. This is only two months from the date of the study. The intent of the TPL
standard should be that entities must study and plan for inadequacies found in the studies.
A one- or two-month lead time is not adequate to address any problems identified. Year
One should be the year containing the first peak 12 months or more from the current date.
Otherwise, TPL studies become merely seasonal operational studies, not planning studies.
Alternative Language: "For the Planning Assessment started in a given year, Year One
should contain the first system peak that occurs twelve months or more after the date of
the Planning Assessment."
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 does not recognize the existence of redundant (or backup) relays. These are an
integral part of the protection system design and should be considered in analysis of SLG
faults. The TPL standard should encourage redundant, fail-safe systems, not ignore them.
In Table 1, P2 and P3, we have a concern about not allowing non-consequential load loss.
Project 2010-11 is deciding on this issue, but is not completed (see footnote 12). Should
the standard become effective before this project is completed, no non-consequential load
loss would be allowed, requiring many transmission additions and reconfigurations. Please
change the "NO" in the last column to "YES" until the completion of Project 2010-11.
Yes
Yes
Individual
Ean O'Neill
California Energy Commission
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No. Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure
of a relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
Kathleen Goodman
ISO New England Inc.
Yes
No
The definition of Year One could be deleted and used in place of Year One within the text of
the requirement. The proposed definition has now added ambiguity with respect to ―year
two‖ and ―year five‖ which are not defined. Year two could be deleted and R.2.1.1 modified
as follows: System peak Load representing a point in time 12-24 months and another point
in time 48-65 months into the future from the time the study is initiated.
No
R1.1 Part 1.1.2. With respect to known outages, there needs to be greater flexibility in the
standards (e.g. more tolerance to non-consequential load shedding or limitations to the
contingencies that need to be considered (e.g. P0, P1, & P2)). Regional allowances for load
shedding under this condition should be approved. Duration of known outages should be
increased from six months to one year; R1.1 Part 1.1.6 Delete "required for Load".
Resources may also be used for export to other areas, not just internal load.
No
We can agree with R2.1 however with respect to R2.2 Language should be consistent with
2.1 for example - use "current or qualified past studies" instead of "the following annual
current study."
No
Part 2.1.4, requires an entity to vary one or more conditions to demonstrate a change in
performance. If the cases were initially stressed, this may force an entity to simulate
conditions with less severe stresses. At this point, there is limited to no value to this
additional workload. Having a requirement to test at least one sensitivity as a blanket
requirement may not be informative by itself and is more unclear since sensitivities are
being required on an undefined base set of conditions. Additionally, our concern involves
wording under 2.1.4 and 2.4.3 that sensitivities are required varying one or more
conditions. Subsequently, in requirement 2.7.2 corrective action plans need to be
developed to resolve performance deficiencies ―only‖ if identified in multiple conditions or
require a rationalization why no corrective action plan is necessary. Multiple conditions
sensitivities under 2.1.4 and 2.4.3 are necessary to satisfy requirement 2.7.2. Requirement
2.7.2 adds ambiguity and should be removed. Requirement 2.7.2 should be revised as
follows: 2.7.2. Corrective Action Plans are not required for performance deficiencies
identified in a sensitivity analysis.
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
We are supportive of the change to P5. However, in making this modification, other items
need to also be changed. In Table 1 – Stability, the language should be made similar to
wording in P5. Protection System should be removed and replaced with the words ―relay
failure‖. This change should be made for 2a through 2d: 2. Local or wide area events
affecting the Transmission System such as: a. 3Ø fault on generator with stuck breaker10
or a relay failure resulting in Delayed Fault Clearing. b. 3Ø fault on Transmission circuit with
stuck breaker10 or a relay failure resulting in Delayed Fault Clearing. c. 3Ø fault on
transformer with stuck breaker10 or a relay failure resulting in Delayed Fault Clearing. d.
3Ø fault on bus section with stuck breaker10 or a relay failure resulting in Delayed Fault
Clearing. We also believe that Note 11 needs clarifying wording as shown below: "Excludes
circuits that share a common structure (Planning event P7, Extreme event steady state 2a)
or common Right-of-Way (Extreme event, steady state 2b) for a total of 1 mile or less"
Yes
Yes
Requirement 8 and 8.1, should be revised to reflect that comments only to the final
Assessment (not drafts developed during a process) need a response and there should be a
limit on the comment period as follows: If a recipient of the planning assessment final
results provides documented comments on the results within 90 days of receipt, the
respective Planning Coordinator or Transmission Planner shall provide a documented
response to such recipient within 90 calendar days of receipt of those comments. We have
other comments not addressed by this Comment Form as follows - Sections 2.7, 3.3, 4.3
and overall. R2.7 requires that Corrective Action Plans are included in each Planning
Assessment and states ―Such actions may include…‖ followed by a list of actions.
Runback/tripping of HVDC should be added to the list. Section 3.3 - We feel that the last
sentence of 3.3.1 should be removed. This is handled by PRC-023. Line ratings are
addressed by PRC-023. PRC-023 requires coordination with the Reliability Coordinator.
Remove ―Tripping of Transmission elements where relay loadability limits are exceeded.‖
Section 4.3 - High speed reclosing needs to be defined.
Individual
Oscar Herrera
Los Angeles Department of Water and Power
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No. Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure
of a relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Yes
Yes
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Orlando A Ciniglio
Idaho Power Co
Yes
We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge redundant relays for primary
protection: ―Single failure of a protection relay13 protecting the Faulted element to operate
as designed, resulting in backup relay actions or Delayed Fault Clearing, for one of the
following‖. In Table 1, P2 and P3, the last column ―Non-Consequential Load Loss Allowed‖
where the requirement "No12" appears, and in footnote 12, the standard as proposed does
not allow for any Non-Consequential Load Loss. When the Non-Consequential Load Loss
(footnote b) issue is clarified in Project 2010-11 this requirement may be changed.
Therefore, if this proposed Standard is enforced before Project 2010-11 is completed,
entities will be required to meet this No Non-Consequential Load Loss requirement without
the exception allowed in the existing TPL-002-0, footnote ―b‖. This will require immediate
redesigns to meet this particular requirement. The unintended consequence could be that
operators of local systems that are currently networked may opt to begin operation as
radial systems, and future designs for local systems may be radial, at any voltage level. We
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
suggest that the proposed footnote 12 include a provision to default to the existing footnote
―b‖ in TPL-002-0 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note:
Non-Consequential Load Loss is being decided in Project 2010-11. When that project is
finalized, the resolution will be copied here. In the interim, planned or controlled
interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in
certain areas without impacting the overall reliability of the interconnected transmission
systems. To prepare for the next contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric power Transfers.‖
Yes
Yes
Individual
David Bradt
United Illuminating
Yes
No
Year One should be used within the text of the requirement. Do not have a definition for
Year One.
No
For R1 Ambiguity regarding base case assumptions, in combination with lack of clarity and
clear direction of purpose regarding the sensitivity analysis, undermines the objectives of
the standard; R1.1 Part 1.1.2. With respect to known outages, there needs to be greater
flexibility in the standards (e.g. more tolerance to non-consequential load shedding or
limitations to the contingencies that need to be considered (e.g. P0, P1, & P2)). Regional
allowances for load shedding under this condition should be approved. Duration of known
outages should be increased from six months to one year; R1.1 Part 1.1.6 Delete "required
for Load". Resources may also be used for export to other areas, not just internal load.
No
We can agree with R2.1 however with respect to R2.2 Language should be consistent with
2.1 for example - use "current or qualified past studies" instead of "the following annual
current study".
No
If an entity does a stressed set of assumptions do they always need to do a non-stressed
case?
Yes
Yes
Yes
In Table 1 – Stability, Make language similar to wording in P5. "Protection System" should
be removed and replaced with the words "relay failure". This would avoid future
interpretation issues about the intent of this requirement (as we understand it) to exclude
more severe though less likely failures such as battery systems. This change should be
made for 2a through 2d on page 12). In Note 11 (page 14) ADD the wording shown in
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"quotes" below: Excludes circuits that share a common structure (Planning event P7,
Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady state 2b)
for "a total of" 1 mile or less.
Yes
Yes
General Comment: We have other comments not addressed by this Comment Form as
follows - Section 3.3, Section 4.3 and overall Section 3.3 - We feel that the last sentence of
3.3.1 should be removed. This is handled by PRC-023. Line ratings are addressed by PRC023. PRC-023 requires coordination with the Reliability Coordinator. Remove ―Tripping of
Transmission elements where relay loadability limits are exceeded.‖ Section 4.3 - High
speed reclosing is not defined. Overall – ISO New England and New England Transmission
Owners have previously made comments which have not been addressed in the current
version of the proposed standard. Support for the standard can at most be limited without
addressing comments. We have previously commented on sensitivity analysis and guidance
for base case assumptions. Also, extreme event analysis should not be mandated in this
standard as no corrective action is required.
Group
Transmission Issues Subcommittee
Bob Cummings
No Comment
No Comment
Yes
No Comment
No comment
No
TIS believes that the term ―expected‖ leaves the question as to ―whose expectation.‖ It
should be stated as to ―expected…by the Transmission Planner.‖
No comment
No
Delete the word ―voltage‖ from the last header note J concerning Stability Only. All types of
transient stability must be observed.
No comment
No comment
No comment
Group
SERC Dynamics Review Subcommittee
Robert Jones
Yes
―The comments expressed herein represent a consensus of the views of the above named
members of the SERC Engineering Committee Dynamics Review Subcommittee only and
should not be construed as the position of SERC Reliability Corporation, its board or its
officers.‖
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
Yes. The SERC DRS supports the revisions.
Yes
Yes
We wish to make a comment on R4.3.1: it appears that this requires stability simulations of
both successful and unsuccessful high-speed reclosing for all contingency simulations
regardless of whether high-speed reclosing is used on the faulted line. We suggest the
following wording be used to replace the first bullet: ―Successful high-speed reclosing and
unsuccessful high-speed reclosing onto a fault, where such reclosing is applied." We wish to
make a comment on the stability extreme event table: Changes were made in planning
event P5 to narrow the focus to specific relay failures. The same changes are needed for
stability extreme event 2a, 2b, 2c, and 2d.
Individual
John Sullivan
Ameren
Yes
Yes
No
The definition does not adequately address normal (pre-contingency) operating procedures
or system configurations. Language should be added to the requirement (perhaps as
R1.1.7) to include normal operating procedures or system configurations in place prior to
any contingency occurring.
Yes
Yes
No
Industry needs guidance regarding how to provide reasonable induction motor
representation as opposed to generic models.
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
For measurements M3 and M4, there is some question as to what is to be provided as
evidence of a study. Would the study results alone provide sufficient evidence, or does the
entire powerflow, stability, or short circuit effort need to be documented in a formal study
report? There are no measures for the creation and coordination of contingency lists that
are to be developed in R3.4, R3.5, R4.4, and R4.5. Are these contingency lists required to
be a documented part of the study?
No
The sharing issues of requirement R8 are still not clear, therefore the R8 VSL is not clear. It
is not clear if the intent of the SDT is for the PC to share the assessments with PCs and TPs
are to share the assessments with TPs, or whether the intent is for the TP to share its
assessments with its PC. Will posting the assessment to a secure web-site meet the intent
of the requirement? Although the comment form is not designed to allow for such, we need
to comment on R4.3.1: As written, it appears that this requires stability simulations of both
successful and unsuccessful high-speed reclosing for all contingency simulations, regardless
of whether high-speed reclosing is actually implemented. A suggested wording change for
the first bullet: ―Successful high-speed reclosing and unsuccessful high-speed reclosing
onto a fault, where such reclosing is applied, and where such additional simulations are
deemed appropriate by the PC or TP.‖ Another comment needs to be made regarding the
stability extreme event table: Changes were made in planning event P5 to concentrate on
specific relay failures. The same changes need to be made for stability extreme events 2a,
2b, 2c, and 2d. The proposed standard will significantly increase the amount of work
required to develop more detailed and complex system models, to perform and document
the engineering studies to meet the performance requirements, and to develop the
assessments necessary for compliance. All of these increased engineering activities are
perceived to provide marginal benefit to the reliability of the bulk electric system, but will
require significant increases in manpower across the industry. Further, the manpower is
presently not available to develop these more detailed models and to perform these studies
with any reasonable assuredness. It will be a continuing challenge to the industry to obtain
and keep the engineering talent needed to perform these compliance activities for such
marginal benefits.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
Yes
Yes
Yes
No
Requirement R2 Part 2.2 should be modified to read as 2.1 (not impose current annual
studies as the only requirement for assessment)
No
It is questionable that sensitivity analysis be included in Requirements since a conservative
approach should already be used in studies, in accordance with good engineering practices.
No
There is insufficient data available to accurately model system wide motor loads.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
In table 1 on page 12 (Stability section), Relay failure should replace Protection System
Yes
Yes
• All references to 300 kV in document should be replaced with EHV (In the introduction,
section 5) • The first phrase of Note 3 on p 14 should be revised as follows: ―Bulk Electric
System (BES) level references include extra-high voltage (EHV) Facilities defined as those
representing the backbone of the System, generally at voltage greater than 300 kV, and
high voltage (HV) Facilities defined as those not representing the backbone of the System,
as determined by the Planning Coordinator and approved by Regional Entity.‖
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
Yes
Yes
Yes
We propose the following changes and questions: R1 – We offer the minor suggestion of
replacing the wording of ―maintain System models within their respective areas‖ with
―maintain System models of elements that are interconnected to any portion of the BES
that is owned or operated by the TP or PC‖. This wording would avoid the ambiguity that
can occur when a BA that is associated primarily with one TP declares ownership of a bus in
another TP‘s geographic area, but expects its primary TP to maintain the BA‘s model data
for the remote generation or load. R1.1.2 – We request the SDT opinion on how two
individual outages should be modeled if they are both in excess of six months duration and
they overlap by less than six months. Should the overlapping condition only be modeled if
the condition is expected to last more than six months?
Yes
R2.1.3 – We offer the minor suggestion of revising R2.1.3 to state, ―Known outages of
generation or Transmission Facilities with a duration of at least six months be simulated
along with P1 events for the System peak or Off-Peak conditions when the outages are
scheduled to occur.‖ We interpret that the requirement should only call for the simulation of
individual outages with duration of six months or more and not imply the simulation of
sequential (back-to-back) outages where each individual outage is less than six months,
but the composite duration of the back-to-back outages is more than six months. We also
interpret that if two or more known outages with duration of at least six months are
overlapping, then the overlapping outage condition would only be simulated for the
conditions when the overlapping outages are scheduled to occur if the duration of the
overlapping condition is at least six months. R2.1.5 – We offer a major suggestion
regarding the phrase ―could result in the unavailability of major transmission equipment‖
because this phrase is ambiguous and not defined. So, there is a significant risk of different
and possibly contradictory interpretations by TPs, PCs, and auditors. We proposed adding
that the TP and PC ―shall provide documentation to support the technical rationale for
defining unavailability of major transmission equipment‖ similar to R2.5.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
R2.1.4 & R2.4.3 – We offer a major suggestion regarding the terms of ‗credible‘ and
‗measurable change‖ because these terms are ambiguous and not defined. So, there is a
significant risk of different and possibly contradictory interpretations by TPs, PCs, and
auditors. We proposed adding that the TP and PC ―shall provide documentation to support
the technical rationale for determining the range of credible conditions and measurable
change in performance‖ similar to R2.5. R2.1.4 & R2.4.3 bullet items – We offer the minor
suggestion that the number and description of the bullet items in R2.1.4 match the bullet
points in R2.4.3. Otherwise, please explain the reasons for any differences between the
bullet items in R2.1.4 and R2.4.3. R2.1.4 bullet #2 & # 5 – We suggest that the wording in
bullet #2 be changed to ―Expected transfers and other generation dispatch scenarios‖. This
modification would put the transfer and dispatch element, which are complementary,
together in the same bullet item, rather than grouping the ‗generation dispatch‘ (operating
level) element together with the generation capacity elements in bullet item #5. R2.1.4
bullet #7 – We offer the minor suggestion that the term ―planned‖ be replaced with
―known‖ to be consistent with R1.1.2 and R2.1.3. Besides the term ―planned outage‖ has a
specific meaning in the Reliability Standards that are specific to the Operating horizon.
R2.7.2 – With regard to "include actions to resolve performance deficiencies identified in
multiple sensitivity studies", we do not think that mitigation plans should be required for
deficiencies found in multiple sensitivity studies because the conditions in some sensitivity
studies are more extreme and less likely than base case conditions. It‘s impractical to
require corrective actions for longer term horizon sensitivities due to how fast the electric
grid changes. We believe sensitivity analyses are valuable to improving the development of
mitigation plans to address base case performance limit concerns. Some of the sensitivity
study conditions are not credible or plausible enough to warrant the implementation of
mitigation measures. What is the interpretation of multiple sensitivity studies - more than
one or a majority of the number that were studied?
Yes
Yes
Yes
We offer the major suggestion that Requirements not be created in the Performance Table
and be absent from the Requirement section. Requirements should only be referred to in
the Performance Table after they already exist in the Requirement section. a. Notes ―f‖ and
―g‖ under ―Steady State Only‖ section in the Table 1 header create requirements (e.g. use
the verb, ―shall‖) that do not appear in the Requirements section. We suggest adding
R3.3.5, which could read, ―Applicable System Operating Limits for the planning horizon
shall not be exceeded.‖ [After R3.3.5 is added, Notes ―f‖ and ―g‖ should be revised and
refer to R3.3.5.]. b. Note ―i‖ under ―Steady State Only‖ section in the Table 1 header
creates a requirement (e.g. use the verb, ―shall‖) that does not appear in the Requirements
section. We suggest adding R3.3.6, which could read, ―The response of voltage sensitive
Load including Load that is disconnected from the System by end-user equipment
associated with an event shall not be used to meet steady state voltage requirements.‖
[After R3.3.6 is added, Note ―d‖ should be revised to refer to R3.3.6. c. Note ―j‖ under the
―Stability Only‖ section in the Table 1 header creates a requirement (e.g. use the verb,
―shall‖) that does not appear in the Requirements section. We suggest adding R4.1.4, which
could read, ―Transient voltage response shall be within acceptable limits established by the
Planning Coordinator and the Transmission Planner‖. [After R4.1.4 is added, Note ―j‖ should
be revised to refer to R4.1.4.]
We offer the major suggestion that the P3 Category performance criteria be modified to
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apply only to the loss of two generators. The SDT properly recognizes that generator
outages are significantly more probable than line or transformer outages and should be
―higher‖ in the category list. However given the clearly higher probability of generator
outages, the probability of the loss of two generators is clearly higher than the loss of a
generator and line or the loss of a generator and transformer. Therefore, if the loss of two
generators is in the P3 category, then the loss of a generator and line or transformer should
be clearly ―lower‖ in the category list. We suggest the listing of: the loss of a generator and
some other element (e.g. transmission circuit, transformer, shunt device, and single pole of
DC line) be moved to a lower event category, such as the P6 Category by adding ―1.
Generator‖ to the listing in the Initial System Condition (Loss of . . .) column. Item 2.a in
the Extreme Events, Steady State section – Clarify the meaning of the loss of multiple
circuits in Item 2.a by using wording similar to P7. We suggest this text: ―a. Loss of three
or more circuits that share a common structure.‖ Footnote 6 – Further clarify the applicable
shunt devices in Footnote 6 with this suggested text: ―6. Requirements which are applicable
to shunt devices, also apply to FACTS devices that are connected to ground, but not
instrument voltage transformers or surge arresters.‖
Yes
Yes
Other Comments: 1. How are backup relays handled (TPL-002-0, R1.3.10 & TPL-001-2 R1
& P5)? What does FERC construe as normal system for a protection system. The TPL-001-2
R1 & P5, this standard doesn‘t appear to address primary protection and how this handled.
2. Revise the Planning Assessment definition to more explicitly apply to the BES and the
TPL-001 requirements. We suggest text of: ―Planning Assessment: Documented evaluation
of future Transmission System performance and Corrective Action Plans to remedy
identified deficiencies in the BES from the steady state and stability performance
requirements set forth in the TPL-001 standard.‖ 3. R2.1.5 – We propose replacing the
term ‗major Transmission‘ with ―BES‖ because BES is a well defined term, while the term,
‗major Transmission‗, is not. 4. Add R2.3.1 – We suggest the addition of a R2.3.1
requirement to emulate the distinction between the requirement to perform a short circuit
assessment and conduct required studies or analysis to support the assessment (e.g.
R2.1/R2.1.1 and R2.2/R2.2.1). We propose wording such as, ―Perform an analysis for at
least one year in the Near Term Transmission Planning Horizon.‖ This requirement would
set an expectation that an analysis should be conducted to at least one or more years in
the near-term planning horizon, rather than imply that an analysis of all five years in the
near-term planning horizon must be conducted. 5. R2.7.4 – We suggest that the wording of
R2.7.4 be the same as R.2.8.2. Otherwise, we propose that R2.7.4 and R2.8.2 be revised
with wording like, ―. . . implementation status of identified Corrective Action Plans for
System Facilities and Operating Procedures.‖ to clarify that the identified system facilities
and operating procedures refer only to those that were in the previous year‘s Corrective
Action Plans. 6. R3.3.1 – The term of ‗controls‘ is ambiguous and not defined, unlike the
term, ‘Protection Systems‘, which is defined. Therefore, we suggest that this item be
defined or more clearly described to avoid the risk of different and possibly contradictory
interpretations by TPs, PCs, and auditors. 7. R3.3.1, bullet #1 - We suggest qualifying
which generating units to consider and which voltage limits to simulate with revised
wording like, ―Trip generating units that are connected to the BES when actual or assumed
minimum generator steady state or ride through voltage limits are known and simulations
show voltages may fall below the voltage limit. If assumed voltage limits are used, then
they should be included in the assessment―. The requirement should not apply to all
relevant generating units until one of the MOD standards requires all Generator Owners to
provide their minimum generating unit voltage limits to the TP and PC. If the wording of
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R3.3.1 bullet #1 must be different from its counterpart, R4.3.1 bullet #2, then please
explain the reasons for any differences. 8. R3.4.1 – Compliance with the requirement ―to
coordinate‖ is problematic and non-measureable We suggest replacing it with the
requirement ―to communicate‖. 9. R3.5 - We interpret that R3.5 requires the TP and PC to
conduct an evaluation of possible actions to reduce the likelihood or impact of extreme
events, which produce the more severe impacts, if cascading outages may occur. Does the
drafting team intend for the TP and PC to fulfill this requirement for at least one event in
each of the five categories (i.e. 3 steady state and 2 stability) or in each of the 21
categories/sub-categories (i.e. 14 steady state and 7 stability). Also, if the resulting
cascading outages do not result in any overloads, under-voltages, voltage collapse, or loss
of generator synchronization, then should the evaluation of possible actions to reduce
likelihood or impact be required? 10. R4.1.1 – We suggest that there should be some
qualification of which generating units are referred to in this requirement. We propose that
the requirement say, ―No generating unit connected to the BES shall pull out of
synchronism.‖ For example, some utilities include smaller generation units that are
connected at voltages below 100 kV and even down to distribution voltage in their base
cases. 11. R4.1.2 – We propose that the wording of this requirement be revised to reflect
the same BES qualification of the generating unit that we noted in R4.1.1 above. 12. R4.3.1
– This requirement refers to high speed reclosing and we presume that this is special high
speed reclosing that is completed in several cycles, rather than the normal high speed
reclosing that is completed in a number of seconds. We recommend that the term high
speed reclosing be more clearly defined for this sub-requirement. 13. R5 – This
requirement should remove the criterion item, ―post-Contingency voltage deviation‖,
because this criterion is not used widely enough in the industry to be well established
criterion. 14. R8 – This requirement should be revised to limit the need to provide the
Planning Assessment as follows ―adjacent Planning Coordinators and adjacent Transmission
Planners and to any registered functional entity…‖ This suggestion is added to the
requirement to clarify that the word adjacent also applies to Transmission Planners and to
clarify that the functional entity must be registered in order for the entity to be applicable
to the requirement.
Individual
Sergio Garza
LCRA TSC
Yes
Yes
Yes
Yes
No
The first bullet item in Section 3.3.1 should be the same as the second bullet in Section
4.3.1. The wording is somewhat confusing in both. Also, the wording as proposed does not
recognize that a high voltage limit could also be violated. Edits to the item as shown below
are suggested. Tripping of generators where simulations show generation bus voltages or
high side generation step up (GSU) voltages are outside known limits, or assumed to be
outside generator steady state limits, or have reached the generator ride through voltage
limit. Include in the assessment any assumptions made.
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Yes
No
The third bullet of 4.3.1 requires the addition of relay models for stability studies. This type
of analysis is performed today by scripting the tripping of multiple lines due to breaker
failure events. The inclusion of relay models into the stability study will result in added
complexity and an over reliance on relay models for system stability assessment. The
stability assessment should assess stability resulting from the operation of relays as
opposed to reliance on a relay model for proper system representations. Assurance of the
proper operation of relays results from the analysis performed to set relays not from
stability studies. From Section 4.3.1: ―Tripping of Transmission lines and transformers
where transient swings cause Protection System operation based on generic or actual relay
models.‖ Section 4.5 requires that ―The rationale for those Contingencies selected for
evaluation shall be available as supporting information.‖ This will have to be developed.
Requirement R5 requires the establishment of criteria for transient voltage response of the
system. This seems unnecessary given the proposed changes to Table 1. The proposed
changes to table 1 seem to make clear the type of system response that is allowable
through its specification of what is allowable in terms of interruptions to Firm Transmission
and Non-Consequential loads. R5 states: ―Each Transmission Planner and Planning
Coordinator shall have criteria for acceptable System steady state voltage limits, postContingency voltage deviations, and the transient voltage response for its System. For
transient voltage response, the criteria shall at a minimum, specify a low voltage level and
a maximum length of time that transient voltages may remain below that level.‖
An important footnote to Table 1 is omitted from this proposed revision. This omission
prevents adequate evaluation of the footnote. Footnote 12 in Table 1 is no longer applied to
P2.1, P2.2, P2.3, P4, and P5. The footnote states: ―Non-Consequential Load Loss is being
decided in Project 2010-11. When that project is finalized, the resolution will be copied
here.‖ The footnote should be removed from the proposed revision until Project 2010-11 is
concluded.
Individual
Saurabh Saksena
National Grid
Yes
No
Year One should be used within the text of the requirement. Do not have a definition for
Year One. Year two could be deleted and R.2.1.1 modified as follows: For the Planning
Assessment started in a given calendar year, the first year that is studied must include the
forecasted peak Load period for one of the following two calendar years. An additional
Near-term study must be performed that is four calendar years beyond the first year that is
studied.
No
For R1: Ambiguity regarding base case assumptions, in combination with lack of clarity and
clear direction of purpose regarding the sensitivity analysis, undermines the objectives of
the standard; R1.1 Part 1.1.2. With respect to known outages, there needs to be greater
flexibility in the standards (e.g. more tolerance to non-consequential load shedding or
limitations to the contingencies that need to be considered (e.g. P0, P1, & P2)). Regional
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allowances for load shedding under this condition should be approved. Duration of known
outages should be increased from six months to one year; R1.1 Part 1.1.6 Delete "required
for Load". Resources may also be used for export to other areas, not just internal load.
No
We can agree with R2.1 however with respect to R2.2 Language should be consistent with
2.1 for example - use "current or qualified past studies" instead of "the following annual
current study".
No
If an entity does a stressed set of assumptions do they always need to do a non-stressed
case?
Yes
Yes
Yes
In Table 1 – Stability, Make language similar to wording in P5. Protection System should be
removed and replaced with the words relay failure. This change should be made for 2a
through 2d: 2. Local or wide area events affecting the Transmission System such as: a. 3Ø
fault on generator with stuck breaker10 or a relay failure resulting in Delayed Fault
Clearing. b. 3Ø fault on Transmission circuit with stuck breaker10 or a relay failure resulting
in Delayed Fault Clearing. c. 3Ø fault on transformer with stuck breaker10 or a relay failure
resulting in Delayed Fault Clearing. d. 3Ø fault on bus section with stuck breaker10 or a
relay failure resulting in Delayed Fault Clearing. In Note 11 change wording as shown
below: Excludes circuits that share a common structure (Planning event P7, Extreme event
steady state 2a) or common Right-of-Way (Extreme event, steady state 2b) for a total of 1
mile or less
Yes
Yes
Other Comments: Section 3.3 - We feel that the last sentence of 3.3.1 should be removed.
This is handled by PRC-023. Line ratings are addressed by PRC-023. PRC-023 requires
coordination with the Reliability Coordinator. Remove ―Tripping of Transmission elements
where relay loadability limits are exceeded.‖ Section 4.3 - High speed reclosing is not
defined. We have previously commented on sensitivity analysis and guidance for base case
assumptions. Also, extreme event analysis should not be mandated in this standard as no
corrective action is required.
Individual
Charles Lawrence
American Transmission Company
Yes
Yes
No
We propose the following changes and questions: R1 – We offer the minor suggestion of
replacing the wording of ―maintain System models within their respective areas‖ with
―maintain System models of elements that are interconnected to any portion of the BES
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that is owned or operated by the TP or PC‖. This wording would avoid the ambiguity that
can occur when a BA that is associated primarily with one TP declares ownership of a bus in
another TP‘s geographic area, but expects its primary TP to maintain the BA‘s model data
for the remote generation or load. R1.1.2 – We request a SDT opinion on how two
individual outages should be modeled if they are both in excess of six months duration and
they overlap by less than six months. Should the overlapping condition only be modeled if
the condition is expected to last more than six months?
No
R2.1.3 – We offer the minor suggestion of revising R2.1.3 to state, ―Known outages of
generation or Transmission Facilities with a duration of at least six months be simulated
along with P1 events for the System peak or Off-Peak conditions when the outages are
scheduled to occur.‖ We interpret that the requirement should only call for the simulation of
individual outages with duration of six months or more and not imply the simulation of
sequential (back-to-back) outages where each individual outage is less than six months,
but the composite duration of the back-to-back outages is more than six months. We also
interpret that if two or more known outages with duration of at least six months are
overlapping, then the overlapping outage condition would only be simulated for the
conditions when the overlapping outages are scheduled to occur if the duration of the
overlapping condition is at least six months.
No
R2.1.4 & R2.4.3 – We offer a major suggestion regarding the terms of ‗credible‘ and
‗measurable change‖ because these terms are ambiguous and not defined. So, there is a
significant risk of different and possibly contradictory interpretations by TPs, PCs, and
auditors. We proposed adding that the TP and PC ―shall provide documentation to support
the technical rationale for determining the range of credible conditions and measurable
change in performance‖ similar to R2.5. R2.1.4 & R2.4.3 bullet items – We offer the minor
suggestion that the number and description of the bullet items in R2.1.4 match the bullet
points in R2.4.3. Otherwise, please explain the reasons for any differences between the
bullet items in R2.1.4 and R2.4.3. R2.1.4 bullet #7 – We offer the minor suggestion that
the term ―planned‖ be replaced with ―known‖ to be consistent with R1.1.2 and R2.1.3.
Besides the term ―planned outage‖ has a specific meaning in the Reliability Standards that
are specific to the Operating horizon. R2.7.2 – With regard to "include actions to resolve
performance deficiencies identified in multiple sensitivity studies", we do not think that
mitigation plans should be required for deficiencies found in multiple sensitivity studies
because the conditions in sensitivity studies are more extreme and less likely than base
case conditions. Some sensitivity study conditions are not credible or plausible enough to
warrant the implementation of mitigation measures. What is the SDT interpretation of
multiple studies - more than one or a majority of the sensitivities that were studied?
Yes
Yes
No
We offer the major suggestion that Requirements not be created in the Performance Table
and be absent from the Requirement section. Requirements should only be referred to in
the Performance Table after they already exist in the Requirement section. (a.) Notes ―f‖
and ―g‖ under ―Steady State Only‖ section in the Table 1 header create requirements (e.g.
use the verb, ―shall‖) that do not appear in the Requirements section. We suggest adding
R3.3.5, which could read, ―Applicable System Operating Limits for the planning horizon
shall not be exceeded.‖ [After R3.3.5 is added, Note ―a‖ should be revised and refer to
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R3.3.5.]. (b.) Note ―i‖ under ―Steady State Only‖ section in the Table 1 header creates a
requirement (e.g. use the verb, ―shall‖) that does not appear in the Requirements section.
We suggest adding R3.3.6, which could read, ―The response of voltage sensitive Load
including Load that is disconnected from the System by end-user equipment associated
with an event shall not be used to steady state voltage requirements.‖ [After R3.3.6 is
added, Note ―i‖ should be revised to refer to R3.3.6.]. (c.) Note ―j‖ under the ―Stability
Only‖ section in the Table 1 header creates a requirement (e.g. use the verb, ―shall‖) that
does not appear in the Requirements section. We suggest adding R4.1.4, which could read,
―Transient voltage response shall be within acceptable limits established by the Planning
Coordinator and the Transmission Planner‖. [After R4.1.4 is added, Note ―j‖ should be
revised to refer to R4.1.4.]
We offer the major suggestion that the P3 Category performance criteria be modified to
apply only to the loss of two generators. The SDT properly recognizes that generator
outages are significantly more probable than line or transformer outages and should be
―higher‖ in the category list. However given the clearly higher probability of generator
outages, the probability of the loss of two generators is clearly higher than the loss of a
generator and line or the loss of a generator and transformer. Therefore, if the loss of two
generators is in the P3 category, then the loss of a generator and line or transformer should
be clearly ―lower‖ in the category list. We suggest the listing of: the loss of a generator and
some other element (e.g. transmission circuit, transformer, shunt device, and single pole of
DC line) be moved to a lower event category, such as the P6 Category by adding ―1.
Generator‖ to the listing in the Initial System Condition (Loss of . . .) column. We offer the
minor suggestion that Item 2.a in the Extreme Events, Steady State section – Clarify the
meaning of the loss of multiple circuits in Item 2.a by using wording similar to P7. We
suggest this text: ―a. Loss of three or more circuits that share a common structure.‖ We
offer the minor suggestion that Footnote 6 – Further clarify the applicable shunt devices in
Footnote 6 with this suggested text: ―6. Requirements which are applicable to shunt
devices, also apply to FACTS devices that are connected to ground, but not instrument
voltage transformers or surge arresters.‖ ATC has significant concerns with Q3.2 (R2.1.4 &
R2.4.3), Q4 (Table requirements) and Q5 (P3 scope), as noted above. In addition, ATC
offers the following suggestions to promote proper Reliability Standard quality and content.
(1.) Revise the Planning Assessment definition to more explicitly apply to the BES and the
TPL-001 requirements. We suggest text of: ―Planning Assessment: Documented evaluation
of future Transmission System performance and Corrective Action Plans to remedy
identified deficiencies in the BES from the steady state and stability performance
requirements set forth in the TPL-001 standard.‖ (2.) R2.1.5 – We propose replacing the
term ‗major Transmission‘ with ―BES‖ because BES is a well defined term, while the term
‗major Transmission‗ is not. (3.) Add R2.3.1 – We suggest the addition of a R2.3.1
requirement to emulate the distinction between the requirement to perform a short circuit
assessment and conduct required studies or analysis to support the assessment (e.g.
R2.1/R2.1.1 and R2.2/R2.2.1). We propose wording such as, ―Perform an analysis for at
least one year in the Near Term Transmission Planning Horizon.‖ This requirement would
set an expectation that an analysis should be conducted to at least one or more years in
the near-term planning horizon, rather than imply that an analysis of all five years in the
near-term planning horizon must be conducted. (4.) R2.7.4 – We suggest that the wording
of R2.7.4 be the same as R.2.8.2. Otherwise, we propose that R2.7.4 and R2.8.2 be revised
with wording like, ―. . . implementation status of identified Corrective Action Plans for
System Facilities and Operating Procedures.‖ to clarify that the identified system facilities
and operating procedures refer only to those that were in the previous year‘s Corrective
Action Plans. (5.) R3.3.1 – The term of ‗controls‘ is ambiguous and not defined, unlike the
term, ‘Protection Systems‘, which is defined. Therefore, we suggest that this item be
defined or more clearly described to avoid the risk of different and possibly contradictory
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interpretations by TPs, PCs, and auditors. (6.) R3.3., bullet #1 - We suggest qualifying
which generating units to consider and which voltage limits to simulate with revised
wording like, ―Trip generating units that are connected to the BES when actual or assumed
minimum generator steady state or ride through voltage limits are known and simulations
show voltages may fall below the voltage limit. If assumed voltage limits are used, then
they should be included in the assessment―. The requirement should not apply to all
relevant generating units until one of the MOD standards requires all Generator Owners to
provide their minimum generating unit voltage limits to the TP and PC. If the wording of
R3.3.1, bullet #1 must be different from its counterpart, R4.3.1, then please explain the
reasons for any differences. (7.) R3.4.1 – Compliance with the requirement ―to coordinate‖
is problematic and non-measurable. We suggest replacing it with the requirement ―to
communicate‖. (8.) R3.5 - We interpret that R3.5 requires the TP and PC to conduct an
evaluation of possible actions to reduce the likelihood or impact of extreme events, which
produce the more severe impacts, if cascading outages may occur. Does the drafting team
intend for the TP and PC to fulfill this requirement for at least one event in each of the five
categories (i.e. 3 steady state and 2 stability) or in each of the 21 categories/subcategories (i.e. 14 steady state and 7 stability). Also, if the resulting cascading outages do
not result in any overloads, under-voltages, voltage collapse, or loss of generator
synchronization, then should the evaluation of possible actions to reduce likelihood or
impact be required? (9.) R4.1.1 – We suggest that there should be some qualification of
which generating units are referred to in this requirement. We propose that the
requirement say, ―No generating unit connected to the BES shall pull out of synchronism.‖
For example, some utilities include smaller generation units that are connected at voltages
below 100 kV and even down to distribution voltage in their base cases. (10.) R4.1.2 – We
propose that the wording of this requirement be revised to reflect the same BES
qualification of the generating unit that we noted in R4.1.1 above. (11.) R4.3.1 – This
requirement refers to high speed reclosing and we presume that this is special high speed
reclosing that is completed in several cycles, rather than the normal high speed reclosing
that is completed in a number of seconds. We recommend that the term high speed
reclosing be more clearly defined for this sub-requirement. (12.) R5 – We propose
removing the criteria item, ―post-Contingency voltage deviation‖, because this criterion has
not been developed and used widely enough in the industry to be introduced into the
standards. (13.) R7 - Revise part of the requirement text to read, ―. . . identify each
entity‘s individual and joint responsibilities . . .― to provide better clarity. Perhaps this
requirement should be listed at the beginning of the Requirements section, instead being
mentioned near the end of this section. (14.) Change the forward referencing to backward
referencing. We agree with R2.6, R3.1, R3.5, R4.1, and 4.2. However, we suggest that the
requirements be ordered so that all of the references refer back to earlier text, rather later
text to be consistent with the rest of this standard and other referencing in this standard
(e.g. R2.1.3, R2.1.4, R2.4.3, R3, R3.3, R3.5, R4, R4.3, R4.4, R4.5), as well as other
standards.
Yes
Yes
Individual
Thad Ness
American Electric Power (AEP)
Yes
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Yes
Yes
Yes
R2, Part 2.1 – idicates that ‗qualified‘ past studies can be utilized. This is an ambiguous
term and we suggest the SDT consider the implications.
Yes
Yes
Yes
Yes
Yes
Yes
Individual
Bill Middaugh
Tri-State Generation & Transmission
Yes
No
Comments: The Year One definition is somewhat clearer now, but there is still some
ambiguity. We recommend the removal of the term ―Year One, year two, and year five‖
from R2.1.1. and deletion of the Year One definition (definitions are not required for year
two and year five, for instance). The Year One concept can be integrated into the definition
of Near-Term Transmission Planning Horizon, which we suggest changing to ―The period
beginning with the first year following the operating horizon, as determined by the
Transmission Planner or Planning Coordinator, through the fifth year.‖ Then, rather than
say ―Year One, year two, and year five‖, we can use the phrase ―at least one of the first two
years of the Near-Term Transmission Planning Horizon, and the fifth year‖. This will require
corresponding changes in R2.1.1 and R2.1.2.
No
We suggest changing the added sentence to ―This establishes the Category P0, No
Contingency, Initial System Conditions in Table 1.‖
No
2.1.5 – Change ―shall be performed for‖ to ―shall have been performed for.‖
Yes
No
Rather than specifically call out induction motor loads, we recommend changing the second
sentence to ―Stability analysis shall include models that represent the expected dynamic
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behavior of system elements that could impact the study area.‖
Yes
Yes
Table 1, P5 does not seem to account for redundant relays in the Protection System to
mitigate potential relay failure. We recommend changing the ―Event‖ to ―Delayed Fault
Clearing due to the failure of a relay to operate as designed, if that is the only relay
protecting the Faulted element, for one of the following:‖ In Table 1, P2 and P3, the last
column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12" appears,
and in footnote 12, the standard as proposed does not allow for any Non-Consequential
Load Loss. When the Non-Consequential Load Loss (footnote b) issue is clarified in Project
2010-11 this requirement may be changed. Therefore, if this proposed Standard is enforced
before Project 2010-11 is completed, entities will be required to meet this No NonConsequential Load Loss requirement without the exception allowed in the existing TPL002-0, footnote ―b‖. This will require immediate redesigns to meet this particular
requirement. The unintended consequence could be that operators of local systems that are
currently networked may opt to begin operation as radial systems, and future designs for
local systems may be radial, at any voltage level. We suggest that the proposed footnote
12 include a provision to default to the existing footnote ―b‖ in TPL-002-0 until Project
2010-11 is decided. Please revise footnote 12 to read, ―Note: Non-Consequential Load Loss
is being decided in Project 2010-11. When that project is finalized, the resolution will be
copied here. In the interim, planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency,
system adjustments are permitted, including curtailments of contracted Firm (nonrecallable reserved) electric power Transfers.‖ Timing of this project and project 2010-11 is
critical. It would be very difficult to vote to approve the proposed TPL-001-2 prior to
knowing the outcome of Project 2010-11 (footnote b issue). Second, we are unclear why
voltage relays are included in footnote 13 and think they can be removed. Third, in the
Extreme Events – Stability section of Table 1, items 2a-2d ―Protection System failure‖
should be changed to ―relay failure‖ to be consistent with Table 1, Category P5.
Yes
Yes
None regarding R8. The following comments refer to parts of the proposed standard for
which no questions are asked. R4, Part 4.1.2: The response to our previous comment
indicated that our description was for a system Stability issue. R4 is addressing system
Stability and we believe the comment still applies and that it was not answered in the
response. We have two issues with 4.1.2: Sometimes out-of-step (loss of generator
synchronism) is better mitigated through islanding by tripping transmission rather than by
tripping generators; the second point is that the ability of present modeling programs does
not include the capability to model all types of impedance relays and their associated OOS
blocking and tripping capabilities that are available. R4, Part 4.3.1: The third bullet implies
that all impedance relays (and perhaps others) will need to be modeled in the stability
databases. We question whether the existing simulation programs can accommodate this
large magnitude of data inclusion and whether there is any benefit to BES reliability.
Certainly using generic models rather than actual models would be of no benefit. We
recommend changing the third bullet to ―Evaluation of Protection System behavior when
transient power swings are detected or predicted to have impedance characteristics that
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may approach relay operating characteristics.‖
Individual
David Miller
Lakeland Electric
Yes
No
While the definition of Year One addresses the time span this year occupies, it does not
address when that time span begins. The example which was added to the definition
suggests that Year One begins twelve months from the start of the Planning Assessment,
but it does not appear to be specifically stated. The following language is recommended:
"The first twelve month period that a Planning Coordinator or a Transmission Planner is
responsible for assessing, beginning twelve months from the planned completion date of
the Planning Assessment."
No
Consider removing ―…the latest…‖ from R1 and changing R1.1.2 to state ―…six months
during the period of study.‖
No
No, the phrase any material changes used in requirement R.2.6.2 will effectively cause all
Planning Authorities to run all studies every year regardless of minor changes in the model.
The overwhelming majority of PAs use a 10 year set of planning models developed annually
by Regions or Subregions. These annual sets of planning models will always have some
changes. The annual study requirement is especially problematic for Stability and Short
circuit studies that require much more engineering time to complete and are much less
likely to have results impacted by minor model changes such as different load forecasts.
Uncertainty with audit review of technical rationale documentation will serve to focus
Transmission Planning engineering resources on short term compliance to an extent that is
counter productive. Please consider removing R.2.6.2
No
It is recommended that the phrase ―…measureable change in performance…‖ be changed to
―…measurable change in system response…‖ A change in performance is unclear, and could
suggest that a sensitivity study is valid only if the System is stressed to the point that it no
longer performs within the criteria established by Table 1. In addition, it is recommended
that the following text appear after the last sentence of 2.4.3: ―The condition or conditions
to be varied shall be left to the discretion of the Transmission Planner or Planning
Coordinator, provided they are selected from the list below.‖
Yes
Yes
Yes
The performance requirements of Table 1 do not allow the loss of non-consequential load
for single and multiple contingency events. The disallowance of load loss does not provide
any real benefit to the reliability of the BES and is an unnecessary overreach into local
quality of service issues that are best addressed by State, Provincial or Municipal
authorities. There may be circumstances such as high local transmission costs or local
opposition to transmission construction where prohibition of non-consequential load loss
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
represents a poor cost/benefit or quality of life tradeoff. Having a provision at the regional
level that a PA or TP can have a certain amount of non-consequential load loss designed or
planned in to its system that would be reasonable if it is acceptable to the RE and does not
have an adverse impact on the remaining BES. In lieu of such a RE provision, providing a
quantitative cap in non-consequential load loss such as 100 MW may be rationale
compromise in the goal of limiting load loss for the more probable outage events. Our
preference would be to retain the capability of limited non-consequential load loss. It is our
understanding that footnote 9 is under consideration as part of Project 2010-11 and should
be noted as such for clarification.
No
Consider removing ―the latest‖ from M1.
No
The requirement to distribute the Planning Assessment should be more flexible and allow
for making the Planning Assessment available, such that those entities that desire the
information can have it readily available. R8 should be modified as follows: Each Planning
Coordinator and Transmission Planner shall make available its Planning Assessment results
to adjacent Planning Coordinators and Transmission Planners and to any functional entity
that indicates a reliability related need for the Planning Assessment results.
Group
E.ON U.S.
[email protected]
No
Comments: 2.2.1. A current study assessing expected System peak Load conditions for one
of the years in the Long-Term Transmission Planning Horizon and the rationale for why that
year was selected. E.ON U.S. believes the scope of the ‗current study‘ should be defined. It
is not clear whether the scope is the same as outlined in section 2.1.
No
In the statement: ―the Planning Coordinator and Transmission Planner shall coordinate with
adjacent Planning Coordinators and Transmission Planners to ensure that Contingencies on
adjacent Systems which may impact their Systems are included in the Contingency list.‖
E.ON U.S. believes that the use of the pronoun ―their‖ in the quoted section above is
confusing. ―Their‖ could be read as applying to the adjacent Planning Coordinators and not
to the Planning Coordinator to whom the standard applies. E.ON U.S. recommends that the
word ―their‖ should be changed to ―the Planning Coordinator‘s and Transmission Planner‘s‖
in order to make it clear.
E.ON U.S. believes that Table 1 should be formatted to avoid having the tables split by
page breakers. In addition, tables spanning across multiple pages should have headers at
the top of each page.
Individual
Steve Stafford
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
GTC
Yes
Yes
Yes
Yes
Yes
No
We have concerns for including induction motor representations in the load models without
any study or bench-marking activities to meet the requirements of R2.4.1. This information
should be supplied by the LSE as part of the MOD standard. We understand that the
proposed standard will accept an aggregate system load model which represents the overall
dynamic behavior of the load to relieve the burden of trying to develop specific induction
motor load representation at each load bus. However this modeled system response will be
considerably different compared to the actual system response which will open up the
industry to unwarranted scrutiny and possible compliance violation investigations.
Yes
Yes
Yes
Yes
Individual
Chifong Thomas
Pacific Gas and Electric Company
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R3 or R4;
therefore, we have included our comments here: Section R4.3.1, bullet point 3 requires the
stability analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
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System operation based on known Protection System response‖. Section 3.4.1 and 4.4.1
require PCs and TPs to coordinate with adjacent PCs and TPs to ensure that Contingencies
on adjacent Systems which may impact their Systems are included in the Contingency list.
Please clarify whether this means 1) that a PC or TP must coordinate with others to identify
contingencies on other Systems that the PC or TP must now include on their Contingency
list to simulate and address any performance violations on their own System, or 2) that the
PC or TP must coordinate with others to identify contingencies on their System that this PC
or TP must now include on their Contingency list to simulate and address any performance
violations on the other Systems. In either case, the standard does not seem to clearly state
what must be done, or whose responsibility it is to develop the corrective action plan, if a
contingency in one System causes a performance violation in another System.
We recognize that the drafting team made changes to the definition of Year One based on
industry comments. However, we believe that the revised language could allow for a
situation where an entity could use its next season‘s operating study as its Year One
planning study. For example, if the entity does its study in the fall of 2011, the proposed
definition would allow the entity to use its summer 2012 operating study as its Year One
study. This is a very short period to address any issued identified. Suggest working into the
requirement that Planning Studies must look out at least 12 months beyond when the study
is performed. This would still allow for the provision in the current definition example (―if a
Planning Assessment was started in 2011, then Year One must include the forecasted peak
Load period for either 2012 or 2013) because the entity would be able to use their 2013
Load period, but it would prevent the entity from using the 2012 Load period if they started
the assessment late in 2011.
Yes
Yes
Yes
Yes
Yes
PG&E does not support the performance table, as currently revised. Table 1, P5 currently
requires the study of ―[d]elayed Fault Clearing due to the failure of a relay13 protecting the
Faulted element to operate as designed‖. As written, this requirement does not recognize
the use of redundant relays for primary protection. In some cases side by side relays are
used to provide primary fault tripping if one relay fails to operate. Per the requirement as
stated, the redundant relay would provide no value in meeting this requirement. Please
revise to acknowledge backup relays: ―Single failure of a protection relay13 protecting the
Faulted element to operate as designed, resulting in backup relay actions or Delayed Fault
Clearing, for one of the following‖. In Table 1, P2 and P3, the last column ―NonConsequential Load Loss Allowed‖ where the requirement "No12" appears, and in footnote
12, the standard as proposed does not allow for any Non-Consequential Load Loss. When
the Non-Consequential Load Loss (footnote b) issue is clarified in Project 2010-11 this
requirement may be changed. Therefore, if this proposed Standard is enforced before
Project 2010-11 is completed, entities will be required to meet this No Non-Consequential
Load Loss requirement without the exception allowed in the existing TPL-002-0, footnote
―b‖. This will require immediate redesigns to meet this particular requirement. The
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unintended consequence could be that operators of local systems that are currently
networked may opt to begin operation as radial systems, and future designs for local
systems may be radial, at any voltage level. We suggest that the proposed footnote 12
include a provision to default to the existing footnote ―b‖ in TPL-002-0 until Project 2010-11
is decided. Please revise footnote 12 to read, ―Note: Non-Consequential Load Loss is being
decided in Project 2010-11. When that project is finalized, the resolution will be copied
here. In the interim, planned or controlled interruption of electric supply to radial customers
or some local Network customers, connected to or supplied by the Faulted element or by
the affected area, may occur in certain areas without impacting the overall reliability of the
interconnected transmission systems. To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers.‖ Timing of this project and project 2010-11 is critical. It
would be very difficult to vote to approve the proposed TPL-001-2 prior to knowing the
outcome of Project 2010-11 (footnote b issue).
Yes
Yes
Group
Florida Reliability Coordinating Council, Inc - Transmission Working Group
Richard BEcker
Yes
No
No, because it is worded to be dependent upon when an assessment is started rather than
when the assessment is completed and valid. Assessments don‘t typically include a ―start
date‖. An assessment completed on a calendar date should include (be valid for) the
forecasted peak load for a timeframe that begins no more than 24 months from the date
that the assessment was completed.
No
No, Since ―the latest‖ data may become available after the study is complete, a planner
may not be able to ever complete a study. Please consider removing ―the latest‖ from the
second sentence.
No
No, Please consider removing R.2.6.2. The overwhelming majority of PAs use a 10 year set
of planning models developed annually by Regions or Subregions. These annual sets of
planning models will always have some changes. The annual study requirement is
especially problematic for Stability and Short circuit studies that require much more
engineering time to complete and are much less likely to have results impacted by minor
model changes such as different load forecasts. Uncertainty with audit review of technical
rationale documentation will serve to focus Transmission Planning engineering resources on
short term compliance to an extent that is counter productive.
No
This change does not clarify the required sensitivity analysis. A measureable change in
performance is unclear? Instead of a measurable change in performance, a measureable
change in contingency response of the Bulk Electric System would be more appropriate. A
change in performance implies not meeting one of the performance requirements as
specified in Table 1.
Yes
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No
This change does not clarify material. Material should be quantified somehow. We
recommend changing the phrase ―material generation additions or changes‖ to ―generation
in the vicinity with additions of changes larger than 200 MW‖.
Yes
We support the changes to the performance tables.
Footnote 12 performance requirements of Table 1 should allow the loss of nonconsequential load for all contingency categories except for P0. The disallowance of load
loss does not provide any real benefit to the reliability of the BES and is an unnecessary
overreach into local quality of service issues that are best addressed by State, Provincial or
Municipal authorities. There may be circumstances such as high local transmission costs or
local opposition to transmission construction where prohibition of non-consequential load
loss represents a poor cost/benefit or quality of life tradeoff. Having a provision at the
regional level that a PA or TP can have a certain amount of non-consequential load loss
designed or planned in to its system that would be reasonable if it is acceptable to the RE
and does not have an adverse impact on the remaining BES. In lieu of such a RE provision,
providing a quantitative cap in non-consequential load loss such as 100 MW may be
rationale compromise in the goal of limiting load loss for the more probable outage events.
Our preference would be to retain the capability of limited non-consequential load loss.
Footnote 9 should also be under consideration as part of Project 2010-11 and should be
noted as such for clarification.
No
It appears that there is a disagreement between R8 and M8, regarding public posting. We
Agree with M8 posting option.
No
The requirement to distribute the Planning Assessment should be more flexible and allow
for making the Planning Assessment available, such that those entities that desire the
information can have it readily available. R8 should be modified to replace distribute with
―make available:, so the new requirement would read as follows: Each Planning Coordinator
and Transmission Planner shall make available its Planning Assessment results to adjacent
Planning Coordinators and Transmission Planners and to any functional entity that indicates
a reliability related need for the Planning Assessment results.
Individual
Michael R. Lombardi
Northeast Utilities
Yes
No
NU does not support the revised definition of Year One as we believe it leads to confusion.
Our suggestion is that Year One should be the Peak Load Year after the study is initiated.
The subsequent years should be counted from Year One (e.g., a study that is started in
year 2010 with peak load in 2011 will have Year One as 2011 and Year Two as 2012, etc.).
No
NU believes that the Normal System Conditions as stated in Requirement R1 should
establish the base case conditions to be used for the assessment studies. More guidelines
for developing base cases should be addressed in the requirements. What the statement in
Requirement R1 lacks is the manner of creating generation dispatches and the level of
interface flows (level of stress), which are central to any base case to be used to assess the
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reliability of the electric power network. Depending upon how the base case dispatches and
the level of interface flows are created, a study may reveal reliability violations in the power
system. This is a weakness of the existing TPL standards. NU, however, will support the
idea of developing regional guidelines in regard to the nature of the base cases to be used
for the NERC reliability studies. Comment on Requirement R1.1, Part 1.1.2: With respect to
known outages NU requests that the six month duration listed by the requirement should
be changed to one year duration. Requirement R1.1 Part 1.1.6: The phrase "required for
Load" should be deleted as this confuses the issue [since resources may also be used for
export to other areas and not just internal load].
No
The revisions made to Requirement R2 Part 2.1 appear to resolve the concern that past
studies could not be used to comply with the short-term steady state study requirements.
However, the language of Requirement R2 Part 2.2 still seems to suggest that current
annual studies are always required for the long-term steady state assessment to be
compliant. This may have been an oversight, for consistency Requirement R2 Part 2.2
should be modified to similarly read as Requirement R2, Part 2.1.
No
The standard is referring to requirements for sensitivity and other issues without a
reference to base assumptions as commented in Question #3. The standard must describe
base assumptions. To define a sensitivity condition, NERC must define base assumptions.
Yes
Yes
Yes
Checked "No" NU agrees with the changes that have been made to the language of P5.
However, for Table 1 (Steady State and Stability Performance Extreme Events) – Stability,
the wording ―Protection Systems failure‖ should be changed to ―relay failure‖ similarly to
the change in P5. This change should be made for items 2a through 2d.
Yes
Yes
No comments on Question 7. Other Comments: As detailed below, NU has other comments
that are not addressed by this Comment Form as follows – Section 3.3, Section 4.3, NonConsequential Load Loss as referenced in the events Table 1 and studies using extreme
event contingencies. Section 3.3 – NU believes that the last sentence of Part 3.3.1 should
be removed since this is handled by PRC-023. Line ratings are addressed by PRC-023 which
requires coordination with the Reliability Coordinator. NU suggests the removal of the
following sentence: ―Tripping of Transmission elements where relay loadability limits are
exceeded.‖ Section 4.3 - High speed reclosing is not defined and to help eliminate any
confusion that it may introduce into the standard it will be worthwhile for the SDT to define
this term. Non-Consequential Load Loss – Depending upon the resolution of ―Project 201011, TPL Table 1, Footnote b‖ NU may have additional comments regarding this issue.
Studies Using Extreme Event Contingencies: The requirements for sensitivity analysis
already address issues going beyond what is expected to meet the reliability requirements
of the standard. Therefore, requiring extreme event analysis is requiring two layers of event
analysis beyond what is required and there is no requirement for corrective action if a
concern is identified.
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Individual
Christopher L. de Graffenried
Consolidated Edison Co. of New York, Inc.
No
Requirement R1 Part 1.1 and following states ―System models shall represent:… 1.1.5.
Known commitments for firm Transmission Service and Interchange. It was commented
during a previous posting that 1.1.5 should be reworded to read: Known commitments for
Firm Transmission Service, and, additionally, other types of transactions provided they
have been demonstrated to not violate existing reliability constraints. The response was
that ―The SDT believes that the defined term ‗Interchange‘ covers other transfers as
described in your comment. No change made.‖ It is agreed that known Interchange should
be modeled. However, it is imperative that existing reliability constraints not be violated in
the process. That is, Interchange relating to economic transactions should not drive
planning studies. Reliability-related investments should not be driven by congestion related
to economic transactions incorporated into planning models. Con Edison‘s Preferred
approach: • 1.1.5. Known commitments for firm Transmission Service and Interchange.
Interchange is meant to refer to energy transactions other than firm Transmission Service.
While rigorous planning studies have been conducted to permit the uninterrupted
implementation of firm Transmission Service without jeopardizing the reliable operation of
the Interconnected System, other types of energy transaction only take place whenever
system conditions permit them. They are usually of very short duration relative to planning
assessment periods (usually spanning for a few hours to a few days) and deemed highly
interruptible subject to reliability issues that may arise during operation of the system. In
other words, the term Interchange refers to economic transactions that are permitted when
the system is secure and there are reasonable reliability margins to effect dispatch changes
to lower operating costs. As such, Interchange should not be reflected in system
representation meant to assess system reliability in adherence to reliability criteria
delineated in documents such as TPL-001.
No
See NPCC comments
Yes
No
See NPCC comments
No
See NPCC comments
No
There is insufficient information and experience regarding dynamic load modeling. It may
also be included as a ―sensitivity‖ analysis in 3.2, rather than requiring and expecting
accurate representation of a dynamic load model. If this requirement is kept, a modeling
standard should be written that is specific to dynamic loads. This change belongs in a
modeling standard, not in TPL-001.
Yes
No
• Header note (i) in the first Table 1 (p. 10) The explicit representation of (voltagedependent) load models is perfectly consistent with the requirements defined in R1 (which
calls for a comprehensive representation of system components and their expected
operating status in the planning assessment period) and the impetus to the creation of
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
more specific load models in dynamic assessments found Requirement 2.4 of this draft of
TPL-001-2. It is a known that depressed voltage conditions cause certain system elements
to perform below their rated capacity. For example, capacitors provide less voltage support
and voltage controlling transformers are impeded by their finite tap range to direct VAR
flow into areas affected by low voltage conditions. Certain load types, on the other hand,
provide a self-compensating relief to depressed voltage by naturally decreasing demand in
a manner proportional to their characteristics, without operator intervention. Choosing to
negate the voltage-dependence of one of these system elements (load, in this case) results
in an inaccurate system representation that, in turn, may lead to erroneous assessments of
the reliability state of the interconnected system and, potentially, to the implementation of
unwarranted system upgrades.
See NPCC comments
Yes
No
See NPCC comments
Individual
Spencer Tacke
Modesto Irrigation District
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
No
The definition as it is in the current standards is fine. The new proposed definition is
unclear.
Yes
Yes
No
This new requirement will expand the scope of the study work beyond a reasonable extent.
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Group
Pepco Holings, Inc - Affiliates
Richard Kafka
Yes
Yes
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Individual
Alex Rost
NBSO
Yes
No
To avoid confusion, the formal definition for Year One should be eliminated and wording
used to describe Year One be placed within the appropriate requirement. For example,
R2.1.1 could be re-written to state: System peak Load representing a point in time 12-24
months and another point in time 48-65 months into the future from the time the study is
initiated.
No
R1 should have some language to state that base case assumptions should be made such
that they appropriately stress the system to be tested and are in accordance with good
engineering practice.
No
NBSO agrees with the language for R2.1, but the language with R2.2 should be changed to
be consistent with R2.1. NBSO disagrees with the revisions to R2.1.5. Requiring PAs to
study instead of assess the possible unavailability of equipment with a lead time of a year
or more will result in significant demand on resources with little impact on system
reliability. NBSO also questions what additional value such studies will bring in addition to
the N-1-1 requirements (P6).
No
Base case assumptions should be made such that they appropriately stress the system to
be tested and are in accordance with good engineering practice. If the base cases are
already stressed, the requirement to study sensitivity cases may result in the study of less
severe conditions, and thus require additional time and resources while providing little
additional value to the overall assessment.
No
By implication, the response of induction motor load would need to be considered when
modeling the expected dynamic behaviour of loads that could impact the study area. NBSO
suggests re-wording parts of R2.4.1 as follows: System peak load levels shall include a
model which represents the expected dynamic behaviour of loads that could impact the
study area. An aggregate system load model which represents the overall expected
dynamic behaviour of load is acceptable.
Yes
Yes
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For consistency, ‘Protection System‘ should be replaced with ‗relay‘ on Table 1 (p12)
Stability Section, items 2a-2d.
Yes
Yes
NBSO suggests considering rewording the VSL so that they address the failure to distribute
the final results of planning assessments.
Individual
Curtis A. Beveridge
Central Maine Power Company
Yes
No
The added clarification to the definition of Year One serves to remove most ambiguity with
respect to Year One. However, the revision has added further ambiguity to the terms ―year
two‖ and ―year five‖ which are not defined. For the Planning Assessment started in a given
calendar year, the first year that is studied must include the forecasted peak Load period
for one of the following two calendar years. An additional Near-term study must be
performed that is four calendar years beyond the first year that is studied. We recommend
defining Year Five as the twelve month period 4 to 6 calendar years from the date of the
Planning Assessment. We further recommend revising R2.1.1 as follows: ―System peak
Load for Year One and for Year Five.‖ Alternatively, the definition of Year One could be
eliminated and described within the text of the requirements.
No
For R1 Ambiguity regarding base case assumptions, in combination with lack of clarity and
clear direction of purpose regarding the sensitivity analysis, undermines the objectives of
the standard; R1.1 Part 1.1.2. With respect to known outages, there needs to be greater
flexibility in the standards (e.g. more tolerance to non-consequential load shedding or
limitations to the contingencies that need to be considered (e.g. P0, P1, & P2)). Regional
allowances for load shedding under this condition should be approved. Duration of known
outages should be increased from six months to one year; R1.1 Part 1.1.6 Delete "required
for Load". Resources may also be used for export to other areas, not just internal load.
No
We completely agree with the revision to R2.1, but this revision must be carried through to
other sections (R2.2, 2.2.1) and R2.2 language should be consistent with 2.1 for example use "current or qualified past studies" instead of "the following annual current study".
Revisions made to Requirement R2.1.5 have made it worse than as originally drafted. This
would require the PC & TP to study, or in other words perform technical analysis of, the
impact and probability of the possible unavailability of any piece of equipment with a lead
time of one year or more. Such an evaluation of spare equipment strategies would require
significant additional resources and data, but provide no benefit to system reliability, as it is
redundant to the existing N-1-1 contingency requirement (P6).
No
These sensitivities need to be considered if not already included in the base case
assumptions.
No
We have not determined a need to model dynamic loads, and therefore have not
benchmarked any such models. We recommend that prior to this requirement being in
place, a modeling standard should exist that is specific to dynamic loads.
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Yes
No
Header note (i) in the first Table 1 could imply that voltage-varying load shall not be used
to meet steady state performance requirements. NYISO steady state load models include
voltage-varying loads. This note should be revised to only reference loads which are
disconnected due to voltage.
In Table 1 – Stability, Make language similar to wording in P5. Protection System should be
removed and replaced with the words relay failure. This change should be made for 2a
through 2d: 2. Local or wide area events affecting the Transmission System such as: a. 3Ø
fault on generator with stuck breaker10 or a relay failure resulting in Delayed Fault
Clearing. b. 3Ø fault on Transmission circuit with stuck breaker10 or a relay failure resulting
in Delayed Fault Clearing. c. 3Ø fault on transformer with stuck breaker10 or a relay failure
resulting in Delayed Fault Clearing. d. 3Ø fault on bus section with stuck breaker10 or a
relay failure resulting in Delayed Fault Clearing. In Note 11 change wording as shown below
to include the words ―a total of‖: Excludes circuits that share a common structure (Planning
event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady
state 2b) for a total of 1 mile or less
Yes
No
Requirement 8 is an administrative burden to TPs and PCs that adds no value to reliability.
PCs should be including TPs, neighboring PCs and interested parties in its planning
processes when developing the Planning Assessments. Therefore, the inclusion of a set of
VSLs for Requirement 8 is unnecessary. Furthermore, the requirement lacks a specified
time frame to receive comments, thereby implying that TPs and PCs would be required to
reply to comments forever following the finalization of a Planning Assessment. The NYISO
proposes a limit of six months. Should the SDT decide to leave the VSLs for Requirement 8,
Requirement 8.1 should be revised to reflect that comments only to the final Assessment
(not drafts developed during a process) need a response as follows: If a recipient of the
planning assessment final results provides documented comments on the results within 180
calendar days of the issuance of those final results, the respective Planning Coordinator or
Transmission Planner shall provide a documented response to such recipient within 90
calendar days of receipt of those comments. We also have other comments not addressed
by this Comment Form as follows – Section 2.7, Section 3.3, Section 4.3, and overall:
Section 2.7 requires that Corrective Action Plans are included in each Planning Assessment
and states ―Such actions may include…‖ followed by a list of actions. Restricting allowable
actions, and excluding runback/tripping of HVDC would have a direct impact on multiple
existing facilities in New York and would adversely impact the reliability planning of the
NYCA. Runback/tripping of HVDC must be added to the list. Section 3.3 - We feel that the
last sentence of 3.3.1 should be removed. This is handled by PRC-023. Line ratings are
addressed by PRC-023. PRC-023 requires coordination with the Reliability Coordinator.
Remove ―Tripping of Transmission elements where relay loadability limits are exceeded.‖
Section 4.3 - High speed reclosing is not defined. Overall – We have previously made
comments which have not been addressed in the current version of the proposed standard.
Support for the standard can at most be limited without addressing comments. We have
previously commented on sensitivity analysis and guidance for base case assumptions.
Also, extreme event analysis should not be mandated in this standard as no corrective
action is required. The requirements for sensitivity analysis already address issues going
beyond what is expected to meet reliability requirements. Requiring extreme event analysis
is requiring two layers of event analysis beyond what is required, and there is no
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requirement for corrective action if anything is identified. The standard is referring to
requirements for sensitivity and other issues without a reference to base assumptions. The
standard must describe base assumptions. To define a sensitivity condition, NERC must
define base assumptions.
Group
Western Area Power Administration
Brandy A. Dunn
Yes
The whole bullet point section in the Effective Date section referring to Corrective Action
Plans could be deleted and instead captured by Requirement R2.7.3. A seven year grace
period is probably not favorable to FERC, and a better solution could be developed to meet
industry needs. In R2.7.3, a possible example of "beyond the control of the Transmission
Planner" could be that the physics of a significant percentage of induction motors in low
inertia air-conditioning loads would tend to pull out for certain N-1 events. This may in
significant part occur because such motors may have nearly no dynamic stability margin to
withstand such N-1 events as close-in 3-phase faults with normal clearing during peak load
conditions. So until the Transmission Planner has been able to institute changes in the
industry to address the basic physics of such loads, this Requirement 2.7.3 would permit
the use of such "Non-Consequential" Load Loss and curtailment of Firm Transmission
Service. In this example, it may take longer than a seven year time period to fix the
problem. On the other hand, some examples of Non-Consequential Load Loss could perhaps
be mitigated in a shorter timeframe. Provided that an entity has a good technical
justification and defined margin for ―Non-Consequential‖ Load Loss or curtailment of Firm
Transfers, then it may be acceptable. Requirement R2.7.3 seems to move in this direction.
Section R4.3.1, bullet point 3 requires the stability analyses to include the impact of
subsequent ―[t]ripping of Transmission lines and transformers where transient swings cause
Protection System operation based on generic or actual relay models‖. As written, this
bullet could be interpreted as requiring the inclusion of these relay models in stability data
bases. We do not have generic or actual relay models in our dynamics data bases for
tripping line faults on lines and transformers represented. We represent actual relay
response and tripping times of relays, communications, and breakers to faults in tripping
transmission lines and transformers. Requiring the inclusion of generic or actual relay
models for all relays that can trip lines and transformers would add a large burden to the
development and maintenance of accurate dynamics model files that would add little or no
benefit. Please change this bullet to read: ―Tripping of Transmission lines and transformers
where transient swings cause Protection System operation based on known Protection
System response‖.
Yes
Yes, this clarification helps. The drafting team could also define ―year five‖.
No
It‘s difficult to tell whether Requirement R1 is intended to require only one base case or
whether it was intended to require creation of separate models for each possible N-0
condition (―normal system condition‖) under a variety of stressing scenarios. The inserted
language does not seem to provide additional clarity. Suggested language may be ‖This
establishes the initial 'Normal System' condition corresponding to category P0 in Table 1.‖
Also, in Requirement R1.1.5, how are the Firm Transmission Service commitments
supposed to be modeled in Power Flow Cases? Are they just to be modeled as loads,
generation, and control area interchanges? Suppose a POR or POD is not at a generator or
load bus. What selection of generation and load would represent the projected system
conditions for this Firm Transmission Service commitment?
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No
R 2.1.5: The issue in this Requirement is studied in the Operations next-day; next-week;
next-month studies required under the TOP Standards; and are also covered by processes
such as the Operational Transfer Capability Policy Committee (OTCPC) seasonal study
process within the WECC. It would be quite onerous to run a complete power flow
simulation on separate base cases for each transformer (or other equipment with long lead
time) initially out of service. The revision in language from ―Planning Assessment‖ to
―studies‖ does not clarify that a power flow simulation is not necessarily required for each
situation. A valid assessment could include other methods such as using sound technical
reasoning to relate the initial out-of-service condition to a condition that has already been
studied. This condition may have taken place in previous operational studies. The language
in the standard could be improved to make this clarification – perhaps reference R2.6.
Additionally, this Requirement still needs further clarification. Currently the scope of
equipment applicable to the requirement could be misinterpreted as larger than that
contemplated by FERC. The standard as written seems to say that the responsible entity
needs to study the spare equipment strategy for all "major transmission equipment" with
long lead times. In the directive to include this requirement, FERC used the term "critical
facilities". In the NOPR to Order No. 693 they stated, "Critical facilities are those facilities
that impact IROLs and deliverability of generation to firm load" (P1081). In Order No. 693
FERC also said, "if an entity‘s spare equipment strategy for the permanent loss of a
transformer is to use a 'hot spare' or to relocate a transformer from another location in a
timely manner, the outage of the transformer need not be assessed under peak system
conditions" (P1725). Finally, the drafting team could clarify if this requirement applies to
radial branches (such as generator step-ups or step-down to load). Such branches may be
construed as ―critical facilities‖ but the impediment to deliverability of generation to firm
load is consequential to the initial outage.
Yes
In Requirement 2.1.4, "Sensitivity Analysis‖. How much change does it take in any of the
modeling assumptions (load, generation, voltage support, topology, etc.) to significantly
stress the system within a range of credible condition? As this Requirement relates to R2.7,
Would it be necessary to have Corrective Action Plan(s) if needed to meet all the Sensitivity
Cases? How many Sensitivities before must have Corrective Action Plan? Also – why is it
essential to use the qualifier ―annual‖ for ―current studies‖ in Part 2.1? Can a study be
considered current if it is conducted less frequently than once per year? Note that Parts 2.3,
2.4 and 2.5 do not use the ―annual‖ qualifier, nor does Requirement R2. Recommend
deleting this apparently non-essential qualifier in both R2.1 and R2.2. We are unable to
appreciate why the wording in Part 2.3 is not consistent with that in Part 2.1, 2.2, 2.4 or
2.5. Note that the semantics of the wording ―… (steady state / stability) analysis shall be
assessed annually…‖ can be interpreted to be much different than the semantics of the Part
2.3 wording ―The short circuit analysis…. shall be conducted annually …‖. The former
requires the analysis to be *assessed* annually but 2.3 requires the analysis to be
*conducted* annually without explicitly requiring it be assessed –- is the usage of
―conducted‖ instead of ‗assessed‖ consistent with the intent? In Part 2.6.2, the intent is
awkwardly conveyed within the phrase ―…the System represented in the study shall not
include any material changes unless…‖. In the context of a *past* study, how can the
System represented possibly include any material changes (that would have presumably
occurred after the study)? Suggest modifying Part 2.6.2 to read ―For steady state, short
circuit or Stability analysis: no material changes have occurred in the System represented
in the study or, if material changes have occurred, a technical rationale shall be provided to
explain why they do not significantly impact the study results.‖
Yes
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Yes
The drafting team could provide guidance on what is "material". In Part 2.5, should
―annually‖ be inserted after ―shall be assessed‖ to make it consistent with Parts 2.1, 2.2,
2.3 and 2.4? If the omission is intentional in 2.5, please explain why.
Yes
Following is a suggested re-ordering of header notes to replace of the three categories
concept – same information: a. Applicable Facility Ratings shall not be exceeded. The
System shall remain stable. Cascading and uncontrolled islanding shall not occur. b.
Planning event P0 is applicable to steady state only. c. Consequential Load Loss as well as
generation loss is acceptable as a consequence of any event except P0. d. The response of
voltage sensitive Load including Load that is disconnected from the System by end-user
equipment as a consequence of any event shall not be used to meet steady state
performance requirements. e. System steady state voltages and post-Contingency voltage
deviations shall be within acceptable limits established by the Planning Coordinator and
Transmission Planner. f. Transient voltage response shall be within acceptable limits as
established by the Planning Coordinator and Transmission Planner. g. Planned System
adjustments such as Transmission configuration changes and re-dispatch of generation are
allowed if such adjustments are executable within the time duration applicable to the
Facility Ratings. h. Simulate the removal of all elements that Protection Systems and other
controls are expected to automatically disconnect for each event. Simulate Normal Clearing
unless otherwise specified.
In footnotes 9 and 12, two critical issues are being addressed in large part via these
"clarifying" footnotes. These are curtailment of "Firm Transmission Service" (which seems
primarily to be a contract/scheduling issue) and the loss of "Non-Consequential Load."
Perhaps these issues should receive more attention in the actual requirements. In P5 the
term ―Protection System‖ was removed and replaced with ―relay‖. How are protection
system elements other than relays accounted for? In studying a multiple contingency event
with a communication system or control circuitry failure would it be necessary demonstrate
P1 performance levels? These details could become critical as industry deals with issues
such as FERC‘s interpretation of TPL-002-0 Requirement R1.3.10 (RM10-6-000). In Table 1
– Extreme Events – Stability – Items 2a-2d, change ―Protection System failure‖ to ―relay
failure‖ to be consistent with changes in P5. Table 1, P5 currently requires the study of
―[d]elayed Fault Clearing due to the failure of a relay13 protecting the Faulted element to
operate as designed‖. As written, this requirement does not recognize the use of redundant
relays for primary protection. In some cases side by side relays are used to provide primary
fault tripping if one relay fails to operate. Per the requirement as stated, the redundant
relay would provide no value in meeting this requirement. Please revise to acknowledge
backup relays: ―Single failure of a protection relay13 protecting the Faulted element to
operate as designed, resulting in backup relay actions or Delayed Fault Clearing, for one of
the following‖. Footnote 13 – Delete ―voltage (#27, #59)‖ since the under/over voltage
relays are not called upon to provide the primary protection for fault clearing on
Transmission elements. Suggest modifying Event P4 description to be more consistent with
Event P5 description by including Delayed Fault Clearing in the description in lieu of ―Loss of
multiple elements‖. Suggested Event P4 description is: ―Delayed Fault Clearing caused by a
stuck non Bus-tie Breaker attempting to clear a fault on one of the following:‖ In Table 1,
P2 and P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement
"No12" appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
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this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Yes
Yes
Individual
Darryl Curtis
Oncor Electric Delivery
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Group
IRC Standards Review Committee
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Ben Li
Yes
Yes
Yes
Yes
No
The primary concern involves wording under 2.1.4 and 2.4.3 that sensitivities are required
by varying one or more conditions. Subsequently, in requirement 2.7.2 corrective action
plans need to be developed to resolve performance deficiencies ―only‖ if identified in
multiple conditions or require a rationalization why no corrective action plan is necessary.
Multiple conditions sensitivities under 2.1.4 and 2.4.3 are necessary to satisfy requirement
2.7.2. Requirement 2.7.2 adds ambiguity and should be removed. Alternatively,
Requirement 2.7.2 could be revised as follows: 2.7.2. Corrective Action Plans are not
required for performance deficiencies identified in a sensitivity analysis. If a Planning
Coordinator includes Corrective Action Plans to resolve performance deficiencies identified
in multiple sensitivity analysis, the Planning Coordinator shall provide documentation to
support those Plans.
Yes
Yes
However, the requirement infers that a subjective judgment from a compliance auditor will
be required.
Yes
Yes
No
(AESO is not a party to the following comments since its VSLs are set by the Alberta
regulatory authority.) Requirement 8 is an administrative burden to TPs and PCs that adds
no value to reliability. PCs should be including TPs, neighboring PCs and interested parties
in its planning processes when developing the Planning Assessments. Therefore, the
inclusion of a set of VSLs for Requirement 8 is unnecessary. Should the SDT decide to leave
the VSLs for Requirement 8, Requirement 8.1 should be revised to reflect that comments
only to the final Assessment (not drafts developed during a process) need a response as
follows: 8.1 If a recipient of the planning assessment final results provides documented
comments on the results, the respective Planning Coordinator or Transmission Planner shall
provide a documented response to such recipient within 90 calendar days of receipt of
those comments. For a Planning Coordinator (PC) who distributes the Planning Assessment
to many different entities (to adjacent PCs, TPs, and other functional entities), a concern
regarding the Requirement R8 VSL is that it is overly restrictive to apply a violation for
failing to distribute the results of its Planning Assessment to only one PC, TP, or functional
entity (and to apply a High VSL for failing to distribute to more than one entity), particularly
since an entity‘s contact is subject to change over time, and since Measure M8 allows for
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publicly posting the results of its Planning Assessment to its website. Should the SDT decide
to include the VSLs for Requirement 8, we would recommend revising to use a percentage
approach rather than applying a violation to a Planning Coordinator who fails to provide the
results of its Planning Assessment to one PC, TP, or other functional entity (or applying a
High VSL for failing to distribute to more than one entity.) Recommend applying a similar
percentage approach to the VSLs drafted by NERC Staff for Project #2007-23 VSLs (e.g.,
for FAC-013-1) to be considered for the TPL-001-2 R8 VSLs. For example, • Lower VSL: The
responsible entity failed to provide the Planning Assessment final results to 5% or less of
the required entities. • Moderate VSL: The responsible entity failed to provide the Planning
Assessment final results to more than 5% up to (and including) 10% of the required
entities. • High VSL: The responsible entity failed to provide the Planning Assessment final
results to more than 10% up to (and including) 15% of the required entities. • Severe VSL:
The responsible entity failed to provide the Planning Assessment final results to more than
15% of the required entities OR [the existing language for the Severe VSL]. Explanation:
The VSLs were modified for consistency with other standards and VSLs. Reference: Link to
VSLs drafted by NERC Staff for Project #2007-23 VSLs (e.g., for FAC-013-1):
http://www.nerc.com/docs/standards/sar/Staff_Proposed_VSLs_2010July27.pdf
Individual
Jeffrey McKinney
New York State Electric & Gas Corp
Yes
No
The added clarification to the definition of Year One serves to remove most ambiguity with
respect to Year One. However, the revision has added further ambiguity to the terms ―year
two‖ and ―year five‖ which are not defined. For the Planning Assessment started in a given
calendar year, the first year that is studied must include the forecasted peak Load period
for one of the following two calendar years. An additional Near-term study must be
performed that is four calendar years beyond the first year that is studied. We recommend
defining Year Five as the twelve month period 4 to 6 calendar years from the date of the
Planning Assessment. We further recommend revising R2.1.1 as follows: ―System peak
Load for Year One and for Year Five.‖ Alternatively, the definition of Year One could be
eliminated and described within the text of the requirements.
No
For R1 Ambiguity regarding base case assumptions, in combination with lack of clarity and
clear direction of purpose regarding the sensitivity analysis, undermines the objectives of
the standard; R1.1 Part 1.1.2. With respect to known outages, there needs to be greater
flexibility in the standards (e.g. more tolerance to non-consequential load shedding or
limitations to the contingencies that need to be considered (e.g. P0, P1, & P2)). Regional
allowances for load shedding under this condition should be approved. Duration of known
outages should be increased from six months to one year; R1.1 Part 1.1.6 Delete "required
for Load". Resources may also be used for export to other areas, not just internal load.
No
We completely agree with the revision to R2.1, but this revision must be carried through to
other sections (R2.2, 2.2.1) and R2.2 language should be consistent with 2.1 for example use "current or qualified past studies" instead of "the following annual current study".
Revisions made to Requirement R2.1.5 have made it worse than as originally drafted. This
would require the PC & TP to study, or in other words perform technical analysis of, the
impact and probability of the possible unavailability of any piece of equipment with a lead
time of one year or more. Such an evaluation of spare equipment strategies would require
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significant additional resources and data, but provide no benefit to system reliability, as it is
redundant to the existing N-1-1 contingency requirement (P6).
No
These sensitivities need to be considered if not already included in the base case
assumptions.
No
We have not determined a need to model dynamic loads, and therefore have not
benchmarked any such models. We recommend that prior to this requirement being in
place, a modeling standard should exist that is specific to dynamic loads.
Yes
No
Header note (i) in the first Table 1 could imply that voltage-varying load shall not be used
to meet steady state performance requirements. NYISO steady state load models include
voltage-varying loads. This note should be revised to only reference loads which are
disconnected due to voltage.
In Table 1 – Stability, Make language similar to wording in P5. Protection System should be
removed and replaced with the words relay failure. This change should be made for 2a
through 2d: 2. Local or wide area events affecting the Transmission System such as: a. 3Ø
fault on generator with stuck breaker10 or a relay failure resulting in Delayed Fault
Clearing. b. 3Ø fault on Transmission circuit with stuck breaker10 or a relay failure resulting
in Delayed Fault Clearing. c. 3Ø fault on transformer with stuck breaker10 or a relay failure
resulting in Delayed Fault Clearing. d. 3Ø fault on bus section with stuck breaker10 or a
relay failure resulting in Delayed Fault Clearing. In Note 11 change wording as shown below
to include the words ―a total of‖: Excludes circuits that share a common structure (Planning
event P7, Extreme event steady state 2a) or common Right-of-Way (Extreme event, steady
state 2b) for a total of 1 mile or less
Yes
No
Requirement 8 is an administrative burden to TPs and PCs that adds no value to reliability.
PCs should be including TPs, neighboring PCs and interested parties in its planning
processes when developing the Planning Assessments. Therefore, the inclusion of a set of
VSLs for Requirement 8 is unnecessary. Furthermore, the requirement lacks a specified
time frame to receive comments, thereby implying that TPs and PCs would be required to
reply to comments forever following the finalization of a Planning Assessment. The NYISO
proposes a limit of six months. Should the SDT decide to leave the VSLs for Requirement 8,
Requirement 8.1 should be revised to reflect that comments only to the final Assessment
(not drafts developed during a process) need a response as follows: If a recipient of the
planning assessment final results provides documented comments on the results within 180
calendar days of the issuance of those final results, the respective Planning Coordinator or
Transmission Planner shall provide a documented response to such recipient within 90
calendar days of receipt of those comments. We also have other comments not addressed
by this Comment Form as follows – Section 2.7, Section 3.3, Section 4.3, and overall:
Section 2.7 requires that Corrective Action Plans are included in each Planning Assessment
and states ―Such actions may include…‖ followed by a list of actions. Restricting allowable
actions, and excluding runback/tripping of HVDC would have a direct impact on multiple
existing facilities in New York and would adversely impact the reliability planning of the
NYCA. Runback/tripping of HVDC must be added to the list. Section 3.3 - We feel that the
last sentence of 3.3.1 should be removed. This is handled by PRC-023. Line ratings are
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addressed by PRC-023. PRC-023 requires coordination with the Reliability Coordinator.
Remove ―Tripping of Transmission elements where relay loadability limits are exceeded.‖
Section 4.3 - High speed reclosing is not defined. Overall – We have previously made
comments which have not been addressed in the current version of the proposed standard.
Support for the standard can at most be limited without addressing comments. We have
previously commented on sensitivity analysis and guidance for base case assumptions.
Also, extreme event analysis should not be mandated in this standard as no corrective
action is required. The requirements for sensitivity analysis already address issues going
beyond what is expected to meet reliability requirements. Requiring extreme event analysis
is requiring two layers of event analysis beyond what is required, and there is no
requirement for corrective action if anything is identified. The standard is referring to
requirements for sensitivity and other issues without a reference to base assumptions. The
standard must describe base assumptions. To define a sensitivity condition, NERC must
define base assumptions.
Individual
Bart White
Progress Energy
Yes
Yes
Yes
No
While PE does not disagree with the basic premise of 2.1, PE disagrees with the language to
the extent that 2.1 is qualified by language in 2.6 and 2.6.2. The issue of managing
modeling of case data is already adequately handled in MOD Standards. Furthermore, PE
does not feel that the term ―material‖ can be defined with any mutually agreed-upon
boundaries, and could be construed to require any and all Transmission Planners and/or
Planning Authorities to make multiple revisions of base cases each year. PE therefore
appeals to the SDT to remove the language referring to R2 Part 2.6.2 and furthermore
appeals for the deletion of R2.6.2. Furthermore, PE appeals to the SDT to modify R2.6.1 to
say ―For steady state, short circuit, or Stability analysis: the study shall be five calendar
years old or less, unless a technical rationale can be provided to demonstrate the validity of
the results of any studies older than five years or any studies using cases containing major
modeling differences from other submitted studies.‖
No
PE does not have concerns in general with either 2.1.4 or 2.4.3. PE does, however, disagree
with the wording at the end of the main paragraph of 2.4.3. Whether or not analysis
qualifies as sensitivity analysis should not be predicated upon the end results; rather, it
should be based upon major case modeling differences. PE therefore recommends that the
phrase ―…that demonstrate a measurable change in performance‖ be removed so that the
last sentence in the main paragraph read ―…by a sufficient amount to stress the System
within a range of credible conditions.‖
Yes
No
PE agrees in general with the changes made to R2.5. PE disagrees, however, with the
language stipulating that current and past studies be qualified by the language in R2.6 Part
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2.6.2 (see notes for Question 3.1 regarding recommending changes with regard to R2.6.2).
Yes
PE assumes the term ―header notes‖ is referring to the ―Planning Performance Events‖ at
the top of Table 1. If this is the case, PE has no concerns with the present language.
PE remains concerned with the present draft of TPL-001-2 regarding the presence or
absence of footnotes in particular events. PE believes that, for all events in Table 1 except
P0, any ―No‖ designation in the ―Non-Consequential Load Loss allowed‖ column should have
Footnote 12 appended to it. Several events do append footnote 12 to a ―No‖ answer, but
several do not. PE does not see why certain events should be denied the use of Footnote 12
as long as Footnote 12 is worded in a manner such that the BES will not be adversely
affected. PE has additional concerns regarding two Footnotes. Footnote 9 contains language
regarding firm transmission service that is very similar to language presently under review
in NERC Project 2010-11. PE feels that Footnote 9 should have had a statement at the end
similar to that of Footnote 12, such as ―Note: Firm Transmission Service is being decided in
Project 2010-11. When that project is finalized, the resolution will be copied into Footnote
9.‖ Without such a statement, PE cannot understand why the Firm Transmission language
in footnote (b) under Project 2010-11 is being reviewed, while it is apparently no longer
being reviewed in Project 2006-02. Footnote 12 contains the following language as a place
holder: ―Note: Non-Consequential Load Loss is being decided in Project 2010-11. When that
project is finalized, the resolution will be copied here.‖ PE has filed substantial comments on
the footnote (b) issue in previous drafts, pointing out that disallowance of curtailment of
non-consequential load is a local load issue and not a BES concern. PE therefore cannot
make any positive determination as to whether the draft Standard, TPL-001-2, and its
associated Table 1, will be a viable Standard until the language in Footnote 12 is resolved
via Project 2010-11. Given the potential for unresolved and confusing issues regarding the
parallel development of Project 2006-02 and 2010-11, PE encourages NERC to resolve all
issues within Project 2010-11 before taking the draft Standard TPL-001-2 to ballot in
Project 2006-02.
Yes
Yes
Group
Bonneville Power Administration
Denise Koehn
Yes
Yes
No
Please clarify R1.1.2 to state ―Known outage(s) of generation or Transmission Facility(ies)
during the Planning Horizon with a duration of of at least six months.‖
Yes
Yes
Yes
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Yes
It should be noted that if there is more generation proposed in an area than there load and
export capability, all proposed material generation additions would not be represented.
Determining what future generation additions to include in the Long-Term Transmission
Planning Horizon may be based on a non-technical rationale rather than a technical
rationale.
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore the proposed
footnote 12 should include a provision to default to the existing footnote ―b‖ in TPL-002-0
until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖
Individual
L Zotter, M Morais, J Billo, J Conto, S Jue, JC Culberson, J Teixeira, G Gnanam, S Myers
ERCOT ISO
Yes
Yes
Yes
No
Previous Comment unaddressed: Requirement 2.1.5: Including the spare equipment
strategy will be difficult for a PC that doesn‘t own or manage the transmission equipment or
the strategies. This requirement should only be applicable to TP. Furthermore, R7 should be
deleted and the responsibilities of each entity should be explicitly stated within the specific
requirements.
No
The stress test requirements should be deleted. The purpose of this proposed Standard is
to establish planning performance standards that support reliable operation. This is
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achieved by imposing performance requirements relative to specific conditions and
contingencies. Compliance with the performance metrics within these boundaries is
presumably indicative of a reliable system. It is unclear what value is added by stress
testing the system in accordance with undefined, vague parameters, as required by
Requirements 2.1.4 and 2.4.3. The criteria in the relevant requirements that govern the
stress testing are defined by the following ambiguous phrase: 1) ―by a sufficient amount‖;
2) ―range of credible conditions‖; and 3) ―measurable change of performance‖. Application
of these criteria introduces uncertainty for both the regulated community and the relevant
compliance enforcement authorities, which, in turn, creates audit risks for regulated
entities. Furthermore, there is no reliability value because the stress test requirements do
not establish objective criteria and do not prescribe any actions based on the stress test
results. Reliability Standards should set specific obligations that are readily discernible and
achievable on a consistent basis. The existing Standard does this by setting specific
performance obligations relative to specific conditions and contingencies. Conversely, the
stress test requirements introduce ambiguity and uncertainty with no reliability benefit; the
only apparent effect is unnecessary audit liability risk for regulated entities. Accordingly,
ERCOT believes that these requirements should be deleted.
No
ERCOT ISO suggests adding ―best available‖ as a descriptor to load models. Distribution
Providers (DPs)/Load Serving Entities (LSEs) are the appropriate NERC functional entities to
provide dynamic load data. Accordingly, Planning Coordinators (PCs) and Transmission
Planners (TPs) must rely on those entities for that data. Despite reliance on DPs/LSEs for
this data, the Standard proposes to impose an obligation on PCs and TPs to include a load
model representative of ―expected‖ dynamic behavior. Simply put, PCs and TPs do not have
this information and should not be subject to compliance liability risk for an issue that is
beyond their control. This change will still accomplish the goal of reflecting dynamic data in
the relevant models, while mitigating PC/TP compliance risk by basing their compliance on
information that is within their control – i.e. the ―best available‖ information. Based on this
change, the language should read - ―System peak Load levels shall include best available
Load models which represent the expected dynamic behavior of Loads that could impact the
study area, considering the behavior of induction motor Loads‖. This language is also a
more accurate reflection of the Consideration of Comments by the Standard Drafting Team
after the March 2010 comment period. To address this issue in the most appropriate
manner, the Standard should be revised to establish an appropriate process for collection,
reporting and use of dynamic data based on assigning obligations to the appropriate
functional entities. In essence, DPs/LSEs should be required to collect the data and report it
to TPs. Because TP models are the basis for PC models, the dynamic data will be included in
PC models as part of the process. However, DPs and TPs should still only be required to use
the ―best available‖ data. Continued use of this language will mitigate the liability risk
associated with a requirement related to data that is within the control of a third party.
Even under a construct where DPs/LSEs are required to collect and report dynamic data,
there is no guarantee they will do so and PCs/TPs should not be held accountable in those
circumstances. Accordingly, PC/TP compliance risk will be mitigated by use of a ―best
available‖ standard.
Yes
Yes
Yes
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Yes
ADDITIONAL COMMENTS: Short circuit analysis (R2.3 and R2.8) should only be applicable
to TPs. Fault duty issues are typically local in nature and it would be an overlap for PCs to
perform this same analysis done by the local Transmission Planner. Furthermore, R7 should
be deleted and the responsibilities of each entity should be explicitly stated within the
specific requirements. Previous Comment Unaddressed : Requirement 2.6.2: Reads as if a
change is being made to an existing study. It is confusing. Possibly restate: "2.6.2 For
steady state, short circuit, or stability analysis: previous studies can be used only if a
material change to the system has not occurred or if a change that did occur does not
impact the study area." R4.1.2 – Planning Coordinators do not perform protection
coordination nor do they have access to the relay settings information required to do this
analysis. This requirement should apply to Transmission Planners only because they
perform system protection. The substantive scope of the standard is relative to Long-Term
Transmission Planning Horizon and Near-Term Transmission Planning Horizon. The Purpose
section is described in terms of the ―planning horizon‖ generally. It may be worthwhile
aligning the two to mitigate the potential for any confusion. ERCOT proposes the following
revisions to the Purpose section: 3.Purpose: Establish Transmission system planning
performance requirements within the relevant planning horizon (i.e. Long-Term or NearTerm) to develop a Bulk Electric System (BES) that will operate reliably over a broad
spectrum of System conditions and following a wide range of probable Contingencies. In
addition, the ―Time Horizon‖ for the Standard is ―Long-Term Planning‖. Obviously, this
necessarily encompasses both Long-Term and Near-Term Transmission Planning Horizons.
However, the scope of the Long-Term Planning time horizon is not readily apparent. ERCOT
recommends appropriate revisions that clearly define the applicable time horizons.
Individual
Gary Trent
Tucson Electric Power Company
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We have included additional comments here since we were not able to find a place to
include comments on the following: Requirement R4; Requirement, Parts 2.1.5, 2.3, and
2.8; Requirement 3, Part 3.3.2; and Requirement 4, Parts 4.3.1and Part 4.3.2 Requirement
2, Part 2.1.5: The spare equipment strategy does not improve reliability performance. If an
outage of a long lead time piece of equipment occurs, the system should still be able to
operate in a reliable manner that meets the performance measures of Categories P3 and
P6. If an entity cannot meet its performance requirements under this standard, a capital
project is indicated. Spare equipment being available would not mitigate this need it only
increases expenses until the item is needed. Requirement 2, Parts 2.3 and 2.8: Short circuit
fault duty is a localized phenomena that is mainly impacted by the addition of new
generation or transmission facilities. Due to proprietary concerns of generation and
transmission interconnection requests, short circuit studies are performed in forums outside
the annual Planning Assessment. Normally, these studies will be conducted before the
projects can be included in regional base cases. As such, short circuit analysis should not be
included in this Standard since it would provided limited benefit. Requirement 3, Part 3.3.2
and Requirement 4, Part 4.3.2 Steady state response of dynamic control devices should
also be included in the Part 3.3.2. and the list of possible devices included should be
removed from Part 3.3.2 and 4.3.2. Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
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relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
No
A seasonal reference should be included in the example. Alternative language beginning
with the second sentence: For the Planning Assessment started in a given calendar year,
Year One must include the forecasted peak load period for the forecasted peak load season
that is between 12 and 24 months into the future from the current season. For example, if
a Planning Assessment was started in 2011 prior to the forecasted peak season, then Year
One must include the forecasted peak load for 2012. If the Planning Assessment was
started in 2011 during or after the forecasted peak season, then Year One must include the
forecasted peak load for 2013.
No
Proposed changes 1.1.1 Existing Facilities that will not be changed before the study year
1.1.3 New planned Facilities and planned changes to existing facilities
Yes
No
TEP agrees with removing the phrase "not already included in the studies." However, TEP
does not understand the purpose of sensitivity studies. TEP is concerned that imposing
additional sensitivity studies could lead to requirements that exceed the proposed
standards. TEP recommends removing sesnitivity analysis from the standard.
Yes
No
If a material change (generator addition/retirement, new generator models based on unit
testing, or transmission line or non-distribution transformer addition) is not planned for the
longer-term planning horizon, do the longer-term stability studies need to be performed?
TEP's agreement/disagreement with Part 2.4.1 is dependent on the response to this
question. If the answer is the studies do not need to be performed, then TEP supports these
changes.
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
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clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue). NonConsequential Load Loss and curtailment of Firm Transmission Service should be allowed
for loss of EHV BES elements for Category P4 and P5 events.
Yes
Yes
Individual
Gregory Campoli
New York Independent System Operator
Yes
No
The added clarification to the definition of Year One serves to remove most ambiguity with
respect to Year One. However, the revision has added further ambiguity to the terms ―year
two‖ and ―year five‖ which are not defined. NYISO recommends defining Year Five as the
twelve month period 4 to 6 calendar years from the date of the Planning Assessment.
NYISO further recommends revising R2.1.1 as follows: ―System peak Load for Year One and
for Year Five.‖ Alternatively, the definition of Year One could be eliminated and described
within the text of the requirements.
Yes
No
NYISO completely agrees with the revision to R2.1, but this revision must be carried
through to other sections (R2.2, 2.2.1). Revisions made to Requirement R2.1.5 have made
it worse than as originally drafted. This would require the PC & TP to study, or in other
words perform technical analysis of, the impact and probability of the possible unavailability
of any piece of equipment with a lead time of one year or more. Such an evaluation of
spare equipment strategies would require significant additional resources and data, but
provide no benefit to system reliability, as it is redundant to the existing N-1-1 contingency
requirement (P6). R2.7 requires that Corrective Action Plans are included in each Planning
Assessment and states ―Such actions may include…‖ followed by a list of actions. Restricting
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allowable actions, and excluding runback/tripping of HVDC would have a direct impact on
multiple existing facilities in New York and would adversely impact the reliability planning of
the NYCA. Runback/tripping of HVDC must be added to the list.
No
Our concern involves wording under 2.1.4 and 2.4.3 that sensitivities are required varying
one or more conditions. Subsequently, in requirement 2.7.2 corrective action plans need to
be developed to resolve performance deficiencies ―only‖ if identified in multiple conditions
or require a rationalization why no corrective action plan is necessary. Multiple conditions
sensitivities under 2.1.4 and 2.4.3 are necessary to satisfy requirement 2.7.2. Requirement
2.7.2 adds ambiguity and should be removed. Requirement 2.7.2 should be revised as
follows: 2.7.2. Corrective Action Plans are not required for performance deficiencies
identified in a sensitivity analysis.
No
The NYISO, along with many other systems, has not determined a need to model dynamic
loads, and therefore has not benchmarked any such models. The NYISO recommends that
prior to this requirement being in place, a modeling standard should exist that is specific to
dynamic loads.
Yes
No
Header note (i) in the first Table 1 could imply that voltage-varying load shall not be used
to meet steady state performance requirements. NYISO steady state load models include
voltage-varying loads. This note should be revised to only reference loads which are
disconnected due to voltage.
There are two tables labeled ―Table 1‖. The extreme events table should be renamed ―Table
2‖.
Yes
No
Requirement 8 is an administrative burden to TPs and PCs that adds no value to reliability.
PCs should be including TPs, neighboring PCs and interested parties in its planning
processes when developing the Planning Assessments. Therefore, the inclusion of a set of
VSLs for Requirement 8 is unnecessary. Furthermore, the requirement lacks a specified
time frame to receive comments, thereby implying that TPs and PCs would be required to
reply to comments forever following the finalization of a Planning Assessment. The NYISO
proposes a limit of six months. Should the SDT decide to leave the VSLs for Requirement 8,
Requirement 8.1 should be revised to reflect that comments only to the final Assessment
(not drafts developed during a process) need a response as follows: If a recipient of the
planning assessment final results provides documented comments on the results within 180
calendar days of the issuance of those final results, the respective Planning Coordinator or
Transmission Planner shall provide a documented response to such recipient within 90
calendar days of receipt of those comments.
Group
PacifiCorp
Sandra Shaffer
Yes
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Under Category P2 (Single Contingency) and Normal System Conditions, the performance
table indicates that, for both HV and EHV, interruption of firm transmission service and
non-consequential load loss are not allowed following the opening of a line section without a
fault. This section of the performance table should distinguish between EHV and HV –
performance requirements following the opening of a line section without a fault should be
the same as those for a bus section fault. As with the bus section fault, interruption of firm
transmission service and non-consequential load loss should be allowed for HV.
Yes
No
The language for Requirement R8 is ambiguous with regard to which adjacent entities must
request in writing the results of the Planning Assessment. The language should be clarified
to read: ―Upon request made in writing, each Planning Coordinator and Transmission
Planner shall distribute its Planning Assessment results to adjacent Planning Coordinators,
adjacent Transmission Planners, and any other functional entity that has a reliability related
need.‖ The Requirement R8 VSL language should also be revised accordingly.
Individual
Claudiu Cadar
GDS Associates, Inc.
No
We disagree with the Implementation Plan and we suggest changes as follows: - The title
should read ―Implementation Plan for TPL-001-2‖ - With regards to the Prerequisite
Approvals, NERC project #2010-11 still in progress (Table 1, Footnote ‗b‘) must be
implemented before this current TPL-001-2 standard gets implemented. However, while the
2010-11 NERC project does not define any of the new terms such as consequential / nonconsequential load, the footnote ‗b‘ cannot be just copied into the new standard (see TPL001-2 standard Table 1, note 12). Note ‗b‘ may further change to reflect the verbiage in the
TPL-001-2 standard. - Not sure what is the intent of the last paragraph. While the proposed
changes to Table 1, footnote ‗b‘ are quite precise, are we still open a door to those entities
that will continue to trip Non-Consequential Load and curtail Firm Transmission Service? If
no penalties for such practices while the proposed standard allows a sufficient time frame to
correct any deficiencies, then what is the point to all the effort behind the development of a
new TPL standard?
No
The definition it seem both incomplete and exhaustive: - If taken out of the planning
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assessment context, the definition is missing the matter that is supposed to identify. We
suggest changing the first sentence such as ―The first twelve month period to which the
functional entity is responsible for the assessment of Transmission System Planning
performance.‖ - While it will be a burdensome task to define each year that follows Year
One, the definition of Year One may include a sentence that define the rule for the following
years such as ―All of the twelve months period following Year One shall commence
immediately after the end of the preceding twelve months period.‖ - The definition should
not include examples.
No
The Time Horizon should be for both Near-Term and Long-Term Planning.
Yes
No
The requirements are extremely burdensome. We recommend changing the last sentence
of 2.1.4 requirement by removing ―by a sufficient amount to stress the System within a
range of credible conditions that demonstrate a measurable change in performance:‖
because there are instances where listed conditions may not result in measurable changes
in performance (Ex. An increase in load in a well built system may not cause any
measurable changes in performance because there is sufficient transmission capacity to
serve the load).
No
We disagree with the content of this requirement based on several facts: - We believe that
the dynamic behavior of the load cannot be accurately estimated beyond current time. We
are concern about the effort required to ascertain the dynamic response of the load - The
requirement references ―Loads that could impact the study area‖ without specifying how an
entity will identify these loads. Perhaps the standard should provide guidelines to determine
which loads would impact the study area.
No
We are not sure what will be included in these ―material generation additions or changes‖.
Perhaps the standard should provide guidelines to determine what are these material
changes or additions?
Yes
Individual
Terry Harbour
MidAmerican Energy
Yes
Yes
No
There are concerns over the FERC outstanding March order on TPL and how FERC interprets
―normal‖ or base case conditions and ―assuming‖ an entities primary protection system is
out of service and must rely on its backup protection system to operate. This concept
combined with the new tables cannot be perpetuated.
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Yes
Yes
R2.1.4 bullet #7 – Replace the adjective ―planned‖ with ―known‖ for consistency with
R1.1.2 and R2.1.3. R2.3 Replace ―conducted‖ with ―assess‖ for consistency with R1.1.2 and
R2.1.3. R2.4 Replace ―current or past studies as qualified‖ with ―current or qualified past
studies as indicated‖ for consistency with R2
No
MidAmerican questions if the widespread use of composite load models really provides
significant benefits to additional dynamic analyses over generic load conversion
assumptions which have been historically used. The use of composite load models may
result in more precise individual load models, but no more accurate dynamic simulations.
This poorly worded requirement should be deleted in its entirety as providing additional
burden without any additional reliability benefits. If the composite load model requirement
must be kept, it should be modified to include the following bolded text: ―…System peak
Load levels shall include a Load model which represents the expected dynamic behavior of
Loads that could impact the study area, considering the behavior of induction motor Loads,
but without requiring a detailed load survey be conducted…‖
Yes
No
The reference to BES should be placed back into Note a in the header above table 1.
Voting "no" - Footnote 6 – Further clarify the applicable shunt devices in Footnote 6 with
this suggested text: 6. Requirements which are applicable to shunt devices, also apply to
FACTS devices that are connected to ground, but not instrument voltage transformers or
surge arresters
No
Revise measures to be consistent with requirements. 1. R6 Delete ―any‖. The use of the
word any in standards should not be allowed. 2. Revise the Planning Assessment definition
to more explicitly apply to the BES and the TPL-001 requirements. We suggest text of:
―Planning Assessment: Documented evaluation of future Transmission System performance
and Corrective Action Plans to remedy identified deficiencies in the BES from the steady
state and stability performance requirements set forth in the TPL-001 standard.‖ 3. R2.1.5
– We propose replacing the term ‗major Transmission‘ with ―BES‖ because BES is a well
defined term, while the term, ‗major Transmission‗, is not. 4. Add R2.3.1 – We suggest the
addition of a R2.3.1 requirement to emulate the distinction between the requirement to
perform a short circuit assessment and conduct required studies or analysis to support the
assessment (e.g. R2.1/R2.1.1 and R2.2/R2.2.1). We propose wording such as, ―Perform an
analysis for at least one year in the Near Term Transmission Planning Horizon.‖ This
requirement would set an expectation that an analysis should be conducted to at least one
or more years in the near-term planning horizon, rather than imply that an analysis of all
five years in the near-term planning horizon must be conducted. 5. R2.7.2 – Delete 2.7.2.
With regard to "include actions to resolve performance deficiencies identified in multiple
sensitivity studies", mitigation plans should not be required for deficiencies found in
multiple sensitivity studies because the conditions in some sensitivity studies are more
extreme and less likely than base case conditions. Some of the sensitivity study conditions
are not credible. 6. R2.7.4 – We suggest that the wording of R2.7.4 be the same as
R.2.8.2. 7. R3.5 - We interpret that R3.5 requires the TP and PC to conduct an evaluation of
possible actions to reduce the likelihood or impact of extreme events, which produce the
more severe impacts, if cascading outages may occur. Does the drafting team intend for
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the TP and PC to fulfill this requirement for at least one event in each of the five categories
(i.e. 3 steady state and 2 stability) or in each of the 21 categories/sub-categories (i.e. 14
steady state and 7 stability). Also, if the resulting cascading outages do not result in any
overloads, under-voltages, voltage collapse, or loss of generator synchronization, then
should the evaluation of possible actions to reduce likelihood or impact be required? 8.
R4.1.1 – We suggest that there should be some qualification of which generating units are
referred to in this requirement. We propose that the requirement say, ―No generating unit
with a Point of Interconnection connected to the BES shall pull out of synchronism.‖ For
example, some utilities include smaller generation units that are connected at voltages
below 100 kV and even down to distribution voltage in their base cases. 9. R4.1.2 – We
propose that the wording of this requirement be revised to reflect the same BES
qualification of the generating unit that we noted in R4.1.1 above. 10. R4.3.1 – This
requirement refers to high speed reclosing and we presume that this is special high speed
reclosing that is completed in several cycles, rather than the normal high speed reclosing
that is completed in a number of seconds. We recommend that the term high speed
reclosing be more clearly defined for this sub-requirement. 11. R.4.3.2 – We suggest
qualifying which generating units to consider and which voltage limits to simulate with
revised wording like, ―Trip generating units that are connected to the BES when actual or
assumed minimum generator transient voltage limits are known and simulations show
voltages may fall below the voltage limit. If assumed voltage limits are used, then they
should be included in the assessment―. The requirement should not apply to all relevant
generating units until one of the MOD standards requires all Generator Owners to provide
their minimum generating unit voltage limits to the TP and PC. If the wording of R4.3.2
must be different from its counterpart, R3.3.2, then please explain the reasons for any
differences. 12. R5 – This requirement should allow the applicable entity (such as the TOP /
TO) to define a ―Post-Contingency Voltage Deviation‖ as this criteria is not used widely
enough in the industry to be a well established criteria. 13. Revise R8 to limit the need to
provide the Planning Assessment as follows ―adjacent Planning Coordinators and adjacent
Transmission Planners and to any registered functional entity…‖ 14. Data Retention for R3,
R5, R6, & R7 - The MRO NSRS proposes that the wording in these elements be revised to
change ―All‖ to ―The‖. The word ―All‖ is unnecessary and could encourage over-the-top
compliance monitoring and enforcement. The revised data retention would read as follows:
―The studies performed in support….‖
Yes
Individual
Catherine Koch
Puget Sound Energy
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
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dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
Joe Tarantino
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Sacramento Municipal Utility District
Yes
We commend the SDT for its work to continue the improvement on the proposed TPL-0011. We were not able to find a place to include comment on Requirement R4; therefore, we
have included our comments here: Section R4.3.1, bullet point 3 requires the stability
analyses to include the impact of subsequent ―[t]ripping of Transmission lines and
transformers where transient swings cause Protection System operation based on generic
or actual relay models‖. As written, this bullet could be interpreted as requiring the
inclusion of these relay models in stability data bases. We do not have generic or actual
relay models in our dynamics data bases for tripping line faults on lines and transformers
represented. We represent actual relay response and tripping times of relays,
communications, and breakers to faults in tripping transmission lines and transformers.
Requiring the inclusion of generic or actual relay models for all relays that can trip lines and
transformers would add a large burden to the development and maintenance of accurate
dynamics model files that would add little or no benefit. Please change this bullet to read:
―Tripping of Transmission lines and transformers where transient swings cause Protection
System operation based on known Protection System response‖.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Table 1, P5 currently requires the study of ―[d]elayed Fault Clearing due to the failure of a
relay13 protecting the Faulted element to operate as designed‖. As written, this
requirement does not recognize the use of redundant relays for primary protection. In some
cases side by side relays are used to provide primary fault tripping if one relay fails to
operate. Per the requirement as stated, the redundant relay would provide no value in
meeting this requirement. Please revise to acknowledge backup relays: ―Single failure of a
protection relay13 protecting the Faulted element to operate as designed, resulting in
backup relay actions or Delayed Fault Clearing, for one of the following‖. In Table 1, P2 and
P3, the last column ―Non-Consequential Load Loss Allowed‖ where the requirement "No12"
appears, and in footnote 12, the standard as proposed does not allow for any NonConsequential Load Loss. When the Non-Consequential Load Loss (footnote b) issue is
clarified in Project 2010-11 this requirement may be changed. Therefore, if this proposed
Standard is enforced before Project 2010-11 is completed, entities will be required to meet
this No Non-Consequential Load Loss requirement without the exception allowed in the
existing TPL-002-0, footnote ―b‖. This will require immediate redesigns to meet this
particular requirement. The unintended consequence could be that operators of local
systems that are currently networked may opt to begin operation as radial systems, and
future designs for local systems may be radial, at any voltage level. We suggest that the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
proposed footnote 12 include a provision to default to the existing footnote ―b‖ in TPL-0020 until Project 2010-11 is decided. Please revise footnote 12 to read, ―Note: NonConsequential Load Loss is being decided in Project 2010-11. When that project is finalized,
the resolution will be copied here. In the interim, planned or controlled interruption of
electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for
the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.‖ Timing of this project
and project 2010-11 is critical. It would be very difficult to vote to approve the proposed
TPL-001-2 prior to knowing the outcome of Project 2010-11 (footnote b issue).
Individual
Patrick Farrell
Southern California Edison Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
SCE supports the revised performance table.
Yes
Yes
Individual
John Mayhan
Omaha Public Power District
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Why is Footnote 12 used for some occurrences of the word "No" in the last column of Table
1 but not other occurrences of the word "No"?
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Reliability Coordination (Project 2006-06)
The Reliability Coordination Standard Drafting Team thanks all commenters who submitted
comments on the proposed revisions to the standards for Project 2006-06 — Reliability
Coordination. These standards were posted for a 45-day public comment period from
January 4, 2010 through February 18, 2010. The stakeholders were asked to provide
feedback on the standards through a special Electronic Comment Form. There were 42 sets
of comments, including comments from more than 150 different people from over 50
companies representing all of the 10 Industry Segments as shown in the table on the
following pages.
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
Summary Consideration:
Stakeholders had three general concerns with the definition of Interpersonal
Communications.
1) The definition of Interpersonal Communication to be ambiguous in terms of
distinguishing between verbal communications and data transfers; The SDT
believes that Webster’s definition of Interpersonal: (being, relating to, or
involving relations between persons) clarifies the exclusion of media
dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3
which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange
Authority, Load-serving Entity, Reliability Coordinator, Transmission Operator, and
Transmission Owner shall provide data and information, as specified, to the
Reliability Coordinator(s) with which it has a reliability relationship. (Violation Risk
Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Realtime Operations)
2) The definition should also clarify that the communication is between
individuals in different entities or physical locations; The SDT believes that
the revised Requirements of COM-001-2 satisfy this concern.
3) Use of the term “method” may imply a communication style; The RCSDT
changed “method” to “medium” in definition.
Several stakeholders indicated that a definition of Alternative Interpersonal
Communications was not needed. The RCSDT disagrees because there is an
important part of the definition of “Alternative Interpersonal Communications”
that distinguishes it from simply being an alternative “Interpersonal
Communications”. The proposed definition contains the words: “which does
not utilize the same infrastructure (medium)”. Also, some stakeholders had
concerns with the usage of “normal”. The RCSDT does not propose defining
“Normal” Interpersonal Communications and has removed it from the
definition. Based on the consensus of stakeholders, we have revised the two
definitions to:
Interpersonal Communication: Any medium that allows two or more
individuals to interact, consult, or exchange information.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Alternative Interpersonal Communication: Any Interpersonal
Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Interpersonal Communication
used for day-to-day operation.
Stakeholders pointed out that COM-001, R1 was a compound requirement and
suggested creating separate requirements. Stakeholders also suggested revising
the VRF to “Medium” as it does not meet the guidelines for a “High” VRF. The
intent of R1 was three-fold.
1
Identify (have) an Alternative Interpersonal Communication capability
2
Test that capability periodically and
3
If the test failed, fix it or identify another Alternative Communications
Capability.
Based on comments received, we have revised R1 (now R9) to eliminate the
compound requirement and therefore created more specific requirements to
delineate Interpersonal and Alternative Interpersonal Communication, and
applicable entity responsibility. The VRF is changed to “Medium.”
The RCSDT also made extensive revisions to COM-001 to provide explicit
Interpersonal Communications and Alternative Interpersonal Communications
capabilities based on the relationships between various entities. The RCSDT
believes that the proposed requirements meet the reliability objectives of the
standard as well as the FERC Order 693 directives.
The comments received regarding the definition of Reliability Directive (for COM002 and IRO-001) ranged from the being “too open-ended” (PPL) to not “flexible”
enough (Public Service Enterprise Group Companies). The SDT expected and
viewed these as attempting to reach middle ground.
There were also value added comments such as removing the unnecessary and
redundant terms “actual or expected” from the definition, which the SDT agrees
with. The definition was revised to:
A communication initiated by a Reliability Coordinator, Transmission
Operator or Balancing Authority where action by the recipient is necessary
to address an Emergency.
A number of commenter’s expressed a concern about the definition not including
three-part communication, clearly identifying a Reliability Directive at the time of
issue, and applying to verbal communications. The SDT believes responsibilities
should not be imbedded in a definition and, as drafted, the requirements of COM002 with the proposed definition of Reliability Directive fully address the
identification and verbal concerns.
The bulk of the comments received on COM-002 regarded the VSL for R3. The SDT
agreed with suggestions for the VSLs and has deleted the Severe VSL and moved
the High VSL to Severe. We believe that there are two possible actions within the
requirement and failure to perform either warrants a Severe VSL.
Several commenter’s expressed concern about three-part communication. The SDT
believes that the requirements as drafted, with the issue, repeat back, and
acknowledgement of a Reliability Directive, three-part communication is covered.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
There was one commenter suggesting the addition of the DP to the applicability
The RCSDT notes that, per the Functional Model, a DP may “direct” an LSE to
communicate requests for voluntary load curtailment and not reliability
situations: Item 9 on page 47 of version 5 of the Functional Model: “Directs
Load-Serving Entities to communicate requests for voluntary load curtailment.”
Furthermore, The RCSDT will forward this comment to the FMWG for their
consideration in revising the language.
The comments regarding the use of Reliability Directive in IRO-001 ranged from
small entities being excluded to whether regulatory or statutory requirements
covers NERC standards. The SDT addressed these by noting registration is not in
the SDT scope and NERC’s general council should be contacted for regulatory
issues.
A few commenter’s expressed concern with the VSL for R2 and one suggested the
words "per Requirement 2," should be added. The SDT believes the phrase “per
Requirement 2” is not necessary as a VSL is only applied AFTER a compliance
violation is determined.
Value added comments such as a concern of the use of the word “threat” as it
can be defined as cyber-related and suggested replacing “Operating Personnel”
with “System Operator” were also made. The SDT concurred and removed the
word “threat” and replaced it with “condition” and also made the revision to
System Operator.
There were numerous comments regarding the definition of Reliability Directive
with multiple wording suggestions. While slightly out of scope for question six,
the SDT expected and viewed these as attempting to reach middle ground.
Some commenter’s expressed concern over clarify that the RC has three separate
actions. The RC can act, direct others to act, or issue Reliability Directives. The
SDT modified R1 to read: ”Each Reliability Coordinator shall take actions or direct
actions, which could include issuing Reliability Directives, of Transmission
Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, Distribution Providers and Purchasing-Selling
Entities within its Reliability Coordinator Area to prevent identified events or
mitigate the magnitude or duration of actual events that result in Adverse
Reliability Impacts”
Note: Based on discussions with FERC Staff, the SDT agreed to make the
following changes:
IRO-001-2 Requirements R4, R5 and associated Measures and VSLs are
moved to IRO-005-4
IRO-001-2 Requirements R6, R7 and associated Measures and VSLs are
moved to IRO-002-2
Several commenters made suggestions regarding IRO-014, R2. The original
requirement was designed to accomplish in one requirement what is proposed by
the commenters as three procedural requirements. R2 is worded to focus on
defining what a “compliant plan” is. In the current requirement a “proposed plan”
is not the same as a “compliant plan”.
The SDT viewed what the commenters are suggesting as follows:
• The initiating RC would submit its “proposed plan” to the other RCs
• The receiving RCs would provide the initiating RC with their responses
indicating whether or not they agree with the proposed roles/actions
offered by the initiating RC
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
•
•
If one or more RCs do not agree with the roles/actions, then the initiating
RC would be required to offer an alternative proposal (and go back to the
first bullet)
When all RCs acknowledge that the proposed roles/actions in the revised
“proposed plan” are acceptable, then and only then would the “proposed
plan” become a “compliant plan”
A closer reading of the current R2 would show the current R2 accomplishes the
exact same result but does so without interjecting the need for documenting the
intervening processes. The SDT does not see the need to document why each
proposal was or was not accepted; nor does the SDT see the need for document
the negotiations that are involved in getting to “an agreed to plan”. For example
the comments’ subrequirement to show the RC submitted its plan would require a
paper trail for the request; followed by a paper trail for the responses, followed by
more paperwork if the RCs are not in agreement. In the end, the only action that
matters (in both the SDT version and in the commenters alternative version) is a
plan that works, and a plan that if others are involved must have their concurrence
that those others will participate.
R2 does not impose a requirement to get agreements; what R2 does is to require
that a “compliant plan” be developed. A proposed plan does not solve problems.
That proposed plan is NOT compliant with R2 if it only assumes that other RC will
effect the actions in the proposal; neither is it compliant if the proposed actions
are not acceptable to the other RCs who are required to act. To be compliant the
initiating RC must either have the concurrence (i.e. agreement) of the other RCs
for their respective part(s) in the proposed plans OR the plan must not include
those RCs.
R2 says to be compliant the other RC must agree with the “proposed plan” before
that “proposed plan” is acceptable as a “compliant plan”. Having a plan that
requires someone else to do an action, but that other entity will not effect that
action, will not resolve the problem at hand. Further having documentation that
someone refuses to participate in the proposed plan does nothing to solve the
problem at hand.
In general, the RC SDT feels that the concept of a Reliability Directive is an
important tool for RC, BA and TOP to maintain reliability and that the revisions are
consistent with the applicable parts of the directives in FERC Order 693. The work
of the RC SDT along with the OPCP SDT and the RTO SDT, as currently recognized,
will cover the original intent of COM-002 and still provide a “defense in depth
strategy” as suggested by commenters. Consensus appears to have been
achieved with respect to the definition of Reliability Directive and the
requirements that the RC SDT have developed for COM-002. This will further the
efforts of the OCPC SDT in achieving stakeholder consensus for their proposed
requirements in COM-003. The intent of this DT is to preserve a method for RCs,
BAs and TOPs to make the determination of “what actions are required” and
clearly communicate the importance to the receiver at a heightened method to
normal day-to-day operational communications. The trigger of “Reliability
Directive” by the issuer highlights these actions as needed to maintain BES
reliability and shall be carried out as directed (unless such actions would violate
safety, equipment, regulatory or statutory requirement per the language of the
requirement) and all parties to the conversation need to be very cognizant of the
system conditions that are requiring actions. The DT has attempted to craft clear
and specific language that support BES reliability and hopes that this work can
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
support and enhance the development of the OPCP SDT. The RCSDT has also
attempted to eliminate redundancy and ambiguity while not creating any
reliability gaps. Several comments were received on the RC’s ability to “act”. The
RC must “act” (ie. do something, “to prevent or mitigate the magnitude or
duration of events that result in Adverse Reliability Impacts”. This may include
analysis, coordination of cooperative actions or the issuance of “Reliability
Directives”. “Act” does not imply solely the manipulation of BES elements.
RC control of “analysis tools” is critical to maintaining the wide area view. Control
by the RC over the tools is imperative and beyond administrative, since it is
intended to prevent planned reliability tool outages without the consent or
knowledge of operating personnel. Although the DT agrees with the premise that
many other requirements may be violated by ineffective communications, the
intent of the requirement is to ensure there are effective communications methods
in place for communicating BES activity across entities. Effective communication
are a cornerstone of BES reliability and the intent of the requirement is to prevent
the violation of other more significant performance type standard requirements
due to ineffective communications before they impact the BES. Failure of the RC
to control outages of analysis tools was mentioned as a contributing factor in the
2003 blackout.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
7.
8.
Do you agree with the proposed definition of Interpersonal Communication
(COM-001-2)? If not, please explain in the comment area. ........................... 15
Do you agree with the proposed definition of Alternative Interpersonal
Communication (COM-001-2)? If not, please explain in the comment area. .. 25
Do you agree with the revisions made to Requirement 1 in COM-001-2 as
shown in the posted Standard and Implementation Plan? If not, please
explain in the comment area. ......................................................................... 34
Do you agree with the definition of Reliability Directive (COM-002-2)? If not,
please explain in the comment area. .............................................................. 46
Do you agree with the revisions to the Requirements in COM-002-3 as shown
in the posted Standard and Implementation Plan? If not, please explain in the
comment area. ............................................................................................... 56
Do you agree with the use of the defined term “Reliability Directive” in
revisions to the Requirements in IRO-001-2 as shown in the posted Standard
and Implementation Plan? If not, please explain in the comment area. ........ 67
Do you agree with the revisions to the Requirements in IRO-014-2 as shown
in the posted Standard and Implementation Plan? If not, please explain in the
comment area. ............................................................................................... 77
Do you have any other comment, not expressed in questions above, for the RC
SDT? ............................................................................................................... 89
6
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Guy Zito
Additional Member
2
3
4
5
6
7
8
9
10
Northeast Power Coordinating Council
X
Additional Organization
Region
Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC
10
2. Gregory Campoli
New York Independent System Operator
NPCC
2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC
2
4. Kurtis Chong
Independent Electricity System Operator
NPCC
2
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC
1
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc.
NPCC
1
7. Brian D. Evans-Mongeon
Utility Services
NPCC
8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC
5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC
5
10. Kathleen Goodman
ISO - New England
NPCC
2
11. David Kiguel
Hydro One Networks Inc.
NPCC
1
12. Michael R. Lombardi
Northeast Utilities
NPCC
1
13. Randy MacDonald
New Brunswick System Operator
NPCC
2
14. Greg Mason
Dynegy Generation
NPCC
5
7
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
2
3
4
5
6
15. Bruce Metruck
New York Power Authority
NPCC
6
16. Chris Orzel
FPL Energy/NextEra Energy
NPCC
5
17. Robert Pellegrini
The United Illuminating Company
NPCC
1
18. Saurabh Saksena
National Grid
NPCC
1
19. Michael Schiavone
National Grid
NPCC
1
20. Peter Yost
Consolidated Edison Co. of New York, Inc.
NPCC
3
21. Lee Pedowicz
Northeast Power Coordinating Council
NPCC
10
22. Gerry Dunbar
Northeast Power Coordinating Council
NPCC
10
2.
Group
Gerald Beckerle
OC Standards Review Group
Additional Member
Additional Organization
X
7
8
9
10
X
Region
Segment Selection
1. Laura Lee
Duke
1, 3, 5
2. Al DiCaprio
PJM
2
3. Gene Delk
SCE&G
1, 3, 5
4. Jim Griffith
Southern
1, 3, 5
5. Mike Hardy
Southern
1, 3, 5
6. Dale Walters
CWLP
1, 3, 5, 9
7. Alvis Lanton
SIPC
3, 5
8. Larry Rodriquez
Union Power Partners
5
9. Tim Lyons
OMU
1, 3, 5
10. Barry Hardy
OMU
1, 3, 5
11. Dwayne Roberts
OMU
1, 3, 5
12. Fred Krebs
Calpine
5
13. Tim Hattaway
PowerSouth
3, 5, 9
14. Jim Case
Entergy
1, 3
15. Rene' Free
Santee Cooper
9, 1, 3, 5
16. Glenn Stephens
Santee Cooper
1, 3, 5, 9
17. Robert Thomasson
Big Rivers
1, 3, 5, 9
18. John Neagle
AECI
3, 5
8
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
19. John Troha
3.
2
3
4
5
SERC
Group
Sam Ciccone
7
X
Additional Organization
X
X
X
Region
RFC
1, 3, 4, 5, 6
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
3. kevin Querry
FES
RFC
6
4. Larry Herman
FE
RFC
3
Carol Gerou
NERC Standards Review Subcommittee
Additional Member
X
Additional Organization
Region
Segment Selection
1. Chuck Lawrence
American Transmission Company
MRO
1
2. Tom Webb
WPS
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Jodi Jenson
Western Area Power Administration
MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
7. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
8. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
9. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
10. Scott Nickels
Rochester Public Utilties
MRO
4
11. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
5.
Group
Jalal babik
Electric Market Policy
Additional Member
X
Additional Organization
X
X
X
Region
Segment Selection
1. Louis Slade
SERC
1, 4
2. Mike Garton
NPCC
5
6.
Group
Brenda Lyn Truhe
Additional Member
10
Segment Selection
FE
Group
9
X
1. Dave Folk
4.
8
10
FirstEnergy
Additional Member
6
PPL
X
Additional Organization
X
Region
X
Segment Selection
9
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
2
3
4
5
6
1. Brenda Truhe
PPL Electric Utilities
RFC
1
2. Jon Williamson
PPL EnergyPlus
WECC
6
3. Mark Heimbach
PPL EnergyPlus
MRO
6
4. Mark Heimbach
PPL EnergyPlus
NPCC
6
5. Mark Heimbach
PPL EnergyPlus
RFC
6
6. Mark Heimbach
PPL EnergyPlus
SERC
6
7. Mark Heimbach
PPL EnergyPlus
SPP
6
8. Annette Bannon
PPL Generation
RFC
5
9. Annette Bannon
PPL Generation
NPCC
5
10. Annette Bannon
PPL Generation
WECC
5
7.
Group
Harry Tom
Operating Personnel Communications Protocols
SDT
Additional Member
X
X
Additional Organization
X
X
X
Region
7
8
X
X
Segment Selection
1. Lloyd Snyder
GSOC
SERC
1
2. Leanne Harrison
PJM
RFC
2
3. Laura Zotter
ERCOT
ERCOT
2
4. Tom Irvine
HydroOne
NPCC
1, 5, 6, 7
5. Bill Ellard
CAISO
WECC
2
6. John Stephens
City of Springfield
RFC
4, 8
7. Mike Brost
JEA
FRCC
1, 3, 5, 7
8. Mark Bradley
ITC
MRO
1
9. Fred Waites
Southern Company
SERC
1, 3, 5, 7
10. Wayne Mitchell
Entergy
SPP
1, 3, 5, 7
8.
Group
Howard Gugel
9
NERC
Please complete the following information.
Additional Member
Additional Organization
Region
1. Laurel Heacock
NERC
NA - Not Applicable
2. Bob Cummings
NERC
NA - Not Applicable
Segment Selection
10
10
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
3. Larry Kezele
NERC
4. Ed Ruck
NERC
5. Todd Thompson
NERC
6. Mark Vastano
NERC
7. Roman Carter
NERC
8. Jule Tate
NERC
9. David Taylor
NERC
10. Al McMeekin
NERC
11. Maureen Long
NERC
12. Andy Rodriquez
NERC
13. Michael Moon
NERC
14. Stephanie Monzon
NERC
15. Gerry Adamski
NERC
9.
Group
Linda Perez
10.
Group
4
5
6
7
Region
WECC
Midwest ISO Standards Collaborators
Additional Member
Segment Selection
X
Additional Organization
Region
Segment Selection
Illinois Municipal Electric Agency
SERC
4
2. Jose Medina
NextEra Energy Resources, LLC
WECC
5
3. Joe O'Brien
NIPSCO
RFC
1
4. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
5. Kirit Shah
Ameren
SERC
1
Group
JT Wood
Additional Member
1. Hugh Frances
9
10
1. Bob Thomas
11.
8
Southern Company Services
10
X
Additional Organization
WECC
Jason L. Marshall
3
Western Electricity Coordinating Council
Additional Member
1. Steve Rueckert
2
X
Additional Organization
X
Region
SERC
Segment Selection
1
11
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
12.
Group
Frank Gaffney
Florida Municipal Power Agency and Some
Members
Additional Member
2
X
Additional Organization
3
4
5
6
X
X
X
X
Region
7
Lakeland Electric
FRCC
1, 3, 5
2. Greg Woessner
Kissimmee Utilities Authority
FRCC
1, 3, 4, 5
Group
Kenneth D. Brown
Public Service Enterprise Group Companies
Additional Member
X
X
Additional Organization
X
X
Region
Segment Selection
1. Jeffrey Mueller
PSE&G
RFC
1, 3
2. Dave Murray
PSEG Fossil
RFC
5
3. Jim Hebson
PSEG ER&T
ERCOT
5, 6
4. Clint Bogan
PSEG Power Connecticut
NPCC
5
14.
Group
Denise Koehn
Bonneville Power Administration
Additional Member
X
X
Additional Organization
X
X
Region
Segment Selection
1. Steve Davis
BPA, Generation Support
WECC
3, 5, 6
2. Tedd Snodgrass
BPA, Transmission Dispatch
WECC
1
3. Tim Loepker
BPA, Transmission Dispatch
WECC
1
4. Huy Ngo
BPA, Transmission Control Cntr HW Design & Maint
15.
Group
Ben Li
1
IRC Standards Review Committee
Additional Member
9
Segment Selection
1. Jim Howard
13.
8
X
Additional Organization
Region
Segment Selection
1. Charles Yeung
SPP
SPP
2
2. James Castle
NYISO
NPCC
2
3. Bill Phillips
MISO
MRO
2
4. Lourdes Estrada-Salinero
CAISO
WECC
2
5. Steve Myers
ERCOT
ERCOT
2
6. Matt Goldberg
ISO-NE
NPCC
2
7. Patrick Brown
PJM
RFC
2
12
10
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
8. Mark Thompson
AESO
2
3
4
5
WECC
6
7
8
9
2
16.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
17.
Individual
Brent Ingebrigtson
E.ON U.S.
X
X
X
X
18.
Individual
Duncan Brown
Calpine Corporation
19.
Individual
Ron Sporseen
PNGC Power (15 member utilities)
20.
Individual
Chris Scanlon
Exelon
21.
Individual
Steve Alexanderson
Central Lincoln
X
22.
Individual
Denise Roeder
North Carolina Municipal Power Agency #1
X
23.
Individual
Jon Kapitz
Xcel Energy
24.
Individual
Martin Bauer
US Bureau of Reclamation
25.
Individual
Kasia Mihalchuk
Manitoba Hydro
26.
Individual
Howard Rulf
We Energies
27.
Individual
Michael R. Lombardi
Northeast Utilities
28.
Individual
CJ Ingersoll
CECD
29.
Individual
Brandy A. Dunn
Western Area Power Administration
X
30.
Individual
Michael J Ayotte
ITC Holdings
X
31.
Individual
Kathleen Goodman
ISO New England Inc
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
13
10
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Commenter
Organization
Industry Segment
1
2
3
4
5
6
32.
Individual
James H. Sorrels, Jr.
American Electric Power
X
X
X
X
33.
Individual
Greg Rowland
Duke Energy
X
X
X
X
34.
Individual
James Sharpe
South Carolina Electric and Gas
X
X
X
X
35.
Individual
Jason Shaver
American Transmission Company
X
36.
Individual
Richard Kafka
Pepco Hodlings, Inc
X
X
X
X
37.
Individual
Kirit Shah
Ameren
X
X
X
X
38.
Individual
Charles Yeung
Southwest Power Pool
39.
Individual
Roger Champagne
Hydro-Québec TransEnergie (HQT)
40.
Individual
Dan Rochester
Independent Electricity System Operator
X
41.
Individual
Laura Zotter
ERCOT ISO
X
42.
Individual
Catherine Koch
Puget Sound Energy
7
8
9
10
X
X
X
X
14
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
1 Do you agree with the proposed definition of Interpersonal Communication (COM-001-2)? If not, please
explain in the comment area.
Summary Consideration: Stakeholders had three general concerns with the definition of Interpersonal
Communications.
1) The definition of Interpersonal Communication to be ambiguous in terms of distinguishing between verbal
communications and data transfers; The SDT believes that Webster’s definition of Interpersonal: (being,
relating to, or involving relations between persons) clarifies the exclusion of media dedicated to
Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability
Coordinator, Transmission Operator, and Transmission Owner shall provide data and information, as specified, to the
Reliability Coordinator(s) with which it has a reliability relationship. (Violation Risk Factor: Medium) (Time Horizon:
Operations Planning; Same-day Operations; Real-time Operations)
2) The definition should also clarify that the communication is between individuals in different entities or
physical locations; The SDT believes that the revised Requirements of COM-001-2 satisfy this concern.
3) Use of the term “method” may imply a communication style; changed “method” to “medium” in definition.
Organization
Yes or No
Question 1 Comment
Calpine Corporation
North Carolina Municipal Power
Agency #1
Public Service Enterprise Group
Companies
We Energies
15
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Operating Personnel
Communications Protocols SDT
CECD
Question 1 Comment
No comment
No
CECD agrees that the term should be very broad and allow a registered entity to establish appropriate
communication tools, devices, processes or systems to suit their operation. However, there is a need to
include the term "normal" interpersonal communication methods based on the definition of alternative
interpersonal communication.
Response: The RCSDT thanks you for your comment. RCSDT does not propose defining “Normal” Interpersonal Communications and has removed it
from the alternative definition and included “…used for day-to-day operation.” Based on the consensus of stakeholders, we have revised the two
definitions to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
ITC Holdings
No
Comments: As written, the definition could be interpreted to include data communications. Suggest modifying
the definition to “Any method that allows two or more individuals to verbally interact, consult, or exchange
information.” Interpersonal Communication to operate the BES must be timely and non voice communication
cannot be relied upon to be timely in all situations.
Response: The RCSDT thanks you for your comment. The intent of this definition is to exclude data, but not preclude e-mail, text, etc.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
NERC
No
Comments: NERC staff believes the definition is unnecessary. “Interpersonal” is a common term and this
definition provides no additional clarity. In addition, COM-001 should maintain the current coverage of voice
and data. The requirements should address both primary and alternative/backup capabilities for voice and
data. Approved standards including TOP-005-1.1 and IRO-010-1, as well as several others under
development rely on the communication capabilities specified in COM-001. By limiting the focus of COM-001-
16
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
2 to this definition of Interpersonal Communication, there will no longer be an obligation to ensure that data
telecommunication paths between entities are adequate and reliable.
Response: The RCSDT thanks you for your comment. The RCSDT and the industry disagree with NERC staff’s assessment. A strong industry request
to clarify “facilities” led to the definition of interpersonal communication which has been modified to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Primary communication is inferred when reference to alternative is made. Moreover, the primary capability is used/tested on a daily basis.
The RCSDT contends that IRO-010 covers the requirement for data and information that includes a requirement for providing specified data when
automated Real-Time system operating data is unavailable.
Exelon
No
Definition is vague and subject to interpretation. Requirement should be to have primary and backup
capabilities. Disagree that a definition is required.
Response: The RCSDT thanks you for your comment. The RCSDT and the industry disagree. A strong industry demand to clarify “facilities” led to the
definition of interpersonal communication which has been modified to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Primary communication is inferred when reference to alternative is made. Moreover, the primary capability is used/tested on a daily basis.
Southern Company Services
No
If there is going to be an alternative definition, than this should be a definition for Normal Interpersonal
Communication.
Response: The RCSDT thanks you for your comment. Primary communication is inferred when reference to alternative is made. Moreover, the
primary capability is used/tested on a daily basis.
Ameren
No
In previous postings, the drafting team confirmed that they intended for COM-001-2 to apply only to verbal
communication systems and not data. However, the phrase “or exchange information.” could still imply data
(information). We suggest that the team should explicitly exclude data in definition.
Midwest ISO Standards
Collaborators
No
In previous postings, the drafting team confirmed that they intended for COM-001-2 to apply only to verbal
communication systems. We believe this definition had inadvertently brought data back into the standard.
Specifically, we are concerned about “or exchange information.” Data can be considered information and
thus some may now interpret SCADA and ICCP being included. We suggest the definition would be sufficient
with the “or exchange information” redacted and would avoid this confusion.
17
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Response: The RCSDT thanks you for your comment. The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving
relations between persons) clarifies the exclusion of media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
NERC Standards Review
Subcommittee
No
In previous postings, the drafting team confirmed that they intended for COM-001-2 to apply only to verbal
communication systems. We believe this definition had inadvertently brought data back into the standard.
Specifically, we are concerned about “or exchange information.” Data can be considered information and
thus some may now interpret SCADA and ICCP being included. To avoid this confusion, we suggest the
definition would be sufficient with the “or exchange information” redacted.
We believe the proposed definition for the term “Interpersonal Communication” is too broad and ambiguous.
We recommend the following instead: “Verbal Communication between two or more registered entities (not
within the same organization) to exchange reliability-related information.” The inclusion of this term
“registered entities” removes the ambiguity which we believe is contained in the proposed definition. In
addition, the inclusion of the phrase “not within the same organization” clarifies that the focus of definition is to
address communication between different registered entities.
Response: The RCSDT thanks you for your comment. The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving
relations between persons) clarifies the exclusion of media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
Also, the SDT believes that the revised Requirements of COM-001-2 satisfy your ambiguity concern.
Southwest Power Pool
No
It appears as if the following two definitions have the same meaning: COM-001-2 Interpersonal
Communication: Any method that allows two or more individuals to interact, consult, or exchange information.
COM-003 -1 Interoperability Communication - Communication between two or more entities to exchange
reliability-related information to be used by the entities to change the state or status of an element or facility of
18
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
the Bulk Electric System. SPP recommends changing the word “method” to medium in Interpersonal
Communication. For Alternative Interpersonal Communication, that definition uses the term “infrastructure
(medium)” as in type of equipment used. These terms should use consistent words if they are referring to the
same thing.
Response: The RCSDT thanks you for your comment. We concur and have revised the two definitions to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
Duke Energy
No
Need to revise this definition to clarify that Interpersonal Communication is the primary method of
communication, and that it is limited to verbal or written communications (not data such as SCADA data), and
that it is limited to real-time operations (time horizon is Real-time Operations). Suggested wording:
Interpersonal Communication: The primary verbal or written method that allows two or more individuals to
interact, consult, or exchange information for real-time operations.
Response: The RCSDT thanks you for your comment. . The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving
relations between persons) clarifies the exclusion of media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
The RCSDT does not believe “primary” is needed because “primary” communication is inferred when reference to “alternative” is made.
PPL
No
The definition should be clarified to state that it is interpersonal communications between functional entities
and not interpersonal communications within the functional entity that the standard is addressing.
Response: The RCSDT thanks you for your comment. The SDT believes that the revised Requirements of COM-001-2 satisfy your concern
Hydro-Québec TransEnergie
(HQT)
No
The definition should be worded to be more explicit, such as: When two or more individuals interact, consult,
or exchange information.
19
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 1 Comment
The definition should be worded to be more explicit, such as: When two or more individuals interact, consult,
or exchange information.
Response: The RCSDT thanks you for your comment. We concur and have revised the definition to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Electric Market Policy
No
The SDT has proposed a definition that is meant to limit the standard to two-way person-to-person
communication between functional entities. However, as written the definition can also be viewed as so openended as to apply to pens and papers used by system operators to show another system operator in the
same control room some operational data. The proposed standard does further constrain the application to
“real-time operation information”, but may be better served to explicitly constrain the definition to functionalentity-to-functional entity. It is these media that the standard means to address.
Response: The RCSDT thanks you for your comment. The SDT believes that the revised Requirements of COM-001-2 satisfy your concern
Bonneville Power Administration
No
The term, ‘interpersonal communication’ as defined by common usage and Webster’s Dictionary is sufficient
for the work at hand. To provide an additional definition via the NERC Standards Development Process
unnecessarily adds to an already convoluted task and provides no further benefit to the user of this proposed
standard.
Response: The RCSDT thanks you for your comment. The RCSDT and the industry disagree. A strong industry request to clarify “facilities” led to the
definition of interpersonal communication which has been modified to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Northeast Utilities
No
The use of “Any method” as the start of the definition of Interpersonal Communication is too board a qualifier.
In normal interpersonal communications only 5 to 10% of the total communication is verbal while 90 to 95% is
non-verbal. As it is not the intent of this standard to address non-verbal communications the use of “Any
method” should be eliminated from the definition and more specific terms that clearly convey the intent of the
standard should be used.
20
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Response: The RCSDT thanks you for your comment. We concur and have modified the definition to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
FirstEnergy
No
This definition should be revised as follows to ensure clarity of scope by excluding electronic data exchange
and for consistency with the proposed requirements: "Interpersonal Communication Capability: Any method
that allows two or more individuals to interact, consult, or exchange real-time Bulk Electric System operating
information using verbal communication equipment."
Response: The RCSDT thanks you for your comment. We agree in principle; however, the SDT believes that Webster’s definition of Interpersonal: (being,
relating to, or involving relations between persons) clarifies the exclusion of media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
Manitoba Hydro
No
When “Interpersonal Communication” is added to the NERC Glossary without the obvious reference to COM001-2 which is “To ensure that operating entities have adequate Interpersonal capabilities” could and does
infer that the definition means “protocol or forum of speaking, interacting or exchanging” information. The
suggested definition does not immediately indicate the normal medium of communications, such a land line,
mobile, radio, electronic, etc. A suggested definition: Interpersonal Communication: The normal mediums
that carry messages, verbal or electronic, between two or more entities, internal or external, for the operation
of the Interconnected Bulk Electric System.
Response: The RCSDT thanks you for your comment. We agree in principle and have modified the definition to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
The SDT believes that the revised Requirements of COM-001-2 satisfy your concern of communication between entities.
21
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
American Electric Power
Yes
American Transmission
Company
Yes
Central Lincoln
Yes
E.ON U.S.
Yes
Florida Municipal Power Agency
and Some Members
Yes
Independent Electricity System
Operator
Yes
IRC Standards Review
Committee
Yes
ISO New England Inc
Yes
OC Standards Review Group
Yes
PacifiCorp
Yes
Pepco Hodlings, Inc
Yes
PNGC Power (15 member
utilities)
Yes
Puget Sound Energy
No
Question 1 Comment
The proposed definition for this term addresses a method of communication, but not the communication itself.
As a result, the defined term is incomplete as proposed. Recommend the addition of the word “capability” so
that the defined term is “Interpersonal Communication Capability”. The addition of this word to the term is
also consistent with the use of the term in the proposed standard language, where Interpersonal
Communication is consistently used in conjunction with the words “capability” or “capabilities”.
22
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Response: The RCSDT thanks you for your comment. We agree in principle and have modified the
definition which replaces “method” with “medium”:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
The RCSDT believes the definition itself infers “capability.”
South Carolina Electric and Gas
Yes
US Bureau of Reclamation
Yes
Western Area Power
Administration
Yes
Western Electricity Coordinating
Council
Yes
Xcel Energy
Yes
ERCOT ISO
No
1) ERCOT ISO considers the definition of Interpersonal Communication to be ambiguous in terms of
distinguishing between verbal communications and data transfers; the definition should specify that it
applies to verbal communication systems.
2) The definition should also clarify that the communication is between individuals in different physical
locations to mitigate any potential for application to communications between employees of the same
company communicating to each other in person at the same physical location – e.g. a control center.
3) Additionally, use of the term “method” could imply a communication style (e.g. 3-part communications) as
opposed to mode. It should be clear that the Standard only applies to modes of communication.
Examples should be provided (e.g. phone, email, etc.) to clarify the scope.
Response: The RCSDT thanks you for your comment.
1. The definition of Interpersonal Communication to be ambiguous in terms of distinguishing between verbal communications and data transfers;
the SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving relations between persons) clarifies the exclusion of
media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
23
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
2. The SDT believes that the revised Requirements of COM-001-2 satisfy your concern of communication in different physical locations.
3. The RCSDT concurs and revised the definition, Interpersonal Communication: Any medium that allows two or more individuals to interact,
consult, or exchange information.
24
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
2 Do you agree with the proposed definition of Alternative Interpersonal Communication (COM-001-2)? If
not, please explain in the comment area.
Summary Consideration: Several stakeholders indicated that a definition of Alternative Interpersonal
Communications was not needed. The RCSDT disagrees because there is an important part of the definition of
“Alternative Interpersonal Communications” that distinguishes it from simply being an alternative
“Interpersonal Communications”. The proposed definition contains the words: “which does not utilize the
same infrastructure (medium)”. Also, some stakeholders had concerns with the usage of “normal”. The RCSDT
does not propose defining “Normal” Interpersonal Communications and has removed it from the definition.
Based on the consensus of stakeholders, we have revised the two definitions to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication used for
day-to-day operation.
Organization
Yes or No
Question 2 Comment
Calpine Corporation
North Carolina Municipal Power
Agency #1
Public Service Enterprise Group
Companies
We Energies
Operating Personnel
Communications Protocols SDT
No Comment
25
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Manitoba Hydro
Yes or No
Question 2 Comment
No
“Alternative Interpersonal Communication” also when added to the NERC Glossary without the obvious
reference to COM-001-2 which is “To ensure that operating entities have adequate Interpersonal capabilities”
could and does infer that the definition means “ other protocols or forums of speaking, interacting or
exchanging” information. The suggested definition does not immediately indicate the backup or alternate
mediums of communications, such a redundant land lines, Satellite phones, battery or diesel back up
electronics, etc. A suggested definition: Alternative Interpersonal Communication: Backup or alternate
mediums that during planned or failure of normal medium systems, that can carry messages, verbal or
electronic, between two or more entities, internal or external, for the operation of the Interconnected Bulk
Electric System.
Response: The RCSDT thanks you for your comment. We have revised the definition to:
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
The RCSDT believes “medium” stands alone in the definition and needs no descriptors.
Exelon
No
Disagree that a definition is required.
Response: The RCSDT thanks you for your comment. The RCSDT disagrees because there is an important part of the definition of “Alternative
Interpersonal Communications” that distinguishes it from simply being an alternative “Interpersonal Communications”. The proposed definition
contains the words: “which does not utilize the same infrastructure (medium)”.
Western Electricity Coordinating
Council
No
Do not need an alternate definition
Response: The RCSDT thanks you for your comment. The RCSDT disagrees because there is an important part of the definition of “Alternative
Interpersonal Communications” that distinguishes it from simply being an alternative “Interpersonal Communications”. The proposed definition
contains the words: “which does not utilize the same infrastructure (medium)”.
Southern Company Services
No
Interpersonal Communication includes any method. If this includes all possibilities why is an additional
definition needed?
Response: The RCSDT thanks you for your comment. The RCSDT revised the definition as:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
The RCSDT believes that an important part of the definition of “Alternative Interpersonal Communications” that distinguishes it from simply being an
26
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 2 Comment
alternative “Interpersonal Communications” are the words: “which does not utilize the same infrastructure (medium)”.
Duke Energy
No
Need to revise this definition to clarify that Alternative Interpersonal Communication is the identified substitute
method for the Interpersonal Communication method. Suggested wording: Alternative Interpersonal
Communication: The identified verbal or written method that is able to serve as the substitute for and is
redundant to Interpersonal Communication and does not utilize the same infrastructure (medium) as
Interpersonal Communication.
Response: The RCSDT thanks you for your comment. The RCSDT does not believe that the definition should be revised as suggested as “Altenative”
is clear when the requirements are viewed.
Southwest Power Pool
No
Replace Alternative Interpersonal Communication definition with: Backup Interpersonal Communication: Any
method that is able to serve as a substitute for and is redundant to the primary normal Interpersonal
Communication and does not utilize the same infrastructure (medium) as the primary normal Interpersonal
Communications. Consistent terms should be used across standards if they are referring to the same thing.
Response: The RCSDT thanks you for your comment. The RCSDT feels that the use of “Alternative” is appropriate and provides flexibility within this
standard. The RCSDT does not believe that the definition should be revised as suggested as “Altenative” is clear when the requirements are viewed.
There is sufficient stakeholder support to retain “Alternative”.
NERC
No
See response to Question 1.
Response: The RCSDT thanks you for your comment. Please see response to Question 1.
E.ON U.S.
No
Suggested edit to definition: Alternative Interpersonal Communication: A Interpersonal Communication
method that is able to serve as a substitute for and is functionally redundant to the normal Interpersonal
Communication method but does not utilize the same infrastructure (medium) as the normal Interpersonal
Communication method. The intent of the edit is to clarify that the entity must to have identified one (1)
normal Interpersonal Communication and one (1) Alternative Intercommunication method.
Response: The RCSDT thanks you for your comment. A definition can not impose requirements that are not explicitly stated in the standard. The
suggested edit is not necessary as the requirements define what an entity must do to be compliant. The RCSDT has also removed the words “and is
redundant to” from the definition based on other stakeholders comments.
27
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Bonneville Power Administration
Yes or No
Question 2 Comment
No
The proposed definition adds value for the user of this proposed standard by adding the ideas of the alternate
mode of communications being both independent and redundant to normal communications. However, this
having been said, the term chosen by the SDT, the term ‘Alternative Interpersonal Communication’ appears to
focus attention on the wrong aspect of what’s being discussed. Since the definition focuses on an alternative
mode or ‘method’ of communicating, clarity would be added if the SDT changed the term to be defined to
either ‘Alternative Mode of Communication’ or ‘Alternative Method of Communication.’ The use of the word
‘interpersonal’ would be optional, but not necessary.
Response: The RCSDT thanks you for your comment. To clarify our intent, the RCSDT changed “method” to “medium” in the definition. The
proposed definition is:
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
Hydro-Québec TransEnergie
(HQT)
No
The proposed definition of Alternative Interpersonal Communication is equally ambiguous as the
aforementioned definition of Interpersonal Communication. A precise definition of Interpersonal
Communication and “Normal” Interpersonal Communication is required before an agreed upon definition of
Alternative Interpersonal Communication can be reached.
Northeast Power Coordinating
Council
No
The proposed definition of Alternative Interpersonal Communication is equally ambiguous as the
aforementioned definition of Interpersonal Communication. A precise definition of Interpersonal
Communication and “Normal” Interpersonal Communication is required before an agreed upon definition of
Alternative Interpersonal Communication can be reached.
Northeast Utilities
No
The proposed definition of Alternative Interpersonal Communication is equally ambiguous as the
aforementioned definition of Interpersonal Communication. A precise definition of Interpersonal
Communication and “Normal” Interpersonal Communication is required before an agreed upon definition of
Alternative Interpersonal Communication can be reached.
Response: The RCSDT thanks you for your comment. The RCSDT does not propose defining “Normal” Interpersonal Communications and has
removed it from the definition. Based on the consensus of stakeholders, we have revised the two definitions to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
28
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 2 Comment
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
FirstEnergy
No
The word "normal" in the proposed definition adds some ambiguity to the definition. This definition should be
revised as follows to ensure clarity of scope by excluding electronic data exchange and for consistency with
the proposed requirements: Alternative Interpersonal Communication Capability: Any verbal communication
equipment that is able to serve as a substitute for and is redundant to Interpersonal Communication
equipment used during day-to-day operations and does not utilize the same infrastructure as the
Interpersonal Communication equipment.
Response: The RCSDT thanks you for your comment. The RCSDT does not propose defining “Normal” Interpersonal Communications and have
removed it from the definition. Based on the consensus of stakeholders, we have revised the two definitions to:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
Ameren
Yes
American Electric Power
Yes
CECD
Yes
Central Lincoln
Yes
Florida Municipal Power Agency
and Some Members
Yes
Independent Electricity System
Operator
Yes
IRC Standards Review
Committee
Yes
ISO New England Inc
Yes
29
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Midwest ISO Standards
Collaborators
Yes
OC Standards Review Group
Yes
PacifiCorp
Yes
Pepco Hodlings, Inc
Yes
PNGC Power (15 member
utilities)
Yes
PPL
Yes
Puget Sound Energy
No
Question 2 Comment
As for the proposed term for “Interpersonal Communication”, the proposed definition for this term addresses a
method of communication, but not the communication itself. As a result, the defined term is incomplete as
proposed. Recommend the addition of the word “capability” so that the defined term is “Alternative
Interpersonal Communication Capability”. The addition of this word to the term is also consistent with the use
of the term in the proposed standard language, where Alternative Interpersonal Communication is
consistently used in conjunction with the words “capability” or “capabilities”.
Response: The RCSDT thanks you for your comment. Based on a consensus of stakeholder comments, the RCSDT has revised the proposed
definitions to: Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
The definition itself describes “capability.”
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
South Carolina Electric and Gas
Yes
US Bureau of Reclamation
Yes
Western Area Power
Administration
Yes
30
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Xcel Energy
Yes
American Transmission
Company
Yes
Question 2 Comment
However, clarity is needed for the word “infrastructure (medium)”. ATC’s interpretation is that satellite
phones, cell phones, radio and land lines are all different mediums.
Response: The RCSDT thanks you for your comment. The RCSDT agrees that the types of communication that you list are all different media which
could be used as a form of Alternative Interpersonal Communications.
ITC Holdings
Yes
None
NERC Standards Review
Subcommittee
Yes
Please clarify. We believe the proposed definition for the term “Interpersonal Communication” is too broad
and ambiguous. We recommend the following instead: “Verbal Communication between two or more
registered entities (not within the same organization) to exchange reliability-related information.” The
inclusion of this term “registered entities” removes the ambiguity which we believe is contained in the
proposed definition. In addition, the inclusion of the phrase “not within the same organization” clarifies that the
focus of definition is to address communication between different registered entities.
Response: The RCSDT thanks you for your comment. The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving
relations between persons) clarifies the exclusion of media dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
The SDT believes that the revised Requirements of COM-001-2 satisfy your concern of communication in different physical locations.
Electric Market Policy
Yes
Subject to adequate resolution of comments provided for Question 1
Response: The RCSDT thanks you for your comment. Please see response to question 1 comments.
ERCOT ISO
No
Although this definition indirectly clarifies the intent of the definition of Interpersonal Communication by noting
that communication mediums/infrastructure are at issue, it does not specify verbal or data communication,
and needs to be clarified accordingly; ERCOT notes clarification of Interpersonal Communication (IC) on this
issue will indirectly clarify this point with respect to the Alternative IC definition.
31
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 2 Comment
Furthermore, ERCOT ISO considers the definition of Alternative Interpersonal Communication unnecessary.
The Standard could simply say an entity must have multiple (at least two) ICs, one if which is primary and
others that serve as back-ups. This would eliminate the need for yet another defined term susceptible to
conflicting interpretations.
In additions, calling the Alternative Interpersonal Communication a substitute and redundant also seems
contradictory, or at least confusing in terms of timing. Redundant implies that the entity has two means that
are applied at the same time. Substitute seems to mean that the entity have a back-up that only has to be
used when the primary isn’t used.
Also, if Interpersonal Communication is intended to be verbal communication, what are considered
acceptable alternates (i.e.: fax, email, etc)? Examples here would be helpful. Is it sufficient to have
redundant/substitute means of verbal communication (i.e.: satellite phones, cell phones, etc.). ERCOT ISO
believes non-verbal proxies for verbal communications should be eligible ICs – e.g. email.
As noted above, ERCOT ISO believes the most efficient way to approach this is to eliminate the use of
Alternative Interpersonal Communication and have the standard require that entities have to have at least two
means of Interpersonal Communication.
Response: The RCSDT thanks you for your comment.
. The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving relations between persons) clarifies the exclusion of media
dedicated to Telemetering or other data exchange.
The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
The RCSDT disagrees that the definition is not needed because there is an important part of the definition of “Alternative Interpersonal
Communications” that distinguishes it from simply being an alternative “Interpersonal Communications”. The proposed definition contains the
words: “which does not utilize the same infrastructure (medium)”.
We concur and have removed the “redundant” portion of the definition.
Interpersonal Communication can include voice and text; examples are satellite phones, cell phones, radio and land lines. We have revised the
proposed definitions to add clarity:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or exchange information.
32
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 2 Comment
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day operation.
33
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
3 Do you agree with the revisions made to Requirement 1 in COM-001-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Summary Consideration: Stakeholders pointed out that R1 was a compound requirement and suggested creating
separate requirements. Stakeholders also suggested revising the VRF to “Medium” as it does not meet the
guidelines for a “High” VRF. The intent of R1 was three-fold.
4
Identify (have) an Alternative Interpersonal Communication capability
5
Test that capability periodically and
6
If the test failed, fix it or identify another Alternative Communications Capability.
Based on comments received, we have revised R1, now R9, to eliminate the compound requirement and therefore
created more specific requirements to delineate Interpersonal and Alternative Interpersonal Communication, and
applicable entity responsibility. The VRF is changed to “Medium.”
Requirement R1 is now R9; R2 is now R10; R3 is now R11; R4 is now R7 and R8.
Organization
Yes or No
Question 3 Comment
Calpine Corporation
North Carolina Municipal Power
Agency #1
Operating Personnel
Communications Protocols SDT
American Electric Power
No Comment
No
AEP is concerned with the use of a sixty minute window without having a broadcast methodology in place to
support the required notifications. As mentioned in other comments, perhaps RCIS could be modified to help
support communications and the confirmation of such communications.
Response: The RCSDT thanks you for your comment. Having a failure of the Alternative Interpersonal Communications per R1 does not indicate that
the Interpersonal Communications used in day-to-day operations is out of service. It is expected that the Interpersonal Communications used in dayto-day operations is indeed operational to make the notifications required in R3 regarding alternative failure.
34
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
We Energies
No
An Alternative Personnel Communications (APC) is intended for use at a Primary Control Center for real-time
voice communications. That needs to be clear in the definitions and standards. The time to either restore or
recognize that the Alternative Communications cannot be re-established should be aligned with proposed
EOP-008 which allows 2 hours. This should also apply to COM-001 R2 which would give an hour past the 2
hours that the APC is unavailable to contact impacted parties. Along with conforming changes to measures
and the like...
Response: The RCSDT thanks you for your comment. The Alternative Interpersonal Communications capability is intended for use as an alternative
for the Interpersonal Communications capability, regardless of whether the normal capability continues to be available or regardless of the location, be
it a primary control center or a back-up facility. R1, now R9, includes “…If the test is unsuccessful, the entity shall initiate action to repair or designate
a replacement Alternative Interpersonal Communications within 2 hours.”
ITC Holdings
No
Comments: The intent of the 60 minute requirement is unclear. As written, the 60 minute requirement could
be interpreted to apply to the initiation of restoration or, alternatively, to the completion of restoration. If the
latter is the intent, then effectively 3 voice communication mediums would be required to ensure compliance
which we believe is not warranted. Suggest modifying the requirement to “If the test is unsuccessful, the
entity shall take action within 60 minutes to initiate restoration of the identified alternative or...”. In addition,
we would suggest separating R1 into two requirements. From an audit perspective, there are two discrete
actions being identified: quarterly testing and initiating repairs.
Response: The RCSDT thanks you for your comment. We concur with your comment and have changed the requirement R1, now R9, to state “…If
the test is unsuccessful, the entity shall initiate action to repair or designate a replacement Alternative Interpersonal Communications within 2 hours.”
The SDT believes that R1, now R9, has a discreet relationship with successful and unsuccessful tests and therefore should remain as one requirement
for clarity.
Public Service Enterprise Group
Companies
No
Initiating actions within the hour should be specified, rather than taking action. It could take longer than an
hour to take (complete) action that resolves the issue.
Response: The RCSDT thanks you for your comment. We concur with your comment and have changed the requirement to state “…If the test is
unsuccessful, the entity shall initiate action to repair or designate a replacement Alternative Interpersonal Communications within 2 hours.”
Southern Company Services
No
It is quite possible for entities to interpret this requirement as not applicable if they include all of there
communications as interpersonal communication.
Response: The RCSDT thanks you for your comment. The requirement states that an entity will “designate” an Alternative Interpersonal
35
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
Communications capability. To do so, the entity would not be able to declare all communications as Interpersonal Communications.
FirstEnergy
No
It should be clear that this requirement applies only to BES information. The requirement should be revised
as follows to improve clarity: Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall identify and test, on a quarterly basis, its Alternative Interpersonal Communications capability used for
communicating real-time Bulk Electric System operating information.
Response: The RCSDT thanks you for your comment. The RCSDT does not believe that adding BES to the requirement adds any clarity as NERC
standards apply to the BES.
Duke Energy
No
o Need to clarify who the RC, TOP and BA are required to have Interpersonal Communications and
Alternative Interpersonal Communications capability with (i.e., each other and the DP and GOP). We believe
that R4 is redundant to R1, and the entities in R4 could be added to R1, and R4 deleted. Also make
conforming changes to the Measures, Data Retention and VSLs.
o Need to clarify that that the requirement is to take action to restore the Alternative Interpersonal
Communications capability, or take action to identify a substitute within 60 minutes, (not actually restore or
identify a substitute within 60 minutes - which may not be possible). Also need to revise the Measure and the
Lower VSL to conform with this clarification to the requirement
o Need to strike the phrase “used for communicating real-time operating information”, because this should be
included in the definition of Interpersonal Communication, as we propose in Comment #1 above, and it would
be redundant to also include it in R1.
o The VRF for R1 should be Medium instead of High, because this is a quarterly test of the alternative
capability - doesn’t meet the criteria for a High VRF.
o Need to clarify in Requirement R2 that the 60 minute clock for notifications BEGINS when you KNOW you
have a failure that has lasted for 30 or more minutes.
o Strike the word “normal” in Requirement R2, because the definition of Interpersonal Communications as
proposed above already includes the word “primary”.
Response: The RCSDT thanks you for your comment.
o
To provide better clarity the SDT created more specific requirements to delineate Interpersonal and Alternative Interpersonal Communication,
and applicable entity responsibility.
o
The RCSDT has revised the requirement R1, now R9, to state “…If the test is unsuccessful, the entity shall initiate action to repair or designate
a replacement Alternative Interpersonal Communications within 2 hours.” The Measure and VSL for R1, now R9, reflect the revision
36
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
o
The definition was not revised to include the phrase “used for communicating real-time operating information” since the Time Horizon is
designated as Real-time Operations.
o
VRF: The RCSDT agrees and has revised the VRF to “Medium.”
o
R2 now R10: The RCSDT believes the requirement as written satisfies your request. The “detection” of failure is the beginning.
o
“Normal”: The RCSDT revised R2, now R10, and deleted “normal.”
Exelon
No
R1. It is not possible to test without identifying, “identify and” is not required. Suggest the requirement say:
The applicable entities shall have primary and backup communication capabilities used for communicating
real-time operating information. The entities shall test and demonstrate system capabilities on a quarterly
basis. Telling someone to “take action” if they identify a failure in their systems is unnecessary. It must be
presumed that an entity will “take action”; otherwise they will be non-compliant with the standard. Allowing an
entity to “identify a substitute” in lieu of taking action to restore within 60 minutes points to the difficulties
inherent in writing prescriptive requirements. The drafting team recognizes all entities may not be able to
restore their capabilities within 60 minutes and therefore provides an alternative. The 60 minute requirement
becomes a guideline, not a requirement under these conditions it is left to auditors to evaluate the technical
and business case that an entity makes for why they can not make the 60 minute deadline.
Response: The RCSDT thanks you for your comment. The RCSDT has revised requirements of COM-001, R1 is now R9, to require an entity to
“designate” an Alternative Interpersonal Communication capability rather than to “identify”. The RCSDT agrees with you that an entity must identify
something in order to be able to designate it or to test it. An Alternative Interpersonal Communication capability is an alternative regardless of
whether one is considering the primary location or a back-up facility. Back-up tends to indicate that it would only be used in the case of the loss of
some other primary capability; that is not the intent. The intent is that an alternative is to be designated and periodically tested to verify its continued
availability and functionality. The alternative capability may or may not be used in normal operations activities. The SDT changed “take action” to
“initiate action” in the requirement and believes the verbiage is needed to identify the start of timing to satisfy “…repair or designate a replacement
Alternative Interpersonal Communications within 2 hours.
Manitoba Hydro
No
R1. Removal of “develop a mitigation plan” and replacing with “take action within 60 minutes” has been done,
this improves the Requirement.
R2. As suggested in a previous SAR, the time line should be delineated further, “if the ICC will not be in
service within 30 minutes, the impacted entities shall be notified within 60 minutes of the detection of the
failure”.
R3. The addition of “dictated by law or otherwise” disclaimers defogs the requirement for Canadian entities
that have varying laws, mandates and obligations: Canada’s basic definition of “Official bilingualism” was
37
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
found as follows: o The federal government must conduct its business and provide services in both official
languages English and French. o The law encourages or mandates lower tiers of government such as
provinces, territories and municipalities to provide services in both official languages. o The law places
obligations on private sectors to provide access to services in both official languages, including that products
be labeled in both English and French. o The government provides support to sectors to encourage and
promote the use of one or the other of the two official languages, for instance English speaking minorities in
Quebec and French Speaking minorities in other provinces. o New Brunswick is the only official bilingual
province and Quebec is officially unilingual (French only).
Response: The RCSDT thanks you for your comment. Thank you for your affirmations with respect to R1 and R3. With respect to R2 (now R10). , it is
the intent of the RCSDT to have notifications performed for outages of 30 minutes or longer within 60 minutes
E.ON U.S.
No
Requiring a 60 minute response to a problem with the Alternative Interpersonal Communication method which
is only tested quarterly doesn’t seem reasonable. One (or more) entities may need to involve IT/telecom
personnel or order parts or material to resolve the problem or agree to the substitute Alternative Interpersonal
Communication method. A 48 hour response requirement would be more appropriate.
Response: The RCSDT thanks you for your comment. Requirement R1, now R9, has been revised to clarify the intent for the entity to “initiate actions
to repair or designate a replacement Alternative Interpersonal Communications within 2 hours.”
Puget Sound Energy
Yes
CECD
No
The requirement to identify an alternative interpersonal communication method within 60 minutes should only
apply if the registered entity only has a single alternative interpersonal communication method in place.
Response: The RCSDT thanks you for your comment. Requirement R1, now R9, has been revised to clarify the intent for the entity to “initiate actions
to repair or designate a replacement Alternative Interpersonal Communications within 2 hours.”
NERC
No
There is a disparity in the timing requirements listed in COM-001. If it is important that a known
communication path interruption be restored in 60 minutes, why would it be necessary to check a path
quarterly only? The drafting team should consider proposing that no concurrent outage of primary and
alternative/backup paths can exceed 5 minutes for voice paths. Additionally, NERC staff believes that data
path concerns still need to be addressed. As written, there is no requirement coverage for ensuring that data
telecommunication paths between entities are adequate and reliable.
Response: The RCSDT thanks you for your comment. The requirement R1, now R9, does not state that a communication path be restored in 60
38
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
minutes but “…shall initiate action to repair or designate a replacement Alternative Interpersonal Communication within 2 hours.” The SDT believes
that it is not feasible to propose that concurrent outages of a primary or backup communication cannot exceed 5 minutes. The SDT believes that IRO010-1 Requirement R1 and specifically R1.4, adopted by the NERC BOT, address your concerns regarding data paths.
Southwest Power Pool
o
No
This standard does want the RC, TOP, and BA to report in R2 if Interpersonal Communication goes down
within 60mins to report it. However, we cannot find a specific requirement that subjects the RC, TOP, and BA
to have Interpersonal Communication in the first place.
Response: The RCSDT thanks you for your comment. To provide better clarity the SDT created more specific requirements to delineate
Interpersonal and Alternative Interpersonal Communication, and applicable entity responsibility.
Hydro-Québec TransEnergie
(HQT)
No
We agree with the revisions made to R1 to remove the requirement for developing a mitigation plan but have
a concern with “...shall take action within 60 minutes to restore the identified alternative or identify a substitute
Alternative Interpersonal Communication Capability”. This can be interpreted to mean completing the repair
within 60 minutes, and hence can present a difficulty for the responsible entity if the spare parts to facilitate a
repair or if a new piece of equipment cannot be obtained within that time frame. More time is needed to fully
repair or replace the lost capability. A suggested rewording is “shall initiate action within 60 minutes to
restore....” Alternatively, the requirement can be revised to require the identification of a substitute Alternative
Interpersonal Communication means within the 60 minute time frame.
Independent Electricity System
Operator
No
We agree with the revisions made to R1 to remove the requirement for developing a mitigation plan but have
a concern with “...shall take action within 60 minutes to restore the identified alternative or identify a substitute
Alternative Interpersonal Communication Capability”. This can be interpreted to mean completing the repair
within 60 minutes, and hence can present a difficulty for the responsible entity if the spare parts to facilitate a
repair or if a new piece of equipment cannot be obtained within that time frame. More time is needed to fully
repair or replace the lost capability. We suggest the wording be revised to “shall initiate action within 60
minutes to restore....” Alternatively, the requirement can be revised to require the identification of a substitute
Alternative Interpersonal Communication means within the 60 minute time frame.
Northeast Power Coordinating
Council
No
We agree with the revisions made to R1 to remove the requirement for developing a mitigation plan but have
a concern with “...shall take action within 60 minutes to restore the identified alternative or identify a substitute
Alternative Interpersonal Communication Capability”. This can be interpreted to mean completing the repair
within 60 minutes, and hence can present a difficulty for the responsible entity if the spare parts to facilitate a
repair or if a new piece of equipment cannot be obtained within that time frame. More time is needed to fully
repair or replace the lost capability. A suggested rewording is "shall initiate action within 60 minutes to
39
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
restore..." Alternatively, the requirement can be revised to require the identification of a substitute Alternative
Interpersonal Communication means within the 60 minute time frame.
Response: The RCSDT thanks you for your comment. The RCSDT agrees and has revised R1, now R9, to clarify the intent for the entity to “intiate
actions to repair or designate a replacement Alternative Interpersonal Communications within 2 hours.”
Western Electricity Coordinating
Council
No
We do not need the definition for alternate, when the definition for interpersonal communication states all
methods of communications. What we think the drafting team is getting at is that we need to test our back up
communication systems.
Response: The RCSDT thanks you for your comment. The RCSDT has revised R1, now R9, and R2, now R10, to clarify that an Alternative
Interpersonal Communication capability be designated and that alternative capability to be tested at least monthly to verify an alternative is available
should the capability normally used be lost. If the test of the Alternative Interpersonal Communication capability is failed, then the entity must initiate
actions within 60 minutes. The RCSDT has intentionally avoided the concept of back-up because back-up could be mistakenly believed to apply only
in back-up facilities or in the case of loss of some unnecessarily designated primary capability.
Midwest ISO Standards
Collaborators
No
We mostly agree with the revisions and thank the drafting team for modifying the requirement to remove the
need for a mitigation plan per our comments from the last posting. However, we do believe that introduction
of a requirement to fix the Alternate Interpersonal Communication within 60 minutes could be a compliance
problem. Our issue is with the time requirement. For example, our stakeholders have experienced situations
with certain communications systems in which a part had to be shipped overnight to fix the communication
system. While we still don’t believe a mitigation plan is necessary in this case, we are concerned that
ordering the part may not be viewed as taking action. Please confirm that SDT believes that the 60 minutes
applies to beginning to repair the Alternative Interpersonal Communication and not to full restoration of the
Alternative Interpersonal Communication. Further, please confirm that identification of a substitute Alternative
Interpersonal Communication could simply mean relying on an already existing and identified secondary or
tertiary Alternative Interpersonal Communication? Similar to our concern identified in Q1, we are concerned
about the clause “used for communicating real-time operating information.” We believe data could be drawn
into the requirement with this clause. Redacting the clause from the requirement will clarify that the
requirement applies to only verbal communications.
NERC Standards Review
Subcommittee
No
We mostly agree with the revisions and thank the drafting team for modifying the requirement to remove the
need for a mitigation plan per our comments from the last posting. However, we do believe that introduction
of a requirement to fix the Alternate Interpersonal Communication within 60 minutes could be a compliance
problem. Our issue is with the time requirement. For example, our stakeholders have experienced situations
with certain communications systems in which a part had to be shipped overnight to fix the communication
system. While we still don’t believe a mitigation plan is necessary in this case, we are concerned that
40
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
ordering the part may not be viewed as taking action. Please confirm that SDT believes that the 60 minutes
applies to beginning to repair the Alternative Interpersonal Communication and not to full restoration of the
Alternative Interpersonal Communication. Further, please confirm that identification of a substitute Alternative
Interpersonal Communication could simply mean relying on an already existing and identified secondary or
tertiary Alternative Interpersonal Communication. Similar to our concern identified in Q1, we are concerned
about the clause “used for communicating real-time operating information.” We believe data could be drawn
into the requirement with this clause. Redacting the clause from the requirement will clarify that the
requirement applies to only verbal communications.
Response: The RCSDT thanks you for your comment. R1, now R9, has been revised to clarify the intent for the entity to “intiate actions to repair or
designate a replacement Alternative Interpersonal Communications within 2 hours.” The verbiage, “used for communicating real-time operating
information” is redacted as you suggest. The SDT believes that Alternative Interpersonal Communication is clearly defined.
Ameren
No
We mostly agree with the revisions. However, we believe that introduction of a requirement to fix the
Alternate Interpersonal Communication (AIC) within 60 minutes could be a compliance problem. The issue is
with the time requirement. It seems illogical to only test the AIC every 90 days but have to replace the
capability in 60 minutes when the IC means is working, It seems more reasonable to have the 60 minutes
apply when both are out.
Similar to our concern expressed in response to Q1 above, we are concerned about the phrase “used for
communicating real-time operating information.” , which could also imply data. We suggest that the team
should remove this phrase from the requirement to clarify that the requirement applies to only verbal
communications.
Response: The RCSDT thanks you for your comment. R1, now R9, has been revised to clarify the intent for the entity to “intiate actions to repair or
designate a replacement Alternative Interpersonal Communications within 2 hours.” Verbiage “used for communicating real-time operating
information” is redacted.
OC Standards Review Group
No
We suggest changing “its” in the first sentence to “their respective” such that the sentence will read, “Each
Reliability Coordinator, Transmission Operator, and Balancing Authority shall identify and test, on a quarterly
basis, “their respective” .......” We also suggest that the risk factor should be “Medium”
Response: The RCSDT thanks you for your comment. The SDT believes that “its” shows appropriate ownership for each respective entity. The risk
factor is revised to “Medium” as suggested.
IRC Standards Review
No
We thank the drafting team for modifying the requirement to remove the need for a mitigation plan per our
comments from the last posting. However, we do believe that introduction of a requirement to fix the
41
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Committee
ISO New England Inc
Question 3 Comment
Alternate Interpersonal Communication within 60 minutes could be a compliance problem. Our issue is with
the time requirement. It is possible that a communications system may require a part that is currently not
available. The requirement should be simply to initiate action to repair the system or to have another
Alternate Interpersonal Communication system available. Further, please confirm that identification of a
substitute Alternative Interpersonal Communication could simply mean relying on an already existing and
identified secondary or tertiary Alternative Interpersonal Communication? To resolve these issues, we
suggest the wording be revised to “shall initiate action within 60 minutes to restore....” Alternatively, the
requirement can be revised to require the identification of a substitute Alternative Interpersonal
Communication means within the 60 minute time frame.
No
We thank the drafting team for modifying the requirement to remove the need for a mitigation plan per our
comments from the last posting. However, we do believe that introduction of a requirement to fix the
Alternate Interpersonal Communication within 60 minutes could be a compliance problem. Our issue is with
the time requirement. It is possible that a communications system may require a part that is currently not
available. The requirement should be simply to initiate action to repair the system or to have another
Alternate Interpersonal Communication system available. Further, please confirm that identification of a
substitute Alternative Interpersonal Communication could simply mean relying on an already existing and
identified secondary or tertiary Alternative Interpersonal Communication? To resolve these issues, we
suggest the wording be revised to “shall initiate action within 60 minutes to restore....” Alternatively, the
requirement can be revised to require the identification of a substitute Alternative Interpersonal
Communication means within the 60 minute time frame.
Response: The RCSDT thanks you for your comment. R1, now R9, has been revised to clarify the intent for the entity to “initiate actions to repair or
designate a replacement Alternative Interpersonal Communications within 2 hours.” The SDT believes that Alternative Interpersonal Communication is
clearly defined.
Pepco Holdings, Inc
No
Why is a requirement for alternate communications given a VRF of High while a requirement (R2) for normal
communications given a VRF of Medium?
Response: The RCSDT thanks you for your comment. The VRF for R1, now R9, has been revised to “Medium.”
Bonneville Power Administration
Yes
Central Lincoln
Yes
42
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Florida Municipal Power Agency
and Some Members
Yes
Northeast Utilities
Yes
PacifiCorp
Yes
PNGC Power (15 member
utilities)
Yes
PPL
Yes
South Carolina Electric and Gas
Yes
US Bureau of Reclamation
Yes
Western Area Power
Administration
Yes
Xcel Energy
Yes
American Transmission
Company
Yes
Question 3 Comment
If the “infrastructure” is defined as we have noted in question 2, then we support the revisions to this
Requirement.
Response: The RCSDT thanks you for your comment.
Electric Market Policy
Yes
Subject to adequate resolution of comments provided for Question 1
Response: The RCSDT thanks you for your comment. Please see response to question1.
ERCOT ISO
No
To follow on the concern noted in Question 1, ERCOT ISO requests that the scope of Interpersonal
Communication be clarified. Without specifically limiting Alternative Interpersonal Communication to verbal
communications, ERCOT ISO considers this requirement to be too broad in that it could potentially
encompass all types of data exchanges and the means for such exchanges.
43
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
ERCOT ISO also has concerns regarding the intent of the 60 minute requirement. Is noting the failure and
identified remedy within 60 minutes sufficient? If not, it may take significantly longer to acquire new equipment
or parts to address a problem thereby making compliance with the 60-minute timeframe practically
impossible. ERCOT ISO recommends that the 60 minute requirement be replaced with “as soon as
practical/possible” to provide the flexibility necessary to cover those types of situations. ERCOT recognizes
that the requirement gives the entity the option of restoring the means within 60-minutes or identifying another
alternative, but to the extent an entity only has two options available and/or identified, the 60-minute
restoration option would practically be the only option. With respect to the third option (i.e. the option if the
first “alternative” fails), the requirement does not state any need to test that communication option. It only
requires the entity to identify the additional alternative. If the intent is that the second alternative needs to be
tested, that should be clarified. If the intent is merely to identify it and then test it on the next quarterly
schedule, that should also be clarified./
Also, the need to “identify” the Alternative ICs for the quarterly test seems pointless. The Alternative ICs
would already be identified; presumably the entity would have established these means in advance of having
to test them. It seems like a pointless exercise to “identify” means already identified. The requirement should
impose an obligation to establish ICs and Alternative ICs, and the testing of those should be an independent
requirement.
With respect to R2, ERCOT recommends clarifying the scope of “impacted entities”. ERCOT ISO believes
that the scope should be left to the discretion of the RC/TOP/BA, or that it should be expressly limited to the
entities that were the subject of the failed communication.
For R3, ERCOT ISO recommends deleting the pre-condition language related to “inter entity” BES “reliability
communications”. This introduces confusion as to the scope and timing of communications under this
requirement, especially where other standards are subject to Reliability Directives. For example, is a
reliability communication a Reliability Directive? If not, what constitutes a reliability communication? The
requirement should simply state that English is required for communications from the relevant functional
entities.
Finally, the risk factor seems inappropriate for the requirement. This is a testing requirement, not real time.
The entity has 60 minutes to correct any issues or have a third option already identified and ready to deploy.
This requirement does not seem to indicate the need for a high risk factor.
Response: The RCSDT thanks you for your comment. R1 is now R9; R2 is now R10; R3 is now R11; R4 is now R7 and R8.
The SDT believes that Webster’s definition of Interpersonal: (being, relating to, or involving relations between persons) clarifies the exclusion of media
dedicated to Telemetering or other data exchange and, SDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
44
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
The SDT believes that the revised Requirements of COM-001-2 now satisfy your concern regarding R1, R2 and R3.
45
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
4 Do you agree with the definition of Reliability Directive (COM-002-2)? If not, please explain in the comment
area.
Summary Consideration:
The comments received regarding the definition of Reliability Directive ranged from the being “to open-ended”
(PPL) to not “flexible” enough (Public Service Enterprise Group Companies). The SDT expected and viewed these
as attempting to reach middle ground.
There were also value added comments such as removing the unnecessary and redundant terms “actual or
expected” from the definition, which the SDT agrees with.
A number of commenter’s expressed a concern about the definition not including three-part communication,
clearly identifying a Reliability Directive at the time of issue, and applying to verbal communications. While valid
concerns, the SDT believes responsibilities should not be imbedded in a definition and, as drafted, the
requirements of COM-002 fully address the identification and verbal concerns.
While outside of the scope of question four, one commenter suggested assigning the COM standard project to
either the OPCPRC or RCSDT projects. The SDT explained the close coordination and collaboration between the
two projects.
Organization
Yes or No
Question 4 Comment
Calpine Corporation
North Carolina Municipal Power
Agency #1
Operating Personnel
Communications Protocols SDT
The OPCP SDT received NERC staff comments to our proposed draft of COM-003-1. In those comments
NERC staff proposed the term “Operating Communication”, defined as “communication with the intent to
change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System.”
The OPCP SDT is accepting this proposed term in the next version of COM-003-1 for posting. Per agreement
reached during the November 17, 2009 joint meeting of the OPCP, RC and RTO SDTs in Charlotte, NC,
46
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 4 Comment
pending the outcome of the industry evaluation of your proposed “Reliability Directive” term, the OPCP SDT
will incorporate the term into COM-003-1 Requirement R?. The OPCP SDT recommends adding the
Transmission Owner to the entities that may issue a Reliability Directive because in many cases (e.g., PJM)
Transmission Owners “operate” the transmission system from local control centers.
The OPCP SDT points out however that the RC SDT have not adhered to scope coordination efforts between
our projects. At the outset of both SDT’s work, the OPCP project would focus upon Requirement R2 of COM002-2 and the RC SDT would focus on Requirement R1 of COM-002-2.
Response: The RCSDT thanks you for your comment. The RCSDT does not believe that the Transmission Owner should be added to the definition as
this would be inconsistent with the Functional Model and the registration process.
Regarding the scope issue: The RCSDT received strong consensus comments on our first posting to make revisions to the original R2. The RCSDT
began making these revisions in response to stakeholder comments.
American Electric Power
No
AEP would recommend that the words "actual or expected" be removed from the definition as unnecessary
and redundant. Since, Emergency: Any abnormal system condition that requires automatic or immediate
manual action to prevent or limit the failure of transmission facilities or generation supply that could adversely
affect the reliability of the Bulk Electric System, then an "expected emergency" is by definition the same as an
emergency. If you already have an 'expected' emergency that causes intervention of some sort, then you are
already in and "emergency." Therefore, you are either in an emergency condition or not in an emergency
condition.
Response: The RCSDT thanks you for your comment. The RCSDT agrees with your comment and we have struck “actual or expected” from the
proposed definition.
Southwest Power Pool
No
By NERC’s Functional Model the RC, BA, TOP, and DP issues directives. (DP to LSE)Reliability Directive - A
communication initiated by a RC, TOP, BA or DP where action by the recipient is necessary to address an
actual or expected Emergency.
Response: The RCSDT thanks you for your comment. The RCSDT notes that, per the Functional Model, a DP may “direct” an LSE to communicate
requests for voluntary load curtailment and not reliability situations:
Item 9 on page 47 of version 5 of the Functional Model: “Directs Load-Serving Entities to communicate requests for voluntary load curtailment.”
The RCSDT will forward this comment to the FMWG for their consideration in revising the language.
Public Service Enterprise Group
No
It is reasonable to require the directing entity to identify which of its communications is a Reliability Directive
47
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Companies
Question 4 Comment
either when first communicated or if questioned by the recipient. Flexibility is the key.
Response: The RCSDT thanks you for your comment. The SDT agrees it might be reasonable however, it is not appropriate to imbed requirements in
definitions.
Also please see Requirement R1 of COM-002-3 (When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as
a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient.) If
the RC, BA, and TOP comply with R1 there is no need for the recipient to question if it is Reliability Directive.
NERC
No
NERC staff proposed the term “Operating Communication” in our comments to Project 2007-02 Operating
Personnel Communications Protocols. Operating Communication would be defined as “communication with
the intent to change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric
System.” This captures all communication that affects BES reliability, not just communication between
function entities and Reliability Coordinators. If the proposed COM-003 is adopted with the definition of
“Operating Communication” and the corresponding three-part communication requirements, this term
“Reliability Directive” is not needed in the COM standard family. However because we cannot pre-judge the
outcome of the changes proposed in Project 2007-02, we must view the proposal here on its own merits. The
proposal herein limits the scope of coverage to emergency situations, a regression from the current coverage
in FERC-approved COM-002 and eliminates a key component of the defense in depth strategy the standards
as a body attempt to provide.
Furthermore, we believe that COM-002 is outside the scope of Project 2006-06 Reliability Coordination and
should properly be addressed by Project 2007-02 Operating Personnel Communications Protocols. The fact
that two teams are addressing aspects of the same standard and requirements is confusing and because the
projects are not linked, there is a real potential to be disjointed if one or the other project modifies its
approach. This could create a gap in reliability coverage. One team should be the primary “owner” of this
issue. Analysis of past Bulk Electric System reliability events has shown that the lack of three-part
communication has been a contributing factor to adverse reliability issues. We believe it is absolutely
imperative that standards concerning all verbal instructions to change or maintain the state of a BES element
must involve three-part communication in order to provide defense-in-depth and reduce human error in these
events.
Response: The RCSDT thanks you for your comment. The RCSDT believes that we are addressing the Blackout Recommendation #26 regarding
“tighten communications protocols, especially during alert and emergency situations”. Our contention is that we have made a good faith effort at
addressing the scope of our SAR and feel that this current position has been validated by stakeholder comments and the NERC Standards Committee
(see November 17, 2009 meeting of RCSDT, OPCPSDT and RTOSDT concerning this issue). We understand the concerns expressed above and fully
support proceeding with the efforts of the OPCP SDT at improving all communications protocols.
However, the RCSDT recognizes that the scope of our proposed revisions to COM-002 is limited to Emergency situations only. The RCSDT feels that
48
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 4 Comment
the concept of a Reliability Directive is an important tool for RC, BA and TOP to maintain reliability and that the revisions are consistent with parts of
the directives in FERC Order 693. The work of the RCSDT along with the OPCPSDT, as currently recognized, will cover the original intent of COM-002
and still provide a “defense in depth strategy”. Stakeholder requests and consensus appears to have been achieved with respect to the definition of
Reliability Directive and the requirements that the RCSDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving
stakeholder consensus for their proposed requirements in COM-003.
Western Electricity Coordinating
Council
No
No, we think IRO 001 R3 covers this more effectively and may be expanded to include transmission operators
and balancing authorities. “The Reliability Coordinator shall have clear decision-making authority to act and
to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators,
Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions shall be
taken without delay, but no longer than 30 minutes.”
Response: The RCSDT thanks you for your comment. The revised IRO-001, R3 is to establish the authority of the RC to act or issue Reliability
Directives. It does not identify the protocols under which a Reliability Directive needs to be issued, acknowledged and carried out. This is handled
through the proposed definition as well as the requirements of COM-002.
Manitoba Hydro
No
Reliability Directive is more clearly defined in the FRCC website: ”Reliability Directives are used during times
of emergency or in situations where reliability may be an issue. A Reliability Directive is usually issued to
control or prevent emergency situations. ”Extrapolated from proposed and FRCC: Reliability Directive: An
instruction initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority that is used
during emergencies or reliability issue which will be used to prevent, control or resolve the situation. This
definition makes it clear that it is for reliability issues (Thus Reliability Directive) and clarifies better that this is
to be used to control or prevent emergency situations. The existing proposed definition doesn’t fully infer this.
With the addition of this glossary term, so should the addition of a definition for Operational Directive (though
not used in this requirement). The new items would further compliment and assist each other in the
understanding of the two new Glossary terms. From the FRCC website: ”Operational Directives are issued by
System Operators when it is necessary to perform a critical function on the BPS, i.e., to manipulate or change
the status of a BES element such as a circuit breaker or substation disconnects. For example, Balancing
Authorities often issue Operational Directives to Generator Operators to raise or lower the MW or MVAR
output of generators during the course of balancing load and generation on the BPS. Transmission Operators
often issue Operational Directives to substation operators to change the status of voltage control devices or
clearing BPS substation equipment or transmission lines for routine maintenance, etc”. Extrapolated from
proposed and FRCC: Operational Directive: An instruction initiated by a Transmission Operator or Balancing
Authority that is used to perform planned or routine critical functions on the Bulk Power System.
Response: The RCSDT thanks you for your comment. The RCSDT believes that our proposed definition of Reliability Directive along with the existing
49
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 4 Comment
definition of Emergency address all of the concepts that you suggest.
The comments regarding Operational Directive are more suited to the work of the OPCP SDT as they are developing requirements along this line. We
will forward your comment to that team for their consideration.
Midwest ISO Standards
Collaborators
No
The combination of the COM-002-3 standard and the definition of Reliability directive do not clearly specify
that the communication is verbal and between only two responsible entities. Otherwise, the communication
could be considered a blast call, written correspondence or conversation between operators within the same
responsible entity. We believe that the Reliability Directive definition should be: “A verbal communication
initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority to another responsible
entity where action by the recipient is necessary to address an actual or expected emergency and the RC,
TOP or BA operator clearly identifies in the communication that this is a Reliability Directive.”
NERC Standards Review
Subcommittee
No
The combination of the COM-002-3 standard and the definition of Reliability directive do not clearly specify
that the communication is verbal and between only two responsible entities. Otherwise, the communication
could be considered a blast call, written correspondence or conversation between operators within the same
responsible entity. We believe that the Reliability Directive definition should be: “A verbal communication
initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority to another registered
entity where action by the recipient is necessary to address an actual or expected emergency and the RC,
TOP or BA operator clearly identifies in the communication that this is a Reliability Directive.”
Response: The RCSDT thanks you for your comment. First issue: verbal communication: The intent of the definition is to not preclude text or other
forms of communication for issuing Reliability Directives. However, entities are still obligated to comply with the requirements of COM-002.
Second issue: “to another registered entity”: The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Adding this verbiage is not appropriate.
Third issue: By adding “clearly identifies in the communication that this is a Reliability Directive”, we would have added a requirement to the
definition. This is better included in the requirements rather than the definition.
We Energies
No
The measures of COM-002-3 imply verbal one-to one communication which needs to be clear within the
definition. Recommend replacing “A communication” with the draft defined term “Interpersonal
Communication” assuming it gets approved.
Response: The RCSDT thanks you for your comment. The intent of the definition and requirements of COM-002 is to not preclude text or other forms
of communication to issue Reliability Directives. However, entities are still obligated to comply with the requirements of COM-002. Interpersonal
Communications is a medium rather than a protocol or message.
50
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
PPL
No
Question 4 Comment
The proposed definition is too open-ended especially since this definition will be used in other standards.
Limiting the application of the standard to announced Reliability Directives in the definition itself will ensure
only announced Reliability Directives are covered by this standard and other standards.
Response: The RCSDT thanks you for your comment. Including the language that you suggest would impose a requirement within the definition.
Potential use of the definition in other requirements would have to be reconciled with COM-002 requirements through the standard development
process.
E.ON U.S.
No
The term “Interoperability Communication” has been proposed and defined in COM-003 (Project 2007-02),
but, the term and definition have not been finalized. Is a “Reliability Directive” communication different from, a
subset of, or related to Interoperability Communication? The definition of Reliability Directive should
recognize and clarify the linkage to Interoperability Communication.
Response: The RCSDT thanks you for your comment. The RCSDT believes that we are addressing the Blackout Recommendation #26 regarding
“tighten communications protocols, especially during alert and emergency situations” in our proposed definition and requirements for COM-002. The
RCSDT feels that the concept of a Reliability Directive is unique and an important tool for the RC, BA and TOP to maintain reliability. The proposed
definition and revisions to COM-002 are consistent with parts of the directives in FERC Order 693. The work of the RCSDT and the OPCPSDT (Project
2007-02) compliment each other and will be coordinated.
Southern Company Services
No
This definition is not needed with the way that the requirements of the standard are written. This definition
used with the definition of Emergency could be interpreted to include such routine operations as turning on
capacitor banks and next day planning. Reliability Directive: A communication initiated by a Reliability
Coordinator, Transmission Operator or Balancing Authority to an entity inside their Reliability, Transmission,
or Balancing Areas where action outside of normal operating practices by the recipient is necessary to
address an actual or expected Emergency or when an action is identified as a reliability directive.
Response: The RCSDT thanks you for your comment. The RCSDT believes that the proposed definition of Reliability Directive, along with the existing
definition of Emergency, provides the heightened awareness that is the goal of the standard and it comports with the directives of Order 693.
Ameren
No
We believe that a reference in the question is to COM-002-3 and not -2. The definition of Reliability directive
is not clear to indicate that it only applies to verbal communications. We suggest the definition should be: “A
verbal communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority to
another responsible entity where action by the recipient is necessary to address an actual or expected
emergency and the RC, TOP or BA operator clearly identifies in the communication that this is a Reliability
Directive.”
51
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 4 Comment
Response: The RCSDT thanks you for your comment. The question does reference COM-002-3 as suggested. First issue: verbal communication:
The intent of the definition is to not preclude text or other forms of communication for issuing Reliability Directives. However, entities are still
obligated to comply with the requirements of COM-002.
Second issue: “to another registered entity”: The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Adding this verbiage is not appropriate.
Third issue: By adding “clearly identifies in the communication that this is a Reliability Directive”, we would have added a requirement to the
definition. This is better included in the requirements rather than the definition.
Hydro-Québec TransEnergie
(HQT)
No
We believe that the Reliability Directive definition as defined in COM-002-3 should be: “A communication
initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by the
recipient is necessary to address an actual or expected emergency and the RC, TOP or BA operator clearly
identifies in the communication that this is a Reliability Directive.”
Northeast Power Coordinating
Council
No
We believe that the Reliability Directive definition as defined in COM-002-3 should be: “A communication
initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by the
recipient is necessary to address an actual or expected emergency and the RC, TOP or BA operator clearly
identifies in the communication that this is a Reliability Directive.”
IRC Standards Review
Committee
No
We believe that the Reliability Directive definition should be: “A communication initiated by a Reliability
Coordinator, Transmission Operator, or Balancing Authority where action by the recipient is necessary to
address an actual or expected emergency and the RC, TOP or BA operator clearly identifies in the
communication that this is a Reliability Directive.”
ISO New England Inc
No
We believe that the Reliability Directive definition should be: “A communication initiated by a Reliability
Coordinator, Transmission Operator, or Balancing Authority where action by the recipient is necessary to
address an actual or expected emergency and the RC, TOP or BA operator clearly identifies in the
communication that this is a Reliability Directive.”
Response: The RCSDT thanks you for your comment. First issue: verbal communication: The intent of the definition is to not preclude text or other
forms of communication for issuing Reliability Directives. However, entities are still obligated to comply with the requirements of COM-002.
Second issue: “to another registered entity”: The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Adding this verbiage is not appropriate.
Third issue: By adding “clearly identifies in the communication that this is a Reliability Directive”, we would have added a requirement to the
52
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 4 Comment
definition. This is better included in the requirements rather than the definition.
FirstEnergy
No
We believe that this standard should be either handed to the OPCPSDT (Project 2007-02) or the OPCPSDT
should hand over the COM-003-1 standard to this RCSDT (Project 2006-06); and then COM-002 and COM003 should be merged. For further explanation of our suggestions, see our comments in Question #8.
Response: The RCSDT thanks you for your comment. The RCSDT feels that the concept of a Reliability Directive is an important tool for RC, BA and
TOP to maintain reliability and that the revisions are consistent with parts of the directives in FERC Order 693. The work of the RCSDT along with the
OPCPSDT, as currently recognized, will cover the original intent of COM-002 and still provide a “defense in depth strategy” as suggested by the NERC
comment. Stakeholder requests and consensus appears to have been achieved with respect to the definition of Reliability Directive and the
requirements that the RCSDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving stakeholder consensus for their
proposed requirements in COM-003. Merging of the two standards is a work in progress and will ultimately be decided by stakeholder consensus.
Independent Electricity System
Operator
No
We suggest the Reliability Directive definition be modified as follows to further clarify the communication
protocol: “A communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing
Authority and made clear by the initiating entity that this is a Reliability Directive which requires action by the
recipient to address an actual or expected Emergency.”
Response: The RCSDT thanks you for your comment. The RCSDT believes that your suggested revision would impose a requirement within the
definition.
Duke Energy
No
We think that Requirement R1 should be folded into the definition, and R1 deleted. Also delete the Measure
and VSL. Suggested rewording of the definition: Reliability Directive: A communication initiated by a
Reliability Coordinator, Transmission Operator, or Balancing Authority, and identified as a Reliability Directive
to the recipient, where action by the recipient is necessary to address an actual or expected Emergency.
Response: The RCSDT thanks you for your comment. The RCSDT believes that your suggested revision would impose a requirement within the
definition.
Bonneville Power Administration
Yes
CECD
Yes
Central Lincoln
Yes
53
Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Exelon
Yes
Florida Municipal Power Agency
and Some Members
Yes
Northeast Utilities
Yes
OC Standards Review Group
Yes
PacifiCorp
Yes
Pepco Hodlings, Inc
Yes
PNGC Power (15 member
utilities)
Yes
Puget Sound Energy
Yes
South Carolina Electric and Gas
Yes
US Bureau of Reclamation
Yes
Xcel Energy
Yes
American Transmission
Company
Yes
Question 4 Comment
Errata comment: It is COM-002-3.
Response: The RCSDT thanks you for your comment. It is COM-002-3.
ITC Holdings
Yes
None
Response: The RCSDT thanks you for your comment.
Western Area Power
Yes
Suggested wording to add clarity: “A communication initiated by a Reliability Coordinator, Transmission
Operator, or Balancing Authority requiring action by the recipient to address an actual or expected
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Administration
Question 4 Comment
Emergency.”
Response: The RCSDT thanks you for your comment. The RCSDT believes that your proposed revision does not materially add clarity to the
proposed definition. Stakeholders generally concur with our proposed definition.
Electric Market Policy
Yes
While I technically agree with the definition, I think it should be expanded to state that a directive that meets
this definition must be clearly identified as such by the issuing BA, RC or TOP. In other words, action is
mandatory on the recipient’s part only if the issuing party clearly states “this is a Reliability Directive”. In many
organized markets, participants (particularly LSE, GOP and PSE) are required to follow instructions only if an
Emergency is declared. This concept has historically been used throughout this industry although such use
may have been implicit.
Response: The RCSDT thanks you for your comment. Your concerns are covered by the requirement R1 of COM-002 which states:
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient.
A requirement can not be imposed by a definition.
ERCOT ISO
No
ERCOT ISO is concerned about defining Reliability Directive in terms of “expected” emergencies. Obviously
all relevant entities will operate to avoid emergency situations. However, the term “expected” is vague and
ambiguous, and, as such, is open to subjective interpretation thereby creating uncertainty for regulated
entities. The definition should put entities on clear notice as to when they have to comply with the relevant
requirements. The only way to provide that certainty is to establish a clear, identifiable trigger. To accomplish
this, the definition should be limited to actual emergencies. Actual emergencies are specifically defined, not
subjective, and lend themselves to demonstration of compliance in an audit. The definition of Emergency
lends itself to alignment with specific circumstances that clearly indicate to a regulated entity that it must use
Reliability Directives and follow the rules that apply to such directives – “expected emergencies” do not.
The requirement should also be revised to clarify that Reliability Directives only apply to communications
between separate entities in distinct locations and do not apply to employees of the same company
communicating in person in the same location – e.g. a control center.
Response: The RCSDT thanks you for your comment. We have removed the words “actual or expected” from the definition. The way that COM-002 is
crafted, it focuses on functional entity communication between and among functions. Face-to-face communication of Reliability Directives are subject
to the requirements of COM-002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support compliance.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
5 Do you agree with the revisions to the Requirements in COM-002-3 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Summary Consideration: The bulk of the comments were about the VSL. The SDT agreed and has deleted the
Severe VSL and moved the High VSL to Severe. We believe that there are two possible actions within the
requirement and failure to perform either warrants a Severe VSL
Several commenters’s expressed concern about three-part communication. The SDT believes that as drafted with
the issue, repeat back, and acknowledgement three-part communication is covered.
There was one commenter suggesting the addition of the DP to the applicability The RCSDT notes that, per the
Functional Model, a DP may “direct” an LSE to communicate requests for voluntary load curtailment and not
reliability situations: Item 9 on page 47 of version 5 of the Functional Model: “Directs Load-Serving Entities to
communicate requests for voluntary load curtailment.” Furthermore, The RCSDT will forward this comment to
the FMWG for their consideration in revising the language.
While outside of the scope of question five, one commenter suggested assigning the COM standard project to
either the OPCPRC or RCSDT projects. The SDT explained the close coordination and collaboration between the
two projects.
Organization
Yes or No
Question 5 Comment
Calpine Corporation
North Carolina Municipal Power
Agency #1
Public Service Enterprise Group
Companies
We Energies
Xcel Energy
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Operating Personnel
Communications Protocols SDT
Question 5 Comment
The OPCP SDT offers the following Requirements language that addresses a Three-Part Communication
Protocol. (It is comprised of two primary Requirements and contains a footnote):
R_. Each Reliability Coordinator, Balancing Authority, Transmission Operator, and Transmission Owner that
issues a Reliability Directive during verbal Operating Communications shall employ three-part Communication
Protocol to ensure that the receiving party has repeated the communication, and shall verbally confirm the
communication to be correct or reinitiate the communication until a correct response is given by the recipient.
An exception is allowed for Reliability Directives that are issued via “All-Call”, during which the initiator shall
ensure that all the receiving parties have positively acknowledged receipt of message rather than verbally
repeating the message. [Violation Risk Factor: High][Time Horizon: Real-time Operations]
R_. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission Operator,
Generator Operator, Transmission Service Provider, Load Serving Entity, Distribution Provider and
Purchasing-Selling Entity that receives a Reliability Directive during verbal Operating Communications shall
employ three-part communication protocol [footnote 1] to repeat the communication back to the initiator and
await verbal confirmation from the initiator. An exception is allowed for the recipient of an “All-Call” Reliability
Directive to acknowledge receipt of the message and is responsible to contact initiator if message is not
understood rather than verbally repeating the message. [Violation Risk Factor: High][Time Horizon: Real time]
Footnote 1: A Communication Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly (not necessarily verbatim) to the party that initiated
the communication by the second party that received the communication, and the same information is
verbally confirmed to be correct by the party who initiated the communication.
Response: The RCSDT thanks you for your comment. The RCSDT believes that we are addressing the Blackout Recommendation #26 regarding
“tighten communications protocols, especially during alert and emergency situations” in our proposed definition and requirements for COM-002. We
have not precluded issuance of Reliability Directives by non-verbal means and the requirements of proposed COM-002 would apply. Respecting the
importance of Reliability Directives during Emergency situations, the RCSDT does not believe that exceptions to the clear, concise three part
communications indicated in COM-002 are appropriate regardless of the medium used to communicate. In addition, the current format of the
requirements provides more effective way to measure compliance.
Ameren
No
(1) As stated in #4 above, the definition of Reliability Directive is not clear. (2) The VSLs for R3 appear to
have some redundancy. (3) Also in R3, the phrase regarding R2 should be changed to “(as described in R2,
above)”
Response: The RCSDT thanks you for your comment.
1) Please see response to question 4.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
2) The RCSDT concurs. We have deleted the Severe VSL and moved the High VSL to the Severe category.
3) We have revised the phrase to be consistent with the verbiage in R2 as follows: “per Requirement R2” which meets the intent of your comment “as
described”.
Southwest Power Pool
No
1) By NERC’s Functional Model the RC, BA, TOP, and DP issues directives. (DP to LSE)COM-002-3 R2...
the recipient of a Reliability Directive issued per Requirement R1, shall repeat the intent of the Reliability
Directive back to the issuer of the Reliability Directive.
2) COM-003-1 R5... shall use Three-part Communications when issuing a directive during verbal
Interoperability Communications. Implementation Plan for COM-002-3 states R2 will stay, for COM-003-1
states that COM_002-3 R2 will go away. The two requirements don’t agree with each other, COM-002-3 R2
wants the Intent repeated back, where COM-003-1 R5 per the Three-part Communication definition “...the
information is repeated back correctly to the party that initiated the communication”.
Response: The RCSDT thanks you for your comment. 1) The RCSDT notes that, per the Functional Model, a DP may “direct” an LSE to communicate
requests for voluntary load curtailment and not reliability situations:
Item 9 on page 47 of version 5 of the Functional Model: “Directs Load-Serving Entities to communicate requests for voluntary load curtailment.”
The RCSDT will forward this comment to the FMWG for their consideration in revising the language.
2) The RCSDT believes that we are addressing the Blackout Recommendation #26 regarding “tighten communications protocols, especially during
alert and emergency situations” in our proposed definition and requirements for COM-002. The RCSDT feels that the concept of a Reliability Directive
is an important tool for RC, BA and TOP to maintain reliability and that the revisions are consistent with parts of the directives in FERC Order 693. The
work of the RCSDT along with the OPCPSDT, as currently recognized, will cover the original intent of COM-002 and still provide a “defense in depth
strategy” as suggested by the NERC comment. Stakeholder requests and consensus appears to have been achieved with respect to the definition of
Reliability Directive and the requirements that the RCSDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving
stakeholder consensus for their proposed requirements in COM-003. Merging of the two standards is a work in progress and will ultimately be decided
by stakeholder consensus.
Central Lincoln
No
Consider the following example. Director calls Directee. Telephone is answered by the Directee’s receptionist.
Director states that he has a Reliability Directive, and proceeds to deliver it. Receptionist manages to parrot
the directive, but has no clue what is being asked. Director confirms receptionist has parroted the directive
accurately. Both parties have met the requirements (avoiding a high risk, severe violation), but the three way
conversation only wasted the time of both parties and delayed the performance of the directive. The Director
should be required to attempt to reach someone with the authority and understanding needed to carry out the
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
directive.
Response: The RCSDT thanks you for your comment. The requirements of the standard do not consider how staffing at a particular functional entity
is achieved. This is covered in the PER standards. It is incumbent on the registered entity to comply with the requirements of the COM-002 standard
as well as all other requirements, some of which will likely be violated in the example above.
CECD
No
For R3, the drafting team should clarify that if a directive is reissued due to a misunderstanding the receiving
party should repeat the reissued directive so that the RC, BA or TOP can verify that the directive is
understood correctly.
Response: The RCSDT thanks you for your comment. The RCSDT believes that this situation is covered by R2.
Duke Energy
No
o It is not clear whether Requirements R2 and R3 are intended to apply to other than verbal Reliability
Directives. We have difficulty envisioning how “repeat back” and “acknowledge the response” would be
expected to work with electronic communications.
o Delete the phrase “issued per Requirement R1” from R2, since R1 should be deleted per our Comment #4
above.
o Revise R3 as follows, to conform to our proposed revised definition in Comment #4 above: “Each Reliability
Coordinator, Transmission Operator, and Balancing Authority that initiates a Reliability Directive shall
acknowledge the response from the recipient as correct, or reissue the Reliability Directive to resolve any
misunderstandings.”
o We believe that only 2 VSLs are appropriate for R3. o Lower - The responsible entity issued a Reliability
Directive, but did not acknowledge that the recipient repeated the intent of the Reliability Directive correctly.
o Severe - The responsible entity issued a Reliability Directive and failed to reissue the Reliability Directive to
resolve any misunderstandings when the intent of the Reliability Directive was not repeated correctly by the
recipient.
Response: The RCSDT thanks you for your comment. The requirements of COM-002 do not preclude non-verbal issuance of directives. It is
incumbent on the entity to ensure compliance with the requirements
R2: We have not retired R1 (see response to Q4) and therefore do not feel this is an appropriate revision.
R3: See response to question 4. The RCSDT believes that R3 is appropriate as written.
VSL: The RCSDT has deleted the Severe VSL and moved the High VSL to Severe. We believe that there are two possible actions within the
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
requirement and failure to perform either warrants a Severe VSL.
Exelon
No
Please clarify R2 to 'repeat back' a Directive; the definition of Directive does not distinguish between verbal
and other methods of communication. Is an electronic response to a verbal or non-verbal Directive allowed?
Response: The RCSDT thanks you for your comment. The requirements of COM-002 do not preclude non-verbal issuance of directives. It is
incumbent on the entity to ensure compliance with the requirements.
Manitoba Hydro
No
R2 requires “recipient to repeat back” and R3 requires “RC, TOP, BA to acknowledge”. This procedure is
NOT identified as Three Part Communication which in fact is. Three Part Communication should be a
common theme for all entities, including RC’s. So why not use the same or similar Requirement as used in
COM-002-2 R2 Three-Part Communication.
Response: The RCSDT thanks you for your comment. The concept of three part communication is in existing COM-002-2, R2 and a definition for the
term is being proposed by the OPCP SDT. The RCSDT feels that the concept of a Reliability Directive is a unique and important tool for RC, BA and
TOP to maintain reliability that is separate from that effort. The requirements of COM-002 are explicit for Reliability Directives and are consistent with
parts of the directives in FERC Order 693. Stakeholder requests and consensus appears to have been achieved with respect to the definition of
Reliability Directive and the requirements that the RCSDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving
stakeholder consensus for their proposed requirements in COM-003. Merging of the two standards is a work in progress and will ultimately be decided
by stakeholder consensus.
E.ON U.S.
No
See comment to question 8.
Response: The RCSDT thanks you for your comment. Please see response to question 8.
NERC
No
See response to Question 4.
Response: The RCSDT thanks you for your comment. Please see response to question 4.
PPL
No
Suggest removing Purchasing-Selling Entity from the standard as a PSE does not receive Reliability
Directives from a BA, RC, or TOP.
Response: The RCSDT thanks you for your comment. Prior stakeholder comments (during previous postings of this standard) indicated that PSE
should be an applicable entity.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Independent Electricity System
Operator
Yes or No
No
Question 5 Comment
The High and Severe VSLs for R3 appear to be the same. We suggest to remove the High VSL and change
the Severe VSL to: “The responsible entity issued a Reliability Directive, but did not acknowledge that the
recipient in R2 repeated the intent of the Reliability Directive correctly OR resolve any misunderstandings
when the intent of the Reliability Directive was not repeated correctly by the recipient.”
Response: The RCSDT thanks you for your comment. We have deleted the Severe VSL and moved the High VSL to the Severe category. We believe
this meets the intent of your comment.
South Carolina Electric and Gas
No
The SDT needs to evaluate the redundancy associated with COM-003-1 Req 5 and COM-002-3 Req 2&3.
Response: The RCSDT thanks you for your comment. The RSDT does not believe that there is redundancy between the standards. COM-002 relates
only to Reliability Directives while COM-003 deals with other forms of communication.
Hydro-Québec TransEnergie
(HQT)
No
The VSLs for R3 appear to have some redundancy. The Severe VSL and the second condition in the High
VSL appear to be similar or the same. We suggest remove the High VSL, and revise the Severe VSL to:”The
responsible entity issued a Reliability Directive, but did not acknowledge that the recipient in R2 repeated the
intent of the Reliability Directive correctly OR resolve any misunderstandings when the intent of the Reliability
Directive was not repeated correctly by the recipient.”
Northeast Power Coordinating
Council
No
The VSLs for R3 appear to have some redundancy. The Severe VSL and the second condition in the High
VSL appear to be similar or the same. Suggest removing the High VSL, and revise the Severe VSL to:”The
responsible entity issued a Reliability Directive, but did not acknowledge that the recipient in R2 repeated the
intent of the Reliability Directive correctly OR resolve any misunderstandings when the intent of the Reliability
Directive was not repeated correctly by the recipient.”
Response: The RCSDT thanks you for your comment. We have deleted the Severe VSL and moved the High VSL to the Severe category. We believe
this meets the intent of your comment.
PNGC Power (15 member
utilities)
No
There is a chance that a reliability directive given to a smaller entity will be taken by a receptionist or
answering service. Requirement R2 should be more specific about contacting an operational authority
directly to relay reliability directives.
Response: The RCSDT thanks you for your comment. The requirements of the standard do not consider how staffing at a particular functional entity
is achieved. This is covered in the PER standards. It is incumbent on the registered entity to comply with the requirements of the COM-002 standard
as well as all other requirements, some of which will likely be violated in the example above.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
Midwest ISO Standards
Collaborators
No
We agree with most of this standard and the apparent intent. However, there are some specific issues. For
instance, measurement of compliance to R1 could be challenging. As the VSL is written, it would appear the
compliance auditor could judge if a Reliability Directive should have been issued. The VSL language that is
problematic is “The responsible entity that required actions to be executed”. Who determines that actions
were required? One could argue that failure to identify a communication as a Reliability Directive means that
actions weren’t required but it is doubtful the compliance authorities would take this approach. Thus, there
would appear to be great judgment left to the compliance auditor in determining if a Reliability Directive
should have been issued. The combination of the COM-002-3 standard and the definition of Reliability
directive do not clearly specify that the communication is verbal and between only two responsible entities.
Otherwise, the communication could be considered a blast call, written correspondence or conversation
between operators within the same responsible entity. We have offered proposed modifications to the
definition of Reliability Directive in Q5 to solve this issue. Alternatively, the issue could be addressed by
modifying the requirements. The VSLs for R3 appear to have some redundancy. The Severe VSL and the
second condition in the High VSL appear to be similar or the same.
NERC Standards Review
Subcommittee
No
We agree with most of this standard and the apparent intent. However, there are some specific issues. For
instance, measurement of compliance to R1 could be challenging. As the VSL is written, it would appear the
compliance auditor could judge if a Reliability Directive should have been issued. The VSL language that is
problematic is “The responsible entity that required actions to be executed”. Who determines that actions
were required? One could argue that failure to identify a communication as a Reliability Directive means that
actions weren’t required but it is doubtful the compliance authorities would take this approach. Thus, there
would appear to be great judgment left to the compliance auditor in determining if a Reliability Directive
should have been issued.
The combination of the COM-002-3 standard and the definition of Reliability directive do not clearly specify
that the communication is verbal and between only two responsible entities. Otherwise, the communication
could be considered a blast call, written correspondence or conversation between operators within the same
responsible entity. We have offered proposed modifications to the definition of Reliability Directive in Q5 to
solve this issue. Alternatively, the issue could be addressed by modifying the requirements.
The VSLs for R3 appear to have some redundancy. The Severe VSL and the second condition in the High
VSL appear to be similar or the same.
Response: The RCSDT thanks you for your comment.
R1: The VSL is a compliance tool that is ONLY used after a violation of the requirement has been determined. COM-002 does not provide guidance on
when to issue a Reliability Directive, only that, when they issue Reliability Directives, they comply with the requirements of COM-002. Proposed IRO-
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
001-2, R1 covers the issue of conditions that merit issuing a Reliability Directive.
Blast Call: The intent of the definition is to not preclude text or other forms of communication for issuing Reliability Directives. However, entities are
still obligated to comply with the requirements of COM-002.
VSL: We have deleted the Severe VSL and moved the High VSL to the Severe category. We believe this meets the intent of your comment.
FirstEnergy
No
We believe that this standard should be either handed to the OPCPSDT (Project 2007-02) or the OPCPSDT
should hand over the COM-003-1 standard to this RCSDT (Project 2006-06); and then COM-002 and COM003 should be merged. For further explanation of our suggestions, see our comments in Question #8.
Response: The RCSDT thanks you for your comment. The RCSDT feels that the concept of a Reliability Directive is an important tool for RC, BA and
TOP to maintain reliability and that the revisions are consistent with parts of the directives in FERC Order 693. The work of the RCSDT along with the
OPCPSDT, as currently recognized, will cover the original intent of COM-002 and still provide a “defense in depth strategy” as suggested by the NERC
comment. Stakeholder requests and consensus appears to have been achieved with respect to the definition of Reliability Directive and the
requirements that the RCSDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving stakeholder consensus for their
proposed requirements in COM-003. Merging of the two standards is a work in progress and will ultimately be decided by stakeholder consensus.
American Transmission
Company
Yes
Bonneville Power Administration
Yes
Electric Market Policy
Yes
Florida Municipal Power Agency
and Some Members
Yes
IRC Standards Review
Committee
Yes
ISO New England Inc
Yes
OC Standards Review Group
Yes
PacifiCorp
Yes
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Pepco Hodlings, Inc
Yes
Southern Company Services
Yes
US Bureau of Reclamation
Yes
Western Area Power
Administration
Yes
Western Electricity Coordinating
Council
Yes
Puget Sound Energy
No
Question 5 Comment
Under the current proposed language of R2, it appears possible that a recipient of a Reliability Directive not
identified as such may still be held responsible for failing to comply with R2, because the word “per” has
several meanings. While those meanings do include “in accordance with”, it would be clearer to simply use
that phrase. As a result, recommend the replacement of the phrase “issued per” with “identified as such in
accordance with”.
Response: The RCSDT thanks you for your comment. The RCSDT believes that the suggested revision does not provide additional clarity to the
requirements.
ITC Holdings
Yes
None
Northeast Utilities
Yes
Support the intent of the changes. However, it is unclear if the mechanics of R1 require the initiator to
actually state “This is a Reliability Directive ...”.
Response: The RCSDT thanks you for your comment. The RCSDT intends for such a statement to be made. Using that exact verbiage in a
requirement is too prescriptive and we leave the exact language up to the issuer as long as they identify it as a Reliability Directive.
American Electric Power
Yes
Why is the term “three part communications” not used in this set of requirements?
Response: The RCSDT thanks you for your comment. While the requirements embody three part communications, the RCSDT believes it is clearer to
have explicit requirements for each part of the process that requires a specific action.
ERCOT ISO
No
R1: ERCOT ISO recommends that the requirement be revised to simply state that the entity has to identify
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
when it is a reliability directive, such that it reads as follows:
R1. When applicable, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify
the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
The deleted language introduces subjectivity and is unnecessary. The use of the defined term implicitly
determines when Reliability Directives are issued and it is unnecessary to impose the condition precedent of
identifying an action as Reliability Directive. This is unnecessary and just creates confusion.
R2: ERCOT ISO recommends removal of “the intent” such that it reads as follows:
R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat the Reliability Directive back to the issuer of the Reliability Directive. [Violation Risk Factor: High][Time
Horizon: Real-Time]
ERCOT ISO believes using “intent” in this requirement was intended to mitigate the practical fact that it is
difficult to repeat, verbatim, a directive. However, use of the word intent could introduce confusion. A
directive will require certain actions to accomplish a specific purpose or to solve a specific problem. Thus, the
intent of a directive has two components to the intent; the first is the specific actions to be taken and the
second is the underlying reason for those actions. The recipient will obviously be privy to the former, but
perhaps not the latter. To remove any ambiguity as to whether intent means the actions or the issue to be
solved by such actions, the word should be removed. ERCOT believes there is little risk that an auditor will
issue a violation if a repeated directive is not verbatim, but reflects the actions to be taken pursuant to the
directive.
Further, ERCOT ISO recommends working closely with the Operating Personnel Communication Protocol
SDT to address all-calls as exceptions. It is practically unreasonable to require multiple recipients on the
same communication to repeat the directive back. In fact, it is counterproductive because the time it takes to
do that would delay the recipients from taking the needed reliability action(s).
ERCOT recommends the
following language to address “all-calls”:
(COM-003) R2. Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive shall repeat the Reliability Directive back to the issuer of the
Reliability Directive. An exception is allowed for Reliability Directives that are issued via “All-Call”
communications. For All-Calls, the entity issuing the directive shall require recipients to acknowledge receipt
of message.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
R3: ERCOT ISO recommends that R3 be combined with R2. Regardless of whether it is combined with R2,
the identification precondition should be removed such that the requirement reads as follows:
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a Reliability
Directive shall acknowledge the response from the recipient of the Reliability Directive in R2 as correct or
reissue the Reliability Directive to resolve any misunderstandings. [Violation Risk Factor: High][Time Horizon:
Real-Time]
The identification pre-condition is unnecessary – again, the defined term is self-executing in terms of
situational application. Imposition of this superfluous language merely creates the potential for confusion.
M1: ERCOT ISO recommends removing “required actions to be taken” language for the same reason this
pre-condition does not make sense in the requirement, as described above.
M3: ERCOT ISO recommends that “Directive” be replaced with “Reliability Directive” because Directive is not
the full defined term.
Response: The RCSDT thanks you for your comment.
R1: The RCSDT believes that the requirement, as written is clear and disagrees that it introduces subjectivity. COM-002 does not provide guidance on
when to issue a Reliability Directive, only that, when they issue Reliability Directives, they comply with the requirements of COM-002. We feel that
adding the phrase “When applicable” adds subjectivity to the requirement.
R2: Without the words “the intent”, the requirement could be interpreted to mean a verbatim repeat of the Reliability Directive. The RCSDT does not
intend for this to be the case and believes that the requirement, as written, is clear and provides sufficient flexibility to meet the requirement. The
requirements of COM-002 do not preclude non-verbal (e.g. “all calls”) issuance of directives regardless of the medium. It is incumbent on the entity to
ensure compliance with the requirements. The RCSDT feels that the concept of a Reliability Directive is an important tool for RC, BA and TOP to
maintain reliability and that the revisions are consistent with parts of the directives in FERC Order 693. The work of the RCSDT along with the
OPCPSDT, as currently recognized, will cover the original intent of COM-002 and still provide a “defense in depth strategy” as suggested by the NERC
comment.
R3: The RCSDT believes that the steps in R2 and R3 are separate and distinct actions that require separate requirements. Otherwise, we would have
compound requirements. We concur with your suggested edit to R3.
M1; We did not make the revision to R1 and therefore M1 is sufficient as written.
M3: We have revised M3 as suggested and to conform to revised R3.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
6 Do you agree with the use of the defined term “Reliability Directive” in revisions to the Requirements in
IRO-001-2 as shown in the posted Standard and Implementation Plan? If not, please explain in the
comment area.
Summary Consideration: The comments regarding question six ranged from small entities being excluded to if
regulatory or statutory requirements covers NERC standards. The SDT addressed these by noting registration is
not in the SDT scope and NERC’s general council should be contacted for regulatory issues.
A few commenter’s expressed concern with the VSL for R2 and one suggested the words "per Requirement 2,"
should be added. The SDT believes the phrase “per Requirement 2” is not necessary as a VSL is only applied
AFTER a compliance violation is determined.
Value added comments such as a concern of the use of the word “threat” as it can be defined as cyber-related
and suggested replacing “Operating Personnel” with “System Operator” were also made. The SDT concurred and
removed the word “threat” and replaced it with “condition” and also made the revision to System Operator.
There were numerous comments regarding the definition of Reliability Directive with multiple wording
suggestions. While slightly out of scope for question six, the SDT expected and viewed these as attempting to
reach middle ground.
Some commenter’s expressed concern over clarify that the RC has three separate actions. The RC can act, direct
others to act, or issue Reliability Directives. The SDT modified R1 to read: ” Each Reliability Coordinator shall take
actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing
Authorities, Generator Operators, Interchange Coordinators and Distribution Providers within its Reliability
Coordinator Area to prevent identified events or mitigate the magnitude or duration of actual events that result
in Adverse Reliability Impacts.”
Note: Based on discussions with FERC staff, the SDT agreed to make the following changes:
IRO-001-2 Requirements R4, R5 and associated Measures and VSLs are moved to IRO-005-4
IRO-001-2 Requirements R6, R7 and associated Measures and VSLs are moved to IRO-002-2
Organization
Yes or No
Question 6 Comment
Calpine Corporation
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
Public Service Enterprise Group
Companies
Operating Personnel
Communications Protocols SDT
FirstEnergy
No Comment
No
Although we agree that a clear definition of Reliability Directive should be included in IRO-001-2, the definition
should be revised per our comments in Question #8.
Response: The RCSDT thanks you for your comment. Please see response to question 8.
North Carolina Municipal Power
Agency #1
No
For IRO-001-2, the VSL for R2 should retain the words "per Requirement 2," because the requirement itself
provides for exceptions to when it is permissible for a directive not to be followed. Requirement 3 then
addresses the required action an entity must take in a case where these exceptions apply. Without these
words, it appears that a VSL of "Severe" may be assigned if a directive isn't followed under any
circumstances.
Response: The RCSDT thanks you for your comment. The phrase “per Requirement 2” is not necessary as a VSL is only applied AFTER a compliance
violation is determined. The requirement provides the exceptions and compliance will be judged based on this.
NERC
No
In principle, NERC staff disagrees with the necessity of defining a term “Reliability Directive.” However, the
principle involved in the standard is valid. The standard needs to ensure that if the Reliability Coordinator
directs an entity to take action that results in an adverse reliability impact, that entity has a chance to raise
valid objection to that action.
Additional clarification is needed to determine if regulatory or statutory requirements covers NERC standards.
One possible solution would be to modify R3 from “its inability to perform” to “its inability or concern to
perform.”
Furthermore, in R4 and R5 the RC is expected to identify “threats” and notify all impacted parties. We have
concerns that “threat” can be defined as cyber-related. Was the standard intended to cover all anticipated
threats, or just transmission/operating issues?
R6 Since Operating Personnel is not a NERC defined term, we suggest replacing “Operating Personnel” with
“System Operator.”
Response: The RCSDT thanks you for your comment.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
“Concern”: We believe that your concern is covered by the “unless such actions would violate safety, equipment, or regulatory or statutory requirements”
statement in R2.
Regulatory: The RCSDT suggests that NERC staff seek input from NERC’s General Counsel in regards to this issue.
R4 and R5: The word threat was not intended to be cyber related. The CIP standards cover cyber “threats”. To that end, we have removed the word
“threat” and replaced it with “condition”. R4, R5 and associated Measures and VSLs are moved to IRO-005-4.
R6: We concur and have made this revision.
OC Standards Review Group
No
In R1, we suggest adding “direct” in the sentence to read: “Each Reliability Coordinator shall act, “direct” or
issue Reliability Directives....” During adverse reliability impact events, system operators should not be
bound by a cumbersome three part communications regime that could prevent prompt responses to the
event. The suggested change would allow for non reliability directives to be issued to correct adverse
reliability impacts.
Response: The RCSDT thanks you for your comment. The RCSDT agrees in principle with adding “direct” to the requirement. In addition, the
requirements of COM-002 should be complied with, especially in such situations. We have revised R1 to state: Each Each Reliability Coordinator
shall take actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing Authorities, Generator
Operators, Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the
magnitude or duration of actual events that result in Adverse Reliability Impacts. To address comments received on R1, we have also revised the
Purpose Statement to: To establish the capability and authority of Reliability Coordinators to direct other entities to prevent Adverse Reliability
Impacts to the Bulk Electric System
Conforming revisions to M1 and the VSLs for R1 were also made.
Southern Company Services
No
Including the requirement of issuing directives every time an action is required by an entity assumes that
entities cannot work in a spirit of cooperation to maintain the reliability of the Bulk Electric System.
Response: The RCSDT thanks you for your comment. To address your concern, we have revised R1 to state: “Each
Reliability Coordinator shall
take actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing Authorities, Generator
Operators, Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the
magnitude or duration of actual events that result in Adverse Reliability Impacts.
To establish the capability and authority of Reliability
Coordinators to direct other entities to prevent Adverse Reliability Impacts to the Bulk Electric System
To address comments received on R1, we have also revised the Purpose Statement to:
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
We Energies
No
IRO-001-2 R1 opens the door for determining if the RC should have issued a Reliability Directive to prevent or
mitigate the magnitude or duration of events that result in Adverse Reliability Impacts which goes beyond the
intention of Emergency. The RC should have any and all options to achieve the required actions, one of
which is a Reliability Directive. Agreed if the RC issues a Reliability Directive it needs to be followed or
notified why it can’t be followed. In IRO-009 ....”the Reliability Coordinator shall have one or more Operating
Processes, Procedures, or Plans that identify actions it shall take or actions it shall direct others to take (up to
and including load shedding) to mitigate the magnitude and duration of” .... Recommend “Each Reliability
Coordinator, in it’s sole discretion, shall take action independently or by others or issue Reliability Directives
for actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, Distribution Providers and Purchasing-Selling Entities within its
Reliability Coordinator Area to prevent or mitigate the magnitude or duration of events that result in Adverse
Reliability Impacts. ”In addition the measures assume the RC only works through others, and others only act
under Directive from the RC and do not allow for operational data to be used to show action was taken like
SCADA logs, or system parameter records for any entity.
The Data Retention is excessive, RC, BA, TOP are on a 3 yr audit cycle, others on a 6yr cycle this is way too
long, recommend one full calendar year plus the current year.
Each Reliability Coordinator shall take
actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing Authorities, Generator Operators,
Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the magnitude or
duration of actual events that result in Adverse Reliability Impacts.
Response: The RCSDT thanks you for your comment. To address your concern, we have revised R1 to state:
To address comments received on R1, we have also revised the Purpose Statement to: To establish the capability and authority of Reliability
Coordinators to direct other entities to prevent Adverse Reliability Impacts to the Bulk Electric System
o
We have revised the data retention section to:
The Reliability Coordinator shall retain its evidence for 90 days for Requirements
R1 and Measures M1.
o
The Transmission Operator, Balancing Authority, Generator Operator, Distribution Provider, Transmission Service Provider,
Purchasing-Selling Entity or Load Serving Entity shall retain its evidence for 90 days for Requirements R2 and R3, Measures M2
and M3.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
American Electric Power
No
Please refer to our response to question #4.
Hydro-Québec TransEnergie
(HQT)
No
Please see our proposed wording change under Q4.
Independent Electricity System
Operator
No
Please see our proposed wording change under Q4.
IRC Standards Review
Committee
No
Please see our proposed wording change under Q4.
Northeast Power Coordinating
Council
No
Please see our proposed wording change under Question 4.
Response: The RCSDT thanks you for your comment.
E.ON U.S.
No
Please see response to Question 4.
See comments to question 4 and question 8.
Response: The RCSDT thanks you for your comment.
Please see response to Question 4 and Question 8.
Ameren
No
See response to #4.
Electric Market Policy
No
See response to Q4
Response: The RCSDT thanks you for your comment.
PNGC Power (15 member
utilities)
No
Please see response to Question 4.
Small non 24/7 entities in WECC should be excluded from these requirements. Not doing so will create a
financial burden for little discernable effect.
Response: The RCSDT thanks you for your comment. It is beyond the scope of the RCSDT to determine registration or compliance issues.
Manitoba Hydro
No
The use of this definition in this requirement appears appropriate at this time, but the definition of Reliability
Directive issue remain the same as identified on Question 4 of this document.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
Response: The RCSDT thanks you for your comment. Please see response to question 4.
Central Lincoln
No
These requirements should be waived in the WECC region, where the RC has stated they will not be
interacting with most of the registered entities.
http://www.bpa.gov/corporate/business/reliability/Docs/2007/PNSC_RE_Data_Letter_2_070723.pdf
Response: The RCSDT thanks you for your comment. It is beyond the scope of the RCSDT to determine registration or compliance issues.
US Bureau of Reclamation
No
This change is problematic in that any automatic protective element operation that trips a BES element could
be construed to be an Adverse Reliability Impact. The modification eliminated the phrase “that affects a
widespread area of the Interconnection” which clarified the scope of “uncontrolled separation”. We would
need the definition to be adjusted to delete “uncontrolled separation” as it is included in the definition of
Cascading.
Response: The RCSDT thanks you for your comment. We concur with your comment and have removed “uncontrolled separation” from the
proposed definition revision.
ISO New England Inc
No
We believe that the Reliability Directive definition should be: “A communication initiated by a Reliability
Coordinator, Transmission Operator, or Balancing Authority where action by the recipient is necessary to
address an actual or expected emergency and the RC, TOP or BA operator clearly identifies in the
communication that this is a Reliability Directive.”
Response: The RCSDT thanks you for your comment. The RCSDT believes that your suggested revision would impose a requirement within the
definition.
Western Electricity Coordinating
Council
No
We do not agree with the definition (see above question 4) but it does clear up when a directive is required.
Response: The RCSDT thanks you for your comment. Please see response to question 4.
Midwest ISO Standards
Collaborators
No
We largely agree with the use of the Reliability Directive term but have some suggested some refinements in
the previous questions to the definition and requirements.
NERC Standards Review
Subcommittee
No
We largely agree with the use of the Reliability Directive term but have some suggested some refinements in
the previous questions to the definition and requirements.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
Response: The RCSDT thanks you for your comment. Please see responses to questions 4 and 5.
Duke Energy
No
We propose a revised definition of the term “Reliability Directive” in our Comment #4 above.
Requirement R1 should be reworded to clarify that the RC has three separate actions. The RC can act, direct
others to act, or issue Reliability Directives.
Requirements R2 and R3 should be revised to include the fact that the listed entities must comply with RC
directions as well as Reliability Directives, or inform the RC of their inability to comply.
Measures and VSLs should also be revised accordingly.
Response: The RCSDT thanks you for your comment.
Definition: Please see response to question 4 with respect to the definition.
Each Reliability Coordinator shall take
actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing Authorities, Generator Operators,
Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the magnitude or
duration of actual events that result in Adverse Reliability Impacts..
R1: To address your comment as well as the comments of other stakeholders, we have revised R1 to state:
We have also revised the Purpose Statement to: To establish the capability and authority of Reliability Coordinators to direct other entities to prevent
Adverse Reliability Impacts to the Bulk Electric System
Conforming revisions to M1 and the VSLs for R1 were also made.
R2 and R3: The RCSDT believes that revised R2 and R3 now satisfy your requested revision.
American Transmission
Company
Yes
Bonneville Power Administration
Yes
CECD
Yes
Exelon
Yes
Florida Municipal Power Agency
Yes
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
and Some Members
Northeast Utilities
Yes
PacifiCorp
Yes
PPL
Yes
Puget Sound Energy
Yes
South Carolina Electric and Gas
Yes
Southwest Power Pool
Yes
Western Area Power
Administration
Yes
Xcel Energy
Yes
ITC Holdings
Yes
None
Pepco Hodlings, Inc
Yes
Requirement R1 should recognize the RC’s option to "direct others to act"
Response: The RCSDT thanks you for your comment. R1: To address your comment as well as the comments of other stakeholders, we have revised
R1 to state: Each Reliability Coordinator shall take actions or direct actions, which could include issuing Reliability Directives, of Transmission
Operators, Balancing Authorities, Generator Operators, Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area
to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts.
To establish the capability and authority of Reliability Coordinators to direct other entities to prevent
Adverse Reliability Impacts to the Bulk Electric System
We have also revised the Purpose Statement to:
Conforming revisions to M1 and the VSLs for R1 were also made.
ERCOT ISO
No
As an initial matter, ERCOT ISO disagrees with the definition of Reliability Directive - See response to
Question 4.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
With respect to the use of Reliability Directive in IRO-001-2, ERCOT ISO does not necessarily take issue with
using the term in this context. However, by doing so, the Drafting Team should consider whether doing so
effectively defines Emergency in terms of the specific conditions that define Adverse Reliability Impact (i.e.
instability, uncontrolled separation or cascading), because Reliability Directives, by definition, are only issued
during emergencies, and pursuant to R1 of IRO-001-2, the relevant entities issue a Reliability Directive for
instances that result in Adverse Reliability Impacts. Accordingly, use of Reliability Directive in this Standard
may effectively revise the definition of Emergency (although it is arguable that the relevant specific conditions
are clearly Emergency conditions), and ERCOT ISO questions whether this is appropriate. It may be
advisable to not use the term here or to revise the definition to explicitly include these conditions.
In addition, ERCOT ISO recommends the following non-substantive revisions to R1, R2 and R3.
R1
SDT PROPOSED LANGUAGE
R1. Each Reliability Coordinator shall act or issue Reliability Directives for actions to be taken by
Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, LoadServing Entities, Distribution Providers and Purchasing-Selling Entities within its Reliability Coordinator Area
to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability Impacts. [Violation
Risk Factor: High][Time Horizon: Real-time Operations and Same Day Operations]
ERCOT PROPOSED LANGUAGE
R1. Each Reliability Coordinator shall act to prevent or mitigate the magnitude or duration of events that result
in Adverse Reliability Impacts. RC actions pursuant to this requirement may include the issuance of Reliability
Directives to Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service
Providers, Load-Serving Entities, Distribution Providers and Purchasing-Selling Entities within its Reliability
Coordinator Area. [Violation Risk Factor: High][Time Horizon: Real-time Operations and Same Day
Operations]
R2
SDT PROPOSED LANGUAGE
R2. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider,
Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall comply with its Reliability
Coordinator’s Reliability Directives unless such actions would violate safety, equipment, or regulatory or
statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time Operations and Same Day
Operations]
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
ERCOT PROPOSED LANGUAGE
R2. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider,
Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall comply with Reliability
Directives issued pursuant to R1 unless such actions would violate safety, equipment, or regulatory or
statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time Operations and Same Day
Operations]
R3
SDT PROPOSED LANGUAGE
R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider,
Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall inform its Reliability
Coordinator upon recognition of its inability to perform an issued Reliability Directive. [Violation Risk Factor:
High] [Time Horizon: Real-time Operations and Same Day Operations]
ERCOT PROPOSED LANGUAGE
R3. Each Transmission Operator, Balancing Authority, Generator Operator, Transmission Service Provider,
Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall inform its Reliability
Coordinator if it cannot perform a Reliability Directive because it would violate safety, equipment, or regulatory
or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time Operations and Same Day
Operations]
Response: The RCSDT thanks you for your comment. Please see responses to your comments on questions 4 and 5.
Definitions: An Emergency is a system condition or event. Adverse Reliability Impact is the result of an Emergency or some other condition or event.
Each Reliability Coordinator shall take
actions or direct actions, which could include issuing Reliability Directives, of Transmission Operators, Balancing Authorities, Generator Operators,
Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the magnitude or
duration of actual events that result in Adverse Reliability Impacts.
To address your comment as well as the comments of other stakeholders, we have revised R1 to state:
To establish the capability and authority of Reliability Coordinators to direct other entities to prevent
Adverse Reliability Impacts to the Bulk Electric System
We have also revised the Purpose Statement to:
Conforming revisions to M1 and the VSLs for R1 were also made.
R1, R2, R3: The RCSDT thanks you for your suggested revisions to R1, R2 and R3. Revised wording best reflects stakeholder consensus. The RCSDT
developed wording of the requirements provides clear direction for actions of applicable entities and to provide clarity regarding compliance.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Do you agree with the revisions to the Requirements in IRO-014-2 as shown in the posted Standard and
Implementation Plan? If not, please explain in the comment area.
Summary Consideration: Several commenters made suggestions regarding R2. The original requirement was
designed to accomplish in one requirement what is proposed by the commenters as three procedural
requirements. R2 is worded to focus on defining what a “compliant plan” is. In the current requirement a
“proposed plan” is not the same as a “compliant plan”.
The SDT viewed what the commenters are suggesting as follows:
• The initiating RC would submit its “proposed plan” to the other RCs
• The receiving RCs would provide the initiating RC with their responses indicating whether or not they agree
with the proposed roles/actions offered by the initiating RC
• If one or more RCs do not agree with the roles/actions, then the initiating RC would be required to offer an
alternative proposal (and go back to the first bullet)
• When all RCs acknowledge that the proposed roles/actions in the revised “proposed plan” are acceptable,
then and only then would the “proposed plan” become a “compliant plan”
A closer reading of the current R2 would show the current R2 accomplishes the exact same result but does so
without interjecting the need for documenting the intervening processes. The SDT does not see the need to
document why each proposal was or was not accepted; nor does the SDT see the need for document the
negotiations that are involved in getting to “an agreed to plan”. For example the comments’ subrequirement to
show the RC submitted its plan would require a paper trail for the request; followed by a paper trail for the
responses, followed by more paperwork if the RCs are not in agreement. In the end, the only action that matters
(in both the SDT version and in the commenters alternative version) is a plan that works, and a plan that if others
are involved must have their concurrence that those others will participate.
R2 does not impose a requirement to get agreements; what R2 does is to require that a “compliant plan” be
developed. A proposed plan does not solve problems. That proposed plan is NOT compliant with R2 if it only
assumes that other RC will effect the actions in the proposal; neither is it compliant if the proposed actions are not
acceptable to the other RCs who are required to act. To be compliant the initiating RC must either have the
concurrence (i.e. agreement) of the other RCs for their respective part(s) in the proposed plans OR the plan must
not include those RCs.
R2 says to be compliant the other RC must agree with the “proposed plan” before that “proposed plan” is
acceptable as a “compliant plan”. Having a plan that requires someone else to do an action, but that other entity
will not effect that action, will not resolve the problem at hand. Further having documentation that someone
refuses to participate in the proposed plan does nothing to solve the problem at hand.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
Ameren
American Transmission
Company
Calpine Corporation
CECD
E.ON U.S.
Exelon
North Carolina Municipal Power
Agency #1
Northeast Utilities
Public Service Enterprise Group
Companies
Puget Sound Energy
Yes
We Energies
Operating Personnel
Communications Protocols SDT
No Comment
PacifiCorp
No comment
Manitoba Hydro
No
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Hydro-Québec TransEnergie
(HQT)
Yes or No
Question 7 Comment
No
R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, Subrequirement R2.1 places a
burden to the initiating RC for actions over which it may not have any control, viz. agreeing to the procedures,
process or plan by the receiving RCs that are required to take actions. We believe there should be
requirements for:a. The initiating RC to seek agreements by the other RCs that are required to take actions;b.
The receiving RCs to indicate agreement, or otherwise with a reason; and;c. The initiating RC to revise the
procedures, process or plan. These requirements would place the needed responsibilities to the appropriate
entities. If the SDT agrees with revising R2 as suggested, then other requirements that may be affected by
this change may need to be revised accordingly.
(ii) There is an extra “or” in the R8 clause: “unless such actions would violate safety, equipment, or regulatory
or statutory requirements”.
IRC Standards Review
Committee
No
(i) R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, Subrequirements R2.1 places a
burden to the initiating RC for actions over which it may not have any control, viz. agreeing to the procedures,
process or plan by the receiving RCs that are required to take actions. We believe there should be
requirements for:a. The initiating RC to seek agreements by the other RCs that are required to take actions;b.
The receiving RCs to indicate agreement, or otherwise with a reason; and;c. The initiating RC to revise the
procedures, process or planThese requirements would place the needed responsibilities to the appropriate
entities. If the SDT agrees with revising R2 as suggested, then other requirements that may be affected by
this change may need to be revised accordingly.
(ii) There is an extra “or” in the R8 clause: “unless such actions would violate safety, equipment, or regulatory
or statutory requirements”.
Northeast Power Coordinating
Council
No
(i) R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, Subrequirement R2.1 places a
burden on the initiating RC for actions over which it may not have any control, namely agreeing to the
procedures, processes or plans by the receiving RCs that are required to take actions. There should be
requirements for:a. The initiating RC to seek agreements by the other RCs that are required to take actions;b.
The receiving RCs to indicate agreement, or otherwise with a reason; and;c. The initiating RC to revise the
procedures, processes or plansThese requirements would place the needed responsibilities on the
appropriate entities. If the SDT agrees with revising R2 as suggested, then other requirements may be
affected by this change, and may need to be revised accordingly.(ii) There is an extra “or” in the R8 clause
preceding "regulatory": “unless such actions would violate safety, equipment, or regulatory or statutory
requirements”.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
ISO New England Inc
Yes or No
Question 7 Comment
No
R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, Subrequirements R2.1 places a
burden to the initiating RC for actions over which it may not have any control, viz. agreeing to the procedures,
process or plan by the receiving RCs that are required to take actions. We believe there should be
requirements for:a. The initiating RC to seek agreements by the other RCs that are required to take actions;b.
The receiving RCs to indicate agreement, or otherwise with a reason; and;c. The initiating RC to revise the
procedures, process or planThese requirements would place the needed responsibilities to the appropriate
entities. If the SDT agrees with revising R2 as suggested, then other requirements that may be affected by
this change may need to be revised accordingly.
Response: The RCSDT thanks you for your comment. The original requirement was designed to accomplish in one requirement what is proposed by the
commenters as three procedural requirements. R2 is worded to focus on defining what a “compliant plan” is. In the current requirement a “proposed
plan” is not the same as a “compliant plan”.
The SDT viewed what the commenters are suggesting as follows:
• The initiating RC would submit its “proposed plan” to the other RCs
• The receiving RCs would provide the initiating RC with their responses indicating whether or not they agree with the proposed roles/actions
offered by the initiating RC
• If one or more RCs do not agree with the roles/actions, then the initiating RC would be required to offer an alternative proposal (and go back to
the first bullet)
• When all RCs acknowledge that the proposed roles/actions in the revised “proposed plan” are acceptable, then and only then would the
“proposed plan” become a “compliant plan”
A closer reading of the current R2 would show the current R2 accomplishes the exact same result but does so without interjecting the need for
documenting the intervening processes. The SDT does not see the need to document why each proposal was or was not accepted; nor does the SDT see
the need for document the negotiations that are involved in getting to “an agreed to plan”. For example the comments’ subrequirement to show the RC
submitted its plan would require a paper trail for the request; followed by a paper trail for the responses, followed by more paperwork if the RCs are not in
agreement. In the end, the only action that matters (in both the SDT version and in the commenters alternative version) is a plan that works, and a plan
that if others are involved must have their concurrence that those others will participate.
R2 does not impose a requirement to get agreements; what R2 does is to require that a “compliant plan” be developed. A proposed plan does not solve
problems. That proposed plan is NOT compliant with R2 if it only assumes that other RC will effect the actions in the proposal; neither is it compliant if
the proposed actions are not acceptable to the other RCs who are required to act. To be compliant the initiating RC must either have the concurrence (i.e.
agreement) of the other RCs for their respective part(s) in the proposed plans OR the plan must not include those RCs.
R2 says to be compliant the other RC must agree with the “proposed plan” before that “proposed plan” is acceptable as a “compliant plan”. Having a
plan that requires someone else to do an action, but that other entity will not effect that action, will not resolve the problem at hand. Further having
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
documentation that someone refuses to participate in the proposed plan does nothing to solve the problem at hand.
Midwest ISO Standards
Collaborators
No
R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, it inappropriately places the
burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to agree. Rather
R2 should remove the bullet to require agreement from the impacted RC and a new requirement should be
written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement
or disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable
actions should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This
contributes to reliability by forcing the impacted RC to take action if the action is reasonable. There is an
extra “or” in the R8 clause: “unless such actions would violate safety, equipment, or regulatory or statutory
requirements”.
IRO-014-2 R2 VSLs differentiate violations based on whether the plans, processes, and procedures were
distributed or agreed to. How can another RC agree to them if it has not received them? Because it is
unlikely that an RC will make notifications without exchanging reliability information or vice versa for IRO-0142 R3, we suggest a more appropriate delineation for the VSLs would be based on the number of other
impacted RCs that were not informed.IRO-014-2 R4 VSLs should be defined based upon the number of
conference calls the RC does not participate in. R4 requires each RC to participate in “agreed upon
conference calls”. Because the statement “conference calls” is plural, VSLs need to be set based on the
aggregate of calls not participated in. Failure to assign VSLs in this way is equivalent to setting the
requirement to “agreed upon conference call” and causes the VSLs to be in violation guideline 3 that the
Commission established in their June 2008 Order on VSLs. Guideline 3 states that the VSL must be
consistent with the requirement and cannot “redefine or undermine the requirement”. Clearly, these VSLs
do.R5’s Severe VSL is redundant with the Moderate VSL. Failure to notify one RC meets both VSLs since
Severe uses the word any. Based on the SDT’s response to our comment from the last time, we believe
instead of any they mean “no impacted”. Unfortunately, “any impacted” could be one or two or higher. If it is
one, it matches the Moderate VSL.The VSL for R8 needs to include the “unless such actions would violate
safety, equipment, regulatory or statutory requirement” clause.
In R1, should “Operating Procedures, Processes, or Plans” be “Operating Procedures, Operating Processes,
or Operating Plans” to comport with the definitions in the NERC Glossary of Terms. We believe “Operating” is
implied on “Processes” and “Plans” but believe it is more appropriate to make the meaning explicit with this
modification since we are dealing with formal definitions.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
NERC Standards Review
Subcommittee
Yes or No
Question 7 Comment
No
R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, it inappropriately places the
burden on the same RC to obtain the agreement of impacted RCs. No RC can be forced to agree. Rather
R2 should remove the bullet to require agreement from the impacted RC and a new requirement should be
written to require the impacted RC to acknowledge the Operating Procedure, Process or Plan with agreement
or disagreement. In the event of disagreement, a reliability or legal reason or failure to implement comparable
actions should be given as the reason for not agreeing with the Operating Process, Procedure or Plan. This
contributes to reliability by forcing the impacted RC to take action if the action is reasonable. There is an
extra “or” in the R8 clause: “unless such actions would violate safety, equipment, or regulatory or statutory
requirements”.
IRO-014-2 R2 VSLs differentiate violations based on whether the plans, processes, and procedures were
distributed or agreed to. How can another RC agree to them if it has not received them? Because it is
unlikely that an RC will make notifications without exchanging reliability information or vice versa for IRO-0142 R3, we suggest a more appropriate delineation for the VSLs would be based on the number of other
impacted RCs that were not informed.IRO-014-2 R4 VSLs should be defined based upon the number of
conference calls the RC does not participate in. R4 requires each RC to participate in “agreed upon
conference calls”. Because the statement “conference calls” is plural, VSLs need to be set based on the
aggregate of calls not participated in. Failure to assign VSLs in this way is equivalent to setting the
requirement to “agreed upon conference call” and causes the VSLs to be in violation guideline 3 that the
Commission established in their June 2008 Order on VSLs. Guideline 3 states that the VSL must be
consistent with the requirement and cannot “redefine or undermine the requirement”. Clearly, these VSLs
do.R5’s Severe VSL is redundant with the Moderate VSL. Failure to notify one RC meets both VSLs since
Severe uses the word any. Based on the SDT’s response to our comment from the last time, we believe
instead of any they mean “no impacted”. Unfortunately, “any impacted” could be one or two or higher. If it is
one, it matches the Moderate VSL.The VSL for R8 needs to include the “unless such actions would violate
safety, equipment, regulatory or statutory requirement” clause.
Independent Electricity System
Operator
No
R2 appropriately requires the RC experiencing the Adverse Reliability Impact to distribute its Operating
Procedure, Process or Plan to other RCs required to take action. However, Subrequirements R2.1 places a
burden to the initiating RC for actions over which it may not have any control, viz. agreeing to the procedures,
process or plan by the receiving RCs that are required to take actions. We believe there should be
requirements for:a. The initiating RC to seek agreements by the other RCs that are required to take actions;b.
The receiving RCs to indicate agreement, or otherwise with a reason; and;c. The initiating RC to revise the
procedures, process or plan. These requirements would place the needed responsibilities to the appropriate
entities. If the SDT agrees with revising R2 as suggested, then other requirements that may be affected by
this change may need to be revised accordingly. There is an extra “or” in the R8 clause: “unless such
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
actions would violate safety, equipment, or regulatory or statutory requirements”.
IRO-014-2 R2 VSLs differentiate violations based on whether the plans, processes, and procedures were
distributed or agreed to. If an intended RC never received the plans, processes and procedures, it would not
be aware of the need to agree to them. Hence, if the plans, etc. were not distributed, then the initiating RC will
be assigned a Moderate VSL but never any higher VSLs even if no agreements were received (since no other
RCs had received the plans to begin with). We suggest the SDT to consider rearranging the VSLs and in
accordance with any changes to R2 reflecting our suggested changes summarized under Q7. Because it is
unlikely that an RC will make notifications without exchanging reliability information or vice versa for IRO-014-2
R3, we suggest a more appropriate delineation for the VSLs would be based on the number of other impacted
RCs that were not informed.
IRO-014-2 R4 VSLs should be defined based upon the number of conference calls the RC does not participate
in. R4 requires each RC to participate in “agreed upon conference calls”. Because the statement “conference
calls” is plural, VSLs need to be set based on the aggregate of calls not participated in. Failure to assign VSLs
in this way is equivalent to setting the requirement to “agreed upon conference call” and causes the VSLs to be
in violation guideline 3 that the Commission established in their June 2008 Order on VSLs. Guideline 3 states
that the VSL must be consistent with the requirement and cannot “redefine or undermine the requirement”.
Clearly, these VSLs do.
The VSL for R8 needs to include the “unless such actions would violate safety, equipment, regulatory or
statutory requirement” clause.
Response: The RCSDT thanks you for your comment. The original requirement was designed to accomplish in one requirement what is proposed by the
commenters as three procedural requirements. R2 is worded to focus on defining what a “compliant plan” is. In the current requirement a “proposed
plan” is not the same as a “compliant plan”.
The SDT viewed what the commenters are suggesting as follows:
• The initiating RC would submit its “proposed plan” to the other RCs
• The receiving RCs would provide the initiating RC with their responses indicating whether or not they agree with the proposed roles/actions
offered by the initiating RC
• If one or more RCs do not agree with the roles/actions, then the initiating RC would be required to offer an alternative proposal (and go back to
the first bullet)
• When all RCs acknowledge that the proposed roles/actions in the revised “proposed plan” are acceptable, then and only then would the
“proposed plan” become a “compliant plan”
A closer reading of the current R2 would show the the current R2 accomplish the exact same result but does so without interjecting the need for
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
documenting the intervening processes. The SDT does not see the need to document why each proposal was or was not accepted; nor does the SDT see
the need for document the negotiations that are involved in getting to “an agreed to plan”. For example the comments’ subrequirement to show the RC
submitted its plan would require a paper trail for the request; followed by a paper trail for the responses, followed by more paperwork if the RCs are not in
agreement. In the end, the only action that matters (in both the SDT version and in the commenters alternative version) is a plan that works, and a plan
that if others are involved must have their concurrence that those others will participate.
R2 does not impose a requirement to get agreements; what R2 does is to require that a “compliant plan” be developed. A proposed plan does not solve
problems. That proposed plan is NOT compliant with R2 if it only assumes that other RC will effect the actions in the proposal; neither is it compliant if
the proposed actions are not acceptable to the other RCs who are required to act. To be compliant the initiating RC must either have the concurrence (i.e.
agreement) of the other RCs for their respective part(s) in the proposed plans OR the plan must not include those RCs.
R2 says to be compliant the other RC must agree with the “proposed plan” before that “proposed plan” is acceptable as a “compliant plan”. Having a
plan that requires someone else to do an action, but that other entity will not effect that action, will not resolve the problem at hand. Further having
documentation that someone refuses to participate in the proposed plan does nothing to solve the problem at hand.
IRO-014 VSLs: R2: The VSLs are differentiated as you suggest.
R3: The RCSDT does not believe that is the correct delineation of the requirement which requires notification of each impacted RC. What if there is only
one and there was no notification?
R4: The RCSDT contends that the requirement specifies participation in all agreed upon calls. If the RC misses an agreed upon call, it has failed to meet
the requirement.
R5: The RCSDT disagrees. If there is only one impacted RC and no notification is made, it should be a Severe violation.
R8: The phrase does not need to be in the VSL. If a plan was not implemented due to safety reasons, then the requirement was not violated and the VSL
would not be considered.
R1: We have revised the requirement per your suggestion to R1, R2 and R3.
Electric Market Policy
No
Agree with most. However, the language proposed for use in IRO-014-2 @ R5 and R6 needs clarity. There
needs to be a way to determine who is required to do what depending upon whether the party is a) Reliability
Coordinator who has the identified Adverse Reliability Impact) An impacted affected Reliability Coordinator.
Suggest revising so that these read similar to R7 and R8.
Response: The RCSDT thanks you for your comment. The RCSDT does not understand your comment. We believe that the requirements are clear as
written as to what each entity must do.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Western Area Power
Administration
Yes or No
No
Question 7 Comment
Comments: In R1 & R2, the first sentence is redundant. The phrase which was added “For conditions or
activities that impact other RC Areas...” should be removed.
Response: The RCSDT thanks you for your comment. The SDT agrees and has made the suggested revision.
OC Standards Review Group
No
In R1.6, we suggest adding “BES” before “conditions” such that the sentence reads: “Authority to act to
prevent and mitigate “BES” conditions......”
Response: The RCSDT thanks you for your comment. The SDT disagrees. Adverse Reliability Impact is defined as follows:
The impact of an event that results in frequency-related instability; unplanned tripping of load or generation; or uncontrolled separation or cascading outages that affects a widespread area of the
Interconnection.
If a condition will cause interconnection “cascading, instability, …” the RC should be mandated to act whether or not the initiating condition is part of the BES.
Florida Municipal Power Agency
and Some Members
No
In requirements R7 and R8, the term mitigation plan is used. Since mitigation plan has another specific
meaning (e.g., a mitigation plan for non-compliance with a standard), FMPA suggests using a different term
with the same meaning, e.g., ameliorative plan, alleviation plan, abatement plan, to help avoid confusion.
Response: The RCSDT thanks you for your comment. The SDT disagrees. Lower case “mitigation” is a proper English word
NERC
No
NERC staff believes that the original language in IRO-016-1 was clearer than the proposed requirements R5
through R8. Additionally, we believe that this standard is already covered in the certification process. We
recommend that this standard, with the exception of R4, be retired and the certification process be revisited to
ensure that IRO-016-1 R1 is covered. Furthermore, operating guidelines should be developed to address the
content of R5 through R8.
Response: The RCSDT thanks you for your comment. The RCSDT is not clear how requirements to make notifications, develop and implement
mitigations plans belong in the certification process. We are also unclear what constitutes an operating guideline. Based on this, we will retain the
requirements in IRO-014 as supported through the stakeholder process. Requirements R5 through R8 were brought into IRO-014 from IRO-016 as you
state. These requirements were revised to eliminate compound requirements. The RCSDT feels that requirements are clear as written and stakeholder
comments indicate consensus has been achieved.
Duke Energy
No
R1.6 - We believe that the word “system” should be added before the word “conditions” to provide additional
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
clarity.
Response: The RCSDT thanks you for your comment. We agree and have made the suggested edit.
US Bureau of Reclamation
No
We would suggest that the language should indicate the plans need to address “neighboring RC areas” to
limit the scope of the plans for "other RC areas" and not try to cover the whole NERC footprint.
Response: The RCSDT thanks you for your comment. The requirements deal with those RC that are seen to have an impact on a problem. To the
extent that one RC expects another RC to be part of a solution, the requirement allows the initiating RC to “propose” a plan of actions and to seek
help. If the other RC disagrees with the proposal, the latter RC would not give agreement.
Bonneville Power Administration
Yes
Central Lincoln
Yes
FirstEnergy
Yes
Pepco Hodlings, Inc
Yes
PNGC Power (15 member
utilities)
Yes
PPL
Yes
South Carolina Electric and Gas
Yes
Southern Company Services
Yes
Southwest Power Pool
Yes
Western Electricity Coordinating
Council
Yes
Xcel Energy
Yes
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
ITC Holdings
Yes
None
American Electric Power
Yes
The use of “. . . act and/or issue . . .” may be more descriptive in Requirement 1 rather than “. . . act or issue .
. .”
Response: The RCSDT thanks you for your comment.
ERCOT ISO
No
ERCOT ISO would like to add clarification to the Purpose statement and the following requirements (1-4) to
alleviate potential interpretation issues. The remaining requirements in IRO-014 are adequately addressed
with respect to “within the Interconnection” if the Adverse Reliability Impact term is modified as identified
above in response to Question All the recommendations tie together.
Purpose: To ensure that each Reliability Coordinator’s operations are coordinated such that they will not
have an Adverse Reliability Impact on other Reliability Coordinator Areas “within its Interconnection” and to
preserve the reliability benefits of interconnected operations.
R1. For conditions or activities that impact other Reliability Coordinator Areas “within its Interconnection”,
each Reliability Coordinator shall have Operating Procedures, Processes, or Plans for activities that require
notification, exchange of information or coordination of actions with impacted Reliability Coordinators to
support Interconnection reliability. These Operating Procedures, Processes, or Plans shall collectively
address the following:
R2. Each Reliability Coordinator’s Operating Procedure, Process, or Plan that requires one or more other
Reliability Coordinators “within its Interconnection” to take action (e.g., make notifications, exchange
information, or coordinate actions) shall be:
R3. For conditions or activities that impact other Reliability Coordinator Areas “within its Interconnection”,
each Reliability Coordinator shall make notifications and exchange reliability–related information with
impacted Reliability Coordinators using its predefined Operating Procedures, Processes, or Plans for
conditions that may impact other Reliability Coordinator Areas or other means to accomplish the notifications
and exchange of reliability-related information.
R4. Each Reliability Coordinator shall participate in agreed upon conference calls, at least weekly, and other
communication forums with impacted Reliability Coordinators “within its Interconnection”.
Additionally, ERCOT ISO recommends that the weekly minimum be eliminated and such meeting should be
pursuant to an “agreed upon schedule” at the discretion of the Reliability Coordinators. The language notes
“impacted” Reliability Coordinators. The “impacted” implies that it is relative to a discrete incident or time
period, which is consistent with the purpose of the standard. Accordingly, it is unclear on the need for and
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 7 Comment
unbounded ongoing meeting obligation.
ERCOT ISO also suggests changing the R4 VSL to allow lower VSL for missing an occasional meeting. The
VSL can be elevated based on the number of missed calls or meetings. Severe would seem to be more
appropriate if the entity refused to participate or calls were not initiated at all.
Furthermore, with respect to R4, It is not clear what value this requirement adds generally. The requirement
is related to “impacted” RCs. This implies that the meetings are relative to discrete incidents/time periods,
which is consistent with the purpose of the standard. Accordingly, given the apparent temporary, incident
specific nature of an “impacted” entity, it doesn’t make sense to impose an unbounded ongoing meeting
obligation. Furthermore, the establishment of the general procedures governs the objective actions impacted
RCs will take for all situations. If there is an incident where an RC is “impacted”, it will manage the situation
by application of the established objective procedures – that is the intent of having those procedures in place
under the standard. Accordingly, it is questionable whether the weekly meeting obligation is necessary or
serves any purpose. At a minimum, the weekly meeting obligation should be eliminated and such meeting
should be pursuant to an “agreed upon schedule” to give discretion to the RCs.
Finally, with respect to R1 – 1.6, in order to provide certainty to the regulated community, ERCOT ISO does
not support the change to the condition precedent for action under the requirement from actual to potential
Adverse Reliability Impacts. Defining an obligation in terms of “potential” situations is vague and ambiguous.
This should generally be avoided because it creates ambiguity and uncertainty for both the regulated entity
and regulator.
Response: The RCSDT thanks you for your comment.
R1-R3: The SDT disagrees. If an RC does not have any other impacted RCs, then no operating processes, procedures or plans would be necessary.
This would mean the R1-R3 would not apply to that RC.
R4 and VSL- The RCSDT has revised R4 to add the words “within the same Interconnection” to the end of R4. We have revised the VSL accordingly.
The RCSDT contends that the requirement specifies participation in all agreed upon calls. If the RC misses an agreed upon call, it has failed to meet
the requirement.
R1.6 – This refers to studying various system conditions and developing operating processes, plans or procedures to address them. If an entity has
run a study and determined that there is an impact on another RC, then a process/plan/procedure should be developed and agree to in order to
address the issue.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
7 Do you have any other comment, not expressed in questions above, for the RC SDT?
Summary Consideration: The RC SDT thanks all commenters for their review of these proposed revisions and has
incorporated many of the comments in the next revision of these requirements. In general, the RC SDT feels that
the concept of a Reliability Directive is an important tool for RC, BA and TOP to maintain reliability and that the
revisions are consistent with the applicable parts of the directives in FERC Order 693. The work of the RC SDT
along with the OPCP SDT and the RTO SDT, as currently recognized, will cover the original intent of COM-002 and
still provide a “defense in depth strategy” as suggested by commenters. Consensus appears to have been
achieved with respect to the definition of Reliability Directive and the requirements that the RC SDT have
developed for COM-002. This will further the efforts of the OCPC SDT in achieving stakeholder consensus for their
proposed requirements in COM-003. The intent of this DT is to preserve a method for RCs, BAs and TOPs to make
the determination of “what actions are required” and clearly communicate the importance to the receiver at a
heightened method to normal day-to-day operational communications. The trigger of “Reliability Directive” by the
issuer highlights these actions as needed to maintain BES reliability and shall be carried out as directed (unless
such actions would violate safety, equipment, regulatory or statutory requirement per the language of the
requirement) and all parties to the conversation need to be very cognizant of the system conditions that are
requiring actions. The DT has attempted to craft clear and specific language that support BES reliability and hopes
that this work can support and enhance the development of the OPCP SDT. The DT has also attempted to eliminate
redundancy and ambiguity while not creating any reliability gaps. Several comments were received on the RC’s
ability to “act”. The RC must “act” (ie. do something, “to prevent or mitigate the magnitude or duration of events
that result in Adverse Reliability Impacts”. This may include analysis, coordination of cooperative actions or the
issuance of “Reliability Directives”. “Act” does not imply solely the manipulation of BES elements.
Several comments on VSL language were received. We have attempted to clarify intent and have revised some in
response to comments.
Several comments were received that reference a “performance based initiative” endorsed by the NERC BOT. The
DT appreciates this new initiative, and to the extent possible, requirements proposed by this DT reflect that
desire. [We have had no official instruction nor direction regarding this initiative in relation to this project.]
RC control of “analysis tools” is critical to maintaining the wide area view. Control by the RC over the tools is
imperative and beyond administrative, since it is intended to prevent planned reliability tool outages without the
consent or knowledge of operating personnel. Although the DT agrees with the premise that many other
requirements may be violated by ineffective communications, the intent of the requirement is to ensure there are
effective communications methods in place for communicating BES activity across entities. Effective
communication are a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of
other more significant performance type standard requirements due to ineffective communications before they
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
impact the BES. Failure of the RC to control outages of analysis tools was mentioned as a contributing factor in
the 2003 blackout.
Overall, it is the intent of the DT to make the requirements flexible and adaptive to new technologies and methods
as directed in order 693 and ensure that no matter how many forms of interpersonal communications are
available. An entity can select a functional alternative to meet the intent of the requirement. The 60 minute
timeframe appears reasonable based on industry comments. The term Interconnection is appropriate as it is.
Effective communications rely on an effective hierarchy. It is crucial for a host TOP or BA to have effective
communications with GOs attached to their systems so that BES operations can be coordinated. Much like RCs
must be able to communicate effectively with the systems within its footprint, effective communications allows
BAs/TOPs to disseminate Interconnection information to DPs/GOPs that are impacted by system conditions
outside of their operating visibility. The RCS DT has relied on the authority hierarchy (RC/ BA/ TOP / DP) to
ensure accountability with the current performance type requirements, while not over-burdening the standards
with prescriptive administrative-type requirements.
Organization
Question 8 Comment
American Transmission
Company
ISO New England Inc
North Carolina Municipal Power
Agency #1
Pepco Hodlings, Inc
Puget Sound Energy
None additional.
South Carolina Electric and Gas
US Bureau of Reclamation
We Energies
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Question 8 Comment
Western Area Power
Administration
Western Electricity Coordinating
Council
CECD
(1). The 60 minute timeframe should be lengthened if normal interpersonal communication paths are in service.
Furthermore, the requirement to take corrective action or identify an alternative interpersonal communication method within
60 minutes should only apply if the registered entity only has a single alternative interpersonal communication method in
place.
(2). For COM-001 Requirement 4: The use of the term "Interconnection" seems inappropriate when describing
communications between the DP/GOP and its BA/TOP and should be deleted. The NERC glossary of terms defines this as
any one of the three major electric system networks in North America: Eastern, Western, and ERCOT. The requirement to
be able to exchange operating information should be subject to the limitation as requested by the BA or TOP.
Response: The RCSDT thanks you for your comment. 1) It is the intent of the DT to make the requirement flexible and adaptive to new technologies
and methods as directed in order 693 and ensure that no matter how many forms of interpersonal communications are available. An entity can select
a functional alternative to meet the intent of the requirement. The timeframe has been revised to 2 hours. 2) We concur and have removed
“Interconnection” from the requirement.
Hydro-Québec TransEnergie
(HQT)
(i) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives per the functional
model.
(ii) The NERC BOT recently approved pursuing the Results/Performance Based standards development activity. Based on
this recent decision, the BOT has signaled their intent to remove administrative types of requirements from all standards. The
IRO-001-2 R6 for the RC to have the authority to veto outages of their analysis tools and the COM-001-2 R3 requirement to
use the English language are clearly not results or performance based, but rather administrative. If an operator used nonEnglish, where it has not been agreed to or subject to law, to issue a Reliability Directive they will not be able to satisfy threepart communications in COM-002-3 in addition to many other standards and requirements they could not comply with. Even
if an RC has veto authority over analysis tools, failure to exercise it would render the authority meaningless. Furthermore, the
RC would not be able to meet other requirements and standards such as operating within IROL because they would not be
able to assess the system appropriately.
Response: The RCSDT thanks you for your c o m m e n ts .
a.
The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability
Impacts”. This may include analysis, coordinate cooperative actions or issue “Reliability Directives”.
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
b.
Question 8 Comment
R6 is beyond administrative; it is intended to prevent planned reliability tool outages with the consent or knowledge of operating
personnel. Although the DT agrees with the premise that many other requirements may be violated by ineffective communications,
the intent of the requirement is to ensure there are effective communications methods in place for communicating BES activity across
entities. Effective communication is a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of
other more significant performance type standard requirements due to ineffective communications before they impact the BES.
Midwest ISO Standards
Collaborators
1) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives per the functional
model.
2) IRO-001-2 R4 and R5 Severe VSLs need to have “any or” removed. The VSL should only apply for three or more and
“any or” conflicts with this.COM-001-2 R2 Severe VSL conflicts with other VSLs. Specifically, the use of the word “any” in
the Severe VSL is problematic. Notifying one entity at 65 minutes fits both the Lower VSL and Severe VSL as well. We
suggest deleting the first portion of the Severe VSL that reads, “The responsible entity failed to notify any impacted entities
of the failure of its normal Interpersonal Communications capabilities within 60 minutes.”
3) The NERC BOT recently approved the pursuing the Results/Performance Based standards development activity. Based
on this recent decision, we believe the BOT has signaled their intent to remove administrative types of requirements from all
standards. The IRO-001-2 R6 for the RC to have the authority to veto outages of their analysis tools and the COM-001-2
R3 requirement to use the English language are clearly not result or performance based but rather administrative. If an
operator used Portuguese to issue a Reliability Directive they will not be able to satisfy three-part communications in COM002-3 in addition to many other standards and requirements they could not comply with. Even if an RC has veto authority
over analysis tools, failure to exercise it would render the authority meaningless. Furthermore, the RC would not be able to
meet a host of other requirements and standards such as operating within IROL because they would not be able to assess
the system appropriately.
Response: The RCSDT thanks you for your comments.
1) The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability Impacts”. This
may include analysis, coordinate cooperative actions or issue “Reliability Directives”.
2) The VSL language is intended to accommodate scenarios where only one entity is impacted or several entities are impacted. “The Reliability
Coordinator failed to notify any or more than three impacted Transmission Operators, Balancing Authorities…” and provide the same measurability
level.
3) R6 is beyond administrative; it is intended to prevent planned reliability tool outages without the consent or knowledge of operating personnel.
Although the DT agrees with the premise that many other requirements may be violated by ineffective communications, the intent of the requirement
is to ensure there are effective communications methods in place for communicating BES activity across entities. Effective communication is a
cornerstone of BES reliability and the intent of the requirement is to prevent the violation of other more significant performance type standard
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Consideration of Comments on Draft Standards for Reliability Coordination — Project 2006-06
Organization
Question 8 Comment
requirements due to ineffective communications before they impact the BES.
Northeast Power Coordinating
Council
(i) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives as per the
functional model.
(ii) The NERC BOT recently approved pursuing the Results/Performance Based standards development activity. Based on
this recent decision, the BOT has signaled their intent to remove administrative types of requirements from all standards.
The IRO-001-2 R6 requirement for the RC to have the authority to veto outages of their analysis tools and the COM-001-2
R3 requirement to use the English language are clearly not results or performance based, but rather administrative. If an
operator used non-English to issue a Reliability Directive they will not be able to satisfy three-part communications in COM002-3, in addition to many other standards and requirements they could not comply with. Even if an RC has veto authority
over analysis tools, failure to exercise it would render the authority meaningless. Furthermore, the RC would not be able to
meet other requirements and standards such as operating within an IROL because they would not be able to assess the
system appropriately.
Response: The RCSDT thanks you for your c o m m e n ts .
I)
The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability
Impacts”. This may include analysis, coordinate cooperative actions or issue “Reliability Directives”.
II)
R6 is beyond administrative; it is intended to prevent planned reliability tool outages without the consent or knowledge of operating
personnel. Although the DT agrees with the premise that many other requirements may be violated by ineffective communications,
the intent of the requirement is to ensure there are effective communications methods in place for communicating BES activity.
Effective communication is a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of other more
significant performance type standard requirements due to ineffective communications before they impact the BES.
Independent Electricity System
Operator
(i) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives per the functional
model.
(ii) The NERC BOT recently approved pursuing the Results/Performance Based standards development activity. Based on
this recent decision, the BOT has signaled their intent to remove administrative types of requirements from all standards.
The IRO-001-2 R6 for the RC to have the authority to veto outages of their analysis tools and the COM-001-2 R3
requirement to use the English language are clearly not results or performance based, but rather administrative. If an
operator used non-English to issue a Reliability Directive they will not be able to satisfy three-part communications in COM002-3 in addition to many other standards and requirements they could not comply with. Even if an RC has veto authority
over analysis tools, failure to exercise it would render the authority meaningless. Furthermore, the RC would not be able to
meet other requirements and standards such as operating within IROL because they would not be able to assess the
system appropriately.
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(iii) COM-001-2 R2 Severe VSL conflicts with other VSLs. Specifically, the condition of failing to notify any impacted entities
within 60 minutes means that no entities received a notification within 60 minutes. But how about they all received this in 65
minutes? Would this be the same condition as the Low VSL? And if they all received this in 75 minutes, the condition would
be the same as the Moderate VSL. We suggest the SDT to review and revise these VSLs to eliminate the
duplication/ambiguity.
Response: The RCSDT thanks you for your c o m m e n ts .
I)
The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability
Impacts”. This may include analysis, coordinate cooperative actions or issue “Reliability Directives”.
II)
R6 is beyond administrative; it is intended to prevent planned reliability tool outages without the consent or knowledge of operating
personnel. Although the DT agrees with the premise that many other requirements may be violated by ineffective communications,
the intent of the requirement is to ensure there are effective communications methods in place for communicating BES activity.
Effective communication is a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of other more
significant performance type standard requirements due to ineffective communications before they impact the BES.
III)
The DT did not consider R1 and R2 to be parallel requirements, and consequently did not attempt to force parallelism between the
VSLs for R1 and R2. The only failure that is severe in this context is the failure to test the Alternative Interpersonal Communications
capability on at least a quarterly basis.
IRC Standards Review
Committee
(i) IRO-001-2 R4 and R5 Severe VSLs need to have “any or” removed. The VSL should only apply for three or more and
“any or” conflicts with this.
(ii) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives per the functional
model.
(iii) COM-001-2 R2 Severe VSL conflicts with other VSLs. Specifically, the condition of failing to notify any impacted entities
within 60 minutes means that no entities received a notification within 60 minutes. But how about they all received this in 65
minutes? Would this be the same condition as the Low VSL? And if they all received this in 75 minutes, the condition would
be the same as the Moderate VSL. We suggest the SDT to review and revise these VSLs to eliminate the
duplication/ambiguity.
(iv) The NERC BOT recently approved the pursuing the Results/Performance Based standards development activity.
Based on this recent decision, we believe the BOT has signaled their intent to remove administrative types of requirements
from all standards. The IRO-001-2 R6 for the RC to have the authority to veto outages of their analysis tools and the COM001-2 R3 requirement to use the English language are clearly not result or performance based but rather administrative. If
an operator used Portuguese to issue a Reliability Directive they will not be able to satisfy three-part communications in
COM-002-3 in addition to many other standards and requirements they could not comply with. Even if an RC has veto
authority over analysis tools, failure to exercise it would render the authority meaningless. Furthermore, the RC would not
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be able to meet a host of other requirements and standards such as operating within IROL because they would not be able
to assess the system appropriately.
(v) The VSLs for COM-002-3 R3 appear to have some redundancy. The Severe VSL and the second condition in the High
VSL appear to be similar or the same.
(vi) Measurement of compliance to COM-002-3 R1 could be challenging. As the VSL is written, it would appear the
compliance auditor could judge if a Reliability Directive should have been issued. The VSL language that is problematic is
“The responsible entity that required actions to be executed”. Please remove: “required actions to be executed as....”. Who
determines that actions were required? One could argue that failure to identify a communication as a Reliability Directive
means that actions weren’t required but it is doubtful the compliance authorities would take this approach. Thus, there
would appear to be great judgment left to the compliance auditor in determining if a Reliability Directive should have been
issued.
(vii) IRO-014-2 R2 VSLs differentiate violations based on whether the plans, processes, and procedures were distributed or
agreed to. If an intended RC never received the plans, processes and procedures, it would be aware of the need to agree
to them. Hence, if the plans, etc. were not distributed, then the initiating RC will be assigned a Moderate VSL but never any
higher VSLs even if no agreements were received (since no other RCs had received the plans to begin with). We suggest
the SDT to consider rearranging the VSLs and in accordance with any changes to R2 reflecting our suggested changes
summarized under Q7.
(viii) Because it is unlikely that an RC will make notifications without exchanging reliability information or vice versa for IRO014-2 R3, we suggest a more appropriate delineation for the VSLs would be based on the number of other impacted RCs
that were not informed.
(ix) IRO-014-2 R4 VSLs should be defined based upon the number of conference calls the RC does not participate in. R4
requires each RC to participate in “agreed upon conference calls”. Because the statement “conference calls” is plural, VSLs
need to be set based on the aggregate of calls not participated in. Failure to assign VSLs in this way is equivalent to setting
the requirement to “agreed upon conference call” and causes the VSLs to be in violation guideline 3 that the Commission
established in their June 2008 Order on VSLs. Guideline 3 states that the VSL must be consistent with the requirement and
cannot “redefine or undermine the requirement”. Clearly, these VSLs do.
(x) IRO-014-2 R5’s Severe VSL is redundant with the Moderate VSL. Failure to notify one RC meets both VSLs since
Severe uses the word any. Based on the SDT’s response to our comment from the last time, we believe instead of any they
mean “no impacted”. Unfortunately, “any impacted” could be one or two or higher. If it is one, it matches the Moderate
VSL.
(xi) The VSL for IRO-014-2 R8 needs to include the “unless such actions would violate safety, equipment, regulatory or
statutory requirement” clause.
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Response: The RCSDT thanks you for your comments.
I)
II)
III)
IV)
V)
VI)
VII)
VIII)
IX)
The VSL language is intended to accommodate scenarios where only one entity is impacted or several entities are impacted. “The Reliability
Coordinator failed to notify any or more than three impacted Transmission Operators, Balancing Authorities…” and provide the same
measurability level.
The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability Impacts”.
This may include analysis, coordinate cooperative actions or issue “Reliability Directives”.
Th e DT d o e s n o t a g re e . Th e S e ve re VS L h a s “a n y im p a c te d e n titie s ”, m e a n in g th a t n o e n tity wa s n o tifie d with in 60 m in u te s . Th is is
in te n tio n a l. Th e Lo we r, Mo d e ra te a n d Hig h VS Ls a d d re s s in d ivid u a l e n titie s th a t m a y n o t h a ve m e t th e s ta n d a rd o f 60 m in u te s .
R6 is beyond administrative, it is intended to prevent planned reliability tool outages without the consent or knowledge of operating
personnel. Although the DT agrees with the premise that many other requirements may be violated by ineffective communications, the intent
of the requirement is to ensure there are effective communications methods in place for communicating BES activity across entities.
Effective communication are a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of other more
significant performance type standard requirements due to ineffective communications before they impact the BES.
The VSLs were set to be flexible in measuring cases where an 1) acknowledgement is not made at all to a correctly repeated directive and 2)
an acknowledgement is not made at all AND a directive repeated incorrectly was not corrected.
The intent of the DT is to allow the issuing entity to make the determination of “what actions are required” to clearly communicate the
importance to the receiver. The word “required actions to be executed” are integral to the requirement and cannot be removed to meet the
intent. In other words, the trigger of “Reliability Directive” by the issuer highlights these actions as needed to maintain BES reliability and
should be carried out as directed (unless such actions would violate safety, equipment, regulatory or statutory requirement etc ) and all
parties to the conversation need to be very cognizant of the system conditions that are requiring actions. The DT has attempted to craft clear
and specific language that support BES reliability and cannot pre-judge the behaviors of compliance auditors.
The DT agrees and will make clarifying changes.
The DT agrees and will make clarifying changes.
The DT feels this is a core RC responsibility and therefore treated this requirement as binary. RCs must be responsive to other RCs that need
to discuss BES reliability. However, we agree to change “calls” to “call(s)” in R4, to read as follows:
R4. Each Reliability Coordinator shall participate in agreed upon conference calls, at least weekly (per Requirement 1, Part 1.7) with other Reliability
Coordinators within the same Interconnection. [Violation Risk Factor: Lower][Time Horizon: Real-time Operations]
X)
XI)
The DT disagrees. “Failure to notify any” means that none were notified. If there is only a total of one impacted RC, then the VSL would be
Severe.
If the action plan could not be implemented for such instances, then there would be no violation of the requirement and the VSL would not
apply.
OC Standards Review Group
“The comments expressed herein represent a consensus of the views of the above named members of the SERC
OC Standards Review group only and should not be construed as the position of SERC Reliability Corporation, its board or
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its officers.”
Response: The RCSDT thanks you for your comments.
FirstEnergy
1. We believe that this standard should be either handed to the OPCPSDT (Project 2007-02) or the OPCPSDT should hand
over the COM-003-1 standard to this RCSDT (Project 2006-06); and then COM-002 and COM-003 should be merged. Per
our comments in Draft 1 of COM-003-1 (OPCPSDT Project 2007-02) we believe that the Reliability Directive definition
should be broadened to include communications associated with BES related information (similar to the proposed definition
of Interoperability Communication from the OPCPSDT). The following are specifics: a. For better project coordination, since
the plan of the OPCPSDT (2007-02) is to eventually incorporate the COM-002-3 requirements into the new COM-003-1
standard, we believe this should be done now by one SDT. b. The definition of Reliability Directive should be broadened to
include any actions that affect the BES reliability. We suggest the following change to the term Reliability Directive: "A
communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where the recipient is
directed to change the state or report the status of an Element or Facility of the Bulk Electric System." c. Per our suggestion
to broaden the definition of Reliability Directive in "b" above, the proposed definition of Interoperability Communication
proposed by the OPCPSDT can be eliminated. d. With respect to the proposed R2 and R3 of COM-002-3 and requirement
R5 of COM-003-1 which all which essentially discuss three-part communication, could be combined and covered by COM002-3. e. R1 of COM-003-1 that requires communication protocols procedures can be covered in COM-002-3.2.
Implementation Plan - The proposed timeline for implementing these standards changes is the 1st day of the 1st quarter
after applicable regulatory approvals. We believe that since there are numerous changes to and retirement of requirements,
this will place a significant compliance burden on industry and warrants more time to adjust compliance evidence and
tracking. Furthermore, standard COM-001-2 is adding the Distribution Provider and Generator Operator as applicable
entities which will cause these entities to show compliance with a requirement they previously were not responsible for.
Therefore, we believe that a minimum of two calendar quarters for implementing these changes is appropriate.
Response: The RC SDT thanks you for your comment. The RC SDT feels that the Reliability Directive is an important tool for RC, BA and TOP to
maintain reliability and that the revisions are consistent with parts of the directives in FERC Order 693. The work of the RC SDT along with the
OPCP SDT, as currently recognized, will cover the original intent of COM-002 and still provide a “defense in depth strategy” as suggested by the
NERC comment. Consensus appears to have been achieved with respect to the definition of Reliability Directive and the requirements that the RC
SDT have developed for COM-002. This will further the efforts of the OCPC SDT in achieving stakeholder consensus for their proposed
requirements in COM-003. The intent of the DT is to preserve a method for RCs, BAs and TOP to make the determination of “what actions are
required” and clearly communicate the importance to the receiver above normal day-to-day operational communications. The trigger of “Reliability
Directive” by the issuer highlights these actions as needed to maintain BES reliability and should be carried out as directed (unless such actions
would violate safety, equipment, regulatory or statutory requirement per the language of the requirement) and all parties to the conversation need to
be very cognizant of the system conditions that are requiring actions. The DT has attempted to craft clear and specific language that support BES
reliability and hopes that this work can support and enhance the development of the OPCP SDT.
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Ameren
Question 8 Comment
1.In COM-001 R2, this “impacted entities’ language is unworkable. Some entities might be impacted because they get
information from the RC, i.e indirectly from the entity with the loss. Team should address direct relationships somehow.2.In
COM-001,R4, does the team consider the need for this for the AIC?3.The team should note that there is no requirement to
even have AIC. Thus R1 would only apply if you have one.
Response: The RCSDT thanks you for your comment. The DT feels that impacted adds clarity to the requirement by limiting the obligation
appropriately. Industry consensus appears to support that “impacted” is a reasonable clarification.
NERC
As stated in the response to Question 1, the scope of COM-001-2 is unclear as to whether it applies to both verbal and data
communication. We believe that it should.
Response: The RCSDT thanks you for your comment. The RCSDT believes that data communication is covered under IRO-010, R3 which states:
Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall provide data and information, as specified, to the Reliability Coordinator(s) with which it has a reliability
relationship. (Violation Risk Factor: Medium) (Time Horizon: Operations Planning; Same-day Operations; Real-time Operations)
Central Lincoln
COM-001 M3, M4, COM-002 M2, and IRO-001 M1, and M2 all require evidence of DPs and/or LSEs “which may include,
but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent documentation. ”While we appreciate the inclusion of “equivalent documentation”, we are unsure what might
qualify and who determines what qualifies as equivalent. We still believe COM-001 should not apply to DPs and LSEs,
since these entities do not own or operate BES assets. Please consider this stakeholder input as well. While CIP-001 M4
can show that documented communication proves capability for R4, an entity has no way of proving capability if such
communications did not take place during the audit period. We are unsure if the SDT realizes that not all of the entities
subject to these standards maintain 24/7 dispatch desks. Much effort will go into complying with standards dealing with
afterhour’s directives that will never come, because the issuing entity will realize any action requested will not be timely
enough and plan accordingly.
Response: The RCSDT thanks you for your comment. DP and LSE were included in this standard per FERC Order 693 Directive. “Equivalent”
documentation is included to provide potential alternatives for entities to provide to prove compliance with the requirement. Compliance audit
personnel will review all documentation to determine compliance with a requirement.
Exelon
COM-001-2 R2. Please consider in place of “impacted entities”, substitute “all applicable entities”.
Response: The RCSDT thanks you for your comment. The proposed substitute language has the same net effect as the current language and
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therefore no change was made.
ITC Holdings
Comments: IRO-001-2 R4 has an errant comma after the first occurrence of the word “Impacts”. IRO-014-2 R8 should
have the first occurrence of the word “or” removed. Also, a new R9 (and associated M9) should be added requiring the RC
who cannot agree on the mitigation plan due to safety, equipment, regulatory, or statutory requirements to notify the RC
experiencing the Adverse Reliability Impact of the reason for the inability to implement the mitigation plan.
Response: The RCSDT thanks you for your comment. The comma in IRO-001-2 R4 has been removed.
The first “or” in IRO-014-2 R8 has been removed.
The suggested R9/M9 are unnecessary. Any RC that claims that a mitigation plan would violate safety, equipment, regulatory or statutory requirements
would have to document that as part of complying with R8.
Northeast Utilities
For IRO-001-2, the VSL language for R1, R4, and R5 is not clear. Specifically, for the R1 VSL the text appears to be
reversed between High and Severe; and for R4 and R5, please clarify what is meant by “any or more than three”.
Response: The RCSDT thanks you for your comment. The High VSL and Severe VSL language is not reversed. The failure to act to mitigate existing
Adverse Reliability Impacts is more negatively-impactful to BES reliability than the failure to prevent future Adverse Reliability Impacts.
“Any or more than three” means that if no TOPs or BAs were notified or, in the case of an RC having four or more TOPs and BAs in its area, more
than 3 of them were not notified.
Bonneville Power Administration
In most proposed NERC standards, it seems the tried and true method of writing a requirement is to list the entities required
to implement the action, list the required action, and then list any exceptions to the required action. In proposed standard
COM-001-2, Requirement R3, the SDT lists the exceptions before the rule. In proposed standard COM-001-2, Measure
M1, when it is discussing quarterly testing, it uses the term, “alternative Interpersonal Communications.” The word
“alternative” should be capitalized. (Please see our comment on question #2 regarding the overall use of the term
‘Alternative Interpersonal Communications.’) we agree and made the change
In proposed standard COM-001-2, Measure M1, after the word, “substitute,” the word “Alternative” should be added in order
to use similar language in both Requirement R1 and in Measure M1. (Again, please see my comment on question #2
regarding the overall use of the term ‘Alternative Interpersonal Communications.’) we agree and made the change
In proposed standard COM-001-2, Measure M2, it uses the wording “normal communications capabilities.” If our comment
on question #1 is acceptable in its entirety, and the SDT decides not to use the term, ‘Interpersonal Communication,’ then
the wording of Measure M2 is also acceptable. However, if the SDT decides to continue with their use of that term, then this
phrase should be replaced with “normal Interpersonal Communications capabilities” in order to use similar language in both
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Requirement R2 and in Measure M2. we agree and made the change
In proposed standard COM-001-2, VSL for R2, the Lower VSL uses the word “failed” to describe notifying the impacted
entities within the tight bounds of a time frame, in this case, “more than 60 minutes but less than or equal to 70 minutes”.
According to the given wording, every entity that is fully compliant with this standard would have “failed” to notify the
impacted entities within the narrow bounds of the Lower VSL’s time constraint! A similar comment could be made for the
Moderate, High and Severe VSL descriptions also. The wording “failed to notify” needs to be taken out and replaced with
“notified.” Related to this, in the Moderate VSL, the description of a responsible entity notifying at least one, but not all
impacted entities within 60-minutes would tend to negate the Lower VSL. If the SDT were trying to force a responsible
entity into making at least one phone call of notification to one of the impacted entities within 60-minutes, the Severe VSL’s
description accomplishes this feat all by itself. However, if the SDT were insistent on all impacted entities being notified
within 60-minutes or a Moderate VSL will result, then that action makes the Lower VSL rather useless. VSLs are only
applied when there is a violation. The time bounds are appropriate for a violation of the requirement
In proposed standard COM-002-3, Measure M3, it uses the term “Directive” by itself. It seems appropriate for what is being
discussed that the term “Reliability Directive” should have been used. We added Reliability
In proposed standard COM-002-3, VSL for R3, the High VSL describes the responsible entity failing to respond
appropriately, either by acknowledging the recipient when they repeated the intent correctly or by failing to reissue when the
recipient did not repeat the intent correctly. This would seem to take care of the options...either the recipient was correct or
they were incorrect, but not both. However, the Severe VSL, by using the word “AND” connects the two thoughts and
provides for the recipient to be both correct and incorrect at the same time. Therefore, the Severe VSL seems to contradict
itself, while the spirit of the VSL seems to be handled quite nicely by the High VSL by itself. It is therefore suggested that
the SDT consider replacing the Severe VSL with the High VSL. The rcsdt believes that the VSLs are appropriate as
written
In proposed standard IRO-001-2, Measure M3, on the second to the last line, the measure repeats the wording “that it,”
making it redundant. We have made the edit
In proposed standard IRO-001-2, Data Retention (Part D, Section 1.3), on the first bullet, the word “operator” (following
“Generator”) should be capitalized. We have made the edit
In proposed standard IRO-001-2, High and Severe VSLs for Requirement R1, we don’t really see the utility of separating the
parts of failing to prevent Adverse Reliability Impacts and failing to mitigate the magnitude or duration of such impacts.
Maybe the SDT could give some examples, because we would be just as fine combining the two into one VSL and therefore
simplifying the VSL part of the standard. VSL drafting guidelines indicate that multiple VSLs should be written for a
requirement when feasible. It is feasible for this requirement.
In proposed standard IRO-001-2, Severe VSL for Requirement R2, the VSL should include wording to indicate that an
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exception can be granted to the responsible entity failing to comply with the given Reliability Directive due to safety,
equipment, or regulatory or statutory requirements. Otherwise, the responsible entity will be given a Severe VSL every time
one of these exceptions comes up. If an entity did not comply with a directive for a safety issue, then the entity did
not violate the requirement. The VSL only applies when a requirement is violated.
In proposed standard IRO-001-2, Severe VSL for Requirement R4, we are not entirely sure what the SDT was trying to say,
but the spirit of the VSL would seem to be captured if the SDT removed the wording “any or” and left the VSL to say in part,
“...failed to issue an alert to more than three...”In a related way, for the Severe VSL for Requirement R5, the spirit of the VSL
would seem to be captured if the SDT removed the wording “any or” and left the VSL to say in part “...failed to notify more
than three...” The intent of the wording is to allow multiple VSLs for the requirement. The word “any” indicates
that there were no notifications made when there were less than three notifications to be made.
Response: The RCSDT thanks you for your comment. See responses above.
Florida Municipal Power Agency
and Some Members
IRO-001-2, R5 refers to only transmission problems being mitigated and not to other types of issues that could result in a
threat of an Adverse Reliability Impacts, such as a large supply / demand imbalance (capacity or energy Emergency). IRO001-2, R6 FMPA does not quite understand the requirement, is the intent to allow Operating Personnel the authority to veto
planned outages "in" its own analysis tools, rather than "to"?
Response: The RCSDT thanks you for your comment. We have removed the word “transmission” from the requirement.
R5: Each Reliability Coordinator that identifies an expected or actual threat with Adverse
Reliability Impacts, within its Reliability Coordinator Area shall notify all impacted
Transmission Operators and Balancing Authorities in its Reliability Coordinator Area when the
problem has been mitigated. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
Regarding IRO-001-2, R6, the planned outages mentioned are actual outages of the analysis tools themselves, not planned outages of transmission elements.
No changes made.
PPL
No additional comments.
Operating Personnel
Communications Protocols SDT
No Comment
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PacifiCorp
No comment.
American Electric Power
Nothing additional at this time.
PNGC Power (15 member
utilities)
PNGC (15 members) would like to associate itself with Steve Alexanderson's (Central Lincoln PUD) comments re 200606:"COM-001 M3, M4, COM-002 M2, and IRO-001 M1, and M2 all require evidence of DPs and/or LSEs “which may
include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or
equivalent documentation. ”While we appreciate the inclusion of “equivalent documentation”, we are unsure what might
qualify and who determines what qualifies as equivalent. We still believe COM-001 should not apply to DPs and LSEs,
since these entities do not own or operate BES assets. Please consider this stakeholder input as well. While CIP-001 M4
can show that documented communication proves capability for R4, an entity has no way of proving capability if such
communications did not take place during the audit period. We are unsure if the SDT realizes that not all of the entities
subject to these standards maintain 24/7 dispatch desks. Much effort will go into complying with standards dealing with
afterhour’s directives that will never come, because the issuing entity will realize any action requested will not be timely
enough and plan accordingly."
Response: The RCSDT thanks you for your comment. The DT included DPs and LSEs per FERC Order 693.
The DT believes your comment regarding “CIP-001 M4” is actually in reference to COM-001-2 M4”. While the DT is concerned that any proposed
requirements must be clear and reasonably simple for which to document compliance, in this instance, a simple test phone call at a reqular interval
would prove capability (assuming it were recorded.)
Manitoba Hydro
R2 2.1 If these actions are required as real time action, “Agreed to” should be opened up to “Acknowledged by”. “Agreed
to” in this requirement would be acceptable when there is time for impacted RC to study the other RC plans to determine
impact on their system. To further justify this suggestion, R3 says “make notifications . . . with impacted RC”. This
statement indicates no commitment to the notifications and therefore presumes “acknowledgement”.R7. Move this
requirement to R2 and label as R2.3. R2 is “Agreed to” and R7 is “Not Agreed to”. R8 covers the action required when “Not
agreed to”R8. The only suggested addition to this is “When an RC with the identified Adverse Reliability Impact has created
and implemented a plan with other affected RC”, there should be an R8.1 stating “No RC shall place a burden on other
RC’s” and or/and an R8.2 stating, that “Reliability will override economics”. The addition of these two sub requirements
would also enhance R7 by removing all other reasoning that an impacted RC may dwell on to “not agree to”.
Response: The RCSDT thanks you for your comment. We assume that this comment is in reference to IRO-014-2. The RCSDT does not agree with
your proposed revision. The intent of the requirements is to have the parties agree to the course of action required to maintain reliability.
Calpine Corporation
Regarding COM-001-2 R4. Many PURPA Qualifying Facilities and tolled Facilities communicate only with a scheduling
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coordinator or similar entity, not necessarily directly with the Transmission Operator and/or Host Balancing Authority. The
standard should be rewritten to clarify that direct communications between these Generator Operators and their
Transmission Operator and/or Host Balancing Authority is either not required or that communications through their
established paths of communication meets the requirement.
Response: The RCSDT thanks you for your comments. Effective communications rely on an effective hierarchy. It is crucial for a host TOP or BA to
have effective communications with GOs attached to their systems so that BES operations can be coordinated, much like RCs must be able to
communicate effectively with the system within its footprint. PURPA qualifying facilities can impact BES reliability, and, as such, are included here.
Duke Energy
Requirement R6 of IRO-001-2 contains the capitalized term “Operating Personnel”. This is not a NERC-defined term and
should not be capitalized. As a general comment on new and revised NERC-defined terms, we believe that when such
terms are introduced in a project with multiple standards, the terms should be included in the “Definitions of Terms Used in
Standard” section of each standard. For example, in this project the term “Adverse Reliability Impact” is revised in IRO-0012, but while it is also used in IRO-014-2, it no longer appears in the “Definitions of Terms Used in Standard” section of IRO014-2.
Response: The RCSDT thanks you for your comment and has changed “Operating Personnel” to “System Operator”.
Southwest Power Pool
SPP has also worked collaboratively with the IRC SRC on the comments submitted by that group on this standard and we
fully support those. However, SPP found additional concerns at the last minute which could not be included in the SRC set
due to the submittal deadline and has chosen to submit these separately. There are 10 other standards where the word
“Directive” is used. Will the term Reliability Directive replace them, or will we get a different definition for Directive, or will
both terms be the same?
The RC SDT believes that “directive” is lowercase in the other instances in NERC standards. The RTO SDT, OPCP SDT and RC SDT have attempted
to move toward “Reliability Directive” in concert so as to remove the remaining ambiguity from NERC standards.
The intent of the DT is to preserve a method for RCs, BAs and TOP to make the determination of “what actions are required” and clearly communicate
the importance to the receiver above normal day-to-day operational communications. The trigger of “Reliability Directive” by the issuer highlights
these actions as needed to maintain BES reliability and should be carried out as directed (unless such actions would violate safety, equipment,
regulatory or statutory requirement per the language of the requirement) and all parties to the conversation need to be very cognizant of the system
conditions that are requiring actions. The DT has attempted to craft clear and specific language that support BES reliability and hopes that this work
can support and enhance the development of the OPCP SDT and subsequent expansion of the term “Reliability Directive”.
E.ON U.S.
The definition of Reliability Directive should be incorporated into COM-003-1 with an associated single requirement that
requires the use of Three-part Communication during the communication of a Reliability Directive.
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Response: The RCSDT thanks you for your comment. The DT has attempted to craft clear and specific language that support BES reliability and
hopes that this work can support and enhance the development of the OPCPSDT and subsequent expansion of the term “Reliability Directive”.COM003 is outside the scope of the RCSDT project.
Public Service Enterprise Group
Companies
The PSEG Companies are generally in agreement with the proposal.
Response: The RCSDT thanks you for your comment.
Southern Company Services
These standards are more restrictive and prescriptive each time that a revision is issued for comments. It appears that the
SDT does not believe that entities operating the Bulk Electric System cannot operate the system in a reliable manner using
cooperation between parties.
Response: The RCSDT thanks you for your comment. The DT feels that these standard requirements have been improved to benefit reliability and
act as a “backstop” to prevent the breakdown of cooperation between parties and incent effective communications between operators of the BES.
NERC Standards Review
Subcommittee
1) This standard could be boiled down to one requirement and that is to maintain the continuous ability to communicate
with other appropriate registered entities regardless of the need for a backup system.
2) For IRO-001-2 R1, “act” should be removed. The RC can’t act but can only issue Reliability Directives per the functional
model.
3) IRO-001-2 R4 and R5 Severe VSLs need to have “any or” removed. The VSL should only apply for three or more and
“any or” conflicts with this.COM-001-2 R2 Severe VSL conflicts with other VSLs. Specifically, the use of the word “any”
in the Severe VSL is problematic. Notifying one entity at 65 minutes fits both the Lower VSL and Severe VSL as well.
We suggest deleting the first portion of the Severe VSL that reads, “The responsible entity failed to notify any impacted
entities of the failure of its normal Interpersonal Communications capabilities within 60 minutes.”
4) COM-001-2 R2 needs to be coordinated with EOP-008-1 since EOP-008-1 R1.5 is requiring 2 hours. COM-001-2 R1
should be clarified to remove 60 minutes. Perhaps the specific time frame is too administrative and too dependent on
the circumstances and doesn’t purport to directly impact reliability of the backup functionality. If a time frame is desired
perhaps the registered entity which knows their backup functionality capabilities and their plan to actuate these
capabilities could be the best entity to define a reasonable immediate time frame.
5) The NERC BOT recently approved the pursuing the Results/Performance Based standards development activity.
Based on this recent decision, we believe the BOT has signaled their intent to remove administrative types of
requirements from all standards. The IRO-001-2 R6 for the RC to have the authority to veto outages of their analysis
tools and the COM-001-2 R3 requirement to use the English language are clearly not result or performance based but
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rather administrative. If an operator used Portuguese to issue a Reliability Directive they will not be able to satisfy
three-part communications in COM-002-3 in addition to many other standards and requirements they could not comply
with. Even if an RC has veto authority over analysis tools, failure to exercise it would render the authority meaningless.
Furthermore, the RC would not be able to meet a host of other requirements and standards such as operating within
IROL because they would not be able to assess the system appropriately.
Response: The RCSDT thanks you for your comments.
1.
2.
3.
4.
5.
The DT has attempted to eliminate redundancy and ambiguity while not creating any reliability gaps. As written, the requirements are geared
to incent folks to have effective communications in-place at all times while flexible enough to accommodate technology changes and process
improvements by the industry.
The RC must “act” (ie. do something “to prevent or mitigate the magnitude or duration of events that result in Adverse Reliability Impacts”.
This may include analysis, coordinate cooperative actions or issue “Reliability Directives”. “Act” does not imply solely the manipulation of
BES elements.
The VSL language is intended to accommodate scenarios where only one entity is impacted or several entities are impacted. “The Reliability
Coordinator failed to notify any or more than three impacted Transmission Operators, Balancing Authorities…” and provide the same
measurability level.
The RCSDT notes that EOP-008-1 is a proposed standard that has not been approved for enforcement. Also, EOP-008-1 deals with an entire
control center where COM-001 deals with Interpersonal Communications capability with another entity. We will retain the original 60 minute
timeframe.
R6 is beyond administrative, it is intended to prevent planned reliability tool outages without the consent or knowledge of operating
personnel. Although the DT agrees with the premise that many other requirements may be violated by ineffective communications, the intent
of the requirement is to ensure there are effective communications methods in place for communicating BES activity across entities. Effective
communication are a cornerstone of BES reliability and the intent of the requirement is to prevent the violation of other more significant
performance type standard requirements due to ineffective communications before they impact the BES.
Xcel Energy
We would like to restate our belief that the Standard should explicitly state the requirement for RCs, TOPs and BAs to have
both primary and alternate means of communication. To “imply” a required element within a Standard is inconsistent with
the NERC Reliability Standards Development Procedure, which states “All mandatory requirements of a reliability standard
shall be within an element of the standard.” We would suggest a requirement language that simply states “Each Reliability
Coordinator, Transmission Operator, and Balancing Authority shall maintain a means for both primary Interpersonal
Communication as well as Alternative Interpersonal Communication used to communication real-time operating
information.“
Response: The RCSDT thanks you for your comment. The RCSDT has crafted the latest versions (as supported by stakeholder comments) to
support reliable communications by better describing how industry communicates and providing flexibility for the adoption of alternative
communication media. The RCSDT also tried to minimize over-prescriptive requirements that result in no value to reliability and impose an
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administrative burden.
Electric Market Policy
We would like to thank, AND highly commend this SDT for their effort. This is the type of effort that every SDT should strive
for. Elimination of requirements that are either redundant or unnecessary, and therefore distract entities, is every bit as
important to the standards process as is the creation of new standards where reliability gaps are found. The proliferation of
new and revised standards is becoming a concern for many in this industry and many of us feel the effort going into the
review and compliance documentation is reducing the focus on monitoring and otherwise insuring that reliable operations
can be maintained.
Response: The RCSDT thanks you for your comments and agrees reducing redundancy and ambiguity in the standards improves industry focus and
therefore reliability of the BES.
ERCOT ISO
ERCOT ISO offers the following additional comments:
COM-001-2
1) The SDT should consider coordinating their efforts with the OPCP drafting team efforts (COM-003) to ensure consistency
across the standards.
2) For R4 – ERCOT ISO recommends considering adding Load-Serving Entity to the applicability due to their role in
capacity and energy emergencies.
3) With respect to the Measures, “alternative” needs to be capitalized in M1. Also, if the intent is to include items such as
regular phones or data links that are daily use items then Measures should reflect this.
4) ERCOT ISO suggests the following change to the terms Adverse Reliability Impact and Emergency. We think these
simple changes will tie all the terms together.
Response: The RC SDT thanks you for your comments.
1) The RC SDT feels that the concept of a Reliability Directive is an important tool for RC, BA and TOP to maintain reliability and that the revisions are
consistent with parts of the directives in FERC Order 693. The work of the RC SDT along with the OPCP SDT, as currently recognized, will cover the
original intent of COM-002 and still provide a “defense in depth strategy” as suggested by the NERC comment. Stakeholder requests and consensus
appears to have been achieved with respect to the definition of Reliability Directive and the requirements that the RC SDT have developed for COM002. This will further the efforts of the OCPC SDT in achieving stakeholder consensus for their proposed requirements in COM-003. 2) The RCSDT
has relied on the authority hierarchy (RC/ BA/ TOP / DP) to ensure accountability with the current FM, while not over-prescribing requirements. The
RC SDT notes that, per the Functional Model, a DP may “direct” an LSE to communicate requests for voluntary load curtailment and not reliability
situations:
Item 9 on page 47 of version 5 of the Functional Model: “Directs Load-Serving Entities to communicate requests for voluntary load curtailment.”
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The RCSDT will forward this comment to the FMWG for their consideration in revising the language.
3) & 4) Please see previous responses to your comments assuming those are the referenced comments.
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 3, 2010.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the third draft. The team is posting for a
30 day pre-ballot review.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments on third posting
March 2010
2. Post Standards for pre-ballot period.
January 2011
3. Standards posted for initial and recirculation ballots.
February 2011
4. Standards sent to BOT for approval.
March 2011
5. Standards filed with regulatory authorities.
June 2011
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any medium that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal
Communications used for day-to-day operation.
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A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate Interpersonal
Communication capabilities for the exchange of Interconnection and operating
information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators..
5.
Effective Date:
The first day of the first calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:
R1.1.
All Transmission Operators, Balancing Authorities and Interchange
Coordinators within its Reliability Coordinator Area
R1.2.
Adjacent Reliability Coordinators within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area
R2.2.
Adjacent Reliability Coordinators within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:
Draft 4:
R3.1.
Its Reliability Coordinator
R3.2.
Each Balancing Authority within its Transmission Operator Area.
R3.3.
Each Distribution Provider within its Transmission Operator Area.
R3.4.
Each Generator Operator within its Transmission Operator Area.
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R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R4.1.
Its Reliability Coordinator
R4.2.
Each Balancing Authority within its Transmission Operator Area.
R5. Each Balancing Authority shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information [Violation
Risk Factor: High][Time Horizon: Real-time Operations]:
R5.1.
Its Reliability Coordinator
R5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area
R5.3.
Each Distribution Provider within its Balancing Authority Area
R5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area
R5.5.
Each Interchange Coordinator within its Balancing Authority area as well as
adjacent Interchange Coordinators.
R6. Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R6.1.
Its Reliability Coordinator
R6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area)
R7. Each Distribution Provider shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]
R7.1.
Its Transmission Operator
R7.2.
Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1.
Its Balancing Authority
R8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall,
on at least a monthly basis, test its Alternative Interpersonal Communications
capability. If the test is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communications within 2 hours.
[Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
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R10. Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
R11. Unless dictated by law or otherwise agreed to, each Reliability Coordinator,
Transmission Operator, Balancing Authority, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Purchasing-Selling Entity and Distribution
Provider shall use English as the language for communications between functional
entities. [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it has Interpersonal
Communications capability with all Transmission Operators, Balancing Authorities
and Interchange Coordinators within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it designated an Alternative
Interpersonal Communications capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it has a Interpersonal
Communications capability with its Reliability Coordinator, with each Balancing
Authority and each Distribution Provider and each Generator Operator within its
Transmission Operator Area. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator, and with each Balancing Authority within its
Transmission Operator Area. (R4.)
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Comment [SC1]: This requirement is being
vetted by the OPCPSDT in COM-003. This
requirement and measure will be removed from
COM-001.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
M5. Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each Generator Operator that operates Facilities within its
Balancing Authority Area and each Distribution Provider within its Balancing
Authority Area, and each Interchange Coordinator within its Balancing Authority area
as well as adjacent Interchange Coordinators. (R5)
M6. Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator and each Transmission Operator that operates Facilities
within its Balancing Authority Area. (R6)
M7. Each Distribution Provider shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Transmission
Operator and its Balancing Authority. (R7)
M8. Each Generator Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Balancing
Authority and its Transmission Operator. (R8)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, dated operator logs, dated voice recordings or dated transcripts of voice
recordings, electronic communications, or equivalent, that it tested, at least on a
monthly basis, its Alternative Interpersonal Communications capabilities designated in
R2, R4 or R6. If the test was unsuccessful, the entity shall have and provide upon
request evidence that it initiated action to repair or designated a replacement
Alternative Interpersonal Communications within 2 hours. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall have and provide upon request
evidence that could include, but is not limited to dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, it notified impacted entities within 60 minutes of the detection of a failure
of its Interpersonal Communications capabilities that lasted 30 minutes or longer.
(R10.)
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall keep the most recent twelve months of historical data (evidence) for
Requirements R1, R2, R3, R4, R5, R6, R9 and R10, Measures M1, M2, M3, M4,
M5, M6, M9 and M10 as applicable..
Each Distribution Provider shall keep the most recent twelve months of historical
data (evidence) for Requirements R7 and R10, Measures M7 and M10.
Each Generator Operator shall keep the most recent twelve months of historical
data (evidence) for Requirements R8 and R10, Measures M8 and M10.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider or Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliance until the
Compliance Enforcement Authority finds it compliant or for the time period
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
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2.
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
N/A
N/A
N/A
The Reliability Coordinator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 1.1 or 1.2.
R2
N/A
N/A
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
2.1 or 2.2.
R3
N/A
N/A
N/A
The Transmission Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 3.1, 3.2, 3.3 or
3.4.
R4
N/A
N/A
N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
4.1 or 4.2.
N/A
N/A
N/A
The Balancing Authority failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 5.1, 5.2, 5.3,
5.4 or 5.5.
N/A
N/A
N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
R5
R6
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R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
6.1 or 6.2.
R7
N/A
N/A
N/A
The Distribution Provider failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 7.1 or 7.2.
R8
N/A
N/A
N/A
The Generator Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 8.1 or 8.2.
R9
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications within
2 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications within
12 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications within
24 hours.
The responsible entity failed to test
the Alternative Interpersonal
Communications capability on at
least a monthly basis.
The responsible entity failed to notify
the impacted entities in more than 60
minutes but less than or equal to 70
minutes.
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its normal
Interpersonal Communications
capabilities within 60 minutes.
The responsible entity failed to notify
the impacted entities in more than 80
minutes but less than or equal to 90
minutes.
The responsible entity failed to notify
any impacted entities of the failure of
its normal Interpersonal
Communications capabilities.
R10
The responsible entity tested the
Alternative Interpersonal
Communications capability and
identified a problem but didn’t initiate
action to repair or designate a
replacement Alternative Interpersonal
Communications within 2 hours.
OR
OR
The responsible entity failed to notify
the impacted entities in more than 90
minutes.
The responsible entity failed to notify
the impacted entities in more than 70
minutes but less than or equal to 80
Draft 4: November 23, 2010
OR
Page 9 of 11
S ta n d a rd COM-001-2 — Co m m u n ic a tio n s
R#
Lower VSL
Moderate VSL
High VSL
minutes.
Draft 4: November 23, 2010
Page 10 of 11
Severe VSL
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
Draft 4: November 23, 2010
Page 11 of 11
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 3, 2010.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the firstthird draft. The team is seeking
comments on the revised standardsposting for a 30 day pre-ballot review.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Respond to comments on third posting
March 2010
2. Post Standards for pre-ballot period.
April 2010January
2011
3. Standards posted for initial and recirculation ballots.
May 2010February
2011
4. Standards sent to BOT for approval.
July 2010March
Draft 3:
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
2011
5. Standards filed with regulatory authorities.
Draft 3:
December 30, 20094:
November 23, 2010
September 2010June
2011
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any methodmediumthod that allows two or more individuals
to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any method Interpersonal Communication that is
able to serve as a substitute for, and is redundant to normal Interpersonal Communication and
does not utilize the same infrastructure (medium) as, normal Interpersonal Communications used
for day-to-day operation.
Draft 3:
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequate Interpersonal
Communication capabilities for the exchange of Interconnection and operating
information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. Distribution Providers.
4.5. Generator Operators...
4.6. Transmission Service Providers.
4.7. Load-Serving Entities.
4.8. Purchasing-Selling Entities.
5.
Effective Date:
The first day of the first calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
identify and test, on a quarterly basis, its Alternative Interpersonal Communications
capability used for communicating real-time operating information. If the test is
unsuccessful, the entity shall take action within 60 minutes to restore the identified
alternative or identify a substitute Alternative Interpersonal Communications
capability. [Violation Risk Factor: High][Time Horizon: Real-time Operations]
R1. Each Reliability Coordinator, shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:
R1.1.
All Transmission Operators, Balancing Authorities and Interchange
Coordinators within its Reliability Coordinator Area
R1.2.
Adjacent Reliability Coordinators within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R2.1.
Draft 3:
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R2.2.
Adjacent Reliability Coordinators within the same Interconnection.
R3. Each Transmission Operator and shall have Interpersonal Communications capability
with the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:
R3.1.
Its Reliability Coordinator
R3.2.
Each Balancing Authority within its Transmission Operator Area.
R3.3.
Each Distribution Provider within its Transmission Operator Area.
R3.4.
Each Generator Operator within its Transmission Operator Area.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R4.1.
Its Reliability Coordinator
R4.2.
Each Balancing Authority within its Transmission Operator Area.
R5. Each Balancing Authority shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information [Violation
Risk Factor: High][Time Horizon: Real-time Operations]:
R5.1.
Its Reliability Coordinator
R5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area
R5.3.
Each Distribution Provider within its Balancing Authority Area
R5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area
R5.5.
Each Interchange Coordinator within its Balancing Authority area as well as
adjacent Interchange Coordinators.
R6. Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R6.1.
Its Reliability Coordinator
R6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area)
R7. Each Distribution Provider shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information
[Violation Risk Factor: High][Time Horizon: Real-time Operations]
Draft 3:
R7.1.
Its Transmission Operator
R7.2.
Its Balancing Authority.
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R8. Each Generator Operator shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1.
Its Balancing Authority
R8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall,
on at least a monthly basis, test its Alternative Interpersonal Communications
capability. If the test is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communications within 2 hours.
[Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
R2.R10.
Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider, and Generator Operator shall notify impacted entities
within 60 minutes of the detection of a failure of its normal Interpersonal
Communications capabilities that lasts 30 minutes or longer. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
R3.R11.
Unless dictated by law or otherwise agreed to, each Reliability
Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Purchasing-Selling Entity and
Distribution Provider shall use English as the language for all inter-entity Bulk Electric
System (BES) reliability communications between and among operating personnel
responsible for the real-time generation control or operation of the interconnected
BES.functional entities. [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
R4. Each Distribution Provider and Generator Operator shall have Interpersonal
Communications capability with its Transmission Operator and Balancing Authority
for the exchange of Interconnection and operating information. [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, operator logs, voice recordings or transcripts of voice recordings,
electronic communications, or equivalent, that it identified and tested, on a quarterly
basis, alternative Interpersonal Communications capabilities used for communicating
real-time operating information. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it took action within 60 minutes to restore the
identified alternative or identified a substitute Interpersonal Communications
capability. (R1.)
M1. Each Reliability Coordinator , Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to
physical assets, dated equipment specifications and installation documentation, dated
test records, dated operator logs, dated and timestamped voice recordings or dated and
timestamped transcripts of voice recordings, electronic communications, or equivalent,
that it has Interpersonal Communications capability with all Transmission Operators,
Draft 3:
December 30, 20094:
November 23, 2010
Page 6 of 14
Comment [SC1]: This requirement is being
vetted by the OPCPSDT in COM-003. This
requirement and measure will be removed from
COM-001.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Balancing Authorities and Interchange Coordinators within its Reliability Coordinator
Area and with adjacent Reliability Coordinators within the same Interconnection. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it designated an Alternative
Interpersonal Communications capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it has a Interpersonal
Communications capability with its Reliability Coordinator, with each Balancing
Authority and each Distribution Provider and each Generator Operator within its
Transmission Operator Area. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator, and with each Balancing Authority within its
Transmission Operator Area. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each Generator Operator that operates Facilities within its
Balancing Authority Area and each Distribution Provider within its Balancing
Authority Area, and each Interchange Coordinator within its Balancing Authority area
as well as adjacent Interchange Coordinators. (R5)
M6. Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator and each Transmission Operator that operates Facilities
within its Balancing Authority Area. (R6)
M7. Each Distribution Provider shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
Draft 3:
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Transmission
Operator and its Balancing Authority. (R7)
M8. Each Generator Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent, that it has Interpersonal Communications capability with its Balancing
Authority and its Transmission Operator. (R8)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that could include, but is not limited to dated
test records, dated operator logs, dated voice recordings or dated transcripts of voice
recordings, electronic communications, or equivalent, that it tested, at least on a
monthly basis, its Alternative Interpersonal Communications capabilities designated in
R2, R4 or R6. If the test was unsuccessful, the entity shall have and provide upon
request evidence that it initiated action to repair or designated a replacement
Alternative Interpersonal Communications within 2 hours. (R9.)
M2.M10.
Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider and Generator Operator shall have and provide upon
request evidence that could include, but is not limited to dated operator logs, dated
voice recordings or dated transcripts of voice recordings, electronic communications,
or equivalent, it notified impacted entities within 60 minutes of the detection of a
failure of its normalInterpersonal Communications capabilities that lasted 30 minutes
or longer. (R2R10.)
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Purchasing-Selling
Entity, and Distribution Provider shall have and provide upon request evidence that
could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, that will be used to
determine that its personnel used English as the language for all inter-entity BES
reliability communications between and among operating personnel responsible for the
real-time generation control or operation of the interconnected BES. If a language
other than English is used, each party shall have and provide upon request evidence
that could include, but is not limited to operator logs, voice recordings or transcripts of
voice recordings, electronic communications, or equivalent, of agreement to use the
alternate language or the law that requires the use of an alternate language. (R3.)
M4. Each Distribution Provider and Generator Operator shall have and provide upon
request evidence that could include, but is not limited to operator logs, voice recordings
or transcripts of voice recordings, electronic communications, or equivalent that it had
Interpersonal Communications capabilities with its Transmission Operator and
Balancing Authority for the exchange of Interconnection and operating information.
(R4.)
Draft 3:
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall keep the most recent three years of historical data (evidence) for
Requirement R1, Measure M1.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall keep the most recent twelve months of historical data (evidence) for
Requirement R2, Measure M2.Requirements R1, R2, R3, R4, R5, R6, R9 and
R10, Measures M1, M2, M3, M4, M5, M6, M9 and M10 as applicable..
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Purchasing-Selling Entity, and Distribution Provider shall keep evidence for
Requirement R3, Measure M3 for the most recent 3twelve months. of historical
data (evidence) for Requirements R7 and R10, Measures M7 and M10.
Each Generator Operator shall keep the most recent twelve months of historical
data (evidence) for Requirements R8 and R10, Measures M8 and M10.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider or Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliance until the
Compliance Enforcement Authority finds it compliant. or for the time period
specified above, whichever is longer.
Each Distribution Provider and Generator Operator shall keep the most recent
three years of historical data (evidence) for Requirement R4, Measure M4.
Draft 3:
December 30, 20094:
November 23, 2010
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 3:
December 30, 20094:
November 23, 2010
Page 10 of 14
S ta n d a rd COM-001-2 — Co m m u n ic a tio n s
2.
R#
R1
Violation Severity Levels
Lower VSL
The responsible entity tested
Alternative Interpersonal
Communications capability but failed
to take action within 60 minutes to
restore the identified alternative
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The responsible entity failed to test
its Alternative Interpersonal
Communications capability on a
quarterly basis.
OR
Failed to identify a substitute
Alternative Interpersonal
Communications capability
R1
N/A
N/A
N/A
The Reliability Coordinator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 1.1 or 1.2.
R2
N/A
N/A
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
2.1 or 2.2.
R3
N/A
N/A
N/A
The Transmission Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 3.1, 3.2, 3.3 or
3.4.
R4
N/A
N/A
N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
4.1 or 4.2.
Draft 3: December 30, 20094: November 23, 2010
Page 11 of 14
S ta n d a rd COM-001-2 — Co m m u n ic a tio n s
R#
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
N/A
The Balancing Authority failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 5.1, 5.2, 5.3,
5.4 or 5.5.
R6
N/A
N/A
N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
6.1 or 6.2.
R7
N/A
N/A
N/A
The Distribution Provider failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 7.1 or 7.2.
R8
N/A
N/A
N/A
The Generator Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 8.1 or 8.2.
R9
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or
designate a replacement Alternative
Interpersonal Communications within
2 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or
designate a replacement Alternative
Interpersonal Communications within
12 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or
designate a replacement Alternative
Interpersonal Communications within
24 hours.
The responsible entity failed to test
the Alternative Interpersonal
Communications capability on at
least a monthly basis.
Draft 3: December 30, 20094: November 23, 2010
OR
The responsible entity tested the
Alternative Interpersonal
Communications capability and
identified a problem but didn’t initiate
action to repair or designate a
replacement Alternative
Interpersonal Communications within
Page 12 of 14
S ta n d a rd COM-001-2 — Co m m u n ic a tio n s
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
2 hours.
R2R10
The responsible entity failed to notify
the impacted entities in more than 60
minutes but less than or equal to 70
minutes.
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its normal
Interpersonal Communications
capabilities within 60 minutes.
The responsible entity failed to notify
the impacted entities in more than 80
minutes but less than or equal to 90
minutes.
The responsible entity failed to notify
any impacted entities of the failure of
its normal Interpersonal
Communications capabilities within
60 minutes.
OR
OR
The responsible entity failed to notify
the impacted entities in more than 70
minutes but less than or equal to 80
minutes.
The responsible entity failed to notify
the impacted entities in more than 90
minutes.
R3
N/A
N/A
N/A
The responsible entity failed to
provide evidence of legal
requirements or concurrence to use
a language other than English for
communications between and
among operating personnel
responsible for the real-time
generation control or operation of the
interconnected BES when a
language other than English was
used.
R4
N/A
N/A
The responsible entity failed to have
Interpersonal Communications
capability with its Transmission
Operator or Balancing Authority.
The responsible entity failed to have
Interpersonal Communications
capability with its Transmission
Operator and Balancing Authority.
Draft 3: December 30, 20094: November 23, 2010
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E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
Draft 3: December 30, 20094: November 23, 2010
Page 14 of 14
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Implementation Plan for COM-001-2
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
•
•
Interpersonal Communication: Any medium that allows two or more
individuals interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal
Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Interpersonal
Communications used for day-to-day operation.
Prerequisite Approvals
• None
Conforming Changes to Requirements in Already Approved Standards
•
None
Revision Summary
• The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
The first day of the first calendar quarter following applicable regulatory approval – or in those jurisdictions
where no regulatory approval is required, the first day of the first calendar quarter following Board of
Trustees adoption. To be determined.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Implementation Plan for COM-001-2 Communications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
R1.4.
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
R1.
Each Reliability Coordinator shall have Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R1.1. All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area
R1.2. Adjacent Reliability Coordinators within the same interconnection.
R2.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communications capability with the following entities to
exchange Interconnection and operating information: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]:
R2.1. All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area
R2.2. Adjacent Reliability Coordinators within the same interconnection.
R3.
Each Transmission Operator shall have Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R3.1. Its Reliability Coordinator
R3.2. Each Balancing Authority within its Transmission Operator Area.
R3.3. Each Distribution Provider within its Transmission Operator Area.
R3.4. Each Generator Operator within its Transmission Operator Area.
R4.
Each Transmission Operator shall designate an Alternative
Interpersonal Communications capability with the following entities to
exchange Interconnection and operating information: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]:
R4.1. Its Reliability Coordinator
R4.2. Each Balancing Authority within its Transmission Operator Area.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have to reliability.
November 16, 2010
2
Implementation Plan for COM-001-2 Communications
November 16, 2010
3
Implementation Plan for COM-001-2 Communications
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission Operator
and Balancing Authority shall provide adequate and
reliable telecommunications facilities for the exchange
of Interconnection and operating information: [Violation
Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor:
High]
R1.2.
Between the Reliability
Coordinator and its Transmission
Operators and Balancing Authorities.
[Violation Risk Factor: High]
R1.3.
With other Reliability
Coordinators, Transmission Operators,
and Balancing Authorities as necessary to
maintain reliability. [Violation Risk Factor:
High]
R1.4.
Where applicable, these facilities
shall be redundant and diversely routed.
[Violation Risk Factor: High]
Proposed Replacement Requirement(s)
R5.
Each Balancing Authority shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R5.1. Its Reliability Coordinator
R5.2. Each Transmission Operator that operates Facilities within its
Balancing Authority Area
R5.3. Each Generator Operator that operates Facilities within its Balancing
Authority Area
R5.4. Each Distribution Provider within its Balancing Authority Area
R6.
Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R6.1. Its Reliability Coordinator
R6.2. Each Transmission Operator that operates Facilities within its
Balancing Authority Area)
R7.
Each Distribution Provider shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
7.1 Its Transmission Operator
7.2 Its Balancing Authority.
R8.
Each Generator Operator shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
8.1 Its Balancing Authority
8.2 Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have to reliability. R8 is created to
address the FERC directive to “expands the applicability to include generator operators and distribution providers and includes
Requirements for their telecommunications facilities”
November 16, 2010
4
Implementation Plan for COM-001-2 Communications
November 16, 2010
5
Implementation Plan for COM-001-2 Communications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall manage, alarm, test
and/or actively monitor vital telecommunications facilities.
Special attention shall be given to emergency
telecommunications facilities and equipment not used for
routine communications. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R9. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall, on at least a monthly basis, test its
Alternative Interpersonal Communications capability. If the test
is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal
Communications within 2 hours. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
November 16, 2010
6
Implementation Plan for COM-001-2 Communications
Already Approved Standard
COM-001-1
R3.
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
November 16, 2010
Proposed Replacement Requirement(s)
COM-001-2
R10. Each Reliability Coordinator, Transmission Operator,
Balancing Authority, Distribution Provider, and Generator
Operator shall notify impacted entities within 60 minutes of
the detection of a failure of its Interpersonal
Communications capabilities that lasts 30 minutes or
longer. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
7
Implementation Plan for COM-001-2 Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
This requirement is being vetted by the OPCPSDT in COM-003. This
requirement and measure will be removed from COM-001.
Notes:
November 16, 2010
8
Implementation Plan for COM-001-2 Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
November 16, 2010
9
Implementation Plan for COM-001-2 Communications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the requirements in
Attachment 1-COM-001, “NERCNet Security Policy.” [Violation Risk
Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
November 16, 2010
10
Implementation Plan for COM-001-2 Communications
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
X
X
X
X
X
X
Communications
November 16, 2010
11
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
•
•
Interpersonal Communication: Any medium that allows two or more
individuals interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal
Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Interpersonal
Communications used for day-to-day operation.
Prerequisite Approvals
• None
Conforming Changes to Requirements in Already Approved Standards
•
None
Revision Summary
• The RC SDT revised the standard and is proposing retiring three requirements (R1, R5 and R6).
Changes were made to eliminate redundancies between standards (existing and proposed), to align
with the ERO Rules of Procedure and to address issues in FERC Order 693.
Effective Dates
The first day of the first calendar quarter following applicable regulatory approval – or in those jurisdictions
where no regulatory approval is required, the first day of the first calendar quarter following Board of
Trustees adoption. To be determined.
Formatted: Font color: Red, Strikethrough
Formatted: French (France)
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Formatted: Centered
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities
for the exchange of Interconnection and operating
information: [Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R1.3.
With other Reliability Coordinators,
Transmission Operators, and Balancing
Authorities as necessary to maintain
reliability. [Violation Risk Factor: High]
R1.4.
Where applicable, these facilities shall be
redundant and diversely routed. [Violation
Risk Factor: High]
Proposed Replacement Requirement(s)
R1.
Each Reliability Coordinator shall have Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R1.1. All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area
R1.2. Adjacent Reliability Coordinators within the same interconnection.
R2.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communications capability with the following entities to
exchange Interconnection and operating information: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]:
R2.1. All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area
R2.2. Adjacent Reliability Coordinators within the same interconnection.
R3.
Each Transmission Operator shall have Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R3.1. Its Reliability Coordinator
R3.2. Each Balancing Authority within its Transmission Operator Area.
R3.3. Each Distribution Provider within its Transmission Operator Area.
R3.4. Each Generator Operator within its Transmission Operator Area.
R4.
Each Transmission Operator shall designate an Alternative
Interpersonal Communications capability with the following entities to
exchange Interconnection and operating information: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]:
R4.1. Its Reliability Coordinator
R4.2. Each Balancing Authority within its Transmission Operator Area.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have to reliability.
November 16, 2010July 30, 200810December 30, 2009
2
Implementation Plan for COM-001-2
TelecommunicationsCommunications
November 16, 2010July 30, 200810December 30, 2009
3
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R1.
Each Reliability Coordinator, Transmission Operator
and Balancing Authority shall provide adequate and
reliable telecommunications facilities for the exchange
of Interconnection and operating information: [Violation
Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor:
High]
R1.2.
Between the Reliability
Coordinator and its Transmission
Operators and Balancing Authorities.
[Violation Risk Factor: High]
R1.3.
With other Reliability
Coordinators, Transmission Operators,
and Balancing Authorities as necessary to
maintain reliability. [Violation Risk Factor:
High]
R1.4.
Where applicable, these facilities
shall be redundant and diversely routed.
[Violation Risk Factor: High]
Proposed Replacement Requirement(s)
R5.
Each Balancing Authority shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:
R5.1. Its Reliability Coordinator
R5.2. Each Transmission Operator that operates Facilities within its
Balancing Authority Area
R5.3. Each Generator Operator that operates Facilities within its Balancing
Authority Area
R5.4. Each Distribution Provider within its Balancing Authority Area
R6.
Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange
Interconnection and operating information: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]:
R6.1. Its Reliability Coordinator
R6.2. Each Transmission Operator that operates Facilities within its
Balancing Authority Area)
R7.
Each Distribution Provider shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
7.1 Its Transmission Operator
7.2 Its Balancing Authority.
R8.
Each Generator Operator shall have Interpersonal Communications
capability with the following entities to exchange Interconnection and
operating information [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
8.1 Its Balancing Authority
8.2 Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have to reliability. R8 is created to
address the FERC directive to “expands the applicability to include generator operators and distribution providers and includes
Requirements for their telecommunications facilities”
November 16, 2010July 30, 200810December 30, 2009
4
Implementation Plan for COM-001-2
TelecommunicationsCommunications
November 16, 2010July 30, 200810December 30, 2009
5
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R2.
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall manage, alarm, test
and/or actively monitor vital telecommunications facilities.
Special attention shall be given to emergency
telecommunications facilities and equipment not used for
routine communications. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
COM-001-2:
R9. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall, on at least a monthly basis, test its
Alternative Interpersonal Communications capability. If the test
is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal
Communications within 2 hours. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
November 16, 2010July 30, 200810December 30, 2009
6
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
COM-001-1
R3.
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall provide a means to coordinate telecommunications
among their respective areas. This coordination shall include the
ability to investigate and recommend solutions to
telecommunications problems within the area and with other areas.
[Violation Risk Factor: Lower]
November 16, 2010July 30, 200810December 30, 2009
Proposed Replacement Requirement(s)
COM-001-2
R10. Each Reliability Coordinator, Transmission Operator,
Balancing Authority, Distribution Provider, and Generator
Operator shall notify impacted entities within 60 minutes of
the detection of a failure of its Interpersonal
Communications capabilities that lasts 30 minutes or
longer. [Violation Risk Factor: Medium][Time Horizon: Realtime Operations]
7
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel
responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
This requirement is being vetted by the OPCPSDT in COM-003. This
requirement and measure will be removed from COM-001.
Notes:
November 16, 2010July 30, 200810December 30, 2009
8
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority
shall have a plan to continue reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the following
requirements:
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice communication from
the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for providing basic
tie line control and procedures and for maintaining the status of all interarea schedules, such that there is an hourly accounting of all
schedules.
R1.3. The contingency plan must address monitoring and control of critical
transmission facilities, generation control, voltage control, time and
frequency control, control of critical substation devices, and logging of
significant power system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for maintaining
basic voice communication capabilities with other areas.
R1.5. The plan shall include procedures and responsibilities for conducting
periodic tests, at least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and responsibilities for providing
annual training to ensure that operating personnel are able to
implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more than
one hour to implement the contingency plan for loss of primary control
facility.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1.
November 16, 2010July 30, 200810December 30, 2009
9
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to
the requirements in Attachment 1-COM-001, “NERCNet Security
Policy.” [Violation Risk Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should
be included in the ERO Rules of Procedure.
November 16, 2010July 30, 200810December 30, 2009
10
Implementation Plan for COM-001-2
TelecommunicationsCommunications
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
X
Balancing
Authority
Purchasing
Selling
EntityInterc
hange
Authority
Transmission
Operator
X
X
X
Transmission
Service
ProviderOwn
er
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
Generator
Owner
X
Telecommuni
Communications
November 16, 2010July 30, 200810December 30, 2009
11
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Ballot Window Open February 25 – March 7, 2011
Project 2006-06 – Reliability Coordination
Available Friday, February 25th at: https://standards.nerc.net/CurrentBallots.aspx
Initial Ballot Window Open February 25th through 8 p.m. on March 7, 2011
An initial ballot for the following standards and associated implementation plans will be open from 8:00 a.m.
on Friday, February 25 through 8:00 p.m. on Monday, March 7, 2011.
• COM-001-2 – Communications
• COM-002-3 – Communication and Coordination
• IRO-001-2 – Reliability Coordination – Responsibilities and Authorities
• IRO-002-2 – Reliability Coordination – Analysis Tools
• IRO-005-4 – Reliability Coordination – Current Day Operations
• IRO-014-2 – Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators
• IRO-015-1 – Notifications and Information Exchange Between Reliability Coordinators
• IRO-016-1 – Coordination of Real-time Activities Between Reliability Coordinators
During the initial ballot window, members of the ballot pool associated with this project may log in and submit
their votes from the following page: https://standards.nerc.net/CurrentBallots.aspx
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap. In
addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated
with standards IRO-003-2.
For more information review the project Web page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Next Steps
The comments submitted during the formal comment period and the ballot results will be posted.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Ballot Pool Open January 25–February 25, 2011
Formal Comment Period Extended to March 7, 2011
Project 2006-06 – Reliability Coordination
Now available at: https://standards.nerc.net/BallotPool.aspx
Ballot Pool Open through 8 a.m. on February 25, 2011
A ballot pool is being formed during the next 30 days. The 45-day formal comment period is open from
January 18 – March 7, 2011 with an initial ballot being conducted during the last 10 days of the comment
period. Please review the Standards Under Development page for updated dates at:
http://www.nerc.com/filez/standards/Reliability_Standards_Under_Development.html
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballot at the
following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: [email protected]
Formal 45-day Comment Period Extended through 8 p.m. Eastern on Monday, March 7, 2011
and Additional Documents Posted
Last week the Reliability Coordination drafting team posted its Consideration of Comments and revised drafts
of the following standards to incorporate input from comments submitted during the January 4-February 18,
2010 comment period and comments provided by a Quality Review team:
•
COM-001-2 – Communications
•
COM-002-3 – Communication and Coordination
•
IRO-001-2 – Reliability Coordination – Responsibilities and Authorities
•
IRO-005-4 – Reliability Coordination – Current Day Operations
•
IRO-014-2 – Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators
Three additional standards were inadvertently omitted from last week’s posting and have now been
posted:
• IRO-002-2 – Reliability Coordination – Analysis Tools
•
IRO-015-1 – Notifications and Information Exchange Between Reliability Coordinators
•
IRO-016-1 – Coordination of Real-time Activities Between Reliability Coordinators
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The Standards Committee has authorized posting the standards and associated implementation plan for a 45-day
comment period, with a parallel ballot during the last 10 days of the comment period. To provide sufficient
time for review of the newly posted standards, the comment period has been extended through 8 p.m.
Eastern on Monday, March 7, 2011.
Instructions
Please use this electronic form to submit comments. For convenience, a Word version of the comment form has
been posted on the project page.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap. In
addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated
with standards IRO-003-2.
Next Steps
An initial ballot will be conducted during the last 10 days of the comment period. After the ballot, the drafting
team will consider all comments (those submitted with a comment form and those submitted with a ballot) and
determine whether further revisions to the standards and supporting documents are needed.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Ballot Pool Open January 25–February 25, 2011
Formal Comment Period Extended to March 7, 2011
Project 2006-06 – Reliability Coordination
Now available at: https://standards.nerc.net/BallotPool.aspx
Ballot Pool Open through 8 a.m. on February 25, 2011
A ballot pool is being formed during the next 30 days. The 45-day formal comment period is open from
January 18 – March 7, 2011 with an initial ballot being conducted during the last 10 days of the comment
period. Please review the Standards Under Development page for updated dates at:
http://www.nerc.com/filez/standards/Reliability_Standards_Under_Development.html
Registered Ballot Body members may join the ballot pool to be eligible to vote in the upcoming ballot at the
following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: [email protected]
Formal 45-day Comment Period Extended through 8 p.m. Eastern on Monday, March 7, 2011
and Additional Documents Posted
Last week the Reliability Coordination drafting team posted its Consideration of Comments and revised drafts
of the following standards to incorporate input from comments submitted during the January 4-February 18,
2010 comment period and comments provided by a Quality Review team:
•
COM-001-2 – Communications
•
COM-002-3 – Communication and Coordination
•
IRO-001-2 – Reliability Coordination – Responsibilities and Authorities
•
IRO-005-4 – Reliability Coordination – Current Day Operations
•
IRO-014-2 – Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators
Three additional standards were inadvertently omitted from last week’s posting and have now been
posted:
• IRO-002-2 – Reliability Coordination – Analysis Tools
•
IRO-015-1 – Notifications and Information Exchange Between Reliability Coordinators
•
IRO-016-1 – Coordination of Real-time Activities Between Reliability Coordinators
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The Standards Committee has authorized posting the standards and associated implementation plan for a 45-day
comment period, with a parallel ballot during the last 10 days of the comment period. To provide sufficient
time for review of the newly posted standards, the comment period has been extended through 8 p.m.
Eastern on Monday, March 7, 2011.
Instructions
Please use this electronic form to submit comments. For convenience, a Word version of the comment form has
been posted on the project page.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap. In
addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated
with standards IRO-003-2.
Next Steps
An initial ballot will be conducted during the last 10 days of the comment period. After the ballot, the drafting
team will consider all comments (those submitted with a comment form and those submitted with a ballot) and
determine whether further revisions to the standards and supporting documents are needed.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Formal Comment Period Open
Project 2006-06 – Reliability Coordination
January 18–March 4, 2011
Now available at: http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
The Reliability Coordination drafting team has posted its Consideration of Comments and revised drafts of the
following standards to incorporate input from comments submitted during the January 4-February 18, 2010
comment period and comments provided by a Quality Review team:
•
COM-001-2 – Communications
•
COM-002-3 – Communication and Coordination
•
IRO-001-2 – Reliability Coordination - Responsibilities and Authorities
•
IRO-005-4 – Reliability Coordination – Current Day Operations
•
IRO-014-2 – Procedures, Processes, or Plans to Support Coordination Between Reliability Coordinators
The Standards Committee has authorized posting the standards and associated implementation plan for a 45-day
comment period, with a parallel ballot during the last 10 days of the comment period.
Instructions
Please use this electronic form to submit comments. For convenience, a Word version of the comment form has
been posted on the project page.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap. In
addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated
with standards IRO-003-2.
Next Steps
An initial ballot will be conducted during the last 10 days of the comment period. After the ballot, the drafting
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
team will consider all comments (those submitted with a comment form and those submitted with a ballot) and
determine whether further revisions to the standards and supporting documents are needed.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 – Reliability Coordination
Initial Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
An initial ballot of the following standards and their associated implementation plans ended on March 7, 2011:
• COM-001-2 – Communications
• COM-002-3 – Communication and Coordination
• IRO-001-2 – Reliability Coordination – Responsibilities and Authorities
• IRO-002-2 – Reliability Coordination – Analysis Tools
• IRO-005-4 – Reliability Coordination – Current Day Operations
• IRO-014-2 – Coordination Among Reliability Coordinators
• IRO-015-1 – Notifications and Information Exchange Between Reliability Coordinators
• IRO-016-1 – Coordination of Real-time Activities Between Reliability Coordinators
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 87.10%
Approval: 49.54%
Background:
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; and 3)
revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards
Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope overlap. In addition,
the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated with
standards IRO-003-2.
For more information review the project Web page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Next Steps
The drafting team will consider all comments (those submitted with a comment form and those submitted with a
ballot. Once the team has prepared its response to comments and made any changes to the standards and
supporting documents, they will submit the revised documents for quality review prior to a successive ballot.
Since a non-binding poll of VRFs and VSLs was not conducted concurrent with the initial ballot that concluded
on March 7, 2011, a non-binding poll will be conducted in conjunction with the successive ballot.
Ballot Criteria
Approval requires both (1) a quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2006-06: Reliability Coordination_in
Password
Ballot Period: 2/25/2011 - 3/7/2011
Ballot Type: Initial
Log in
Total # Votes: 297
Register
Total Ballot Pool: 341
Quorum: 87.10 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
49.54 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
88
11
85
24
69
44
0
8
4
8
341
#
Votes
1
0.7
1
1
1
1
0
0.3
0.1
0.6
6.7
#
Votes
Fraction
34
3
35
9
33
17
0
1
1
2
135
Negative
Fraction
0.586
0.3
0.493
0.429
0.611
0.5
0
0.1
0.1
0.2
3.319
Abstain
No
# Votes Vote
24
4
36
12
21
17
0
2
0
4
120
0.414
0.4
0.507
0.571
0.389
0.5
0
0.2
0
0.4
3.381
13
3
7
2
8
5
0
2
1
1
42
17
1
7
1
7
5
0
3
2
1
44
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Member
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Andrew Z Pusztai
Robert D Smith
Scott Kinney
Gregory S Miller
Patricia Robertson
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Ballot
Affirmative
Negative
Comments
View
Affirmative
Affirmative
Affirmative
Affirmative
View
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Bonneville Power Administration
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Joseph S. Stonecipher
Donald S. Watkins
Kevin L Howes
Negative
Affirmative
Abstain
Chang G Choi
Affirmative
Randall McCamish
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Gordon Pietsch
Negative
Negative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
View
Affirmative
Affirmative
Randy MacDonald
Arnold J. Schuff
David H. Boguslawski
Kevin M Largura
John Canavan
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Daryl Hanson
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F. Afranji
David Thorne
Larry D. Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Catherine Koch
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
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View
View
Robert Solomon
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Robert Ganley
Joe D Petaski
Danny Dees
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch
View
View
Negative
Affirmative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Michael Moltane
View
View
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Abstain
Affirmative
Negative
View
View
View
Abstain
Abstain
Affirmative
Negative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
Negative
View
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Sierra Pacific Power Co.
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Leesburg
City of Redding
Clearwater Power Co.
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
Georgia System Operations Corporation
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Rich Salgo
Richard McLeon
Dana Cabbell
Robert A Schaffeld
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Kelly Nguyen
Steven Norris
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
View
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
View
View
View
Affirmative
Abstain
Negative
Negative
Negative
Negative
Abstain
Abstain
Affirmative
View
View
View
View
View
Affirmative
View
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
View
Dave Markham
Negative
View
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R. Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Phil Janik
Bill Hughes
Dave Hagen
Michelle A Corley
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
R Scott S. Barfield-McGinnis
Negative
View
Negative
Abstain
Affirmative
Negative
View
Affirmative
Negative
View
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6a132722-b4da-45ad-823c-293f4e5a2eea[6/23/2011 2:44:18 PM]
Negative
Abstain
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
View
NERC
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Northern Lights Inc.
Okanogan County Electric Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
Sam Kokkinen
David L Kiguel
Shaun Jensen
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Daniel D Kurowski
Richard Reynolds
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Jon Shelby
Ray Ellis
David Burke
Ballard Keith Mutters
John Apperson
Terry L Baker
Robert Reuter
Jeffrey Mueller
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Marc Farmer
James R. Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Timothy Beyrle
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Negative
View
View
View
View
View
Negative
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph G. DePoorter
Douglas Hohlbaugh
Aleka K Scott
Henry E. LuBean
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
John D. Martinsen
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=6a132722-b4da-45ad-823c-293f4e5a2eea[6/23/2011 2:44:18 PM]
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View
View
View
View
View
View
View
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4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group Incorporated
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul A Cummings
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Max Emrick
Affirmative
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
Jim M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
David Gordon
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Michelle DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
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NERC
Standards
20140514-5129
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Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Shell Energy North America (US), L.P.
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
Brandy D Olson
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Claire Warshaw
Steven J Hulet
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Paul Benjamin Kerr
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Affirmative
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Peter H Kinney
Affirmative
David F. Lemmons
James A Maenner
Roger C Zaklukiewicz
Edward C Stein
Jim D. Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
Negative
Negative
Affirmative
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Donald E. Nelson
Affirmative
Diane J. Barney
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NERC
Standards
20140514-5129
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Oregon Public Utility Commission
Snohomish County PUD No. 1
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity
Western Electricity Coordinating Council
Jerome Murray
William Moojen
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Larry D. Grimm
Louise McCarren
Abstain
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Negative
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (41 Responses)
Name (22 Responses)
Organization (22 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
Question 1 (38 Responses)
Question 1 Comments (41 Responses)
Question 2 (32 Responses)
Question 2 Comments (41 Responses)
Question 3 (28 Responses)
Question 3 Comments (41 Responses)
Question 4 (27 Responses)
Question 4 Comments (41 Responses)
Question 5 (27 Responses)
Question 5 Comments (41 Responses)
Question 6 (0 Responses)
Question 6 Comments (41 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
No
It was expressed in the last posting that the definition of Interpersonal Communications might inadvertently include
data. The SDT responded that it does not by referring to Interpersonal in the wording of the definition. The word being
defined shouldn’t be in the definition. However, incorporating “allows two or more individuals to …” is an option that
may solve this problem. The next posting should clarify this. This standard does not comport with the informational
filing that NERC submitted to FERC on August 10, 2009 regarding its discontinued use of sub-requirements in
standards development activities. The sub-requirements should be modified into bulleted lists. Consider striking “to
exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to the use of
Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider striking “to
exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of Alternative
Interpersonal Communications which uses Interpersonal Communications in its definition. Interpersonal
Communications includes “to interact, consult, or exchange information” in its definition. For R2, why is Interchange
Coordinator excluded? It is included in the Requirement R1 which deals with the Interpersonal Communications.
Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the
Interpersonal Communications. For R3, affected neighboring Transmission Operators should be included. For R4 and
R6, the sub-requirement list is different from the associated Interpersonal Communications requirements R3 and R5
respectively. These should be duplicate. The sub-requirement list for R4 should match R3, and the sub-requirement list
for R6 should match R5. In the event of a failure of the Interpersonal Communications, the Transmission Operator and
Balancing Authority both would need to maintain communications to the same entities as in the requirement to have
Interpersonal Communications. The sub-requirements should be bulleted lists. For R5, why are neighboring Balancing
Authorities not included? Additionally, R5 should only read Contact with Interchange Coordinator within the same
Interconnection. They need to be able to contact one another to identify discrepancies in scheduling and sources of
meter error that could lead to deviations in ACE. Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In
R1, R3 and R5, the requirement is “shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one
is for the Interpersonal Communications and the other is for the Alternative Interpersonal Communications, the same
wording should be used. R2.2 and R1.2 should not be limited to Reliability Coordinators in the same Interconnection
only. Modify “within the same Interconnection” to “within the same Interconnection, and, as appropriate, between asynchronously connected RCs which are not precluded by law from scheduling interchange energy (for schedule
changes, curtailments, etc.)” since reliability coordination may be required among the RCs on both sides of an
Interconnection boundary. The VSLs for R1 through R8 should be expanded to include multiple levels based on the
number of entities that the functional entity does not have Interpersonal Communications or Alternative Interpersonal
Communications with. FERC specified their general preference for gradated in paragraph 27 of their June 19, 2008
order on VSLs. The second half of the Severe VSL for R9 is almost a duplicate of the Lower VSL. There are some
small changes in the wording but both situations deal with the case where there is a problem that has been identified
with the Interpersonal Communications system and it takes more than two hours to initiate repair.
No
If the requirement were going to remain, but the Project 2007-03 Real-Time Operations SDT proposed to retire that
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
requirement during their last posting. There needs to be better coordination with that SDT.
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess Bulk
Electric System reliability” to reflect what the enforceability of the standards are meant to be. The requirement on the
ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all operating entities and the entire BES are
covered under a Reliability Coordinator. In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL applies to the
Regional Entity.
Yes
No
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or
actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator
shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area.” The word “notify” should be stuck.
The SDT did not address all concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving as the Transmission Operator or Balancing Authority. It
should never be necessary for these System Operators to issue Reliability Directives to themselves in the first example
or to their co-worker in the second example to demonstrate compliance to NERC standards. How the entity coordinates
its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is a corporate
governance issue that should not be confused or complicated by the NERC standards. Thus, standards should be
made clear that the Reliability Directive is directed to another company. In place of requiring an operator, in real-time,
to state “this is a Reliability Directive,” there should be an allowance for an entity to develop procedures indicating, in
advance, their expectations for three-part communications to their sub-operating entities. Therefore, we suggest
modifying R1 to be “When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to
be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall
identify the action, either verbally, when the communication is issued, or in advance through documented procedures,
as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time.]” Also, the definition of
Emergency as currently cited in these draft Standards and included in the existing NERC Glossary should be modified
to include the NERC Glossary term Adverse Reliability Impact to make the Standards more crisp, clear and
enforceable. Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the definition of Adverse
Reliability Impact in TOP-001-2 R5 during the last posting, the change to the definition should be coordinated with that
team. There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain requirements in
the standard and various other associated documentation that indicates requirements are being move to this standard.
Delete the text box. Strike IRO-014-2 Part 1.7. There is no need to have a weekly conference to discuss every
Operating Procedure, Operating Process and Operating Plan. As this requirement is written, a conference call would
be necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have weekly conference calls
that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures, Processes and Plans likely will
not need to be discussed weekly as it only requires an annual update. Requirement R2 in IRO-001 contains the words
“which could include issuing Reliability Directives”, but Reliability Directives are not referenced anywhere else in the
standard. This inclusion seems unnecessary since without it, R2 already requires that the RC take actions or direct
actions by others to prevent identified events or mitigate the magnitude or duration of actual events that result in
Adverse Reliability Impacts. Whether or not a Reliability Directive is issued is irrelevant in this requirement. These
words should be removed. Note that COM-002 already stipulates the requirement for 3-part communication when a
Reliability Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is
unnecessary.
Individual
Greg Froehling
Green Country Energy, Green Country Operating Services
No
COM-001 General question/comment. The reference to infrastructure should be removed and just keep the word
“medium”. Here's why What communication medium (infrastructure) does not use satellite at some point unless entities
are within a close geographical proximity? How likely is it to have 2 different mediums? • Local phone and fax hard-wire
likely. • Long distance phone and fax – satellite • Cell phone – satellite • Internet – satellite • Radio – antenna The
reason for mentioning this is, if all we have is satellite then the reference to infrastructure should be removed and just
keep the word “medium”.
No Comment
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No Comment
No Comment
No Comment
IRO-001-2 as proposed does not include the PSE in the applicability, nor does it require the PSE to respond to a
directive. However, COM-002 requires them to repeat the directive back… If the directive is that important to repeat
back should they not have to act upon the directive? I think the PSE should be included in IRO-001-2 this standard as
they represent and direct generation facility deployment in many cases. Including the PSE in COM-001 may be a good
idea too, just for the situations listed above.
Individual
Steve Alexanderson
Central Lincoln
No
See Q 6 below.
The stated purpose of COM-002 is: “To ensure emergency communications between operating personnel are
effective.” As written, the standard fails to meet this purpose because the three requirements only deal with
communications at the entity level. There is no requirement for the directing entity to even try to reach operating
personnel at the receiving entity. The directing entity may follow all the requirements of this standard by following R1
and R3 with the receiving entity’s receptionist, answering service, janitor, night watchman, etc. The receiving entity only
needs to meet R2, parroting the directive. Again this could be accomplished by anyone with no assurance the directive
reaches the operating personnel who can implement it. When we stated a similar objection during the last comment
period, The SDT’s answer suggested this was a PER staffing issue, but none of the PER requirements even apply to
DP/LSE directive recipients. We suggest the entity issuing the directive should be required to make an attempt to get it
to those who are competent to understand and implement the directive. This is not a staffing, training, or credentials
issue; it is a performance issue that falls squarely within the stated purpose of this standard. COM-001 R10 presents a
paradoxical situation to an entity attempting to comply. Consider an interpersonal communication capability failure that
lasts longer than 60 minutes past initial detection. At or before 60 minutes, the affected entity is expected to notify
impacted entities. If it has no interpersonal communication capability, how shall it make this notification? And if the
entity does manage to make such a notification, it has thereby proven that it does have interpersonal communication
capability making such notification unnecessary. We again ask the SDT to consider that not all the entities in the
applicability sections of COM-001 and 002 have 24/7 dispatch centers. These are typically smaller entities that were
required to register because they exceed 25 MW or were asked in the past to voluntarily provide UFLS. They do not
and do not need to continuously communicate with TOPs, BAs, RCs, etc; and a “reliability directive” is a theoretical
thing that has never happened during the memories of thirty year employees. The directive issuing entities simply
realize the limitations around the receiving entities and work around them. The financial burden on these small entities
and their customers to go to 24/7 dispatch will not have a corresponding reliability benefit. And while the two COM
standards do not explicitly state that entities must maintain 24/7 dispatch, when all the requirements and definitions and
time horizons are taken together 24/7 continuous competent communication is implied. During the last comment
period, the SDT suggested this was a registration issue beyond their control. We submit instead that this is a standard
applicability question that the SDT does have control over, since it is right there in Section A.4 of the two COM
standards. While we appreciate that the SDT is responding to FERC order 693 to include DPs, we note that FERC also
stated: Paragraph 487: “We expect the telecommunication requirements for all applicable entities will vary according to
their roles and that these requirements will be developed under the Reliability Standards development process.”
Paragraph 6: “A Reliability Standard may take into account the size of the entity that must comply and the costs of
implementation” Paragraph 141: “…the Commission clarifies that it did not intend to … impose new organizational
structures…” Paragraph 31: “We emphasize that we are not, at this time, mandating a particular outcome by way of
these directives, but we do expect the ERO to respond with an equivalent alternative and adequate support that fully
explains how the alternative produces a result that is as effective as or more effective that the Commission’s example
or directive. We ask the SDT to exclude DPs, LSEs, and PSEs that do not have 24/7 dispatch centers from the
applicability of these two standards in order to meet FERC order 693.
Group
Competitive Suppliers
Jack Cashin
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
EPSA is the trade association for competitive suppliers including both generators and marketers that represent over
700 entities in the NERC compliance registry. As such, the EPSA membership includes members registered as
Purchasing Selling Entities (PSE) in each NERC region. Moreover, many of EPSA’s members are also registered as
LSEs in several regions. In general, EPSA supports the progress made in revising COM-001, COM-002 and IRO-001
in Project 2006-06, particularly the improvements made to the definition of Reliability Directive. However, EPSA also
has concerns with some proposed changes to the applicability sections of the revised standards. In addition, EPSA
requests that the implementation plans be be changed so that they are consistent with the standard. Regarding
applicability, EPSA agrees that COM-001 should continue to not apply to Purchasing Selling Entity (PSE) and Load
Serving Entity (LSE) functions. However, the implementation plan for COM-001-2 still includes a reference that PSEs
and LSEs must comply (page 11 of the implementation plan). Additionally, EPSA supports the removal of LSEs and
PSEs from IRO-001-2. Much like the situation with COM-001-2, the implementation plan for IRO-001-2 still includes a
reference that LSEs and PSEs must comply (page 11 of the implementation plan). In both the implementation plans for
COM-001-2 and IRO-001-2 these references should be removed. For reasons similar to those underlying why COM001-2 and IRO-001-2 do not apply to PSEs and LSEs, EPSA opposes the addition of PSEs to the COM-002-3
applicability. The purpose of the emergency communications in these standards is "To ensure emergency
communications between operating personnel are effective." The removal would recognize that PSEs and LSEs do not
play an active role in reliability coordination under this standard since they have no authority, nor ability to assume or
perform responsibilities associated with reliability coordination. When a RC, TOP, or BA needs to address an
Emergency they do not contact, consult, or direct a PSE to take action to address the Emergency. Reliability is neither
improved nor degraded by having these Standards applicable to PSEs or LSEs; therefore,COM-001, COM-002 and
IRO-001 need not be applicable to PSEs or LSEs. Thanks to the drafting team members for their effort on revising the
Project 2006-06 standards.
Individual
Mace Hunter
Lakeland Electric
Yes
COM-002-3 R2. Each Balancing Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient of a Reliability
Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability Directive with
enough details that the accuracy of the message can be confirmed by the originator. (Replace ‘has been’ with ‘can be’
and add ‘by the originator’ to better fit into the sequence with R3.)
Group
Exelon
John Bee
No
1. COM-001-2, 4.4 - Distribution Providers and 4.5, Generation Operators should be highlighted and communicated as
a substantive change since entities may not be aware that they are being added to the applicability section of the
standard. 2. COM-001-2, R10 - should have the following underlined clarifying text added, shall notify impacted entities
within 60 minutes of the detection of a failure “of all primary and alternative ” Interpersonal Communications capabilities
that lasts 30 minutes or longer. Exelon believes that the intent of R10 is for complete loss of communication ability and
should not be applied to facilities that have multiple backups. 3. COM-001-2, M1 thru 9 – Suggest that network
diagrams and / or communications schematics be added as suggested evidence. 4. COM-001-2, VSL for R9 –
Regarding failure to test the Alternative Interpersonal Communication, the Severity Level does not align with the
potential impact to the BES. The Severity Level for simply missing a test should be revised to a High VSL.
Yes
No comment - only applicable to RC
Comments: No comment – only applicable to RC
Comments: No comment - only applicable to RC
1. COM-002-2, R2 – Remove the word “recapitulate”, feel that “restate or rephrase” is adequate. The word
"recapitulate" is not commonly used and is somewhat obscure. 2. COM-002-2, R3 – Suggest using the words “repeat
back” rather then “state or respond that” to more clearly identify the expectation with more commonly used language. 3.
IRO-001-2, R3 – While we appreciate that the SDT has defined the term "directive" as a much needed definition, IRC001-2 R.3 now introduces a new term “direction”, what is a "direction" and how does it differ from "directive"? If a new
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
term is going to be introduced it needs to be defined, if the intent was to use the word “directive” then “direction” should
be replaced with “directive.” 4. IRO-001-2, R4 – Again the term “as directed” is confusing, recommend that the text be
changed to align with the term directive, “unable to perform the directive per Requirement R3.”
Individual
Joe Petaski
Manitoba Hydro
Yes
Yes
Yes
Yes
Yes
-The current data retention requirement of 90 days is more than adequate. Increasing this period to 12 months would
result in a significant amount of work with no benefit to reliability. -Clarification required on the VSL for R9 - there
appears to be no difference in the description of the Lower VSL and second part of the Severe VSL following “or”. Clarification required - The existing version of COM-001 M1 indicates that maintenance records for communication
facilities may be required but the proposed revision makes no mention of maintenance records. So evidence of
maintenance is no longer required?
Group
PNGC Power member owners
Ron Sporseen
No
Thank you for the opportunity to comment and for your hard work on this project: While we agree that effective
Interpersonal Communications capability are integral to reliability, many Distribution Providers (DP) are small entities
that do not maintain a 24-7 dispatch desk capable of receiving or responding to emergency reliability directives in a
timely manner. It is our belief that some of the proposals in this project could unnecessarily force small entities to make
investments that will not enhance reliability. Many DPs rely on answering services to address customer-service issues
during non-business hours. On-call personnel are contacted in the event of an outage or emergency and crews are
dispatched as appropriate. It is difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a small
entity (25 MW or so) which would require these smaller entities to comply with COM-001. Order 693 directs the
inclusions of DPs in the COM-001-2 standard but it is our belief that the Commission offered language that GOs and
DPs need not have redundant communications, training unrelated to normal/emergency operations, and that
telecommunications requirements for entities will vary according to their function. We believe those intentions should
be reflected in the language of this standard. We would suggest adding wording such as in the applicability section,
"Distribution Providers who maintain a 24-7 control centers with the ability to manually shed load of at least 100 MW
within a 15-minute operational window." Also, a note that smaller, rural entities can be dependent on a phone system
provider that will not allow for backup communications. Should the communication line(s) be dependent on one main
phone trunk line, the failure due to an issue on this main line will make it impossible to notify anyone of its failure short
of physically traveling to an area where phone service is available. For some rural areas, this will exceed the one hour
time limit to report the communication outage. Forcing smaller entities to acquire satellite phone service to mitigate for
a phone outage is a high price to pay when no reliability improvement will be achieved. Suggested change could be: "...
shall notify impacted entities within 60 minutes of the detection of a failure of its Interpersonal Communications
capabilities that lasts 30 minutes or longer where alternate forms of communication are available within a 15 minute
access time. Should alternate forms of communication not be available within the 15 minute access time, then upon
reestablishment of Communication capabilities impacted entities will be notified of the past loss and current status of
Communication." We’ve heard many representatives from FERC and NERC indicate that the standards development
process has led the industry to take action in many cases for the sake of compliance while not necessarily enhancing
reliability. As has been stated many times, the process should be about improving reliability, not about complying with
standards. Unnecessarily including smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Brian J Murphy
NextEra Energy, Inc.
No
As drafted, COM-001 is not clear or complete. At this stage in the evolution of compliance with the mandatory
Reliability Standards, it is important that any new or revised Reliability Standard clearly articulate all compliance
obligations and tasks consistent with Sections 302 (6) and (8) of the NERC Rules of Procedure. Thus, NextEra Energy
Inc. (NextEra) has numerous recommended corrections to provide clarity and completeness to COM-001. For example,
the requirement to designate an Alternative Interpersonal Communication capability is not clear. Does the designator
solely designate for the designator’s knowledge or does the designator need to inform the entity on the other end of the
connection. In R2, for instance, the Reliability Coordinator must designate, but it is also not clear whether the Reliability
Coordinator must inform the Balancing Authorities or Transmission Operators. It is further unclear whether the
designation must be documented, or if any informing of the Balancing Authorities or Transmission Operators must be
documented. Thus, it is recommended that the drafters decide what was intended regarding the designation and clearly
state the requirements. In R9 it states that “. . . on at least a monthly basis.” There are two issues to consider here. If
the sentence stays, grammatically it should read “. . . on, at least, a monthly basis. . . ” However, from a compliance
and technical perspective, the term “at least” has no significance and should be deleted. The requirement is to test on a
monthly basis – the phrase “at least” only introduces ambiguity and implies that the party should consider every two or
three weeks. If the drafting team believes a best practice is less than a month, there are other NERC educational tools
to explain a best practice. In R10, it states “. . . shall notify the impacted entity . . .” It would be clearer to state: “. . .
shall notify the impacted Reliability Coordinator, Transmission Operator, Balancing Authority, Distribution Provider or
Generator Operator . . .”
No
As stated in response to number 1, Reliability Standards are to be clear and complete. If a Transmission Operator is
not responsible for a delay caused by a Reliability Coordinator, the Standard should specifically state that the
Transmission Operator does not need to wait for an assessment or approval of a Reliability Coordinator to take actions
pursuant to TOP-001-1 R3. Since the Reliability Coordinator is atop the reliability higherachy, such a statement
provides clarity and completeness to understanding a Transmission Operators rights. Thus, TOP-001-1 R3 should be
revised to lead with: “Without any obligation to first seek and obtain an assessment or approval from its Reliability
Coordinator, each Transmission Operator . . . .”
At this stage in evolution of compliance with the mandatory Reliability Standards, it is important that any new or revised
Reliability Standard clearly articulate all compliance obligations and tasks consistent with Sections 302 (6) and (8) of
the NERC Rules of Procedure. COM-002, IRO-001, IRO-002 and IRO-014 do not meet this threshold. Thus, NextEra
has numerous recommended corrections to provide clarity and completeness to these Reliability Standards. COM-002
R1 The addition of defined terms for Reliability Directive and Emergency is a very good approach that helps provides
clarity. Hence, it is also be appropriate to make the language in the requirement as clear as possible, and not add other
implied or unexplained notions. Also, at times, in those regions with markets, it is not always clear whether a
requirement to curtail for reliability reasons is being issued pursuant to market rules or from the Reliability Coordinator
or Transmission Operator under the Reliability Standards. Therefore, it is also appropriate that the Reliability
Coordinator, Transmission Operator, Balancing Authority be required to identify themselves;, and if they fail to identify
themselves or fail to use the term Reliability Directive, the registered entity receiving the flawed issuance should not be
consider in violation of a Reliability Standard for failing to act. Accordingly, R1 would be clearer and have the same
intent, if it stated as follows: “A Reliability Coordinator, Transmission Operator or Balancing Authority have the authority
to issue an oral or written Reliability Directive as authorized in [list the specific Reliability Standard requirements such
as IRO-001 R8 and TOP-001 R3]. The issuance of an oral of written Reliability Directive, by a Reliability Coordinator,
Transmission Operator or Balancing Authority shall: (1) use the term ‘Reliability Directive;’ and (2) identify the issuer of
the Reliability Directive as a Reliability Coordinator, Transmission Operator or Balancing Authority. If a Reliability
Coordinator, Transmission Operator or Balancing Authority issues an oral or writtern directive without using the term
“Reliability Directive” or failing to indentify itself as a Reliability Coordinator, Transmission Operator or Balancing
Authority, the registered entity receiving the directive cannot be considered in violation for its failure to act.” IRO-001
The definition of Adverse Reliability Impacts uses the term “instability.” It is important that this term be technically
defined in the same way “Cascading” is defined, otherwise the new requirement is not adding clarity; rather, it is
maintaining the ambiguous term “instability” that will likely lead to confusion and debate. R1 Similar to the comments
set forth with respect to COM-001 (question #1), the term “at least” should be deleted from R1 – it serves no useful
purpose from a technical or compliance perspective; instead, it will add unnecessary ambiguity to the requirement. R2,
as drafted, states: “Each Reliability Coordinator shall take actions or direct actions, which could include issuing oral or
written Reliability Directives, of Transmission Operators, Balancing Authorities, Generator Operators, Interchange
Coordinators and Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate
the magnitude or duration of actual events that result in Adverse Reliability Impacts. “ This long sentence has several
significant grammatical errors that result in the reader not being able to discern the meaning of the requirement. It also
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
unnecessarily adds verbiage that detracts from its primary focus. It is, therefore, recommended that R2 be revised as
follows: “Each Reliability Coordinator shall take all necessary actions to prevent identified Emergencies or Adverse
Reliability Impacts. These Reliability Coordinator actions shall include, to the extent necessary, the issuing of oral or
written Reliability Directives to Transmission Operators, Balancing Authorities, Generator Operators, Interchange
Coordinators and Distribution Providers located within its Reliability Coordinator Area. “ R3, as drafted, is confusing and
inconsistent with R2, and, thus, R3 should be revised to read as follows: “Upon receipt of a Reliability Directive issued
pursuant to R2, a Transmission Operator, Balancing Authority, Generator Operator, Interchange Coordinator and
Distribution Provider shall comply with the Reliability Directive, unless compliance would violate safety, equipment,
regulatory or statutory requirements. In the event that a Transmission Operator, Balancing Authority, Generator
Operator, Interchange Coordinator or Distribution Provider determines that compliance with a Reliability Directive would
violate safety, equipment, regulatory or statutory requirements, the Transmission Operator, Balancing Authority,
Generator Operator, Interchange Coordinator or Distribution Provider shall, within 10 minutes after the determination,
inform the Reliability Coordinator of its inability to comply.” IRO-002 R1 and R2, as written, are confusing. It is
recommended that R1 and R2 be combined to read as follows: “Pursuant to a written procedure to mitigate the impact
of a Reliability Coordinator’s analysis tool outage, a Reliability Coordinator’s System Operator shall also have the
authority to approve, deny or cancel a planned outage for its analysis tool.” IRO-014 It is unclear why the terms
Operating Procedure, Operating Process or Operating Plan needs to be plural, as currently written in the Standard.
Hence, it is recommended that these terms be made singular, otherwise a violation may be inferred for not having more
than one Procedure, Process or Plan. 1.1 Insert the word “applicable” before “Reliability Coordinator.” 2.1, as written, is
confusing. Recommend that 2.1 read as follows: “Review and update, if an update is necessary, on an annual basis.
Annual basis means the review shall be within one month plus or minus that date of the last review.” R3 This
requirement uses a very vague term “reliability-related information,” which, also, does not track the language used in
R1 -- “information.” It is recommended that R1 and R3 use the same terms and read “ . . . information, as defined by
the Reliability Coordinator, . . ” R4 As stated above, “at least” does not add value, and, therefore, should be deleted.
R5, as written, is confusing. The recommended fix is to delete “all other” and replace with “impacted”.
Group
PacifiCorp
Sandra Shaffer
Yes
Yes
Yes
Yes
Yes
Individual
Jonathan Appelbaum
United Illuminating Company
No
COM-001-2 does not specify the amount of time a DP has to reestablish the Interpersonal Communication Capability
after the capability fails before it is assessed non-compliance for not having the communication. Is an entity noncompliant the minute the communication capability is unavailable If so, then to be compliant a tertiary (or secondary
capability for DP) must be installed by the entity. Something similar was discussed with EOP-008 R3: "To avoid
requiring a tertiary facility, a backup facility is not required during: • Planned outages of the primary or backup facilities
of two weeks or less • Unplanned outages of the primary or backup facilities" UI suggests the drafting team incorporate
something similar. The VSL for R7 is severe only and states: "The Distribution Provider failed to have Interpersonal
Communications capability with one or more of the entities listed in Parts 7.1 or 7.2.". I believe there should be a time
component to the VSL and the VSL staged. For example, failure to have communication established for less than 60
minutes would be Lower, anything over 1 hour severe Also needed is a phrase to state when the violation begins. Does
the violation begin when the loss of Communication Capability is detected or when it occurred? In other words, does
the violation start when the operator attempts to use the phone and it is not functional, or did it occur when the phone
line functionality failed but was not yet detected because no attempt to use the phone was made. So the VSL for R7
would follow a format of: "The Distribution Provider failed to have Interpersonal Communication Capability with one or
more entities listed in Parts 7.1 or 7.2 for a continual 60 minutes period as measured from the time the ICC failure was
detected". An alternative remedy is to alter the language of R7 to allow for unplanned outage. NERC does not have a
Reliability Requirement for a DP to staff a control room 24/7. COM-0001 can be interpreted to imply that a DP needs to
be staffed 24/7 to facilitate interpersonal communications. If NERC wants to extend the requirement for a 24/7 staffed
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operating position at the DP then the appropriate method is thru a SAR to PER-002. COM-001 R7 should have a subrequirement added recognizing that DP’s are not required to staff 24/7 and many do not staff overnight. UI suggests
adding R7.3: DP’s will notify their TOP and/or BA when it is not staffing an operating desk. R7: Should address the
instance if the DP is not required to have communication with the BA, because the BA communicates thru the TOP.
Yes
Yes
Yes
Yes
Comments: 1. COM-002 R2 seems awkwardly worded. R2. Each [Entity] that is the recipient of a Reliability Directive
issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
that the accuracy of the message has been confirmed. " R2 as it is written says the repeat is confirming the accuracy of
the message itself. I think it is agreed that the repeat back in R2 is to allow the issuer of the Directive to confirm that the
message was received accurately understood by the recipient. I suggest: R2. Each [Entity] that is the recipient of a
Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability Directive
with enough details to allow the Issuer to confirm that the directive recipient accurately understands the Directive" 2.
The VSL for R2 is severe and states "The responsible entity that was the recipient of a Reliability Directive failed to
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details that the accuracy of the message
was confirmed." The purpose of the R2 repeat-back is to allow the Issuer verify the message was accurately received.
This VSL penalizes the responsible entity for not accurately receiving the message. The VSL should penalize the
refusal of the registered entity to repeat back the message not for receiving the message incorrectly. Suggested
rewording: "The responsible entity that was the recipient of a Reliability Directive failed to repeat, restate, rephrase or
recapitulate the Reliability Directive with enough details that the accuracy of the message can be evaluated by the
entity issuing the Reliability Directive" 3. United Illuminating does agree with the definition of Reliability Directive and
Emergency.
Group
Bonneville Power Administration
Denise Koehn
Yes
Yes
Yes
Yes
Yes
Group
PPL
Brenda Truhe
Yes
Yes
Yes
Yes
Yes
We are providing the following comments for the Standards Drafting Team to consider. 1) Consider changing R1 to
‘Each RC shall have the capability for Interpersonal Communications with the following entities to exchange
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Interconnection and operating information…’ for clarity as Interpersonal Communications and capability are both
nouns. 2) We feel changing the applicability of the standard is important to the accuracy of the standard. The purpose
of COM-002 is ‘To ensure emergency communications between operating personnel are effective’. Since operating
personnel are covered by the applicability of RC, BA, TOP and GOP, we suggest the applicability to TSP, LSE, and
PSE be removed from COM-002-3. 3) Additionally, we would like to bring to the attention of the Standards Drafting
Team, that the implementation plan for COM-001-2 and IRO-001-2 still includes TSP, LSE, and PSE although the
revised standard does not include these entities in the Applicability Section. For COM-001-2 refer to the implementation
plan, page 1. For IRO-001-2 refer to the implementation plan for new R2, new R3, new R4 and the chart on the last
page. Thank you for your consideration in addressing these comments.
Individual
Paul Kerr
Shell Energy North America (US), L.P.
The introduction of the definition of “Reliability Directive” and its connection to the definition of “Emergency” within this
Project brings much needed clarity for the sector and will promote consistency between Regional Entities and within
the audits of Registered Entities. Shell Energy supports the removal of Purchasing Selling Entities as a function to
which IRO-001 applies. This removal recognizes that PSEs do not play a role in reliability coordination under this
standard since they have no authorities and no abilities to assume or perform responsibilities associated with reliability
coordination. This conclusion is reinforced by the adoption of the defined term “Reliability Directive”. Where a RC, TOP,
or BA needs to address an Emergency they do not contact, consult, or direct a PSE to take action that would address
the Emergency. Rather, where the PSE is a user of the grid to perform or execute transactions, it is subject to the
actions of these other entities that have the authority to stop, curtail, or alter the submitted transactions of the PSE in a
way that aids in resolving the problem. With the fitting adoption of “Reliability Directive” into COM-002 as well, Shell
Energy does not believe it is necessary or appropriate for the applicability of this standard to include Purchasing Selling
Entities, as is contained in the current draft proposal. This standard does not apply to PSEs today, however, during the
progression of Project 2006-06 this applicability was added to an early draft version that preceded the discussions and
clarification that comes from the definition of a Reliability Directive in the standard. Shell Energy does not support the
inclusion of PSEs in the current draft version of COM-002, and feels that it should be removed. The purpose of this
standard is, “To ensure Emergency communications between operating personnel are effective” and relates directly to
the capabilities and authorities established for the RC, TOP, or BA that requires actions to be taken by a recipient of a
Reliability Directive. As noted previously, PSEs are acted upon by the entities with the necessary authority, and are not
in a role that would initiate or fulfil the required actions. As additional matters related to the clarification and cleanup of
the standards in this project, the implementation plans for both IRO-001 and COM-001 erroneously contain references
to PSEs in the sections “Functions that Must Comply with the Requirements”. These references need to be removed.
Individual
Thad Ness
American Electric Power
No
The applicability of COM-001 and COM-002 appear to be at odds with each other. The requirements may need to be
re-written so that they are in sync.
Yes
No
This is out of scope with the standard, as it is currently addressed through the NERC certification process that the
NERC reliability coordinators are subject to.
The language used in COM-002-3 R2 including “with enough details that the accuracy of the message has been
confirmed” is subjective and ambiguous. IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in
lower case (while it appears that “Directives” is a subset of “directions”). We believe that this muddies the waters and
could bring numerous conversations and dialog into scope unnecessarily. The end result is that the RC has the right to
issue and use “Directives” and anything short of this could just be communications. For example, a number of entities
that are Reliability Coordinators also facilitate energy markets. There are many communications related to markets that
probably should be out of scope with respect to the standards. Furthermore, it might not be clear what role (eg
Reliability Coordinator, market operator, etc) the staff at these entities are fulfilling.
Group
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PSEG
Patricia Hervochon
No
Com-001-2 implementation plan lists that this is applicable to PSE’s and LSE’s however, PSE’s and LSE’s were
removed from the actual standard. The implementation plan should be revised.
IRO Com-002-3 standard continues to include PSE. PSE’s do not play an active role and have no authority or ability to
perform reliability coordination. PSE’s should be removed from the standard. -001-2 references PSE’s in the
implementation for R2, R3, R4 and ”Functions that must comply with the requirements in this standard” table. PSE’s
were removed from the standard and should be removed from the implementation plan.
Group
Dominion
Louis Slade
No
The monthly testing requirement for Alternative Interpersonal Communications is overly burdensome without any
evidence to support that it is necessary to insure reliability. We believe that an entity will take necessary steps to insure
the Alternative Interpersonal Communications is functioning properly, especially if it experiences problems with its
Interpersonal Communications, it. We can support quarterly testing as we believe it strikes a reasonable balance.
Yes
We do not agree with the addition of weekly conference calls as required in R4. We believe that RCs should schedule
calls as needed but do not agree that a weekly scheduled call improves reliability.
Individual
David Thorne
Pepco Holdings Inc
Yes
Yes
Yes
Yes
Yes
Group
SERC OC Standards Review Group
Jim Case
No
Each sub-requirement should not have an “R” in front of the number in order to be consistent with NERC’s August 10,
2009 filing at FERC on this subject. Requirement R3 and R4 should include adjacent TOPs as a sub-requirement.
Requirements R5 and R6 should include adjacent BAs as a sub-requirement. “to exchange Interconnection and
operating information” should be deleted from requirements R1 through R8 as it is redundant with the definition of
Interpersonal Communications The last page of the Implementation Plan includes LSEs, PSE, and TSPs as being
responsible entities under this standard, yet the standard does not include them. Please correct the implementation
plan.
No
Top-001-1, Requirement R3, which is what the SDT appears to be using as its justification for not adding a requirement
here is proposed to be deleted by the RTO-SDT on Project 2007-03.
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No
We think you are attempting to create a requirement similar to BAL-005, R1. That language copied here is clear and
concise - All generation, transmission, and load operating within an Interconnection must be included within the
metered boundaries of a Balancing Authority Area.
Yes
Yes
Please remove the yellow box on page 1 indicating this standard will be retired.
Reliability Directives may be issued by blast calls from Reliability Coordinators. It is inefficient and may be a hindrance
to reliability to require 3-part communications in these instances. There are several organizations registered as BAs,
RCs and TOPs. It is not uncommon for those entities to be distributed across multiple desks in the same control room
without regard to how an entity is registered. Thus, a single System Operator may perform functions that are
categorized under two or more of those functional entities. The drafting team should clarify that under no circumstances
should that System Operator be required to issue a Reliability Directive to himself. This is a corporate governance
issue. In IRO-014, R1, delete sub-requirement 1.7. The requirement for weekly conference calls related to operating
procedures is duplicative to R4 and could be burdensome while adding very little value under certain circumstances. In
IRO-014, R4, delete the phrase “(per Requirement 1, Part 1.7)” as a conforming change. In IRO-014, Requirements
R6-R8 allow at least the theoretical possibility that an RC may determine an Adverse Reliability Impact in another RC’s
area that the other RC neither can see nor believes that any action should be taken. R7 puts the burden on the first RC
to develop a plan that it cannot implement because it has no agreement with the BAs and TOPs in the other RC area.
As such, this requirement is unenforceable. Please review all the implementation plans to be sure the applicable
entities match those in the standards. “The comments expressed herein represent a consensus of the views of the
above named members of the SERC OC Standards Review group only and should not be construed as the position of
SERC Reliability Corporation, its board or its officers.”
Individual
Andrew Pusztai
American Transmission Company
Yes
ATC agrees with the understanding that the line of demarcation is up to the point where ATC owns the equipment.
Yes
Yes
Yes
Yes
None
Group
Arizona Public Service Company
Janet Smith
Yes
Yes
Yes
Yes
Group
LG&E and KU Energy
Brent Ingebrigtson
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1) LG&E/KU suggests that the definitions and related Reliability Standards be edited to provide a clearer understanding
of what is required. When used in the requirements of COM-001, the proposed definitions for Interpersonal
Communication and Alternative Interpersonal Communication read improperly (i.e., a “medium capability”). This may
cause confusion as to what is required by the Applicable entities. Any further use of these terms may cause greater
confusion. Suggested Alternative: Interpersonal Communication: Any instance where two or more individuals interact,
consult, or exchange information. The definition of “Alternative Interpersonal Communication” would not have to be
changed since it is dependent upon the definition of “Interpersonal Communication.” The change of the definitions of
Interpersonal Communication and Alternative Interpersonal Communication shifts their focus to the communication
itself—the event. This makes the Requirements themselves much clearer since the Requirements focus on the need
that entities have the capabilities—the medium. It appears the SDT’s intent is to ensure that the event takes place by
requiring that the medium for those events are in place. This is much clearer if there is a distinction between the two
(the event and the medium) than if they have similar definitions (a medium and a “medium capability”). 2) LG&E/KU
question the consistency of the Applicability sections as they pertain to the TSP, LSE and PSE functions between
COM-001 and COM-002. The deletion of the TSP, LSE and PSE from COM-001 is supported, but if these entities are
not required to establish Interpersonal Communication (or Alternative Interpersonal Communication) capability with
reliability entities (RC, BA, TOP), should they still be required to follow the reliability directive process of COM-002? If
the probability of issuing a Reliability Directive to a TSP, LSE or PSE is so low that Interpersonal Communications
capabilities with reliability entities is not justified under COM-001, why are the TSP, LSE and PSE still held to the 3 way
communication requirements of COM-002? Suggest the Applicability of COM-002 to TSP, LSE and PSE and
associated requirements be deleted.
Group
IRC Standards Review Committee
Albert DiCaprio
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might inadvertently include
data. The SDT responded that it does not by referring to Interpersonal in the name of the definition. Clearly, you can’t
refer to the word you are defining in order to define it. However, it is possible “allows two or more individuals to …” may
solve this problem. Clarity should be sought in the next posting, if possible. This standard does not comport with the
informational filing that NERC submitted to FERC on August 10, 2009 regarding its discontinued use of subrequirements in standards development activities. We request the sub-requirements be modified into bulleted lists.
Consider striking “to exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to
the use of Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of Alternative
Interpersonal Communications which uses Interpersonal Communications in its definition. Interpersonal
Communications includes “to interact, consult, or exchange information” in its definition. For R2, why is Interchange
Coordinator excluded? It is included in the Requirement R1 which deals with the Interpersonal Communications.
Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the
Interpersonal Communications. For R3, affected neighoring Transmission Operators should be included. For R4 and
R6, the sub-requirement list is different than for than for the associated Interpersonal Communications requirements R3
and R5 respectively. We believe these should be duplicate. That is the sub-requirement list for R4 should match R3
and the R6 should match R5. In the event of a failure of the Interpersonal Communications, the Transmission Operator
and Balancing Authority both would need to maintain communications to the same entities as in the requirement to
have Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists. For R5,
why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact with Interchange
Coordinator within same Interconnection. They certainly need to be able to contact one another to identify
discrepancies in scheduling and sources of meter error that could lead to deviations in ACE. Should R2, R4 and R6 be
constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is “shall have” while in R2, R4, and R6, the
requirement is “shall designate”. Since one is for the Interpersonal Communications and the other is for the Alternative
Interpersonal Communications, it seems the same wording should be used. We do not believe R2.2 and R1.2 should
be limited to Reliability Coordinators in the same Interconnection only. We suggest modifying “within the same
Interconnection” to “within the same Interconnection, and, as appropriate, between a-synchronously connected RCs
which are not precluded by law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since
reliability coordination may be required among the RCs on both sides of an Interconnection boundary. The VSLs for R1
through R8 should be expanded to include multiple levels based on the number of entities that the functional entity
does not have Interpersonal Communications or Alternative Interpersonal Communications. FERC specified their
general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs. The second half of the Severe
VSL for R9 is almost a duplicate to the Lower VSL. There are some small changes in the wording but both situations
deal with the case where there is a problem that has been identified with the Interpersonal Communications system
and it takes more than two hours to initiate repair.
No
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire
that requirement during their last posting. We believe there needs to be better coordination with that SDT.
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess Bulk
Electric System reliability” to reflect what the enforceability of the standards are meant to be. The requirement on the
ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all operating entities and the entire BES is
covered under a Reliability Coordinator. In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL applies to the
Regional Entity.
Yes
Yes
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or
actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator
shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area.” The word “notify” should be stuck.
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving the as the Transmission Operator or Balancing Authority. We
believe that it should never be necessary for these System Operators to issue Reliability Directives to themselves in the
first example or to their co-worker in the second example to demonstrate compliance to NERC standards. How the
entity coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is
a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to another company. We believe that, in
place of requiring an operator, in real-time, to state “this is a Reliability Directive,” there should be an allowance for an
entity to develop procedures indicating, in advance, their expectations of three-part to their sub-operating entities.
Therefore, we suggest modifying R1 to be “When a Reliability Coordinator, Transmission Operator or Balancing
Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator
or Balancing Authority shall identify the action, either verbally, when the communication is issued, or in advance
through documented procedures, as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
Real-Time.]” Also, we believe that the definition of Emergency, as currently cited in these draft Standards and included
in the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to
make the Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time Operations SDT
proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the change to
the definition should be coordinated with that team. There is a text box in IRO-005-4 that indicates this standard will be
retired. Yet, there still remain requirements in the standard and various other associated documentation indicates
requirements are being move to this standard. Please delete the text box. IRO-014-2 R4 already includes a
requirement to have weekly conference calls that should suffice. IRO-014-2 R2 seems to recognize that these
Operating Procedures, Processes and Plans likely will not need to be discussed weekly as it only requires an annual
update. In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
reliability constraint or a declared Emergency”. Further, Requirement R2 in IRO-001 contains the words “which could
include issuing Reliability Directives” but Reliability Directives are not referenced anywhere else in the standard. This
inclusion seems unnecessary since without it, R2 already requires that the RC take actions or direct actions by others
to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability
Impacts. Whether or not a Reliability Directive is issued is irrelevant in this requirement. We suggest that these words
be removed. Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability
Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is unnecessary.
Individual
Kathleen Goodman
ISO New England
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might inadvertently include
data. The SDT responded that it does not by referring to Interpersonal in the name of the definition. Clearly, you can’t
refer to the word you are defining in order to define it. However, it is possible “allows two or more individuals to …” may
solve this problem. Clarity should be sought in the next posting, if possible. This standard does not comport with the
informational filing that NERC submitted to FERC on August 10, 2009 regarding its discontinued use of subrequirements in standards development activities. We request the sub-requirements be modified into bulleted lists.
Consider striking “to exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
the use of Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of Alternative
Interpersonal Communications which uses Interpersonal Communications in its definition. Interpersonal
Communications includes “to interact, consult, or exchange information” in its definition. For R2, why is Interchange
Coordinator excluded? It is included in the Requirement R1 which deals with the Interpersonal Communications.
Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the
Interpersonal Communications. For R3, affected neighoring Transmission Operators should be included. For R4 and
R6, the sub-requirement list is different than for than for the associated Interpersonal Communications requirements R3
and R5 respectively. We believe these should be duplicate. That is the sub-requirement list for R4 should match R3
and the R6 should match R5. In the event of a failure of the Interpersonal Communications, the Transmission Operator
and Balancing Authority both would need to maintain communications to the same entities as in the requirement to
have Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists. For R5,
why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact with Interchange
Coordinator within same Interconnection. They certainly need to be able to contact one another to identify
discrepancies in scheduling and sources of meter error that could lead to deviations in ACE. Should R2, R4 and R6 be
constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is “shall have” while in R2, R4, and R6, the
requirement is “shall designate”. Since one is for the Interpersonal Communications and the other is for the Alternative
Interpersonal Communications, it seems the same wording should be used. We do not believe R2.2 and R1.2 should
be limited to Reliability Coordinators in the same Interconnection only. We suggest modifying “within the same
Interconnection” to “within the same Interconnection, and, as appropriate, between a-synchronously connected RCs
which are not precluded by law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since
reliability coordination may be required among the RCs on both sides of an Interconnection boundary. The VSLs for R1
through R8 should be expanded to include multiple levels based on the number of entities that the functional entity
does not have Interpersonal Communications or Alternative Interpersonal Communications. FERC specified their
general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs. The second half of the Severe
VSL for R9 is almost a duplicate to the Lower VSL. There are some small changes in the wording but both situations
deal with the case where there is a problem that has been identified with the Interpersonal Communications system
and it takes more than two hours to initiate repair.
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire
that requirement during their last posting. We believe there needs to be better coordination with that SDT.
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess Bulk
Electric System reliability” to reflect what the enforceability of the standards are meant to be. The requirement on the
ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all operating entities and the entire BES is
covered under a Reliability Coordinator. In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL applies to the
Regional Entity.
Yes
Yes
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or
actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator
shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area.” The word “notify” should be stuck.
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving the as the Transmission Operator or Balancing Authority. We
believe that it should never be necessary for these System Operators to issue Reliability Directives to themselves in the
first example or to their co-worker in the second example to demonstrate compliance to NERC standards. How the
entity coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is
a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to another company. We believe that, in
place of requiring an operator, in real-time, to state “this is a Reliability Directive,” there should be an allowance for an
entity to develop procedures indicating, in advance, their expectations of three-part to their sub-operating entities.
Therefore, we suggest modifying R1 to be “When a Reliability Coordinator, Transmission Operator or Balancing
Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator
or Balancing Authority shall identify the action, either verbally, when the communication is issued, or in advance
through documented procedures, as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Real-Time.]” Also, we believe that the definition of Emergency, as currently cited in these draft Standards and included
in the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to
make the Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time Operations SDT
proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the change to
the definition should be coordinated with that team. There is a text box in IRO-005-4 that indicates this standard will be
retired. Yet, there still remain requirements in the standard and various other associated documentation indicates
requirements are being move to this standard. Please delete the text box. IRO-014-2 R4 already includes a
requirement to have weekly conference calls that should suffice. IRO-014-2 R2 seems to recognize that these
Operating Procedures, Processes and Plans likely will not need to be discussed weekly as it only requires an annual
update. In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
reliability constraint or a declared Emergency”. Further, Requirement R2 in IRO-001 contains the words “which could
include issuing Reliability Directives” but Reliability Directives are not referenced anywhere else in the standard. This
inclusion seems unnecessary since without it, R2 already requires that the RC take actions or direct actions by others
to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability
Impacts. Whether or not a Reliability Directive is issued is irrelevant in this requirement. We suggest that these words
be removed. Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability
Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is unnecessary.
Individual
Steve Myers
ERCOT ISO
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might inadvertently include
data. The SDT responded that it does not by referring to Interpersonal in the name of the definition. Clearly, you can’t
refer to the word you are defining in order to define it. However, it is possible “allows two or more individuals to …” may
solve this problem. Clarity should be sought in the next posting, if possible. This standard does not comport with the
informational filing that NERC submitted to FERC on August 10, 2009 regarding its discontinued use of subrequirements in standards development activities. We request the sub-requirements be modified into bulleted lists.
Consider striking “to exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to
the use of Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of Alternative
Interpersonal Communications which uses Interpersonal Communications in its definition. Interpersonal
Communications includes “to interact, consult, or exchange information” in its definition. For R2, why is Interchange
Coordinator excluded? It is included in the Requirement R1 which deals with the Interpersonal Communications.
Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the
Interpersonal Communications. For R3, affected neighoring Transmission Operators should be included. For R4 and
R6, the sub-requirement list is different than for than for the associated Interpersonal Communications requirements R3
and R5 respectively. We believe these should be duplicate. That is the sub-requirement list for R4 should match R3
and the R6 should match R5. In the event of a failure of the Interpersonal Communications, the Transmission Operator
and Balancing Authority both would need to maintain communications to the same entities as in the requirement to
have Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists. For R5,
why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact with Interchange
Coordinator within same Interconnection. They certainly need to be able to contact one another to identify
discrepancies in scheduling and sources of meter error that could lead to deviations in ACE. Should R2, R4 and R6 be
constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is “shall have” while in R2, R4, and R6, the
requirement is “shall designate”. Since one is for the Interpersonal Communications and the other is for the Alternative
Interpersonal Communications, it seems the same wording should be used. We do not believe R2.2 and R1.2 should
be limited to Reliability Coordinators in the same Interconnection only. We suggest modifying “within the same
Interconnection” to “within the same Interconnection, and, as appropriate, between a-synchronously connected RCs
which are not precluded by law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since
reliability coordination may be required among the RCs on both sides of an Interconnection boundary. The VSLs for R1
through R8 should be expanded to include multiple levels based on the number of entities that the functional entity
does not have Interpersonal Communications or Alternative Interpersonal Communications. FERC specified their
general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs. The second half of the Severe
VSL for R9 is almost a duplicate to the Lower VSL. There are some small changes in the wording but both situations
deal with the case where there is a problem that has been identified with the Interpersonal Communications system
and it takes more than two hours to initiate repair.
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire
that requirement during their last posting. We believe there needs to be better coordination with that SDT.
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess Bulk
Electric System reliability” to reflect what the enforceability of the standards are meant to be. The requirement on the
ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all operating entities and the entire BES is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
covered under a Reliability Coordinator. In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL applies to the
Regional Entity.
Yes
Yes
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or
actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator
shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator
Area.” The word “notify” should be stuck.
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving the as the Transmission Operator or Balancing Authority. We
believe that it should never be necessary for these System Operators to issue Reliability Directives to themselves in the
first example or to their co-worker in the second example to demonstrate compliance to NERC standards. How the
entity coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is
a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to another company. We believe that, in
place of requiring an operator, in real-time, to state “this is a Reliability Directive,” there should be an allowance for an
entity to develop procedures indicating, in advance, their expectations of three-part to their sub-operating entities.
Therefore, we suggest modifying R1 to be “When a Reliability Coordinator, Transmission Operator or Balancing
Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator
or Balancing Authority shall identify the action, either verbally, when the communication is issued, or in advance
through documented procedures, as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
Real-Time.]” Also, we believe that the definition of Emergency, as currently cited in these draft Standards and included
in the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to
make the Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time Operations SDT
proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the change to
the definition should be coordinated with that team. There is a text box in IRO-005-4 that indicates this standard will be
retired. Yet, there still remain requirements in the standard and various other associated documentation indicates
requirements are being move to this standard. Please delete the text box. IRO-014-2 R4 already includes a
requirement to have weekly conference calls that should suffice. IRO-014-2 R2 seems to recognize that these
Operating Procedures, Processes and Plans likely will not need to be discussed weekly as it only requires an annual
update. In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
reliability constraint or a declared Emergency”. Further, Requirement R2 in IRO-001 contains the words “which could
include issuing Reliability Directives” but Reliability Directives are not referenced anywhere else in the standard. This
inclusion seems unnecessary since without it, R2 already requires that the RC take actions or direct actions by others
to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability
Impacts. Whether or not a Reliability Directive is issued is irrelevant in this requirement. We suggest that these words
be removed. Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability
Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is unnecessary.
Individual
Steve Rueckert
WECC
Yes
Yes
Yes
Yes
Yes
Suggested minor revision to the definition of Reliability Directive as follows (change in caps) A communication,
IDENTIFIED AS A RELIABILITY DIRECTIVE, initiated by a Reliability Coordinator, Transmission Operator, or
Balancing Authority where action by the recipient is necessary to addrss an Emergency. Clearly identifying a
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
communication as a Reliability Directive provides immediate information to the recpient as the the nature of the
communications.
Individual
Bill Keagle
BGE
Yes
BGE has no additional comments.
Yes
BGE has no additional comments.
Yes
BGE has no additional comments.
Yes
BGE has no additional comments.
Yes
BGE has no additional comments.
BGE has no additional comments.
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
No
A. R5.5 states a BA shall have Interpersonal Communications with each Interchange Coordinator within its BA area
and adjacent Interchange Coordinators. NERC Registry Criteria (v5) uses the term “Interchange Authority” not
Interchange Coordinator, please clarify. B. Upon review of the NERC Compliance Registry, there are only 56 BA’s that
are also registered as an IA but 138 total BA’s within the registry. R5.5 is not clearly written because many BA’s do not
have an IA within their BA area. Though a BA will use an IA to schedule interchange, a possible rewrite of R5.5 may be
“Each Interchange Authority that the BA actively uses to arrange Interchange”. C. R10 states that the RC, TOP, BA, DP
and GOP shall notify “impacted entities” within 60 minutes… Please clarify if the SDT means the entities within the
applicability section or is this to be determined by the entity. A possible rewrite may be; “Each RC shall notify TOP’s,
BA’s, and IA’s within its RC area along with adjacent RC’s within the same Interconnection”. This break down would
need to be required for each affected entity and would provide clarity to the industry. D. We do not agree with a DP and
GOP need to be held to the same level of compliance as a RC, BA or TOP. FERC Order 693 (paragraph 487) directed
the DP and GOP to be included in this standard by stating:” We expect the telecommunication requirements for all
applicable entities will vary according to their roles and that these requirements will be developed under the Reliability
Standards development process”. A DP and GOP may not be staffed 24 hours a day like a BA or TOP and the SDT did
not take this into consideration. E. We understand that the DP and GOP need a means of communicating with their BA
and TOP (R7 and R8) but would this not be the same Interpersonal Communications capability that as stated in R3 and
R5 for the TOP and BA? Example: If the BA uses a phone line as their Interpersonal Communication medium to
contact the DP wouldn’t the DP also use the same medium to communicate with their BA? Yes, there could be different
mediums but 99% of the time it will be the same medium. F. R10 could mean that if there is a logging system that
detects an Interpersonal Communication failure, then all applicable entities will need to monitor that monitoring device.
Since this requirement applies to all applicable entities, and Interpersonal Communication mediums will most likely be
the same, there will always be two entities found non compliant if the 60 minute threshold is passed.
No
A. Agree that a receiving entity should not be held accountable until such time that they are required to take such
action. B. It might if the requirement were going to remain but the Project 2007-03 (“Real-Time Operations SDT”)
proposed to retire that requirement during their last posting. This needs to be coordinated with that SDT.
No
A. R1, As written it is unclear what level of certification this will entail? Presently written within the NERC Reliability
Standards, responsibility is given to RC’s to manage the reliability of their areas. Recommend deleting this
requirement. The ERO has pushed back in other Standards to having a responsibility for any NERC Requirements,
since they are not a user, owner, or operator of the BES (see EOP-004-2). If this does move forward and an RC is
certified by the ERO and then the RC is found non-compliant by a Regional Entity, for an associated certified item, will
the ERO be held responsible, too? If the SDT selects to keep R1, there are some issues with how the requirement is
written. The requirement places emphasis on regions and regional boundaries when no emphasis should be placed
there. There are multiple Reliability Coordinators the span multiple regions. The language “to continuously assess
transmission reliability” should be changed to “to continuously assess Bulk Electric System reliability” to reflect on what
the standards are enforceable. The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to
ensure that all operating entities and the entire BES is covered under a Reliability Coordinator. B. In R2, should “of” be
“to”. Reliability Directives are issued to TOPs, BA, etc. C. The VSL for R1 is not consistent with the requirement. The
requirement applies to the ERO but the VSL applies to the Regional Entity.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
A. COM-002-3, R2 As stated in FERC Order 693, section 512, it is essential that RCs, BA’s and TOP’s have
communications with DPs. R2 also applies to TSPs, LSEs and PSEs. There is no directive for this and it is going to be
almost impossible to communicate with a DP since DPs are usually not operated 24 hours per day as like a RC, TOP,
or BA. Many DPs have answering services that will relay a message once they receive it and then pass it along to
someone. An answering company could repeat the directive word for word but this will not add to any reliability level.
The SDT should reconsider the applicability section of this Standard to only apply to a RC, TOP and BA for the
issuance of a Reliability Directive. BA’s should have the responsibility to have an Interpersonal Communication medium
with DPs in their BA area per COM-001-2. B. IRO-002-2, R1, Recommend that “System Operators” be replaced with
“system operators” since NERC has defined System Operator to be an individual at a control center (BA, TOP, GOP, or
RC). The lower cased system operator will only point to the RC system operator that will have this R1 authority. C. The
SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving the as the Transmission Operator or Balancing Authority. We
believe that it should never be necessary for these System Operators to issue Reliability Directives to themselves in the
first example or to their co-worker in the second example to demonstrate compliance to NERC standards. How the
entity coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is
a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to another company. D. We also are
concerned about the need to conduct three-part communications for a Reliability Directive issued through a blast call.
Under these circumstances, the need for immediate action of multiple parties may require a blast call and there may
not be time for all parties to complete three-part communications before initiating actions. Thus, we believe blast calls
should be treated separately and that should be made clear. E. COM-002-3 R2 needs to be rewritten as it is too
verbose. The point is for the recipient of the original message to get the issuer to confirm that the message was
understood. We suggest rewording R2 to “Each Reliability Coordinator, Balancing Authority, Transmission Operator,
Generator Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or
recapitulate the Reliability Directive.” Once the receiver has completed this requirement, the ball is in the issuer’s court
per Requirement R3. No additional words are necessary in the requirement. F. Per COM-002-3 R1, who decides that
actions need to be issued as a Reliability Directive? Shouldn’t it be the responsible entity? Thus, can we assume that if
the responsible entity does not identify a communication as a Reliability Directive that it is not a Reliability Directive per
the requirement? After all, why would an entity require actions but not issue a Reliability Directive. Following this logic,
the VSL for R1 would never apply. Would a compliance auditor second guess if an action required a Reliability
Directive? G. Because the Project 2007-03 (“Real-Time Operations SDT”) proposed to utilize the definition of Adverse
Reliability Impact in TOP-001-2 R5 during the last posting, the change to the definition should be coordinated with that
team. H. There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain requirements
in the standard and various other associated documentation indicates requirements are being move to this standard.
Please delete the text box. I. Please strike part IRO-014-2 Part 1.7. There is no need to have a weekly conference to
discuss every Operating Procedure, Operating Process and Operating Plan. As this requirement is written, a
conference call would be necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have
weekly conference calls that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures,
Processes and Plans likely will not need to be discussed weekly as it only requires an annual update. J. IRO-014-2 R4
is overly broad and would require Reliability Coordinators that will not impact one another to participate on conference
calls with one another without any reliability benefit. The issue is created by the addition of the clause “within the same
Interconnection” to the requirement. ISO-NE, FRCC, Midwest ISO, and SPP are all in the same Interconnection. It is
hard to fathom there being reliability benefit to SPP and ISO-NE conversing weekly or Midwest ISO and FRCC
conversing weekly. We suggest limiting the requirement to adjacent Reliability Coordinators. K. For IRO-014-2 R5, we
suggest replacing “other” with “impacted” to limit the notification of Adverse Reliability Impacts to only those Reliability
Coordinators that need to know. Because the definition of Adverse Reliability Impact includes “Bulk Electric System
instability or Cascading”, it is possible that the cascading of 138 kV lines serving a load pocket or generator outlet
stability issues could require a Reliability Coordinator to notify all other Reliability Coordinators regardless of impact.
This would include Reliability Coordinators outside of the Interconnection with the problem. It would also include
Reliability Coordinators that are not impacted. For instance, an issue in New England that would not pose a threat
outside the northeast would require ISO-NE to notify SPP and FRCC and Reliability Coordinators in the Western
Interconnection. There is no reliability benefit to this notification. L. IRO-014-2 R6-R8 are problematic and need to be
refined to make clear that the Reliability Coordinators shall operate to the most conservative limit. It should not require
a Reliability Coordinator that disagrees with an action plan to implement the action plan. The Reliability Coordinator will
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
be disagreeing with the action plan for a reliability reasons. Assuming they are correct, the requirement to implement
said action plan will actually put the Interconnection at greater risk. These requirements inappropriately attempt to
codify the debate and analysis that occurs between and within Reliability Coordinators when there are differing results
in reliability analysis. This is part of the problem with having a Wide Area view that results in Reliability Coordinators
having a view into other Reliability Coordinator Area. Their results and conclusions may be different. There should be a
hierarchical structure for whose results should be used. It should be the Reliability Coordinator with primary
responsibility unless the other Reliability Coordinator has evidence to demonstrate that the Reliability Coordinator with
primary responsibility is incorrect. What this should do is, to trigger both to review their models and data to assess the
problem. None of this needs to be codified in the standards though. M. In the definition of Reliability Directive, we
suggest changing “to address an Emergency” to “to address a declared Emergency”. This would help limit second
guessing for a situation where a System Operator took action because he truly believed he was in an Emergency but
after the fact analysis demonstrates there really was not an Emergency. N. The drafting team should expand its
rationale for deleting IRO-002-1 R3. Currently, TOP-005 R1 is referenced. The project 2007-03 (“Real-Time Operations
SDT”) proposed to retire TOP-005-2 R1 in its most recent posting. O. We disagree with deleting IRO-002-1 R5 and R7
which establishes tools and monitoring capabilities. There should be basic tool requirements established for Reliability
Coordinators. The project 2009-02 (“Real-time Reliability Monitoring and Analysis Capabilities”) will be addressing
these issues in more detail. Thus, it does not make sense to delete these requirements until that drafting team
completes its task.
Group
FirstEnergy
Sam Ciccone
No
It is not clear from the definition of Interpersonal Communications if certain communications “mediums” such as email,
instant messaging, etc. are included. Furthermore, the Measures for these requirements all include “electronic
communications” as acceptable evidence. If the drafting team does not intend these mediums be included, then it
should be clarified in the definition. We suggest the following wording of the definition: Interpersonal Communication:
Any medium that allows two or more individuals to interact, consult, or exchange information. This interaction consists
of verbal, spoken words exchanged in Real-time.
Yes
Yes
Yes
Yes
FirstEnergy offers the following additional comments: 1. The effective dates of the standards indicate an effective date
of the first day of the first calendar quarter following regulatory approval. The changes to these standards will require
changes to existing compliance evidence, as well as the creation of compliance evidence for some entities such as the
Generator Operator which is a new applicable entity in COM-001. Therefore, to give entities ample time to get their
compliance evidence in place, we suggest the effective state “the first day of the second quarter after regulatory
approval”. 2. With regard to the requirements for Alternative Interpersonal Communications, we question why the
Generator Operator or Distribution Provider is not required to have backup communication. It would be difficult for a
Reliability Coordinator, for instance, to contact a Generator Operator whose primary communications have been
disabled if that entity does not have a backup. We suggest that the drafting team consider adding the GOP and DP as
applicable entities requiring alternative communications.
Group
Midwest ISO Standards Collaborators
Jason Marshall
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might inadvertently include
data. The drafting team responded that it does not by referring to Interpersonal in the name of the definition. Clearly,
you can’t refer the word you are defining to define it. However, it is possible “allows two or more individuals to …” may
solve this problem. What are the drafting team’s thoughts on this issue? This standard does not comport with the
informational filing that NERC submitted to FERC on August 10, 2009 regarding its discontinued use of subrequirements in standards development activities. Consider striking “to exchange Interconnection and operating
information” in R1, R3, R5, R7, and R8. It is redundant to the use of Interpersonal Communications “to interact, consult,
or exchange information” in the definition. Consider striking “to exchange Interconnection and operating information” in
R2, R4, R6. It is redundant to the use of Alternative Interpersonal Communications which uses Interpersonal
Communications in its definition. Interpersonal Communications includes “to interact, consult, or exchange information”
in its definition. For R2, why is Interchange Coordinator excluded? It is included in the Requirement R1 which deals
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with the Interpersonal Communications. Communications would need to be maintained with the Interchange
Coordinator in the event of a failure of the Interpersonal Communications. For R3, neighboring Transmission Operators
should be included. For R4 and R6, the sub-requirement list is different than for than for the associated Interpersonal
Communications requirements R3 and R5 respectively. They should be duplicate. That is the sub-requirement list for
R4 should match R3 and the R6 should match R5. In the event of a failure of the Interpersonal Communications, the
Transmission Operator and Balancing Authority both would need to maintain communications to the same entities as in
the requirement to have Interpersonal Communications. For R5, why are neighboring Balancing Authorities not
included? They certainly need to be able to contact one another to identify discrepancies in scheduling and sources of
meter error that could lead to deviations in ACE. Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In
R1, R3 and R5, the requirement is “shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one
is for the Interpersonal Communications and the other is for the Alternative Interpersonal Communications, it seems the
same wording should be used. Should R2.2 and R1.2 be limited to Reliability Coordinators in the same Interconnection
only? The VSLs for R1 through R8 should be expanded to include multiple levels based on the number of entities that
the functional entity does not have Interpersonal Communications or Alternative Interpersonal Communications. FERC
specified their general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs. The second half
of the Severe VSL for R9 is almost duplicate to the Lower VSL. There are some small changes in the wording but both
situations deal with the case where there is a problem that has been identified with the Interpersonal Communications
system and it takes more than two hours to initiate repair.
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire
that requirement during their last posting. This needs to be coordinated with that SDT.
No
In general, we are not opposed to the concept of the ERO certifying the Reliability Coordinators; however, there are
some issues with how the requirement is written. The requirement places emphasis on regions and regional
boundaries when no emphasis should be placed there. There are multiple Reliability Coordinators that span multiple
regions. The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect on what the standards are enforceable. The requirement on the ERO should
also be expanded similar to BAL-005-0.1b R1 to ensure that all operating entities and the entire BES is covered under
a Reliability Coordinator Area. In R2, should “of” be “to”. Reliability Directives are issued to TOPs, BA, etc. The VSL for
R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL applies to the Regional
Entity.
Yes
Yes
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as multiple
functions, the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a
company to issue directives to itself. There are several organizations registered as a Reliability Coordinator,
Transmission Operator and Balancing Authority. In these companies, it is not uncommon for those responsibilities to be
distributed across multiple desks. Thus, for certain situations, a single System Operator may actually be the Reliability
Coordinator and the Transmission Operator. In other situations, the System Operator serving the Reliability Coordinator
function may be adjacent to the System Operator serving the as the Transmission Operator or Balancing Authority. We
believe that it should never be necessary for these System Operators to issue Reliability Directives to themselves in the
first example or to their co-worker in the second example to demonstrate compliance to NERC standards. How the
entity coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is
a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to another company. We also are
concerned about the need to conduct three-part communications for a Reliability Directive issued through a blast call.
Under these circumstances, the need for immediate action of multiple parties may require a blast call and there may
not be time for all parties to complete three-part communications before initiating actions. Thus, we believe blast calls
should be treated separately and that should be made clear. COM-002-3 R2 needs to be rewritten as it is too verbose.
The point is for the recipient of the original message to get the issuer to confirm that the message was understood. We
suggest rewording R2 to “Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that
is the recipient of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the
Reliability Directive.” Once the receiver has completed this requirement, the ball is in the issuer’s court per
Requirement R3. No additional words are necessary in the requirement. Per COM-002-3 R1, who decides that actions
need to be issued as a Reliability Directive? Shouldn’t it be the responsible entity? Thus, can we assume that if the
responsible entity does not identify a communication as a Reliability Directive that it is not a Reliability Directive per the
requirement? After all, why would an entity require actions but not issue a Reliability Directive. Following this logic, the
VSL for R1 would never apply. Would a compliance auditor second guess if an action required a Reliability Directive?
Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the definition of Adverse Reliability Impact
in TOP-001-2 R5 during the last posting, the change to the definition should be coordinated with that team. There is a
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text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain requirements in the standard and
various other associated documentation indicates requirements are being move to this standard. Please delete the text
box. Please strike part IRO-014-2 Part 1.7. There is no need to have a weekly conference to discuss every Operating
Procedure, Operating Process and Operating Plan. As this requirement is written, a conference call would be
necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have weekly conference calls that
should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures, Processes and Plans likely will not
need to be discussed weekly as it only requires an annual update. IRO-014-2 R4 is overly broad and would require
Reliability Coordinators that will not impact one another to participate on conference calls with one another without any
reliability benefit. The issue is created by the addition of the clause “within the same Interconnection” to the
requirement. ISO-NE, FRCC, Midwest ISO, and SPP are all in the same Interconnection. It is hard to fathom there
being reliability benefit to SPP and ISO-NE conversing weekly or Midwest ISO and FRCC conversing weekly. We
suggest limiting the requirement to adjacent Reliability Coordinators. For IRO-014-2 R5, we suggest replacing “other”
with “impacted” to limit the notification of Adverse Reliability Impacts to only those Reliability Coordinators that need to
know. Because the definition of Adverse Reliability Impact includes “Bulk Electric System instability or Cascading”, it is
possible that the cascading of 138 kV lines serving a load pocket or generator outlet stability issues could require a
Reliability Coordinator to notify all other Reliability Coordinators regardless of impact. This would include Reliability
Coordinators outside of the Interconnection with the problem. It would also include Reliability Coordinators that are not
impacted. For instance, an issue in New England that would not pose a threat outside the northeast would require ISONE to notify SPP and FRCC and Reliability Coordinators in the Western Interconnection. There is no reliability benefit
to this notification. IRO-014-2 R6-R8 are problematic and need to be refined to make clear that the Reliability
Coordinators shall operate to the most conservative limit. It should not require a Reliability Coordinator that disagrees
with an action plan to implement the action plan. The Reliability Coordinator will be disagreeing with the action plan for
reliability reasons. Assuming they are correct, the requirement to implement said action plan will actually put the
Interconnection at greater risk. These requirements inappropriately attempt to codify the debate and analysis that
occurs between and within Reliability Coordinators when there are differing results in reliability analysis. This is part of
the problem with having a Wide Area view that results in Reliability Coordinators having a view into other Reliability
Coordinator Areas. Their results and conclusions may be different. There should be a hierarchical structure for whose
results should be used. It should the Reliability Coordinator with primary responsibility unless the other Reliability
Coordinator has evidence to demonstrate that the Reliability Coordinator with primary responsibility is incorrect. What
this should do is to trigger both to review their models and data to assess the problem. None of this needs to be
codified in the standards though. In the definition of Reliability Directive, we suggest changing “to address an
Emergency” to “to address a declared Emergency”. This would help limit second guessing for a situation where a
System Operator took action because he truly believed he was an Emergency but after the fact analysis demonstrates
there really was not an Emergency. The drafting team should expand its rationale for deleting IRO-002-1 R3. Currently,
TOP-005 R1 is referenced. The Real-Time Operations drafting team proposed to retire TOP-005-2 R1 in its most
recent posting. We disagree with deleting IRO-002-1 R5 and R7 which establish tools and monitoring capabilities.
There should be basic tools requirements established for Reliability Coordinators. Project 2009-02 Real-time Reliability
Monitoring and Analysis Capabilities will be addressing these issues in more detail. Thus, it does not make sense to
delete these requirements until that drafting team completes its task.
Individual
Brenda Powell
Constellation Energy Commodities Group
Yes
Yes
Yes
Yes
Yes
Group
Southern Company
Cindy Martin
No
Comments: Standard COM-001-2 R10. Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall notify impacted entities within 60 minutes of the detection of a
failure of its Interpersonal Communications capabilities that lasts 30 minutes or longer. Comment: It is not clear
whether the notification requirements identified in R10 apply to failure of ALL available Interpersonal Communications
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or ANY Interpersonal Communications. We suggest that the existence of functioning Alternative Interpersonal
Communications precludes the requirement for notification of impacted entities. D. Compliance 1. Compliance
Monitoring Process 1.3 Data Retention Each Generator Operator shall keep the most recent twelve months of historical
data (evidence) for Requirements R8 and R10, Measures M8 and M10. Comment: The data retention requirements
specified for the Generator Operator in Para. 1.3 (above) are not consistent with the 3-year audit interval for the GOP.
Question: When audited on this Standard is the expectation that the GOP will have 12 months of evidence or 36
months of evidence? Standard COM-002-3 R2. Each Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the
recipient of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the
Reliability Directive with enough details that the accuracy of the message has been confirmed. Comment: The term
“Reliability Directive” is currently not defined in the NERC Glossary of Terms. However, in the Implementation Plan for
COM-002-3 the RC SDT proposes a definition for Reliability Directive. It is implied in the standard that the Reliability
Directive is issued as a voice command which precludes the use of our preferred method of Interpersonal
Communication. However, this is not definitively stated in either the standard or the proposed definition. I think this
needs to be made clearer if the Reliability Directive must be issued as a voice command. D. Compliance 1. Compliance
Monitoring Process 1.3 Data Retention The Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity shall retain
evidence of Requirement 2, Measure 2 for the most recent 3 months. Comment: The data retention requirements
specified for the Generator Operator in Para. 1.3 (above) are not consistent with the 3-year audit interval for the
GOP/PSE. Question: When audited on this Standard is the expectation that the GOP and PSE will have 3 months of
evidence or 36 months of evidence?
No
Comments: I see no connection between XCELs comment on COM-001-1. The requirements of COM-001-1 require
the RCs, TOPs, and BAs to have a primary interpersonal communications method and to designate an alternative. I
believe that if the requirements for the entity to have both primary and alternative methods of interpersonal
communications this objection could be cleared. For example, R2 Each Reliability Coordinator shall designate have an
Alternative Interpersonal Communications capability with the following entities to exchange Interconnection and
operating information
No
Comments: This would allow NERC to designate one entity to be the Reliability Coordinator for an entire
interconnection or the entire continent. This would reduce the Regional Reliability Organizations to compliance entities.
Yes
Yes
Comments: It appears that the requirements for entities designated in the IRO standards to have tools to access and/or
monitor the system have been moved to pending standards that are not enforceable. It seems that if the newest
revisions of the IRO standards are not implemented as a group there will be either missing requirements or duplicate
requirements in the IRO standards.
Individual
Greg Rowland
Duke Energy
No
• We question how far the definition of Alternative Interpersonal Communication goes in requiring separate
infrastructure from Interpersonal Communication. For example, wireless communications sometime utilize fiber optic
networks. • We question why the requirements state that entities must “have” Interpersonal Communications capability,
but must “designate” Alternative Interpersonal Communications capability? • R1.2 and R2.2 – Why is this limited to the
same interconnection? • R3 – need to add neighboring TOPs. • R5 – need to add adjacent BAs. • Interchange
Coordinator – Add IC to the Applicability Section, and add a requirement that the IC have Interpersonal Communication
capability with its BA and adjacent BAs. • Requirements to “designate” Alternative Interpersonal Communication should
carry a “Medium” VRF instead of “High”, because they are a backup capability. The word “designate” carries the
connotation that these are documentation requirements. • R9 requires a monthly test of Alternative Interpersonal
Communications capability. This was quarterly in the last draft. We question how these requirements for “Alternative
Interpersonal Communications” capability are related to requirements for “backup functionality” in EOP-008-1, which
requires an annual test of backup functionality. Clarity on the relationship between “Interpersonal Communications”,
“Alternative Interpersonal Communications”, “primary control center functionality” and “backup control center
functionality” would be appreciated. • R11 – is this requirement being moved to COM-003? • Data Retention – Is data
retention really going to be just 12 months? Most auditors seem to be asking for everything since the last audit.
No
Requirements of TOP-001-1 are being revised under Project 2007-03, which may not continue to adequately address
Xcel’s concern.
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No
How is NERC going to certify the RCs? Also, we believe the word “all” should be inserted after the word “among”, so
that it’s clear that all generation, transmission and load must be included.
Yes
Yes
• COM-002-3 contains the proposed definition “Reliability Directive”. We continue to believe Requirement R1 should be
deleted and that this definition should contain the phrase “identified as a Reliability Directive to the recipient”.
Otherwise, compliance controversies will arise when auditors second-guess the RC, TOP or BA’s judgment regarding
whether or not an abnormal system condition met the definition of “Emergency”, and warranted a “Reliability Directive”
with 3-part communication. A conforming change will need to be made to R2, since it refers to R1. This change in the
definition of “Reliability Directive” is also needed because this term is used in other standards such as IRO-001-2, and
without repeating a similar requirement to COM-002-3 requirement R1 in IRO-001-2, there is potential for confusion. •
We disagree with the VSL for COM-002-3. This is clearly a requirement with two possible compliance failures: Failure
to acknowledge a correct repeat-back, and failure to resolve an incorrect repeat-back. These failures have dramatically
different consequences, which the drafting team should recognize via a graduated VSL. We think that the failure to
acknowledge should either be “Lower” or “Medium”. • Requirement R2 of IRO-001-2 is unclear and should be reworded
as follows: “Each Reliability Coordinator shall take actions or direct actions (which could include issuing Reliability
Directives to Transmission Operators, Balancing Authorities, Generator Operators, Interchange Coordinators and
Distribution Providers within its Reliability Coordinator Area) to either prevent identified events that could result in an
Adverse Reliability Impact, or mitigate the magnitude or duration of actual events that result in Adverse Reliability
Impacts.” • Various changes have been made to the defined term “Adverse Reliability Impact” as this project has
progressed. We believe the latest change should not be made, and the Phrase “uncontrolled separation” should be
reinserted in the definition, because that phrase is part of the Epact 2005 legislation definition of “reliable operation”.
Here is the text from the legislation: “The term ‘reliable operation’ means operating the elements of the bulk-power
system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements.”
Group
SPP Standards Development
Robert Rhodes
No
We would suggest that the applicability of COM-001-2 be expanded to that listed in COM-002-3. How can the directives
to be issued in COM-002 be delivered and confirmed without having Interpersonal Communications capability? All of
the functional entities listed in R1.1 should also be listed in R2.1. Similarly the sub-requirements of R3 should also be
applied to R4. The same holds true for R5 and R6. If the SDT intends to exclude data communications from
Interpersonal Communications and Alternative Interpersonal Communications, we suggest the SDT be more specific in
the definition to specifically exclude data communications in the definition. It is not readily apparent that these terms do
not apply to data communications and without a clarification, confusion exists.
Yes
In fact, we believe that R1, R2 and R5 more specifically put that requirement on the TOP. The TOP doesn’t have to
wait for the RC and any directive that may be associated with R3 prior to taking action to mitigate an emergency
condition.
No
Is this more of a registry question than a standards issue? While we agree that there needs to be a requirement
somewhere that establishes the need for Reliability Coordinators, isn’t there also a similar need for other functional
entities such as Transmission Operators, Balancing Authorities, etc? Should these be captured in standards or in the
certification/registration process?
Yes
Yes
IRO-001-2, R2 implies that the RC could interrupt the normal chain of command from the TOP and/or BA to their
respective GOPs, ICs and DPs thereby circumventing the coordinating process that currently exists. In fact, these
entities may not even know their RCs nor be able to identify them and as such any directive from the RC may not be
implemented in a timely manner. We would like to see a qualifier on this requirement that does not remove the normal
coordination role from the TOP with his DP, etc. We would suggest that "with enough details that the accuracy of the
message has been confirmed" be deleted from COM-002-3, R2. We would suggest the use of the term 'instruction" and
its derivatives rather than 'direct' in IRO-001-2, R2, R3 and R4. Delete ‘issue an alert to’ in IRO-005-4, R1. There are
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yellow boxes in IRO-005-4, redline versions, which indicate that this standard is being retired, but it isn’t because two
requirements from IRO-001 are being returned to this standard.
Individual
CJ Ingersoll
CECD
No
Based on the drafting teams response that the definition of Interpersonal"clarifies the exclusion of media dedicated to
Telemetering or other data exchange,the term Interpersonal Communication should be replaced with verbal
communication capabilties. The term Alternative Interpersonal Communication should be replaced with alternative
verbal communication capability that is able to serve as a substitute for and does not utilize the same infrastructure
(medium) as verbal communications capabilities used for day-to-day operations.
Yes
Yes
Yes
1. COM-002 R2 states that "the recipient of a Reliability Directive issued per Requirement R1, shall repeat, restate,
rephrase or recapitulate the Reliability Directive with enough details that the accuracy of the message has been
confirmed." Recommend a change to "the recipient of a Reliability Directive issued per Requirement R1, shall repeat,
restate, rephrase or recapitulate the Reliability Directive with enough details that the desired outcome of the message
is clear". 2. IRO-001 R2 states "Each Reliability Coordinator shall take actions or direct actions which could include
issuing Reliability Directives of Transmission Operators, ...." Recommend a change to "Each Reliability Coordinator
shall take actions or direct actions which could include issuing Reliability Directives [See COM-002] to Transmission
Operators, ..." 3. IRO-001 R4 states entities "shall inform its Reliability Coordinator upon recognition of its inability to
perform as directed per Requirement R3." Recommend a change to, entities "shall inform its Reliability Coordinator
upon recognition of its inability to perform as directed."
Individual
Rex A Roehl
Indeck Energy Services
No
Yes
No
Yes
Yes
Individual
Shaun Anders
City of Springfield, IL - City Water Light and Power (CWLP)
No
The definition of “Interpersonal Communications” is overly broad and does not address the functional needs of
reliability coordination. The definition should be limited to systems utilized for essential reliability functions. While the
Purpose statement in the standard does address this intent, the explicit inclusion in the definition removes all
ambiguity. Further, the definition of “Alternative Interpersonal Communications” without corresponding explicit definition
of Primary Interpersonal Communications may lead to confusion and unnecessary duplication of efforts in testing and
maintenance.
No
TOP-001 is in the process of being substantially modified by Project 2007-03. These changes may conflict with the
matter addressed by Xcel’s comment. Thus, Xcel’s concern should be addressed independently but in the context of
the TOP-001-2 revisions proposed by Project 2007-03.
Yes
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CWLP generally concurs with and supports comments previously submitted by the SERC Operating Committee where
those comments are not in conflict with the specific comments above.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
Each sub-requirement should not have an “R” in front of the number in order to be consistent with NERC’s August 10,
2009 filing at FERC on this subject. Requirement R3 and R4 should include adjacent TOPs as a sub-requirement.
Requirements R5 and R6 should include adjacent BAs as a sub-requirement. “to exchange Interconnection and
operating information” should be deleted from requirements R1 through R8 as it is redundant with the definition of
Interpersonal Communications The last page of the Implementation Plan includes LSEs, PSE, and TSPs as being
responsible entities under this standard, yet the standard does not include them. Please correct the implementation
plan.
No
Top-001-1, Requirement R3, which is what the SDT appears to be using as its justification for not adding a requirement
here is proposed to be deleted by the RTO-SDT on Project 2007-03.
No
We think you are attempting to create a requirement similar to BAL-005, R1. That language copied here is clear and
concise - All generation, transmission, and load operating within an Interconnection must be included within the
metered boundaries of a Balancing Authority Area.
Yes
Yes
Reliability Directives may be issued by blast calls from Reliability Coordinators. It is inefficient and may be a hindrance
to reliability to require 3-part communications in these instances. There are several organizations registered as BAs,
RCs and TOPs. It is not uncommon for those entities to be distributed across multiple desks in the same control room
without regard to how an entity is registered. Thus, a single System Operator may perform functions that are
categorized under two or more of those functional entities. The drafting team should clarify that under no circumstances
should that System Operator be required to issue a Reliability Directive to himself. This is a corporate governance
issue. In IRO-014, R1, delete sub-requirement 1.7. The requirement for weekly conference calls related to operating
procedures is duplicative to R4 and could be burdensome while adding very little value under certain circumstances. In
IRO-014, R4, delete the phrase “(per Requirement 1, Part 1.7)” as a conforming change. In IRO-014, Requirements
R6-R8 allow at least the theoretical possibility that an RC may determine an Adverse Reliability Impact in another RC’s
area that the other RC neither can see nor believes that any action should be taken. R7 puts the burden on the first RC
to develop a plan that it cannot implement because it has no agreement with the BAs and TOPs in the other RC area.
As such, this requirement is unenforceable. Please review all the implementation plans to be sure the applicable
entities match those in the standards.
Individual
Dan Rochester
Independent Electricity System Operator
No
(1) NERC filed with FERC on August 10, 2009 indicating that it would discontinue the use of sub-requirements in
standards. All draft standards posted since have the format of Part Numbers within each main Requirement. Please
revise the standards in this project accordingly. (2) Having defined the terms Interpersonal Communication and
Alternative Interpersonal Communication, the phrase “to exchange Interconnection and operating information” in a
number of requirements is redundant and can be removed. Further, for R1, we suggest removing the phrase “within the
same Interconnection since there RCs between two Interconnections still need to communication with each other for
reliability coordination (e.g. curtailment of interchange transactions crossing Interconnection boundary, as stipulated in
IRO-006). (3) R2: Suggest to add Purchasing-Selling Entity and Interchange Authority (INT-004 and INT-005 have
requirements for communication between the RC and the PSE and IA), and remove the phrase “within the same
Interconnection since there RCs between two Interconnections still need to communication with each other for reliability
coordination (e.g. curtailment of interchange transactions crossing Interconnection boundary, as stipulated in IRO-006).
(4) R3: Suggest to add adjacent Transmission Operator and Purchasing-Selling Entity (the latter needed for meeting
INT-004 requirements). (5) The list of entities in R4 and R6 is different from those in R3 and R5. They should be the
same for having Alternative Interpersonal Communication capability. (6) R5: Suggest to add adjacent Balancing
Authority as adjoining BAs need to communication with each to check schedules and other balancing information. (7)
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There are a number of parts in Requirements R1 to R8 each of which must be complied with. However, the VSLs for
R1 to R8 are binary which do not provide any distinction in partial failure of each of these requirements. We suggest
the SDT to apply the VSL guideline and re-establish the various levels of violation severity for these requirements.
No
TOP-001 is being revised and some of the requirements that fulfill this need may have been removed. We suggest the
SDT check with the latest draft version of TOP-001 and coordinate with the Real-time Operation SDT to ensure there
are not gaps.
No
1. R2: The word “of” before Transmission Operators should be “to”. 2. The VSL for R1 should be revised to replace
Regional Entities with ERO.
Yes
Yes
1. IRO-001: Reliability Directive: We do not agree with the proposed definition since it addresses Emergencies only.
There are situations where a Reliability Directive is issued such that the directed action must be taken by the receiving
entity to address a reliability constraint or any condition on the BES which if left unattended could, in the judgment of
the issuing entity, lead to an Emergency. These conditions themselves do not constitute an Emergency which is
defined as “Any abnormal system condition that requires automatic or immediate manual action to prevent or limit the
failure of transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric
System.” There could be no abnormal condition but the actions must nevertheless be taken promptly to prevent the
bulk electric system from entering into an abnormal condition. We therefore suggest the term Reliability Directive be
revised to: Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or
Balancing Authority where action by the recipient is necessary to address a reliability constraint or an Emergency. 2.
IRO-001, Requirement R2: This requirement contains the words “which could include issuing Reliability Directives”
which is not referenced anywhere else in the standard. We do not think this inclusion is necessary since without it, R2
already requires that the RC take actions or direct actions by others to prevent identified events or mitigate the
magnitude or duration of actual events that result in Adverse Reliability Impacts. Whether or not a Reliability Directive is
issued is irrelevant in this requirement. We suggest to remove these words. Note that COM-002 already stipulates the
requirement for 3-part communication when a Reliability Directive is issued. The inclusion of “which could include
issuing Reliability Directives” in IRO-001 is unnecessary. We suggest replacing “identified events” with “anticipated
events”. This requirement also lists Interchange Coordinators as one of the recipients of Reliability Directives which is
not consistent with the implementation plan. 3. IRO-014: R4 as written creates unnecessary requirements for an RC to
participate in conference calls for issues that may not affect the RC itself. We suggest to reinstate the original word
“impacted” as opposed to “other”, and remove the words “within the same Interconnection” since such calls and
coordination may be required for RCs on both side of the Interconnection boundary. Same change suggested for R5,
i.e. replace “other” with “impacted”. 4. If an entity provides Interpersonal Communication for day-to-day communication
using two different media, e.g. radio and telephone, the proposed definition of Alternative Interpersonal Communication
suggests that it would not be possible for one medium to be used as the Alternative Interpersonal Communication for
the other since the two media are both used every day. 5. COM-001-2 R10 suggests that the responsible entity must
wait for at least 30 minutes before notifying other entities of the failure of its Interpersonal Communication capability.
We recommend changing “that lasts 30 minutes” to “that lasts or is expected to last 30 minutes”. This allows
responsible entities to start notifying other entities earlier. 6. In IRO-005-4 R1: Delete “notify”.
Individual
Alice Ireland
Xcel Energy
No
We feel that either the definitions, or the requirements, should make it clear whether data is included.
No
We are concerned that the drafting team may not have understood Xcel Energy’s comments and FERC’s directive in
Order 693. FERC had asked that NERC consider Xcel Energy’s suggestion. This consideration does not necessarily
equate to the development of additional requirements, however that may be the solution. We recognize that R1 and R2
of TOP-001-1 give the TOP authority to take immediate actions necessary to alleviate operating emergencies. We were
concerned with the potential situation where the RC’s directive (R3 of IRO-001-2) may conflict with actions the TOP
has ALREADY taken. In this situation, we do not feel the TOP should be held at fault for the actions it took prior to the
RC's directive. (R3 of IRO-001-2 is currently in effect under TOP-001-1 R3.) Additionally, R1 and R2 of TOP-001-1
have been removed from the latest draft of version 2. So, if TOP-001-2 and IRO-001-2 are approved as drafted, it
would appear that all rights and protections of the TOP to take immediate actions will be removed and our initial issue,
as detailed in Order 693, still exists.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Group
Kansas City Power & Light
Michael Gammon
No
These requirements require TOP’s, BA’s, and GOP’s to establish alternative means of “interpersonal” communications
with other BA’s, GOP’s, and BA’s respectively without regard to the reliability impact each TOP, BA or GOP has on the
interconnection. Why would it be necessary for a TOP with one 161kv transmission line or a BA with 100 MW of total
load, or one GOP with a 30MW unit to realize additional costs when the facilities they operate have little reliability
impact? In addition, most RC’s have established satellite telephone systems as back-up communication with TOP’s.
RC’s may have to establish additional communication systems with BA’s as these requirements impose to avoid
Standards of Conduct issues. R9 – considering the reliability of communication systems, a 2 hour response to a
problem with the alternative means of communication is over sensitive. Allowing for sometime in an operating shift
would be more in line, such as 8 hours.
Yes
Yes
Yes
Yes
There are more requirements that are being removed in the IRO standards than are currently proposed. It would be
helpful if the SDT would consider a mapping of each requirement that is being eliminated and whether the requirement
is duplicated elsewhere, moved elsewhere and where, or is deemed not needed would be helpful in judging if the
changes are appropriate. Without this mapping it is difficult to fully support all the proposed changes to all these
Standards.
Consideration of Comments on Initial Ballot — Reliability Coordination (Project 2006-06)
Date of Initial Ballot: February 25 – March 7, 2011
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
1
Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Summary Consideration:
The RCSDT thanks all stakeholders for their comments. Many stakeholders provided comments suggesting revisions to the standards. Many of
these suggestions were incorporated into the standards. As a result of the revisions, the RCSDT is moving COM-001-2, COM-002-3 and IRO-0012 to a successive ballot. The RCSDT made a few clarifying edits to the remaining standards based on stakeholder comments. Therefore, IRO002-3, IRO-005-4 and IRO-014-2 are being moved to recirculation ballot. Because of this approach, the SDT will be proposing an interim change
to IRO-001: the elimination of Requirement R7, as it is duplicative of one of the requirements in IRO-014-2.
For the COM-001 standard, several commenters had suggestions for improvements to the requirement language and applicability. The RCSDT
believes the standard correctly and adequately requires each applicable entity that would have capability to receive Interconnection and operating
information to have Interpersonal Communications and Alternative Interpersonal Communications to be used when the Interpersonal
Communication is not available. The RCSDT has addressed the applicability of the standards and implementation plans by aligning COM-001-2,
and COM-002-3 to include the same entities and by removing LSE, PSE and TSP from the COM standards.
Many comments were concerned about both the medium (e.g. cellular, satellite, etc.) and media (e.g. voice, email, etc.) used for Interpersonal
Communications. The current language avoids being prescriptive and allows each entity to determine what is suitable. Interpersonal
Communication and Alternative Interpersonal Communication is between the applicable entities which may include multiple locations (e.g. a
primary and back-up control center).
The RCSDT added the following Requirement Parts at the suggestion of stakeholders:
3.5 Adjacent Transmission Operators synchronously connected within the same Interconnection
4.3 Adjacent Transmission Operators synchronously connected within the same Interconnection
5.6 Adjacent Balancing Authorities
6.3 Adjacent Balancing Authorities
The RCSDT agrees with the many industry comments and removed the phrase "to exchange Interconnection and operating information" in
requirements R1 through R8. This removal clarifies that the intent of this capability is NOT for the exchange of data.
A few commenters also expressed concerns about the frequency of testing Alternative Interpersonal Communications capability. The RCSDT
believes that the proposed testing frequency is supported by the majority of stakeholders and is not overly burdensome.
1
The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.
Several commenters suggested that VSLs should be written based on the percent of entities rather than by an occurrence of a violation. VSLs
must be written on a violation occurrence basis in accordance with FERC guidelines. The requirements specify which entities must be included in
communications capabilities. If a single entity is missing, this is a violation of the requirement. According to VSL guidelines, if missing any part of
the requirement could have the same reliability outcome as missing the entire requirement, the requirement is binary and the VSL must be severe.
A new requirement was added to COM-001 for clarity regarding responsibilities of the Distribution Provider and the Generator Operator when
either entity experiences a failure of its Interpersonal Communication capability:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication capabilities
shall consult with its Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
This requirement requires collaboration between entities to restore a failed communications capability.
The RCSDT asked stakeholders if they believed that the requirements of TOP-001-1 obviate the need to develop additional requirements to
address Xcel’s comment as directed in FERC Order 693. The original justification that the RCSDT posited for not adding a requirement to directly
address Xcel Energy’s comments in paragraph 516 and FERC’s related recommendation in paragraph 523 was that TOP-001-1 R3 was
considered to address this concern. Since that time, the RTO SDT has proposed to retire TOP-001-1 R3. However, NERC has since retired IRO004-1 R3 and R5 along with IRO-005-3 R5. Because these are retired, there are no longer any requirements that would force a TOP to wait for a
delayed RC response during an emergency. Therefore the question is resolved, albeit differently than it was proposed to be resolved in this
posting. If an RC were to give a Reliability Directive to a TOP that the TOP considered “would violate safety, equipment, regulatory, or statutory
requirements,” the TOP may respond to the RC that it cannot comply.
Stakeholders were asked if they agree with the revision to IRO-001, R1 for certifying Reliability Coordinators. Many commenters suggested
removing the requirement because it is addressed in the NERC Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
A significant revision to IRO-001-2 was made by removing the Interchange Coordinator from the standard. The RCSDT made this revision
because the Balancing Function is responsible for implementing interchange (see NERC Reliability Functional Model, version 5, page 32, item 7)
and to operate the Balancing Authority Area to maintain load-interchange-generation balance (item 3).The RCSDT asked stakeholders if they
agree with moving two requirements from IRO-001 back to IRO-002 relating to Analysis Tool outages. All stakeholders that responded agreed
and there were no comments received.
The RCSDT asked stakeholders if they agree with moving two requirements from IRO-001 back to IRO-005 relating to Reliability Coordinator
notifications. Several commenters noted a typographical error in R1 which was corrected to read:
When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or actual condition with Adverse
Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator shall notify issue an alert to all impacted
Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. [Violation Risk Factor: High] [Time Horizon: Realtime Operations, Same Day Operations and Operations Planning]”
One commenter also asked that an errant yellow text box be removed from Page 1, which was also done.
The RCSDT received a number of comments regarding the applicability of COM-001, and COM-002. The RCSDT agrees with these comments
and has removed PSE and LSE from the COM-001-2 implementation plan. The RCSDT also addressed minor issues involving typos, formatting
and style.
2
The RCSDT received comments suggesting clarification of COM-002-3. The RCSDT intends the communication of Reliability Directives to be
person-to-person and in such a manner that the Reliability Directive is understood and not necessarily repeated verbatim. COM-002-3 is not
intended to be prescriptive on how the Reliability Directive is issued. Spoken or written communications are valid methods (i.e. using the
telephone, radio, electronic texting, email, etc.). The purpose of COM-002-3 is to ensure emergency communications between operating
personnel are effective. There is no proxy requirement for 24/7 operating personnel regarding small entities. Only “capability” as provided for in
COM-001-2 is applicable. The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient and effective. The
RCSDT believes Reliability Directives issued in mass should be defined by procedure, and that the procedure would establish a method of
affirmation and notice of implementation. As envisioned, communications protocols would be addressed in the COM-003 standard being
developed in Project 2007-02.
Some commenters suggested revisions to IRO-014, requirement R8 to conform to similar requirements R6 and R7. The RCSDT made the
suggested revision by re-ordering R8:
R8. During those instances where Reliability Coordinators disagree on the existence of an Adverse Reliability Impact, each Reliability
Coordinator shall implement the action plan developed by the Reliability Coordinator that identified the Adverse Reliability Impact unless
such actions would violate safety, equipment, regulatory or statutory requirements. [Violation Risk Factor: High][Time Horizon: Operations
Planning, Same Day Operations and Real-time Operations]
IRO-014-2, requirement R4 is applicable to those Reliability Coordinators engaged in activities related to requirement R1 and part 1.7. It is
unlikely that Reliability Coordinators geographically and electrically distant from one another will have mutually agreed upon operating procedures
(per requirement R1), and therefore requirement R4 would not be applicable. The RCSDT believes IRO-014-2, requirement R4 (which requires
weekly communication) provides reasonable contact and flexibility – and this requirement is in effect today.
The RCSDT coordinated the use of the NERC Glossary term “Adverse Reliability Impact” with the Real-Time Operations team and continues the
practice of informing all RCs of Adverse Reliability Impacts in requirement R5.
The RCSDT has revised IRO-014-2, requirements R6-R8 to clarify that when one RC identified a problem and presents an action plan for another
RC, the second RC is obligated to implement the action plan. The RCSDT will forward the concern about RC's identifying themselves and the
receiver to establish authority to the Project 2007-02, Operating Personnel Communications Protocols SDT. The Project 2007-02 team is
developing a standard that includes requirements for use of specific communications protocols.
Voter
Entity
Edward P.
Cox
AEP
Marketing
Segment
6
Vote
Negative
Comment
1) The applicability of COM-001 and COM-002 appear to be at odds with each
other. The requirements may need to be re-written so that they are in sync.
Response: The RCSDT has revised the applicability of COM-001 and COM002 such that they contain the same functional entities. These are: RC,
TOP, BA, GOP, and DP.
2) The revision to IRO-001, R1 is out of scope with the standard, as it is currently
addressed through the NERC certification process that the NERC reliability
coordinators are subject to.
3
Voter
Entity
Segment
Vote
Comment
Response: Many commenters suggested removing the requirement because it
is addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
3) The language used in COM-002-3 R2 including “with enough details that the
accuracy of the message has been confirmed” is subjective and ambiguous.
Response: The RCSDT agrees with the intent of your comment and has
modified COM-002-3, R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity,
Distribution Provider, and Purchasing-Selling Entity that is the recipient of
a Reliability Directive issued per Requirement R1, shall repeat, restate,
rephrase or recapitulate the Reliability Directive.
4) IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in
lower case (while it appears that “Directives” is a subset of “directions”). We
believe that this muddies the waters and could bring numerous conversations
and dialog into scope unnecessarily. The end result is that the RC has the right
to issue and use “Directives” and anything short of this could just be
communications. For example, a number of entities that are Reliability
Coordinators also facilitate energy markets. There are many communications
related to markets that probably should be out of scope with respect to the
standards. Furthermore, it might not be clear what role (eg Reliability
Coordinator, market operator, etc) the staff at these entities are fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios
and also emergency scenarios. The required performance encompasses
issuing and responding to Reliability Directives as well as other directions.
The requirement language specifically ties back to Requirement R2 which
states that the RC “shall take actions or direct actions, which could include
issuing Reliability Directives, “. This is the “direction in accordance with
Requirement R2” stated in R3 and the “direction in accordance with
Requirement R3” stated in R4.
Response: The RCSDT thanks you for your comment. Please see responses above.
4
Voter
Brock
Ondayko
Entity
AEP Service
Corp.
Segment
5
Vote
Negative
Comment
1) The applicability of COM-001 and COM-002 appear to be at odds with each
other. The requirements may need to be re-written so that they are in sync.
Response: The RCSDT has revised the applicability of COM-001, and COM002 such that they contain the same functional entities. These are: RC, TOP,
BA, GOP, and DP.
2) The revision to IRO-001, R1 is out of scope with the standard, as it is currently
addressed through the NERC certification process that the NERC reliability
coordinators are subject to.
Response: Many commenters suggested removing the requirement because it
is addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
3) The language used in COM-002-3 R2 including “with enough details that the
accuracy of the message has been confirmed” is subjective and ambiguous.
Response: The RCSDT agrees with the intent of your comment and has
modified COM-002-2, R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, Transmission Service Provider, Load-Serving Entity,
Distribution Provider, and Purchasing-Selling Entity that is the recipient of
a Reliability Directive issued per Requirement R1, shall repeat, restate,
rephrase or recapitulate the Reliability Directive.
4) IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in
lower case (while it appears that “Directives” is a subset of “directions”). We
believe that this muddies the waters and could bring numerous conversations
and dialog into scope unnecessarily. The end result is that the RC has the right
to issue and use “Directives” and anything short of this could just be
communications. For example, a number of entities that are Reliability
Coordinators also facilitate energy markets. There are many communications
related to markets that probably should be out of scope with respect to the
standards. Furthermore, it might not be clear what role (eg Reliability
Coordinator, market operator, etc) the staff at these entities are fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios
and also emergency scenarios. The required performance encompasses
issuing and responding to Reliability Directives as well as other directions.
The requirement language specifically ties back to Requirement R2 which
5
Voter
Entity
Segment
Vote
Comment
states that the RC “shall take actions or direct actions, which could include
issuing Reliability Directives.” This is the “direction in accordance with
Requirement R2” stated in R3 and the “direction in accordance with
Requirement R3” stated in R4.
Response: The RCSDT thanks you for your comment. Please see responses above.
Richard J.
Mandes
Alabama
Power
Company
3
Affirmative
Please see comments
Response: The RCSDT thanks you for your comment. Please see response to posting comments for the SERC OC Standards Review Group;
the RCSDT did not specifically find comments from Alabama Power Company and believes comments were included within this group.
Kenneth
Goldsmith
Alliant Energy
Corp.
Services, Inc.
4
Negative
While most of the changes recommended in the standards are acceptable to us, we
do not believe multiple standards should be included in one ballot. You might ask
for comments as a group, but each standard should be balloted separately.
Response: The SDT has discussed this recommendation and has changed the
way that these standards are being posting for ballot. Thank you for your
suggestion.
COM-001 R10 needs to be clarified that the "impacted entities" are within the same
interconnection/area. It is not necessary to contact all entities as could be
interpreted by the standard as currently written. We believe there may be differing
levels of communication requirements, especially as it relates to smaller entities
registered as DP's or LSE's that are not staffed 24 hours per day. We agree there is
some responsibility of everyone to have some level of communications, the
question is to what level.
Response: R10 specifies only “impacted entities.” That phrase is used to limit the
scope of the requirement. If an entity has a failure of its Interpersonal
Communications capability with only one entity, then that entity is the “impacted
entity” and they should be notified of the failure.
6
Voter
Entity
Segment
Vote
Comment
Response: The RCSDT thanks you for your comment. Please see responses above.
Jennifer
Richardson
Ameren
Energy
Marketing Co.
6
Negative
Comment COM-001: (1) R2 is written with the onus on the Recipient to get repeat
an accurate message. The Measure and VSL appear to attach to the Recipient to
make a bad message into an accurate one.
Response: The SDT assumes you intended to comment regarding COM-002-3 R2,
as that is where the issuance, dialogue, and confirmation process is described, not
COM-001. The SDT believes that it is the issuing entity which is required to decide
whether the message has been received to its satisfaction. However, the SDT
further believes the recipient of the original communications must be responsible for
responding and participating in dialogue with the issuing entity. Without that, the
issuing entity cannot decide whether the message has been received and
understood.
(2) R2 is too verbose.
Response: Based on specific suggestions from other stakeholders, the team
deleted the following phrase from R2:
with enough details that the accuracy of the message has been confirmed
The team revised the associated VSL to:
The responsible entity that was the recipient of a Reliability Directive failed
to repeat, restate, rephrase or recapitulate the Reliability Directive. with
enough details that the accuracy of the message was confirmed.
(3) We don’t think Operations should rely on email, for instance, as an Interpersonal
Communication capability. We should be explicit to exclude these kinds of medium.
The medium must be near instantaneous like voice, cell, and satellite.
Response: COM-002 does not preclude text or other forms of communication for
issuing Reliability Directives.
Response: The RCSDT thanks you for your comment. Please see responses above.
7
Voter
Kirit S. Shah
Entity
Ameren
Services
Segment
1
Vote
Negative
Comment
Comment COM-001: (1) R2 is written with the onus on the Recipient to get repeat
an accurate message. The Measure and VSL appear to attach to the Recipient to
make a bad message into an accurate one.
Response: The SDT assumes you intended to comment regarding COM-002-3 R2,
as that is where the issuance, dialogue, and confirmation process is described, not
COM-001. The SDT believes that it is the issuing entity which is required to decide
whether the message has been received to its satisfaction. However, the SDT
further believes the recipient of the original communications must be responsible for
responding and participating in dialogue with the issuing entity. Without that, the
issuing entity cannot decide whether the message has been received and
understood.
(2) R2 is too verbose.
Response: COM-002-3 R2: Based on specific suggestions from other
stakeholders, the team deleted the following phrase from R2:
with enough details that the accuracy of the message has been confirmed
The team revised the associated VSL to:
The responsible entity that was the recipient of a Reliability Directive failed
to repeat, restate, rephrase or recapitulate the Reliability Directive. with
enough details that the accuracy of the message was confirmed.
(3) We don’t think Operations should rely on email, for instance, as an Interpersonal
Communication capability. We should be explicit to exclude these kinds of medium.
The medium must be near instantaneous like voice, cell, and satellite.
Response: COM-002 does not preclude text or other forms of communication for
issuing Reliability Directives.
Response: The RCSDT thanks you for your comment. Please see responses above.
Gregory S
Miller
Baltimore
Gas & Electric
Company
1
Affirmative
BGE is supportive of all 5 questions in the Comment Form.
8
Voter
Entity
Segment
Vote
Comment
Response: The RCSDT thanks you for your support.
Joseph S.
Stonecipher
Beaches
Energy
Services
1
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding.
I suggest changing COM-002-3 R2 to read:
Each Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and
Purchasing-Selling Entity that is the recipient of a Reliability Directive issued per
Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability
Directive with enough details to clearly communicate the recipient's understanding
of the Reliability Directive.
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to ensure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
identify a feasible measure for “understanding”. A recipient can judge whether the
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
For IRO-001-2, I don't see a need for R1. Doesn't the ERO already have that
authority to establish RC's through the registration process, and to certify system
operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
9
Voter
Entity
Segment
Vote
Comment
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: This requirement continues the current practice of informing all RCs of
Adverse Reliability Impacts (ARIs). Due to the nature of an ARI, this requirement is
typically implemented as an RCIS message or a hotline call to all RCs. This is
intended to make all RCs aware of ARIs and support situational awareness.
More minor comments / suggestions for improvement: IRO-002 R2 can be
improved by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT did indeed consider using the
word “anticipated” rather than identified. However, the SDT believes that a decision
cannot be made regarding whether to anticipate an event unless it is first identified
through some method of assessment. Contingency analysis certainly can be one
valid form useful in assessment. Since anything identified by such an assessment
must be considered, the SDT believes the requirement should apply to what is
identified, rather than the subjective decision of whether to expect or anticipate that
which has been identified
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT agrees, and has revised the requirements per your
suggestion.
Response: The RCSDT thanks you for your comment.
Bud Tracy
Blachly-Lane
Electric Co-op
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
10
Voter
Entity
Segment
Vote
Comment
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window."
Also, a note that smaller, rural entities can be dependent on a phone system
provider that will not allow for backup communications. Should the communication
line(s) be dependent on one main phone trunk line, the failure due to an issue on
this main line will make it impossible to notify anyone of its failure short of physically
traveling to an area where phone service is available. For some rural areas, this will
exceed the one hour time limit to report the communication outage. Forcing smaller
entities to acquire satellite phone service to mitigate for a phone outage is a high
price to pay when no reliability improvement will be achieved. Suggested change
could be: "... shall notify impacted entities within 60 minutes of the detection of a
failure of its Interpersonal Communications capabilities that lasts 30 minutes or
longer where alternate forms of communication are available within a 15 minute
access time. Should alternate forms of communication not be available within the
15 minute access time, then upon reestablishment of Communication capabilities
impacted entities will be notified of the past loss and current status of
Communication." We’ve heard many representatives from FERC and NERC
indicate that the standards development process has led the industry to take action
in many cases for the sake of compliance while not necessarily enhancing
reliability. As has been stated many times, the process should be about improving
reliability, not about complying with standards. Unnecessarily including smaller
entities that will NEVER receive an emergency reliability directive might be an
example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
11
Voter
Entity
Segment
Vote
Comment
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Gregory Van
Pelt
California ISO
2
Abstain
The California ISO will be submitting comments Jointly as part of the ISO/RTO
Council Standards Review Committee
Response: Thank you; please see responses to the comments submitted on the posting by the ISO/RTO Council Standards Review
Committee.
Dave
Markham
Central
Electric
Cooperative,
Inc.
(Redmond,
Oregon)
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
12
Voter
Entity
Segment
Vote
Comment
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Steve
Alexanderson
Central
Lincoln PUD
3
Negative
The stated purpose of COM-002 is: “To ensure emergency communications
between operating personnel are effective.” As written, the standard fails to meet
this purpose because the three requirements only deal with communications at the
entity level. There is no requirement for the directing entity to even try to reach
operating personnel at the receiving entity. The directing entity may follow all the
requirements of this standard by following R1 and R3 with the receiving entity’s
receptionist, answering service, janitor, night watchman, etc. The receiving entity
only needs to meet R2, parroting the directive. Again this could be accomplished by
anyone with no assurance the directive reaches the operating personnel who can
implement it. When we stated a similar objection during the last comment period,
The SDT’s answer suggested this was a PER staffing issue, but none of the PER
requirements even apply to DP/LSE directive recipients. We suggest the entity
issuing the directive should be required to make an attempt to get it to those who
are competent to understand and implement the directive. This is not a staffing,
training, or credentials issue; it is a performance issue that falls squarely within the
stated purpose of this standard. COM-001 R10 presents a paradoxical situation to
an entity attempting to comply. Consider an interpersonal communication capability
13
Voter
Entity
Segment
Vote
Comment
failure that lasts longer than 60 minutes past initial detection. At or before 60
minutes, the affected entity is expected to notify impacted entities. If it has no
interpersonal communication capability, how shall it make this notification? And if
the entity does manage to make such a notification, it has thereby proven that it
does have interpersonal communication capability making such notification
unnecessary. We again ask the SDT to consider that not all the entities in the
applicability sections of COM-001 and 002 have 24/7 dispatch centers. These are
typically smaller entities that were required to register because they exceed 25 MW
or were asked in the past to voluntarily provide UFLS. They do not and do not need
to continuously communicate with TOPs, BAs, RCs, etc; and a “reliability directive”
is a theoretical thing that has never happened during the memories of thirty year
employees. The directive issuing entities simply realize the limitations around the
receiving entities and work around them. The financial burden on these small
entities and their customers to go to 24/7 dispatch will not have a corresponding
reliability benefit. And while the two COM standards do not explicitly state that
entities must maintain 24/7 dispatch, when all the requirements and definitions and
time horizons are taken together 24/7 continuous competent communication is
implied. During the last comment period, the SDT suggested this was a registration
issue beyond their control. We submit instead that this is a standard applicability
question that the SDT does have control over, since it is right there in Section A.4
of the two COM standards. While we appreciate that the SDT is responding to
FERC order 693 to include DPs, we note that FERC also stated: Paragraph 487:
“We expect the telecommunication requirements for all applicable entities will vary
according to their roles and that these requirements will be developed under the
Reliability Standards development process.” Paragraph 6: “A Reliability Standard
may take into account the size of the entity that must comply and the costs of
implementation” Paragraph 141: “...the Commission clarifies that it did not intend to
... impose new organizational structures...” Paragraph 31: “We emphasize that we
are not, at this time, mandating a particular outcome by way of these directives, but
we do expect the ERO to respond with an equivalent alternative and adequate
support that fully explains how the alternative produces a result that is as effective
as or more effective that the Commission’s example or directive. We ask the SDT
to exclude DPs, LSEs, and PSEs that do not have 24/7 dispatch centers from the
applicability of these two standards in order to meet FERC order 693.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
14
Voter
Entity
Segment
Vote
Comment
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Shamus J
Gamache
Central
Lincoln PUD
4
Negative
The stated purpose of COM-002 is: “To ensure emergency communications
between operating personnel are effective.” As written, the standard fails to meet
this purpose because the three requirements only deal with communications at the
entity level. There is no requirement for the directing entity to even try to reach
operating personnel at the receiving entity. The directing entity may follow all the
requirements of this standard by following R1 and R3 with the receiving entity’s
receptionist, answering service, janitor, night watchman, etc. The receiving entity
only needs to meet R2, parroting the directive. Again this could be accomplished by
anyone with no assurance the directive reaches the operating personnel who can
implement it. When we stated a similar objection during the last comment period,
The SDT’s answer suggested this was a PER staffing issue, but none of the PER
requirements even apply to DP/LSE directive recipients. We suggest the entity
issuing the directive should be required to make an attempt to get it to those who
are competent to understand and implement the directive. This is not a staffing,
training, or credentials issue; it is a performance issue that falls squarely within the
stated purpose of this standard. COM-001 R10 presents a paradoxical situation to
an entity attempting to comply. Consider an interpersonal communication capability
failure that lasts longer than 60 minutes past initial detection. At or before 60
minutes, the affected entity is expected to notify impacted entities. If it has no
interpersonal communication capability, how shall it make this notification? And if
the entity does manage to make such a notification, it has thereby proven that it
does have interpersonal communication capability making such notification
unnecessary. We again ask the SDT to consider that not all the entities in the
applicability sections of COM-001 and 002 have 24/7 dispatch centers. These are
typically smaller entities that were required to register because they exceed 25 MW
or were asked in the past to voluntarily provide UFLS. They do not and do not need
to continuously communicate with TOPs, BAs, RCs, etc; and a “reliability directive”
is a theoretical thing that has never happened during the memories of thirty year
employees. The directive issuing entities simply realize the limitations around the
receiving entities and work around them. The financial burden on these small
entities and their customers to go to 24/7 dispatch will not have a corresponding
reliability benefit. And while the two COM standards do not explicitly state that
entities must maintain 24/7 dispatch, when all the requirements and definitions and
time horizons are taken together 24/7 continuous competent communication is
15
Voter
Entity
Segment
Vote
Comment
implied. During the last comment period, the SDT suggested this was a registration
issue beyond their control. We submit instead that this is a standard applicability
question that the SDT does have control over, since it is right there in Section A.4
of the two COM standards. While we appreciate that the SDT is responding to
FERC order 693 to include DPs, we note that FERC also stated: Paragraph 487:
“We expect the telecommunication requirements for all applicable entities will vary
according to their roles and that these requirements will be developed under the
Reliability Standards development process.” Paragraph 6: “A Reliability Standard
may take into account the size of the entity that must comply and the costs of
implementation” Paragraph 141: “...the Commission clarifies that it did not intend to
... impose new organizational structures...” Paragraph 31: “We emphasize that we
are not, at this time, mandating a particular outcome by way of these directives, but
we do expect the ERO to respond with an equivalent alternative and adequate
support that fully explains how the alternative produces a result that is as effective
as or more effective that the Commission’s example or directive. We ask the SDT
to exclude DPs, LSEs, and PSEs that do not have 24/7 dispatch centers from the
applicability of these two standards in order to meet FERC order 693.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Gregg R
Griffin
City of Green
Cove Springs
3
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FMPA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive..
The term "accuracy" can be interpreted as requiring the recipient to second-guess
16
Voter
Entity
Segment
Vote
Comment
the Reliability Directive of the RC to enure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
identify a feasible measure for “understanding”. A recipient can judge whether the
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
For IRO-001-2, FMPA does not see a need for R1. Doesn't the ERO already have
that authority to establish RC's through the registration process, and to certify
system operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: This requirement continues the current practice of informing all RCs of
Adverse Reliability Impacts (ARIs). Due to the nature of an ARI, this requirement is
typically implemented as an RCIS message or a hotline call to all RC’s. This is
intended to make all RCs aware of ARIs and support situational awareness.
More minor comments / suggestions for improvement: IRO-002 R2 can be
improved by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT did indeed consider using the
word “anticipated” rather than identified. However, the SDT believes that a decision
cannot be made regarding whether to anticipate an event unless it is first identified
through some method of assessment. Contingency analysis certainly can be one
valid form useful in assessment. Since anything identified by such an assessment
must be considered, the SDT believes the requirement should apply to what is
17
Voter
Entity
Segment
Vote
Comment
identified, rather than the subjective decision of whether to expect or anticipate that
which has been identified.
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT agrees and have revised the requirements per your
suggestion.
Response: The RCSDT thanks you for your comment.
18
Randall
McCamish
City of Vero
Beach
1
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. The City of Vero Beach (COVB) suggests changing
COM-002-3 R2 to read: Each Balancing Authority, Transmission Operator,
Generator Operator, Transmission Service Provider, Load-Serving Entity,
Distribution Provider, and Purchasing-Selling Entity that is the recipient of a
Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or
recapitulate the Reliability Directive with enough details to clearly communicate the
recipient's understanding of the Reliability Directive. The term "accuracy" can be
interpreted as requiring the recipient to second-guess the Reliability Directive of the
RC to enure the accuracy of the RC's directive in the first place. Under tight time
constraints of Emergencies, this is not practical. We are sure that was not the intent
of the drafting team.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
identify a feasible measure for “understanding”. A recipient can judge whether the
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
For IRO-001-2, COVB does not see a need for R1. Doesn't the ERO already have
that authority to establish RC's through the registration process, and to certify
system operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: This requirement continues the current practice of informing all RCs of
Adverse Reliability Impacts (ARIs). Due to the nature of an ARI, this requirement is
typically implemented as an RCIS message or a hotline call to all RC’s. This is
19
intended to make all RCs aware of ARIs and support situational awareness.
More minor comments/suggestions for improvement: IRO-002 R2 can be improved
by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT did indeed consider using the
word “anticipated” rather than identified. However, the SDT believes that a decision
cannot be made regarding whether to anticipate an event unless it is first identified
through some method of assessment. Contingency analysis certainly can be one
valid form useful in assessment. Since anything identified by such an assessment
must be considered, the SDT believes the requirement should apply to what is
identified, rather than the subjective decision of whether to expect or anticipate that
which has been identified.
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT agrees and have revised the requirements per your
suggestion.
Response: The RCSDT thanks you for your comment.
John Allen
City Utilities of
Springfield,
Missouri
4
Negative
See comments from the SPP Standards Development group.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Shaun
Anders
City Water,
Light & Power
of Springfield
1
Negative
The definition of “Interpersonal Communications” is overly broad and does not
address the functional needs of reliability coordination. The definition should be
limited to systems utilized for essential reliability functions. While the Purpose
statement in the standard does address this intent, the explicit inclusion in the
definition removes all ambiguity. Further, the definition of “Alternative Interpersonal
Communications” without corresponding explicit definition of Primary Interpersonal
Communications may lead to confusion and unnecessary duplication of efforts in
20
testing and maintenance.
Response: The RCSDT thanks you for your comment. The certification of an entity as a functional entity by the ERO through its certification
process will not take place unless the entity has the needed communications capabilities. If the entity cannot perform, it will not be registered.
Once an entity is certified as a functional entity, then that entity must comply with all requirements applicable to that functional entity. These
standard revisions establish clear requirements for alternative interpersonal communications capability which may or may not be part of the entity
certification process. Taken together, the certification process and the Reliability Standards clearly establish the requirements for both normal
interpersonal communications capability and alternative interpersonal communications capability.
The RCSDT has revised the applicability of COM-001, and COM-002 such that they contain the same functional entities. These are: RC, TOP,
BA, GOP, and DP.
Dave Hagen
Clearwater
Power Co.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
21
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Bruce
Krawczyk
ComEd
3
Negative
Exelon is voting negative based on our previously submitted comments.
Response: The RCSDT thanks you for your comment. Please see the response to those comments.
Christopher L
de
Graffenried
Consolidated
Edison Co. of
New York
1
Abstain
o COM-002 assumes, but does not require, voice logs. This needs to be fixed.
Otherwise the documentation could just be a paper log 'check box' entry which says
"Yes, we used 3-part." This is not adequate, verifiable documentation for entity
audits.
Response: The standards establish “what” is required, not “how” to do it. The
Measures identify methods which are examples of evidence that may be provided
to demonstrate compliance, but requirements cannot be established in the
measures. Further, valid requirements should not be established that preclude
improvements that may arise through technological innovations or other equally
effective alternatives. The state of the art at present would seem to indicate that
the most prevalent evidence would likely come from a form of voice recordings or
transcripts.
22
o COM-002 only requires the entity maintain this documentation 3 months. This
short retention time period expires long before most auditors check on the entity.
So, why bother? This also needs to be fixed or clarified.
Response: The retention time was established using the NERC Data Retention
Guidelines and to recognize that vast amount of data which would have to be
retained to present evidence. In addition, any event under investigation has likely
been accompanied by a requirement to “freeze” data retention and keep all relevant
information and date for a specified timeframe surrounding the event.
Response: The RCSDT thanks you for your comment.
Roman Gillen
Consumers
Power Inc.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
23
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Roger
Meader
Coos-Curry
Electric
Cooperative,
Inc
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
24
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Russell A
Noble
Cowlitz
County PUD
3
Negative
COM-001 presents problems for smaller entities that do not have any other option
for communications other than the failed communication line. The SDT should
consider exempting such entities, requiring them to contact others to inform of their
failed one and only communication option is a catch-22.
COM-002 does not adequately provide for effective communication with smaller
entities that do not have 24-7 control/dispatch functions. The directing entity issuing
Reliability Directives must contact competent personnel. The SDT’s reference to
25
the PER requirements falls very short in addressing this problem as the DPs and
LSEs are not even applicable to the suggested standards. Again, the SDT should
consider certain exemptions for such entities. Please note that FERC itself noted
that “a Reliability Standard may take into account the size of the entity that must
comply and the costs of implementation...””...the Commission clarifies that it did not
intend to ... impose new organizational structures...” and also “[w]e expect the
communication requirements for all applicable entities will vary according to their
roles and that these requirements will be developed under the Reliability Standards
development process.” Although the STD did not include all applicable entities to
have backup communications, it failed to see the limitations of such entities without
backup communications impeding their ability to comply with other requirements.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Rick Syring
Cowlitz
County PUD
4
Negative
COM-001 presents problems for smaller entities that do not have any other option
for communications other than the failed communication line. The SDT should
consider exempting such entities, requiring them to contact others to inform of their
failed one and only communication option is a catch-22.
COM-002 does not adequately provide for effective communication with smaller
entities that do not have 24-7 control/dispatch functions. The directing entity issuing
Reliability Directives must contact competent personnel. The SDT’s reference to
the PER requirements falls very short in addressing this problem as the DPs and
LSEs are not even applicable to the suggested standards. Again, the SDT should
consider certain exemptions for such entities. Please note that FERC itself noted
that “a Reliability Standard may take into account the size of the entity that must
comply and the costs of implementation...””...the Commission clarifies that it did not
intend to ... impose new organizational structures...” and also “[w]e expect the
communication requirements for all applicable entities will vary according to their
roles and that these requirements will be developed under the Reliability Standards
development process.” Although the STD did not include all applicable entities to
have backup communications, it failed to see the limitations of such entities without
backup communications impeding their ability to comply with other requirements.
26
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Bob Essex
Cowlitz
County PUD
5
Negative
COM-001 presents problems for smaller entities that do not have any other option
for communications other than the failed communication line. The SDT should
consider exempting such entities, requiring them to contact others to inform of their
failed one and only communication option is a catch-22. COM-002 does not
adequately provide for effective communication with smaller entities that do not
have 24-7 control/dispatch functions. The directing entity issuing Reliability
Directives must contact competent personnel. The SDT’s reference to the PER
requirements falls very short in addressing this problem as the DPs and LSEs are
not even applicable to the suggested standards. Again, the SDT should consider
certain exemptions for such entities. Please note that FERC itself noted that “a
Reliability Standard may take into account the size of the entity that must comply
and the costs of implementation...””...the Commission clarifies that it did not intend
to ... impose new organizational structures...” and also “[w]e expect the
communication requirements for all applicable entities will vary according to their
roles and that these requirements will be developed under the Reliability Standards
development process.” Although the STD did not include all applicable entities to
have backup communications, it failed to see the limitations of such entities without
backup communications impeding their ability to comply with other requirements.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Dave Sabala
Douglas
Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
27
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
28
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Henry ErnstJr
Duke Energy
Carolina
3
Negative
o We question how far the definition of Alternative Interpersonal Communication
goes in requiring separate infrastructure from Interpersonal Communication. For
example, wireless communications sometime utilize fiber optic networks.
Response: The definition requires the use of different infrastructure (medium)
than the Interpersonal Communication used for day to day operations. The
RCSDT does not believe it is appropriate to be prescriptive with respect to the
specific medium employed. This is intended to apply to assets and access to
media that is under your control. For example, the way cell phone signals are
routed are not under your control.
o We question why the requirements state that entities must “have”
Interpersonal Communications capability, but must “designate” Alternative
Interpersonal Communications capability?
Response: Many entities have multiple Alternative Interpersonal
Communication capabilities. Large entities may have a second land line, cell
phone, satellite phone, etc. The purpose of “designating” the Alternative is so
that other entities know which one is in use and is a reliable means of
communications. Allowing them to designate which one they want to employ
allows for flexibility in which one they use for AIC.
o R1.2 and R2.2 - Why is this limited to the same interconnection?
Response: The phrase “within the same interconnection” is added for the case
of ERCOT which has only DC tie lines with the Eastern Interconnection and has
minimal interchange.
o R3 - need to add neighboring TOPs.
Response: Agreed. The standard has been modified as suggested.
o R5 - need to add adjacent BAs.
Response: Agreed. The standard has been modified as suggested.
o Interchange Coordinator - Add IC to the Applicability Section, and add a
requirement that the IC have Interpersonal Communication capability with its BA
and adjacent BAs.
Response: We eliminated the Interchange Coordinator from COM-001-2 based
29
on stakeholder feedback.
o Requirements to “designate” Alternative Interpersonal Communication should
carry a “Medium” VRF instead of “High”, because they are a backup capability.
The word “designate” carries the connotation that these are documentation
requirements.
Response: While the requirement is phrased to focus on the documentation,
the reliability objective is that the entity has an alternative communication
capability with those functional entities most critical to its real-time operations.
o R9 requires a monthly test of Alternative Interpersonal Communications
capability. This was quarterly in the last draft. We question how these
requirements for “Alternative Interpersonal Communications” capability are
related to requirements for “backup functionality” in EOP-008-1, which requires
an annual test of backup functionality. Clarity on the relationship between
“Interpersonal Communications”, “Alternative Interpersonal Communications”,
“primary control center functionality” and “backup control center functionality”
would be appreciated.
Response: Interpersonal Communication and Alternative Interpersonal
Communication are not related to EOP-008. The provision to test may be
performed through day to day use of the capability.
Response: The RCSDT thanks you for your comment. Please see responses above.
George S.
Carruba
East
Kentucky
Power Coop.
1
Negative
As currently written, IRO-014 could be interpreted that if a RC identifies an adverse
reliability impact in another RC and the other RC does not agree with the findings,
the RC who identified the adverse reliability impact would be responsible for
creating a mitigation plan to address the issue. This may not be possible if the
identifying RC does not have agreements in place with the TOPs/BAs in the other
RC area.
Response: The RCSDT thanks you for your comment. IRO-014-2 requirement R6, requires all RCs to operate as if the problem exists even
when they disagree with the RC that identified the problem. Even if there is a disagreement between RCs, R8 still requires that all RCs comply
with the action plan developed by the RC that identified the adverse reliability impact unless compliance with the action plan would violate safety,
equipment, regulatory or statutory requirements. As envisioned, the TOPs and BAs would receive operating instructions from their own RC, not
from the RC in another Reliability Coordinator Area.
Sally Witt
East Kentucky
Power Coop.
3
Negative
As currently written it could be interpreted that if an RC identifies an Adverse
reliability Impact in another RC Area and they do not agree with the findings, the
30
RC who identified the adverse reliability Impact would be responsible for creating a
mitigation plan to address the issue. This may not be feasible if the identifying RC
does not have agreements in place with TOPs/BAs in the other RC Area.
Response: The RCSDT thanks you for your comment. IRO-014-2 requirement R6, requires all RCs to operate as if the problem exists even
when they disagree with the RC that identified the problem. Even if there is a disagreement between RCs, R8 still requires that all RCs comply
with the action plan developed by the RC that identified the adverse reliability impact unless compliance with the action plan would violate safety,
equipment, regulatory or statutory requirements. As envisioned, the TOPs and BAs would receive operating instructions from their own RC, not
from the RC in another Reliability Coordinator Area.
John R
Cashin
Electric
Power Supply
Association
5
Affirmative
I will be submitting comments in the regular form tomorrow.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Chuck B
Manning
Electric
Reliability
Council of
Texas, Inc.
2
Negative
We agree with the comments submitted by the IRC SRC and we have submitted
those same comments.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Martin
Kaufman
ExxonMobil
Research and
Engineering
5
Negative
The Measurement 2 of COM-002-3 has the potential to create numerous violations
without any reliability impact to the Bulk Electric System. Specifically, for those
facilities without voice recording equipment, the requirement to record in an
operator log that the BA/GOP/TOP/TSP repeated the intent of a directive back to
the RC provides no benefit to the reliability of the BES and adds a situation where
an entity can be found non-compliant by an RE with zero impact to the reliability of
the BES. In response to a directive from an RC, it's important for the reliability of the
BES for a facility to identify an instruction as a directive, resolve whether the facility
can comply with the directive, and inform the RC when it could not comply with the
directive. Documentation requirements should reflect these three items.
Response: The RCSDT thanks you for your comment. Based on comments from other stakeholders, the SDT has removed the TSP, LSE and
PSE from responsibility for any of the requirements in COM-002. As envisioned, in an emergency the RC would issue most Reliability
Directives to its BAs and TOPs, and there may be times when the RC bypasses its TOPs and BAs and issues a Reliability Directive to its DPs
31
and GOPS. The RC would not, however, issue a Reliability Directive to TSPs, LSEs, or PSEs.
Note that M2 only requires that the recipient document that it repeated the reliability directive. Collectively, the three measures do what you
have proposed – they require that the applicable entities document that the three parts of the communication took place – original issuance;
accurate repeat; confirmation. Operating logs are offered as one form of acceptable evidence – but other types of evidence could also be used
to demonstrate compliance.
Bryan Case
Fall River
Rural Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
32
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Robert
Martinko
FirstEnergy
Energy
Delivery
1
Affirmative
FirstEnergy supports the proposed standards and would appreciate consideration
of our comments submitted through the formal comment period.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Kevin Querry
FirstEnergy
Solutions
3
Affirmative
FirstEnergy supports the proposed standards and would appreciate consideration
of our comments submitted through the formal comment period.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Mark S
Travaglianti
FirstEnergy
Solutions
6
Affirmative
FirstEnergy supports the proposed standards and would appreciate consideration
of our comments submitted through the formal comment period.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Frank
Gaffney
Florida
Municipal
4
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
33
Power
Agency
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FMPA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive. The
term "accuracy" can be interpreted as requiring the recipient to second-guess the
Reliability Directive of the RC to ensure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We
assume that was not the intent of the drafting team.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
identify a feasible measure for “understanding”. A recipient can judge whether the
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
For IRO-001-2, FMPA does not see a need for R1. Doesn't the ERO already have
that authority to establish RC's through the registration process, and to certify
system operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: This requirement continues the current practice of informing all RCs of
Adverse Reliability Impacts (ARIs). Due to the nature of an ARI, this requirement is
typically implemented as an RCIS message or a hotline call to all RC’s. This is
intended to make all RCs aware of ARIs and support situational awareness.
More minor comments / suggestions for improvement: IRO-002 R2 can be
34
improved by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT did indeed consider using the
word “anticipated” rather than identified. However, the SDT believes that a decision
cannot be made regarding whether to anticipate an event unless it is first identified
through some method of assessment. Contingency analysis certainly can be one
valid form useful in assessment. Since anything identified by such an assessment
must be considered, the SDT believes the requirement should apply to what is
identified, rather than the subjective decision of whether to expect or anticipate that
which has been identified.
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT agrees and have revised the requirements per your
suggestion.
Response: The RCSDT thanks you for your comment.
Thomas E
Washburn
Florida
Municipal
Power Pool
6
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FMPA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive..
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to ensure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
identify a feasible measure for “understanding”. A recipient can judge whether the
35
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
For IRO-001-2, do not see a need for R1. Doesn't the ERO already have that
authority to establish RC's through the registration process, and to certify system
operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: IRO-014-2 R5: This requirement continues the current practice of
informing all RCs of ARIs. Due to the nature of an ARI, this requirement is typically
implemented as an RCIS message or a hotline call to all RC’s. This is intended to
make all RCs aware of ARIs and support situational awareness.
More minor comments / suggestions for improvement: IRO-002 R2 can be
improved by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT did indeed consider using the
word “anticipated” rather than identified. However, the SDT believes that a decision
cannot be made regarding whether to anticipate an event unless it is first identified
through some method of assessment. Contingency analysis certainly can be one
valid form useful in assessment. Since anything identified by such an assessment
must be considered, the SDT believes the requirement should apply to what is
identified, rather than the subjective decision of whether to expect or anticipate that
which has been identified.
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT agrees, and has revised the requirements per your
36
suggestion.
Response: The RCSDT thanks you for your comment.
Silvia P.
Mitchell
Florida Power
& Light Co.
6
Negative
8) Question 1
1. Do you agree with COM-001 requirements for Interpersonal Communications
capability and Alternative Interpersonal Communications capability (R1-R8)? If not,
please explain in the comment area below. No
9) Question 1 Comments: As drafted, COM-001 is not clear or complete. At this
stage in the evolution of compliance with the mandatory Reliability Standards, it is
important that any new or revised Reliability Standard clearly articulate all
compliance obligations and tasks consistent with Sections 302 (6) and (8) of the
NERC Rules of Procedure. Thus, NextEra Energy Inc. (NextEra) has numerous
recommended corrections to provide clarity and completeness to COM-001. For
example, the requirement to designate an Alternative Interpersonal Communication
capability is not clear. Does the designator solely designate for the designator’s
knowledge or does the designator need to inform the entity on the other end of the
connection.
In R2, for instance, the Reliability Coordinator must designate, but it is also not
clear whether the Reliability Coordinator must inform the Balancing Authorities or
Transmission Operators. It is further unclear whether the designation must be
documented, or if any informing of the Balancing Authorities or Transmission
Operators must be documented. Thus, it is recommended that the drafters decide
what was intended regarding the designation and clearly state the requirements.
In R9 it states that “. . . on at least a monthly basis.” There are two issues to
consider here. If the sentence stays, grammatically it should read “. . . on, at least,
a monthly basis. . . “ However, from a compliance and technical perspective, the
term “at least” has no significance and should be deleted. The requirement is to test
on a monthly basis - the phrase “at least” only introduces ambiguity and implies that
the party should consider every two or three weeks. If the drafting team believes a
best practice is less than a month, there are other NERC educational tools to
explain a best practice.
In R10, it states “. . . shall notify the impacted entity . . .” It would be clearer to state:
“. . . shall notify the impacted Reliability Coordinator, Transmission Operator,
Balancing Authority, Distribution Provider or Generator Operator . . .” Page 6
37
Response: The Requirement R2 is for the RC to designate an AIC and inform the
other entity (BA, TOP, etc.) as to what that AIC is. The Measure M2 provides
examples of the types of evidence which may be used to prove compliance with the
requirement.
The RCSDT believes that stakeholders are satisfied with the wording of the
requirements of this standard. The phrase “at least” was included to relay the intent
– that the monthly requirement is a minimum, and some entities may wish to
perform this more frequently. It does not add any compliance obligation to perform
this activity more frequently than specified.
For R10, the RCSDT believes that the existing language is sufficiently clear.
10) Question 2 2. The RCSDT believes that the requirements of TOP-001-1 obviate
the need to develop additional requirements to address Xcel’s comment. Do you
agree? If not, please explain in the comment area below. No
11) Question 2 Comments: As stated in response to number 1, Reliability
Standards are to be clear and complete. If a Transmission Operator is not
responsible for a delay caused by a Reliability Coordinator, the Standard should
specifically state that the Transmission Operator does not need to wait for an
assessment or approval of a Reliability Coordinator to take actions pursuant to
TOP-001-1 R3. Since the Reliability Coordinator is atop the reliability higherachy,
such a statement provides clarity and completeness to understanding a
Transmission Operators rights. Thus, TOP-001-1 R3 should be revised to lead with:
“Without any obligation to first seek and obtain an assessment or approval from its
Reliability Coordinator, each Transmission Operator . . . .” Page 10
Response: The SDT thanks you for your comment. The RTO SDT proposes to
retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a
TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this
posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirements”,
the TOP may respond to the RC that it cannot comply.
12) Question 6 Comments: At this stage in evolution of compliance with the
mandatory Reliability Standards, it is important that any new or revised Reliability
Standard clearly articulate all compliance obligations and tasks consistent with
Sections 302 (6) and (8) of the NERC Rules of Procedure. COM-002, IRO-001,
IRO-002 and IRO-014 do not meet this threshold. Thus, NextEra has numerous
recommended corrections to provide clarity and completeness to these Reliability
38
Standards. COM-002 R1 The addition of defined terms for Reliability Directive and
Emergency is a very good approach that helps provides clarity. Hence, it is also be
appropriate to make the language in the requirement as clear as possible, and not
add other implied or unexplained notions. Also, at times, in those regions with
markets, it is not always clear whether a requirement to curtail for reliability reasons
is being issued pursuant to market rules or from the Reliability Coordinator or
Transmission Operator under the Reliability Standards. Therefore, it is also
appropriate that the Reliability Coordinator, Transmission Operator, Balancing
Authority be required to identify themselves;, and if they fail to identify themselves
or fail to use the term Reliability Directive, the registered entity receiving the flawed
issuance should not be consider in violation of a Reliability Standard for failing to
act. Accordingly, R1 would be clearer and have the same intent, if it stated as
follows: “A Reliability Coordinator, Transmission Operator or Balancing Authority
have the authority to issue an oral or written Reliability Directive as authorized in
[list the specific Reliability Standard requirements such as IRO-001 R8 and TOP001 R3]. The issuance of an oral of written Reliability Directive, by a Reliability
Coordinator, Transmission Operator or Balancing Authority shall: (1) use the term
‘Reliability Directive;’ and (2) identify the issuer of the Reliability Directive as a
Reliability Coordinator, Transmission Operator or Balancing Authority. If a
Reliability Coordinator, Transmission Operator or Balancing Authority issues an oral
or writtern directive without using the term “Reliability Directive” or failing to
indentify itself as a Reliability Coordinator, Transmission Operator or Balancing
Authority, the registered entity receiving the directive cannot be considered in
violation for its failure to act.”
Response: There is a new standard under development (COM-003) that is
addressing a broader range of communications protocols, and has proposed a
requirement for the Reliability Coordinator to announce his/her title when issuing
alerts and other types of announcements.
IRO-001 The definition of Adverse Reliability Impacts uses the term “instability.” It is
important that this term be technically defined in the same way “Cascading” is
defined, otherwise the new requirement is not adding clarity; rather, it is maintaining
the ambiguous term “instability” that will likely lead to confusion and debate.
Response: The term, ‘instability’ is already used in many reliability standards.
R1 Similar to the comments set forth with respect to COM-001 (question #1), the
term “at least” should be deleted from R1 - it serves no useful purpose from a
technical or compliance perspective; instead, it will add unnecessary ambiguity to
the requirement.
Response: The phrase, “at least” was included to relay the intent – that the
monthly requirement is a minimum, and some entities may wish to perform this
39
more frequently. It does not add any compliance obligation to perform this activity
more frequently than specified.
R2, as drafted, states: “Each Reliability Coordinator shall take actions or direct
actions, which could include issuing oral or written Reliability Directives, of
Transmission Operators, Balancing Authorities, Generator Operators, Interchange
Coordinators and Distribution Providers within its Reliability Coordinator Area to
prevent identified events or mitigate the magnitude or duration of actual events that
result in Adverse Reliability Impacts. “ This long sentence has several significant
grammatical errors that result in the reader not being able to discern the meaning of
the requirement. It also unnecessarily adds verbiage that detracts from its primary
focus. It is, therefore, recommended that R2 be revised as follows: “Each Reliability
Coordinator shall take all necessary actions to prevent identified Emergencies or
Adverse Reliability Impacts. These Reliability Coordinator actions shall include, to
the extent necessary, the issuing of oral or written Reliability Directives to
Transmission Operators, Balancing Authorities, Generator Operators, Interchange
Coordinators and Distribution Providers located within its Reliability Coordinator
Area. “
Response: The SDT has considered the alternative language proposed and finds
that the– the phrase, ‘all necessary action’ is ambiguous. Who would decide that
‘all necessary action’ had been taken?
R3, as drafted, is confusing and inconsistent with R2, and, thus, R3 should be
revised to read as follows: “Upon receipt of a Reliability Directive issued pursuant to
R2, a Transmission Operator, Balancing Authority, Generator Operator,
Interchange Coordinator and Distribution Provider shall comply with the Reliability
Directive, unless compliance would violate safety, equipment, regulatory or
statutory requirements. In the event that a Transmission Operator, Balancing
Authority, Generator Operator, Interchange Coordinator or Distribution Provider
determines that compliance with a Reliability Directive would violate safety,
equipment, regulatory or statutory requirements, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution
Provider shall, within 10 minutes after the determination, inform the Reliability
Coordinator of its inability to comply.”
Response: The team adopted the intent of part of this suggestion by replacing the
word, ‘per’ with, ‘in accordance with’. The team elected not to add a time constraint
because the proposed time constraint implies that it would be acceptable to delay
up to 10 minutes before notifying the RC – and in some instances this time delay
40
could result in and adverse impact to reliability.
IRO-002R1 and R2, as written, are confusing. It is recommended that R1 and
R2 be combined to read as follows: “Pursuant to a written procedure to mitigate
the impact of a Reliability Coordinator’s analysis tool outage, a Reliability
Coordinator’s System Operator shall also have the authority to approve, deny or
cancel a planned outage for its analysis tool.”
Response: The drafting team believes that the language in the proposed standard
is clear as written. No reason has been provided for merging the two requirements,
and the benefit of merging the requirements is not clear.
IRO-014 It is unclear why the terms Operating Procedure, Operating Process or
Operating Plan needs to be plural, as currently written in the Standard. Hence,
it is recommended that these terms be made singular, otherwise a violation may
be inferred for not having more than one Procedure, Process or Plan.
Response: The range of activities that must be addressed by the documents is
expected to require more than one document, thus the use of the plural versions of
these terms.
Insert the word “applicable” before “Reliability Coordinator.”
Response: The benefit of adding the word ‘applicable’ is not clear.
2.1, as written, is confusing. Recommend that 2.1 read as follows:”Review and
update, if an update is necessary, on an annual basis. Annual basis means the
review shall be within one month plus or minus that date of the last review.”
Response: The 15 month interval was recommended by the compliance program
as the outer bound to recommend in standards that use the term, “annual” or
“annually.”
There is a compliance bulletin on this issue.
R3 This requirement uses a very vague term “reliability-related information,”
which, also, does not track the language used in R1 -- “information.” It is
recommended that R1 and R3 use the same terms and read “ . . . information,
as defined by the Reliability Coordinator, . . “
Response: Requirement R1 is not open-ended – it identifies information needed
for Interconnection reliability. R3 points to the information identified by complying
with R1. The intent was to limit the scope to areas needed for reliability. RCs
may want other information for reasons not related to reliability, and that
information Is outside the scope of this standard.
R4 As stated above, “at least” does not add value, and, therefore, should be
41
deleted.
Response: The phrase, “at least” was included to relay the intent – that the
monthly requirement is a minimum, and some entities may wish to perform this
more frequently. It does not add any compliance obligation to perform this activity
more frequently than specified.
R5, as written, is confusing. The recommended fix is to delete “all other” and
replace with “impacted”.
Response: The SDT did intend that all other RCs be notified. This requirement
continues the current practice of informing all RCs of Adverse Reliability Impacts
(ARIs). Due to the nature of an ARI, this requirement is typically implemented as
an RCIS message or a hotline call to all RC’s. This is intended to make all RCs
aware of ARIs and support situational awareness.
Response: The RCSDT thanks you for your comment. Please see responses above.
Thomas W.
Richards
Fort Pierce
Utilities
Authority
4
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. "Accuracy" is not the correct term here. "Understanding" is a better
term. It would seem that "accuracy" is a term to be used in R3, the third part of the
3-part communication so that the issuer of the directive ensures the accuracy of the
recipients understanding. FPUA suggests changing COM-002-3 R2 to read: Each
Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling
Entity that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive with enough details
to clearly communicate the recipient's understanding of the Reliability Directive..
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to enure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team.
Response: The RCSDT revised the requirement as follows to remove the
“accuracy’ language:
R2. Each Balancing Authority, Transmission Operator, Generator
42
Operator, and Distribution Provider that is the recipient of a Reliability
Directive issued per Requirement R1, shall repeat, restate, rephrase or
recapitulate the Reliability Directive.
For IRO-001-2, FPUA does not see a need for R1. Doesn't the ERO already have
that authority to establish RC's through the registration process, and to certify
system operators through the PER standards?
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
IRO-014-2 R5, "impacted" was replaced with "other". Wouldn't it be better to at
least limit the notification to within the same interconnection? Or is R5 truly to
identify all NERC registered RC's?
Response: This requirement continues the current practice of informing all RCs of
ARIs. Due to the nature of an ARI, this requirement is typically implemented as an
RCIS message or a hotline call to all RC’s. This is intended to make all RCs aware
of ARIs and support situational awareness.
More minor comments / suggestions for improvement: IRO-002 R2 can be
improved by replacing "prevent identified events" with "prevent anticipated events".
"Anticipated" aligns better with contingency analysis than "identified"
IRO-005-4 R1 and R2 can be improved by replacing "expected" with "anticipated".
Contingencies are not necessarily "expected"; however, we do "anticipate" them.
Response: The SDT believes the commenter intended to be commenting upon
IRO-001-2 R2 rather than IRO-002-2 R2. The SDT has revised the requirements
per your suggestion.
Response: Thank you for your comments. Please see responses above.
Anthony L
Wilson
Georgia
Power
Company
3
Affirmative
Please see comments
Response: The RCSDT thanks you for your comment. Please see response to posting comments for the SERC OC Standards Review Group;
the RCSDT did not specifically find comments from Georgia Power Company and believes comments were included within this group.
43
Gordon
Pietsch
Great River
Energy
1
Negative
Reliability Directive: It is our opinion the definition as currently written is too
subjective and may cause a compliance auditor to question the grounds under
which one of applicable entities declared the directive. We believe that revising the
definition to state “to address a declared emergency...” will remove the subjectivity.
Requirements for using three-part communication: It is our opinion that the
standard needs language that clearly states that during a Blast Call three-part
communication is not required. Blast Calls are used when information needs to be
disseminated quickly to a large number of entities. Strictly enforcing the use of
three-part communication under these circumstances has the potential to be more
harmful to reliability than helpful.
Response: The RCSDT thanks you for your comment.
Reliability Directive: The RCSDT believes the proposed standard requirement addresses your requested revision. “R1…shall identify the action
as a Reliability Directive…” is addressing a declared emergency.
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to
the recipient.
As a reference, we have included the existing definition of Emergency:
Emergency: Any abnormal system condition that requires automatic or immediate manual action to prevent or limit the failure of
transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric System.
The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient and effective. The RCSDT believes Reliability
Directives issued in mass should be defined by procedure, and that the procedure would establish a method of affirmation and notice of
implementation. As envisioned, communications protocols would be addressed in the COM-003 standard being developed in Project 2007-02.
Shaun
Jensen
Idaho Power
Company
3
Negative
It appears there is much concern with the wording, particularly in R2, as well as
parties having issues with intermingled definitions. It is recommended to reword
this, and ensure the VSL accurately reflects a direct definition that all entities all
clear and certain on.
Response: The RCSDT thanks you for your comment. The RCSDT is not sure of which standard requirement is being referenced.
Bob C.
Thomas
Illinois
Municipal
Electric
Agency
4
Negative
IMEA appreciates the SDT's efforts to date. We are basing our negative vote on
ballot pool communications that have addressed points that need further refinement
before the proposed revisions to these reliability standards are affirmed. IMEA
supports, in particular, comments submitted by the Midwest ISO and the SERC OC
44
Standards Review Group.
Response: The RCSDT thanks you for your comments. Please see responses to Midwest ISO and SERC OC Standards Review Group.
Kim Warren
Independent
Electricity
System
Operator
2
Negative
While we support the general direction of these standards development actions, we
do have are a number of concerns which cumulatively lead us to advocate a
NEGATIVE vote. These include:
(1) The phrase “within the same Interconnection” in COM-001-2 R1, limits the
coordination activities to RCs, TOPs and BAs that can be detrimental to reliability.
We recommend removing this phrase.
Response: The RCSDT does not agree that the phrase “within the same
interconnection” limits coordination between entities. The purpose of the phrase
is to place a bound on which adjacent entity an RC must have Interpersonal
Communication (e.g., an EI RC does not need communication with WI RCs). The
phrase “within the same interconnection” is added for the case of ERCOT which
has only DC tie lines with the Eastern Interconnection and has minimal
interchange.
(2) We believe the Interchange Coordinator and Purchasing-Selling Entity also
need to have adequate communication capabilities with other entities but they are
not included in the applicability section of COM-001-2.
Response: We disagree that the IC and PSE need to be an applicable entity. To
maintain reliability does not require communication with these entities. The
applicability of COM-001, COM-002 and IRO-001 were revised to include the
same reliability entities: RC, TOP, BA, DP and GOP. LSE, PSE and TSP were
removed from the applicability of these standards per stakeholder suggestion.
(3) The proposed definition of Reliability Directive addresses Emergency condition
only. There are situations where a Reliability Directive is issued such that the
directed action must be taken by the receiving entity to address a reliability
constraint, which by itself does not constitute an Emergency. We suggest the term
Reliability Directive be revised to: “A communication initiated by a Reliability
Coordinator, Transmission Operator or Balancing Authority where action by the
recipient is necessary to address a reliability constraint or an Emergency.”
Response: The RCSDT believes that your comment concerns “directives” or
“instructions” for normal operational activities rather than a Reliability Directive.
There is no requirement preventing an entity from issuing either directives or
45
instructions for the situations you mention. The intent of creating a Reliability
Directive definition is to ensure that communications is tightened during
Emergencies (per blackout report). When an RC issues a Reliability Directive, the
RC has made a deliberate decision to formally end collaboration and require
specific action(s). In addition, the Operating Personnel Communication Protocols
SDT is addressing your concern about instances that are not considered an
emergency. As envisioned, communications protocols requiring additional
applications for use of three-part communications would be addressed in the COM003 standard being developed in Project 2007-02.
(4) Requirement R9 of COM-001-2 needs to be clarified. As written the requirement
seems open ended once action to repair of a failed Alternative Interpersonal
Communication is initiated within 2 hours but not completed within that time. It is
not clear whether there is an expectation on the responsible entity to designate a
replacement Alternative Interpersonal Communication if repairs cannot be
completed within that period.
Response: The requirement is saying that if the test fails you must initiate action
for repair or designate a replacement alternative within two hours. There is no
requirement for a tertiary capability nor is there a requirement for a repair deadline.
We have also submitted additional comments in response to the request for
comments.
Response: Please see responses to other comments
Response: The RCSDT thanks you for your comment. Please see responses above.
Michael
Moltane
International
Transmission
Company
Holdings
Corp
1
Negative
ITC votes negative for the reasons detailed in the MISO-submitted comment form
related to this Project (ITC signed onto the MISO comments). While this standard
revision moves in the right direction, we believe at least one additional iteration will
be needed to correct the concerns indicated in the comment form.
Response: The RCSDT thanks you for your comments. Please see responses to Midwest ISO.
Kathleen
Goodman
ISO New
England, Inc.
2
Negative
Although ISO-NE believes these Standard represent a great improvement, we are
voting against because we believe they would be improved by the comments that
we have offered. We would gladly modify our vote in the Affirmative if our
comments are considered in the next ballot.
46
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Charles
Locke
Kansas City
Power & Light
Co.
3
Negative
These requirements impose alternative means of communication on TOP's, BA's
and GOP's regardless of the impact the entity may have on maintaining
interconnection reliability. In addition, there are many IRO requirements that are
proposed to be eliminated that do not appear to be considered in other places.
Response: The RCSDT thanks you for your comments. We cannot delineate entity impact on reliability and respond only regarding entity
registration with NERC.
Scott
Heidtbrink
Kansas City
Power & Light
Co.
5
Negative
These requirements impose alternative means of communication on TOP's, BA's
and GOP's regardless of the impact the entity may have on maintaining
interconnection reliability. In addition, there are many IRO requirements that are
proposed to be eliminated that do not appear to be considered in other places.
Response: The RCSDT thanks you for your comments. We cannot delineate entity impact on reliability and respond only regarding entity
registration with NERC.
Jessica L
Klinghoffer
Kansas City
Power & Light
Co.
6
Negative
These requirements impose alternative means of communication on TOP's, BA's
and GOP's regardless of the impact the entity may have on maintaining
interconnection reliability. In addition, there are many IRO requirements that are
proposed to be eliminated that do not appear to be considered in other places.
Response: The RCSDT thanks you for your comments. We cannot delineate entity impact on reliability and respond only regarding entity
registration with NERC.
Jim M
Howard
Lakeland
Electric
5
Negative
From the last posting to this posting, for COM-002-3 R2, the phrase "the accuracy
of the message has been confirmed" was added to the second step of three part
communication. Why was this added? - "Accuracy" is not the correct term here.
Suggest changing COM-002-3 R2 to read: Each Balancing Authority, Transmission
Operator, Generator Operator, Transmission Service Provider, Load-Serving Entity,
Distribution Provider, and Purchasing-Selling Entity that is the recipient of a
Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or
recapitulate the Reliability Directive with enough details to clearly communicate the
recipient's understanding of the Reliability Directive.
Response: The SDT, in drafting the proposed language, did indeed discuss using
the word “understanding” rather than accuracy. However, the SDT was not able to
47
identify a feasible measure for “understanding”. A recipient can judge whether the
response is accurate when compared with the communications issued, but cannot
judge the understanding of anyone, even though the responder may have
accurately responded.
The term "accuracy" can be interpreted as requiring the recipient to second-guess
the Reliability Directive of the RC to ensure the accuracy of the RC's directive in the
first place. Under tight time constraints of Emergencies, this is not practical. We are
sure that was not the intent of the drafting team.
Response: Several commenters expressed concern about the use of the word,
‘accuracy’ and the team revised the requirement to remove this word.
Response: The RCSDT thanks you for your comment.
Paul Shipps
Lakeland
Electric
6
Negative
The phrase "the accuracy of the message has been confirmed" was added to the
second step of three part communication. "Accuracy" is not the correct term here.
"Understanding" is a better term. The term "accuracy" is a term to be used in R3,
the third part of the 3-part communication, so that the issuer of the directive
ensures the accuracy of the recipients understanding.
Response: The RCSDT thanks you for your comment. The RCSDT has removed that phrase from the requirement as it was difficult to measure
and many stakeholders had concerns with the language.
Rick Crinklaw
Lane Electric
Cooperative,
Inc.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
48
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Michael
Henry
Lincoln
Electric
Cooperative,
Inc.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customer-
49
service issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
50
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Bruce Merrill
Lincoln
Electric
System
3
Negative
For NERC Reliability Standard COM-001-2, LES believes that interpersonal
communication is the act of communicating and that the requirements specify
normal and redundant facilities for Interpersonal Communication. As such, LES
recommends the definition for “Interpersonal Communication” be changed to “Any
act where two or more individuals communicate, interact, consult or exchange
information, including listening or reading”. Additionally, for NERC Reliability
Standard IRO-001-2, LES recommends replacing the word “certify” in R1 and M1
with “assign”. As currently written it is unclear what the certification of the Reliability
Coordinator will entail and how it will be established by the ERO.
Response: The RCSDT thanks you for your comment. We specifically included “medium” to distinguish a source or vehicle of communication
instead of a “personal” reference.
NERC has an established certification procedure for all registered entities and “certify” is in line with NERC’s process.
Dennis
Florom
Lincoln
Electric
System
5
Negative
For NERC Reliability Standard COM-001-2, LES believes that interpersonal
communication is the act of communicating and that the requirements specify
normal and redundant facilities for Interpersonal Communication. As such, LES
recommends the definition for “Interpersonal Communication” be changed to “Any
act where two or more individuals communicate, interact, consult or exchange
information, including listening or reading”. Additionally, for NERC Reliability
Standard IRO-001-2, LES recommends replacing the word “certify” in R1 and M1
with “assign”. As currently written it is unclear what the certification of the Reliability
Coordinator will entail and how it will be established by the ERO.
Response: The RCSDT thanks you for your comment.. We specifically included “medium” to distinguish a source or vehicle of communication
instead of a “personal” reference.
NERC has an established certification procedure for all registered entities and “certify” is in line with NERC’s process.
Richard
Reynolds
Lost River
Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
51
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
52
Charles A.
Freibert
Louisville Gas
and Electric
Co.
3
Negative
Refer to the comment form.
Response: The RCSDT thanks you for your comment. Please see response to posting comments for LGE/KE; the RCSDT did not specifically
find comments from Louisville Gas and Electric Co.
Joseph G.
DePoorter
Madison Gas
and Electric
Co.
4
Negative
MGE is voting negative for several reasons. Please see the MRO NSRS comments
for a full description. Plus, whenever there are multiple Standards within a Project,
registered entities will be forced to vote negative when there is at least one
negative aspect.
Response: The RCSDT thanks you for your comment. Please see response to MRO NSRS comments. The NERC SC approved the SAR and
the RCSDT only drafts requirements within the scope of the SAR. The RCSDT will move to a successive ballot with each standard balloted
separately.
Joe D Petaski
Manitoba
Hydro
1
Negative
The current data retention requirement of 90 days is more than adequate.
Increasing this period to 12 months would result in a significant amount of work with
no benefit to reliability. For additional comments, please see Manitoba Hydro’s
comments provided during formal comment period.
Response: The RCSDT thanks you for your comment. However, the comment submitted is incomplete and does not reference specific
standard(s) or requirement(s). The data retention periods for the set of standards proposed is consistent with the guidelines provided in the
NERC Drafting team Guidelines. Note that with recent changes to the Rules of Procedure, entities must be prepared to demonstrate that they
were compliant for the full time period since the last audit.
Greg C.
Parent
Manitoba
Hydro
3
Negative
The current data retention requirement of 90 days is more than adequate.
Increasing this period to 12 months would result in a significant amount of work with
no benefit to reliability. For additional comments, please see Manitoba Hydro’s
comments provided during formal comment period.
Response: The RCSDT thanks you for your comment. However, the comment submitted is incomplete and does not reference specific
standard(s) or requirement(s). The data retention periods for the set of standards proposed is consistent with the guidelines provided in the
NERC Drafting team Guidelines. Note that with recent changes to the Rules of Procedure, entities must be prepared to demonstrate that they
were compliant for the full time period since the last audit.
S N Fernando
Manitoba
Hydro
5
Negative
The current data retention requirement of 90 days is more than adequate.
Increasing this period to 12 months would result in a significant amount of work with
no benefit to reliability. For additional comments, please see Manitoba Hydro’s
53
comments provided during formal comment period.
Response: The RCSDT thanks you for your comment. However, the comment submitted is incomplete and does not reference specific
standard(s) or requirement(s). The data retention periods for the set of standards proposed is consistent with the guidelines provided in the
NERC Drafting team Guidelines. Note that with recent changes to the Rules of Procedure, entities must be prepared to demonstrate that they
were compliant for the full time period since the last audit.
Daniel
Prowse
Manitoba
Hydro
6
Negative
The current data retention requirement of 90 days is more than adequate.
Increasing this period to 12 months would result in a significant amount of work with
no benefit to reliability. For additional comments, please see Manitoba Hydro’s
comments provided during formal comment period.
Response: The RCSDT thanks you for your comment. However, the comment submitted is incomplete and does not reference specific
standard(s) or requirement(s). The data retention periods for the set of standards proposed is consistent with the guidelines provided in the
NERC Drafting team Guidelines. Note that with recent changes to the Rules of Procedure, entities must be prepared to demonstrate that they
were compliant for the full time period since the last audit.
Jason L
Marshall
Midwest ISO,
Inc.
2
Negative
We thank the drafting team for their efforts on this project to improve the reliability
coordination standards. The quality of the standards continues to improve over
previous postings. While the drafting team is definitely moving the standards in the
right direction, we believe we have not reached the point of diminishing returns and
that there are several issues that the drafting team still needs to address.
1 This standard does not comport with the informational filing that NERC submitted
to FERC on August 10, 2009 regarding its discontinued use of sub-requirements in
standards development activities.
Response: The sub-requirements are an old format. The standard was updated to
the new template, and sub-requirements are now Parts.
2 In general, we are not opposed to the concept of the ERO certifying the
Reliability Coordinators; however, there are some issues with how the requirement
IRO-001-2 R1 is written. The requirement places emphasis on regions and regional
boundaries when no emphasis should be placed there. There are multiple
Reliability Coordinators that span multiple regions. The language “to continuously
assess transmission reliability” should be changed to “to continuously assess Bulk
Electric System reliability” to reflect on what the standards are enforceable. The
requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to
ensure that all operating entities and the entire BES are covered under a Reliability
Coordinator Area.
54
Response: Many commenters suggested removing the requirement
because it is addressed in the NERC Rules of Procedure. The RCSDT
concurs and has removed R1 from IRO-001-2.
3 The SDT did not address all of our concerns with COM-002-3 from the last
posting. For entities registered as multiple functions, the combination of the
definition of Reliability Directive and Requirement R1 could be confused to require
a company to issue directives to itself. There are several organizations registered
as a Reliability Coordinator, Transmission Operator and Balancing Authority. In
these companies, it is not uncommon for those responsibilities to be distributed
across multiple desks. Thus, for certain situations, a single System Operator may
actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be
adjacent to the System Operator serving the as the Transmission Operator or
Balancing Authority. We believe that it should never be necessary for these System
Operators to issue Reliability Directives to themselves in the first example or to their
co-worker in the second example to demonstrate compliance to NERC standards.
How the entity coordinates its actions among its Reliability Coordinator, Balancing
Authority and Transmission Operator roles is a corporate governance issue that
should not be confused or complicated by the NERC standards. Thus, we believe
that standards should be made clear that the Reliability Directive is directed to
another company.
Response: COM-002 does not preclude text or other forms of communication for
issuing Reliability Directives. However, entities still must comply with the
requirements of COM-002. Further, the RCSDT believes it to be equally
imperative that each NERC registered function hold the authority to issue
Reliability Directives, and the ability to receive Reliability Directives, whether
those Reliability Directives are issued to subordinate registered functions within a
vertically integrated utility, or to registered entities that are corporately separate.
The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity
communication
between
and
among
functions.
Face-to-face
communication of Reliability Directives are subject to the requirements of
COM-002 and can be measured for COM-002 by allowing Operator Logs
as possible evidence to support compliance”.
The use of operator logs to memorialize and provide evidence of compliance is
applicable to those Reliability Directives issued and received within the same
control room or operations center. The RCSDT believes that any Registered Entity
or person operating as such must understand the intent of the issued Reliability
Directive, and that the issuer of the Reliability Directive believe that the Reliability
55
Directive was correctly received.
4 We also are concerned about the need to conduct three-part communications for
a Reliability Directive issued through a blast call. Under these circumstances, the
need for immediate action of multiple parties may require a blast call and there may
not be time for all parties to complete three-part communications before initiating
actions. Thus, we believe blast calls should be treated separately and that should
be made clear.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability
Directives, in mass, is efficient and effective. However the essence of accurately
implementing Reliability Directives is accomplished by use of 3-part
communications. The RCSDT believes Reliability Directives issued in mass should
be defined by procedure, and that the procedure would establish a method of
affirmation and notice of implementation. As envisioned, communications protocols
requiring for issuing alerts will be addressed in the COM-003 standard being
developed in Project 2007-02.
5 COM-002-3 R2 needs to be rewritten as it is too verbose. The point is for the
recipient of the original message to get the issuer to confirm that the message was
understood. We suggest rewording R2 to “Each Reliability Coordinator, Balancing
Authority, Transmission Operator, Generator Operator, Transmission Service
Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity
that is the recipient of a Reliability Directive issued per Requirement R1, shall
repeat, restate, rephrase or recapitulate the Reliability Directive.” Once the receiver
has completed this requirement, the ball is in the issuer’s court per Requirement
R3. No additional words are necessary in the requirement.
Response: The RCSDT agrees and has revised the requirement as you suggest.
6 Please strike part IRO-014-2 Part 1.7. There is no need to have a weekly
conference to discuss every Operating Procedure, Operating Process and
Operating Plan. As this requirement is written, a conference call would be
necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to
have weekly conference calls that should suffice. IRO-014-2 R2 seems to
recognize that these Operating Procedures, Processes and Plans likely will not
need to be discussed weekly as it only requires an annual update.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific
activities with other impacted Reliability Coordinators. These activities are listed as
Parts. Further the RCSDT believes that it is prudent that Reliability Coordinators
talk at least once a week to verify viability of mutual plans, procedures or
processes. The relation of IRO-14-2 PART 1.7 to R4 is that PART 1.7 requires
56
having a conference call, R4 requires participation by all impacted Reliability
Coordinators. As such, neither replaces the other.
7 IRO-014-2 R4 is overly broad and would require Reliability Coordinators that will
not impact one another to participate on conference calls with one another without
any reliability benefit. The issue is created by the addition of the clause “within the
same Interconnection” to the requirement. ISO-NE, FRCC, Midwest ISO, and SPP
are all in the same Interconnection. It is hard to fathom there being reliability benefit
to SPP and ISO-NE conversing weekly or Midwest ISO and FRCC conversing
weekly. We suggest limiting the requirement to adjacent Reliability Coordinators.
Response: IRO-14-2 R4 is applicable to those Reliability Coordinators engaged in
activities related to R1 and subsequently PART 1.7. It is unlikely that Reliability
Coordinators whom are geographically and electrically distant will have mutually
agreed upon operating procedures; therefore requirement R4 would not apply.
8 For IRO-014-2 R5, we suggest replacing “other” with “impacted” to limit the
notification of Adverse Reliability Impacts to only those Reliability Coordinators that
need to know. Because the definition of Adverse Reliability Impact includes “Bulk
Electric System instability or Cascading”, it is possible that the cascading of 138 kV
lines serving a load pocket or generator outlet stability issues could require a
Reliability Coordinator to notify all other Reliability Coordinators regardless of
impact. This would include Reliability Coordinators outside of the Interconnection
with the problem. It would also include Reliability Coordinators that are not
impacted. For instance, an issue in New England that would not pose a threat
outside the northeast would require ISO-NE to notify SPP and FRCC and Reliability
Coordinators in the Western Interconnection. There is no reliability benefit to this
notification.
Response: This requirement continues the current practice of informing all RCs of
ARIs. Due to the nature of an ARI, this requirement is typically implemented as an
RCIS message or a hotline call to all RC’s. This is intended to make all RCs aware
of ARIs and support situational awareness.
9 IRO-014-2 R6-R8 are problematic and need to be refined to make clear that the
Reliability Coordinators shall operate to the most conservative limit. It should not
require a Reliability Coordinator that disagrees with an action plan to implement the
action plan. The Reliability Coordinator will be disagreeing with the action plan for
reliability reasons. Assuming they are correct, the requirement to implement said
action plan will actually put the Interconnection at greater risk. These requirements
inappropriately attempt to codify the debate and analysis that occurs between and
within Reliability Coordinators when there are differing results in reliability analysis.
This is part of the problem with having a Wide Area view that results in Reliability
Coordinators having a view into other Reliability Coordinator Areas. Their results
57
and conclusions may be different. There should be a hierarchical structure for
whose results should be used. It should the Reliability Coordinator with primary
responsibility unless the other Reliability Coordinator has evidence to demonstrate
that the Reliability Coordinator with primary responsibility is incorrect. What this
should do is to trigger both to review their models and data to assess the problem.
None of this needs to be codified in the standards though.
Response: Requirements R6-R8 are translated from IRO-016-1, Requirement R1.
If an RC sees a problem and another does not see the same problem, then there
may be an issue with someone’s model or processes or procedures. The RC’s are
supposed to have coordinated Operating Plans, Processes or Procedures to
operate reliably. R6-R8 are only applicable if one of the two (or more) RCs do not
see that a problem exists. It would be a detriment to reliability for both RCs to take
no action. RCs are required to coordinate actions under existing IRO-016-1, R1. If
one RC identifies a problem and provides an action plan to another RC to mitigate
the problem, the second RC is obligated under R8 to implement it. We have
revised the R8 to clarify this intent.
IRO-014-2, Revised R8. During those instances where Reliability
Coordinators disagree on the existence of an Adverse Reliability Impact,
each Reliability Coordinator shall implement the action plan developed by
the Reliability Coordinator that identified the Adverse Reliability Impact
unless such actions would violate safety, equipment, regulatory or statutory
requirements.
10 In the definition of Reliability Directive, we suggest changing “to address an
Emergency” to “to address a declared Emergency”. This would help limit second
guessing for a situation where a System Operator took action because he truly
believed he was in an Emergency but after the fact analysis demonstrates there
really was not an Emergency.
Response: The RCSDT believes that modifying Reliability Directive by including
“declared Emergency” would add an unnecessary step in mitigation of the
Emergency.
11 We disagree with deleting IRO-002-1 R5 and R7 which establish tools and
monitoring capabilities. There should be basic tools requirements established for
Reliability Coordinators. Project 2009-02 Real-time Reliability Monitoring and
Analysis Capabilities will be addressing these issues in more detail. Thus, it does
not make sense to delete these requirements until that dra
Response: Each RC has been certified to continue operations as an RC or been
certified prior to beginning operations as an RC. The minimum set of tools and
capabilities for an RC are “checked off” during the certification process. The
58
reliability objective of R5 and R7 is to perform analyses to ensure reliability of the
BES by specifying capability rather than mandating specific tools. The analysis
provisions of R5 and R7 are covered under IRO-008-1, Requirements R1 (perform
Operational Planning Analysis) and R2 (perform Real-time Analysis). It is
anticipated that Project 2009-02 team will address this issue more fully.
Response: The RCSDT thanks you for your comments.
Richard Burt
Minnkota
Power Coop.
Inc.
1
Negative
Minnkota is in agreement with the comments submitted by the MRO NSRS.
Response: The RCSDT thanks you for your comment. Please see MRO NSRS response to comments.
Don Horsley
Mississippi
Power
3
Affirmative
Please see comments
Response: The RCSDT thanks you for your comment. Please see response to those comments.
John S Bos
Muscatine
Power &
Water
3
Negative
1 In the COM-001 requirements, MP&W does not agree that a Distribution Provider
and a Generator Operator need to be held to the same level of responsibility as a
Reliability Coordinator, Balancing Authority, or Transmission Operator. In FERC
Order 693 (paragraph 487), FERC directed the Distribution Provider and Generator
Operator to be incorporated in this standard by stating:” We expect the
telecommunication requirements for all applicable entities will vary according to
their roles and that these requirements will be developed under the Reliability
Standards development process.” A Distribution Provider and Generator Operator
may not be staffed 24 hours a day like a Balancing Authority or Transmission
Operator; nevertheless, the Standards Drafting Team did not consider this.
Response: There is no requirement that requires identical communications
systems. The requirement is to have “a” communication capability. Regarding 24/7
support, the requirement is to have communications capability. The type of media
used is not specified. For a small DP, an on-call system could suffice. The RCSDT
also recognizes the FERC directive and has not included GOPs and DPs in the
requirements for Alternative Interpersonal Communications capability.
2 MP&W does not agree with the revision of IRO-001 with the statement included
59
for certifying Reliability Coordinators. As written, it is ambiguous as far as what level
of certification this would involve.
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
3 MP&W disagrees with COM-002-3 R2. As stated in FERC Order 693 (paragraph
512) it is essential that Reliability Coordinators, Balancing Authorities, and
Transmission Operators have communications with Distribution Providers.
Requirement 2 also applies to Transmission Service Providers, Load-Serving
Entities and Purchasing and Selling Entities. As stated above, it is going to be
unattainable to communicate with a Distribution Provider since most Distribution
Providers are usually not operated 24 hours per day like Reliability Coordinators,
Balancing Authorities, and Transmission Operators. Many Distribution Providers
have answering services that will relay a message once they receive it and then
pass it along to someone. An answering service could repeat the directive back,
word for word, but this would not add any level of reliability. The Standards Drafting
Team should reconsider the applicability section of this Standard to apply to only
Reliability Coordinators, Balancing Authorities, and Transmission Operators for the
issuance of a Reliability Directive.
Response: There is no requirement for 24/7 support. The requirement is to have
communications capability. The type of system (e.g., On-Call) is not prescribed in
the standard, and the standard is designed not to impose needless communications
requirements. The purpose of COM-002 is, “to ensure emergency communications
between operating personnel are effective.” It’s not a proxy requirement to
establish 24/7 operating personnel at small distribution providers. The intent is to
establish a method of communicating Reliability Directives during Emergencies.
While it is true that many small Distribution Providers are not staffed 24x7, it is
typical that they have a means of communication - in many cases this may be via a
receptionist or answering service. It is the expectation that an issuer of a Reliability
Directive would request a return call by the Distribution Provider operating
personnel, then issue the Reliability Directive. If this return call would not be timely
enough, then the issuer would determine a different mitigation plan.
Response: The RCSDT thanks you for your comments. Please see responses above.
Mike Avesing
Muscatine
Power &
Water
5
Negative
In the COM-001 requirements, MP&W does not agree that a Distribution Provider
and a Generator Operator need to be held to the same level of responsibility as a
Reliability Coordinator, Balancing Authority, or Transmission Operator. In FERC
60
Order 693 (paragraph 487), FERC directed the Distribution Provider and Generator
Operator to be incorporated in this standard by stating:” We expect the
telecommunication requirements for all applicable entities will vary according to
their roles and that these requirements will be developed under the Reliability
Standards development process.” A Distribution Provider and Generator Operator
may not be staffed 24 hours a day like a Balancing Authority or Transmission
Operator; nevertheless, the Standards Drafting Team did not consider this.
Response: There is no requirement that requires identical communications
systems. The requirement is to have “a” communication capability. Regarding
24/7 support, the requirement is to have communications capability. The type of
media used is not specified. For a small DP, an on-call system could suffice. The
RCSDT also recognizes the FERC directive and has not included GOPs and DP
in the requirements for Alternative Interpersonal Communications capability.
MP&W does not agree with the revision of IRO-001 with the statement included for
certifying Reliability Coordinators. As written, it is ambiguous as far as what level of
certification this would involve.
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
MP&W disagrees with COM-002-3 R2. As stated in FERC Order 693 (paragraph
512) it is essential that Reliability Coordinators, Balancing Authorities, and
Transmission Operators have communications with Distribution Providers.
Requirement 2 also applies to Transmission Service Providers, Load-Serving
Entities and Purchasing and Selling Entities. As stated above, it is going to be
unattainable to communicate with a Distribution Provider since most Distribution
Providers are usually not operated 24 hours per day like Reliability Coordinators,
Balancing Authorities, and Transmission Operators. Many Distribution Providers
have answering services that will relay a message once they receive it and then
pass it along to someone. An answering service could repeat the directive back,
word for word, but this would not add any level of reliability. The Standards Drafting
Team should reconsider the applicability section of this Standard to apply to only
Reliability Coordinators, Balancing Authorities, and Transmission Operators for the
issuance of a Reliability Directive.
Response: The RCSDT thanks you for your comment. There is no requirement for
24/7 support. The requirement is to have communications capability. The type of
system (e.g., On-Call) is not prescribed in the standard, and the standard is
61
designed not to impose needless communications requirements. The purpose of
COM-002 is, “to ensure emergency communications between operating personnel
are effective.” It’s not a proxy requirement to establish 24/7 operating personnel at
small distribution providers. The intent is to establish a method of communicating
Reliability Directives during Emergencies. While it is true that many small
Distribution Providers are not staffed 24x7, it is typical that they have a means of
communication - in many cases this may be via a receptionist or answering service.
It is the expectation that an issuer of a Reliability Directive would request a return
call by the Distribution Provider operating personnel, then issue the Reliability
Directive. If this return call would not be timely enough, then the issuer would
determine a different mitigation plan.
Response: The RCSDT thanks you for your comment.
Brandy D
Olson
Muscatine
Power &
Water
6
Negative
In the COM-001 requirements, MP&W does not agree that a Distribution Provider
and a Generator Operator need to be held to the same level of responsibility as a
Reliability Coordinator, Balancing Authority, or Transmission Operator. In FERC
Order 693 (paragraph 487), FERC directed the Distribution Provider and Generator
Operator to be incorporated in this standard by stating:” We expect the
telecommunication requirements for all applicable entities will vary according to
their roles and that these requirements will be developed under the Reliability
Standards development process.” A Distribution Provider and Generator Operator
may not be staffed 24 hours a day like a Balancing Authority or Transmission
Operator; nevertheless, the Standards Drafting Team did not consider this.
Response: There is no requirement that requires identical communications
systems. The requirement is to have “a” communication capability. Regarding 24/7
support, the requirement is to have communications capability. The type of media
used is not specified. For a DP an on-call system could suffice. The RCSDT also
recognizes the FERC directive and has not included GOPs and DP in the
requirements for Alternative Interpersonal Communications capability.
MP&W does not agree with the revision of IRO-001 with the statement included for
certifying Reliability Coordinators. As written, it is ambiguous as far as what level of
certification this would involve.
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
62
MP&W disagrees with COM-002-3 R2. As stated in FERC Order 693 (paragraph
512) it is essential that Reliability Coordinators, Balancing Authorities, and
Transmission Operators have communications with Distribution Providers.
Requirement 2 also applies to Transmission Service Providers, Load-Serving
Entities and Purchasing and Selling Entities. As stated above, it is going to be
unattainable to communicate with a Distribution Provider since most Distribution
Providers are usually not operated 24 hours per day like Reliability Coordinators,
Balancing Authorities, and Transmission Operators. Many Distribution Providers
have answering services that will relay a message once they receive it and then
pass it along to someone. An answering service could repeat the directive back,
word for word, but this would not add any level of reliability. The Standards Drafting
Team should reconsider the applicability section of this Standard to apply to only
Reliability Coordinators, Balancing Authorities, and Transmission Operators for the
issuance of a Reliability Directive.
Response: The RCSDT thanks you for your comment. There is no requirement for
24/7 support. The requirement is to have communications capability. The type of
system (e.g., On-Call) is not prescribed in the standard, and the standard is
designed not to impose needless communications requirements. The purpose of
COM-002 is, “to ensure emergency communications between operating personnel
are effective.” It’s not a proxy requirement to establish 24/7 operating personnel at
small distribution providers. The intent is to establish a method of communicating
Reliability Directives during Emergencies. While it is true that many small
Distribution Providers are not staffed 24x7, it is typical that they have a means of
communication - in many cases this may be via a receptionist or answering service.
It is the expectation that an issuer of a Reliability Directive would request a return
call by the Distribution Provider operating personnel, then issue the Reliability
Directive. If this return call would not be timely enough, then the issuer would
determine a different mitigation plan.
Response: The RCSDT thanks you for your comment.
Tony
Eddleman
Nebraska
Public Power
District
3
Negative
COM-001-2:
A) We would need clarification as to what the process would be for Interpersonal
communication and alternate Interpersonal communications and voice recording if
the (1) TO and the BA are the same person, (2) if the TO and the BA are sitting
across the desk from each other, or (3) if the TO, BA, and Distribution provider are
all in the same company or same room.
B) In the definition of Interpersonal Communications if data is included (?), what
63
evidence of compliance is expected?
C) R 1.2 and R2.2 Reliability Coordinators communication shouldn’t be limited to
the same interconnection. They need communications concerned with schedules
across DC ties.
D) For R3, neighboring Transmission Operators should be included.
E) For R5, neighboring Balancing Authorities should be included.
Response: A) The IC and AIC requirements apply to the functional entity. If a
company has all of the functions performed in the same room, they would verbally
communicate with each other in person (with sound waves being the medium).
B) Data is not included in the definition of Interpersonal Communications but is
covered in approved IRO-010-1 and proposed TOP-003-2.
C) BAs handle Interchange Schedules. The RC has Interpersonal
Communications with its BAs. DC ties usually have contractually designated
operators who handle operating concerns.
D) The SDT agrees, and has revised the requirement to include ‘adjacent’ TOPs
synchronously connected within the same Interconnection.
E) The SDT agrees and has revised the requirement to include ‘adjacent’ BAs
COM-002-3 (R1):
A) Since an entity can be registered for multiple functions (functions noted in R1),
this could lead to the requirement for entities to issue directives to themselves or
co-workers in the same room.
B) How would a 3-part communication work when a “blast” call is used to provide
directives to several entities?
Response: A) COM-002 does not preclude text or other forms of communication
for issuing Reliability Directives. However, entities still must comply with the
requirements of COM-002. Further, the RCSDT believes it to be equally
imperative that each NERC registered function hold the authority to issue
Reliability Directives, and the ability to receive Reliability Directives, whether
those Reliability Directives are issued to subordinate registered functions within a
vertically integrated utility, or to registered entities that are corporately separate.
64
The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity
communication between and among functions. Face-to-face
communication of Reliability Directives are subject to the requirements
of COM-002 and can be measured for COM-002 by allowing Operator
Logs as possible evidence to support compliance”.
COM-002 should not be construed to mean that an individual serving in two
functions be required to issue a Reliability Directive to himself, but rather it is
expected that such an individual would appropriately address the reliability issues
as required by the function they are serving and its subsequent responsibilities.
B) The RCSDT agrees that the use of Blast Call’s to issue Reliability Directives, in
mass, is efficient and effective. However the essence of accurately implementing
Reliability Directives is accomplished by use of 3-part communications. The
RCSDT believes Reliability Directives issued in mass should be defined by
procedure, and that the procedure would establish a method of affirmation and
notice of implementation. As envisioned, communications protocols requiring for
issuing alerts will be addressed in the COM-003 standard being developed in
Project 2007-02.
Response: The RCSDT thanks you for your comment.
Don Schmit
Nebraska
Public Power
District
5
Negative
COM-001-2:
A) We would need clarification as to what the process would be for Interpersonal
communication and alternate Interpersonal communications and voice recording if
the TO and the BA are the same person, if the TO and the BA are sitting across the
desk from each other, or if the TO, BA, and Distribution provider are all in the same
company or same room.
B) If the Interpersonal Communication definition includes data (?) then what
evidence needs to provided?
C) R1.2 and R2.2, Reliability Coordinators communication shouldn’t be limited to
the same interconnection. They also need communications concerned with
schedules across DC ties.
D) For R3, neighboring Transmission Operators should be included.
E)For R5, neighboring Balancing Authorities should be included.
Response: A) The IC and AIC requirements apply to the functional entity. If a
65
company has all of the functions performed by the same person or people in the
same room, they would verbally communicate with each other in person. (sound
waves – medium)
B) Data is not included in the definition of Interpersonal Communications but is
covered in approved IRO-010-1 and proposed TOP-003-2.
C) BAs handle Interchange Schedules.
The RC has Interpersonal
Communications with its BAs. DC ties usually have contractually designated
operators who handle operating concerns.
D) The SDT agrees, and has revised the requirement to include ‘adjacent’ TOPs
synchronously connected within the same Interconnection.
E) The SDT agrees and has revised the requirement to include ‘adjacent’ BAs
COM-002-3(R1):
A) Concern regarding entities registered with multiple functions. Could lead to
requirement for entities to give directives to themselves or to co-workers in the
same room.
B) How would 3-part communications be handled during 'blast' calls?
Response: A) COM-002 does not preclude text or other forms of communication
for issuing Reliability Directives. However, entities still must comply with the
requirements of COM-002. Further, the RCSDT believes it to be equally
imperative that each NERC registered function hold the authority to issue
Reliability Directives, and the ability to receive Reliability Directives, whether
those Reliability Directives are issued to subordinate registered functions within a
vertically integrated utility, or to registered entities that are corporately separate.
The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity
communication between and among functions. Face-to-face
communication of Reliability Directives are subject to the requirements
of COM-002 and can be measured for COM-002 by allowing Operator
Logs as possible evidence to support compliance”.
Com-002 should not be construed to mean that an individual serving in two
functions be required to issue a Reliability Directive to himself, but rather it is
expected that such an individual would appropriately address the reliability issues
as required by the function they are serving and its subsequent responsibilities.
B) The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in
66
mass, is efficient and effective. However the essence of accurately implementing
Reliability Directives is accomplished by use of 3-part communications. The
RCSDT believes Reliability Directives issued in mass should be defined by
procedure, and that the procedure would establish a method of affirmation and
notice of implementation. As envisioned, communications protocols requiring for
issuing alerts will be addressed in the COM-003 standard being developed in
Project 2007-02.
Response: The RCSDT thanks you for your comment.
Gregory
Campoli
New York
Independent
System
Operator
2
Abstain
The NYISO agrees that these revised standards are an improvement from the
current version. However we believe that the comments submitted by the IRC and
NPCC are required to make them acceptable as the new set of standards. We will
have an opportunity to revise our vote on the second ballot based on the
consideration given to the comments submitted.
Response: The RCSDT thanks you for your comment. See IRC and NPCC comments.
Michael
Schiavone
Niagara
Mohawk
(National Grid
Company)
3
Affirmative
IRO-001 R1 The language “to continuously assess transmission reliability” should
be changed to “to continuously assess Bulk Electric System reliability” to reflect
what the enforceability of the standards are meant to be.
Response: Many commenters suggested removing the requirement
because it is addressed in the NERC Rules of Procedure. The RCSDT
concurs and has removed R1 from IRO-001-2.
IRO-001 R2 Should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
Response: The requirement was rewritten for clarity as follows:
R2. Each Reliability Coordinator shall take actions or direct actions
(which could include issuing Reliability Directives) by Transmission
Operators, Balancing Authorities, Generator Operators, and Distribution
Providers within its Reliability Coordinator Area to prevent identified
events or mitigate the magnitude or duration of actual events that result in
Adverse Reliability Impacts.
IRO-001 R2 Contains the words “which could include issuing Reliability Directives”,
but Reliability Directives are not referenced anywhere else in the standard. This
inclusion seems unnecessary since without it, R2 already requires that the RC take
actions or direct actions by others to prevent identified events or mitigate the
67
magnitude or duration of actual events that result in Adverse Reliability Impacts.
Whether or not a Reliability Directive is issued is irrelevant in this requirement.
These words should be removed. Note that COM-002 will stipulate the requirement
for 3-part communication when a Reliability Directive is issued. The inclusion of
“which could include issuing Reliability Directives” in IRO-001 is unnecessary.
Response: R2 requires the Reliability Coordinator to act. These actions could in
include Reliability Directives in the case of an Emergency. However, issuing
Reliability Directives might not always be necessary, as the Reliability Coordinator
may be acting proactively well in advance of an emergency. R2 promotes this
proactive approach, but reserves the use of Reliability Directives for circumstances
that require its use. During the vetting of the prior version of this requirement, some
stakeholders expressed concern that the word, “action,” if not clarified, could lead
some people to believe that the Reliability Coordinator must be the entity to perform
the actual operation.
COM-002 In place of requiring an operator, in real-time, to state “this is a Reliability
Directive,” there should be an allowance for an entity to develop procedures
indicating, in advance, their expectations of three-part to their sub-operating
entities. Modify R1 to be “When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability Directive, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall identify
the action, either verbally, when the communication is issued, or in advance
through documented procedures, as a Reliability Directive to the recipient.
[Violation Risk Factor: High][Time Horizon: Real-Time.]”
Response: Your proposed edit does not meet the reliability intent of the
requirement. The RCSDT believes that it is important to state that the Reliability
Directive is being issued to convey that action by the recipient is required. An RC
could issue a Reliability Directive to implement an agreed upon procedure whereby
the three part communication would not list each step of the procedure individually,
but would include implementation of the entire procedure. As envisioned,
communications protocols such as the procedure you’ve proposed will be
addressed in the COM-003 standard being developed in Project 2007-02.
Response: The RCSDT thanks you for your comment. Please see responses above.
Jon Shelby
Northern
Lights Inc.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
68
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
69
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Douglas
Hohlbaugh
Ohio Edison
Company
4
Affirmative
FirstEnergy supports the proposed standards and would appreciate consideration
of our comments submitted through the formal comment period.
Response: The RCSDT thanks you for your comment. Your comments have been considered, Please see the Consideration of Comments
document for FirstEnergy.
Ray Ellis
Okanogan
County
Electric
Cooperative,
Inc.
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
70
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Margaret
Ryan
Pacific
Northwest
Generating
Cooperative
8
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
71
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Brenda L
Truhe
PPL Electric
Utilities Corp.
1
Negative
Comments were submitted as part of a group via the comment form. Thank you for
your work on the standard.
Response: The RCSDT thanks you for your comment. You other comments have been considered. Please see the Consideration of
Comments document.
Mark A
Heimbach
PPL
EnergyPlus
LLC
6
Negative
Comments: We thank the Standards Drafting Team for the improvements made in
the revisions to COM-001 and COM-002. The revision appropriately clarifies the
standard. We are providing the following comments for the Standards Drafting
Team to consider.
1) Consider changing R1 to ‘Each RC shall have the capability for Interpersonal
Communications with the following entities to exchange Interconnection and
72
operating information...’ for clarity as Interpersonal Communications and capability
are both nouns.
Response: Thank you for your suggestion to modify the sentence structure into a
noun phrase. However the RCSDT believes the current form is unambiguous.
2) We feel changing the applicability of the standard is important to the accuracy of
the standard. The purpose of COM-002 is ‘To ensure emergency communications
between operating personnel are effective’. Since operating personnel are covered
by the applicability of RC, BA, TOP and GOP, we suggest the applicability to TSP,
LSE, and PSE be removed from COM-002-3.
Response: The SDT agrees. The applicability of COM-002 has been revised.
COM-001, and COM-002 are now applicable to the RC, TOP, BA, GOP and DP
only.
3) Additionally, we would like to bring to the attention of the Standards Drafting
Team, that the implementation plan for COM-001-2 and IRO-001-2 still includes
TSP, LSE, and PSE although the revised standard does not include these entities
in the Applicability Section. For COM-001-2 refer to the implementation plan, page
11. For IRO-001-2 refer to the implementation plan for new R2, new R3, new R4
and the chart on the last page. Thank you for your consideration in addressing
these comments.
Response: The RCSDT has revised the implementation plans appropriately to
address your comment.
Response: The RCSDT thanks you for your comments. .
Annette M
Bannon
PPL
Generation
LLC
5
Negative
We thank the Standards Drafting Team for the improvements made in the revisions
to COM-001 and COM-002. The revision appropriately clarifies the standard. We
are providing the following comments for the Standards Drafting Team to consider.
1) Consider changing R1 to ‘Each RC shall have the capability for Interpersonal
Communications with the following entities to exchange Interconnection and
operating information...’ for clarity as Interpersonal Communications and capability
are both nouns.
Response: Thank you for your suggestion to modify the sentence structure into a
noun phrase. However the RCSDT believes the current form is unambiguous.
2) We feel changing the applicability of the standard is important to the accuracy of
the standard. The purpose of COM-002 is ‘To ensure emergency communications
73
between operating personnel are effective’. Since operating personnel are covered
by the applicability of RC, BA, TOP and GOP, we suggest the applicability to TSP,
LSE, and PSE be removed from COM-002-3.
Response: We agree. The applicability of COM-002 has been revised. COM-001,
and COM-002 are now applicable to the RC, TOP, BA, GOP and DP only.
3) Additionally, we would like to bring to the attention of the Standards Drafting
Team, that the implementation plan for COM-001-2 and IRO-001-2 still includes
TSP, LSE, and PSE although the revised standard does not include these entities
in the Applicability Section. For COM-001-2 refer to the implementation plan, page
11. For IRO-001-2 refer to the implementation plan for new R2, new R3, new R4
and the chart on the last page. Thank you for your consideration in addressing
these comments.
Response: The RCSDT has revised the implementation plans appropriately to
address your comment.
Response: The RCSDT thanks you for your comments.
John T
Sturgeon
Progress
Energy
6
Negative
COM-001-2 R10 states that “Each Reliability Coordinator, Transmission Operator,
Balancing Authority, Distribution Provider and Generator Operator shall notify
impacted entities within 60 minutes of the detection of a failure of its Interpersonal
Communications capabilities that last 30 minutes or longer”. The standard states
that the RC, TOP, BA shall designate an Alternative Interpersonal Communication
capability but does not require the same of the DP and GOP. Compliance by the
DP and GOP with R10 would be jeopardized while still being compliant with the rest
of the standard by having only the Interpersonal Communications capability.
Response: The DP or GOP has access to additional Interpersonal
Communications, in all likelihood, to make notifications for failure. There is not a
requirement for an alternative, but it is likely that someone could use a cell phone to
make the notification. The RCSDT is proposing to add Part 7.3 and 8.3 to the
requirements as follows:
7.3 Each Distribution Provider that experiences a failure of its
Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority to determine a mutually
agreeable time to restore its Interpersonal Communication capability.
8.3 Each Generator Operator that experiences a failure of its
Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority to determine a mutually
74
agreeable time to restore its Interpersonal Communication capability.
The phrase “within” used in R3-R6 does not take into account that there are
electrically adjacent BAs/TOPs who are not “within” each other’s area.
Response: The requirements are dealing with entities within the Area or entities
that operate Facilities located within the Area. We have also added the following to
R3:
Adjacent Transmission Operators synchronously connected within the
same Interconnection.
The SDT also added, ‘adjacent Balancing Authorities” to Requirements R4, R5 and
R6.
Response: The RCSDT thanks you for your comment.
Peter Dolan
PSEG Energy
Resources &
Trade LLC
6
Negative
Com-001-2 implementation plan lists that this is applicable to PSE’s and LSE’s
however, PSE’s and LSE’s were removed from the actual standard. The
implementation plan should be revised. Com-002-3 standard continues to include
PSE. PSE’s do not play an active role in operating the BES and have no authority
or ability to perform reliability coordination related tasks as may be directed by a
RC. PSE’s should be removed from the standard.
IRO-001-2 references PSE’s in the implementation for R2, R3, R4 and “Functions
that must comply with the requirements in this standard” table. PSE’s were
removed from the standard and should be removed from the implementation plan.
Response: The RCSDT thanks you for your comment. The applicability of COM-002 has been revised. COM-001, and COM-002 are now
applicable to the RC, TOP, BA, GOP and DP only.
The RCSDT has revised the implementation plans appropriately to address your comment.
Kenneth D.
Brown
Public
Service
Electric and
Gas Co.
1
Negative
Com-001-2 implementation plan lists that this is applicable to PSE’s and LSE’s
however, PSE’s and LSE’s were removed from the actual standard. The
implementation plan should be revised. Com-002-3 standard continues to include
PSE. PSE’s do not play an active role in operating the BES and have no authority
or ability to perform reliability coordination related tasks as may be directed by a
75
RC. PSE’s should be removed from the standard.
IRO-001-2 references PSE’s in the implementation for R2, R3, R4 and “Functions
that must comply with the requirements in this standard” table. PSE’s were
removed from the standard and should be removed from the implementation plan.
Response: The RCSDT thanks you for your comment. The applicability of COM-002 has been revised. COM-001, and COM-002 are now
applicable to the RC, TOP, BA, GOP and DP only.
The RCSDT has revised the implementation plans appropriately to address your comment.
Jeffrey
Mueller
Public
Service
Electric and
Gas Co.
3
Negative
PSEG opposes this standard for the following reasons: Com-001-2 implementation
plan lists that this is applicable to PSE’s and LSE’s however, PSE’s and LSE’s were
removed from the actual standard. The implementation plan should be revised.
Com-002-3 standard continues to include PSE. PSE’s do not play an active role in
operating the BES and have no authority or ability to perform reliability coordination
related tasks as may be directed by a RC. PSE’s should be removed from the
standard.
IRO-001-2 references PSE’s in the implementation for R2, R3, R4 and “Functions
that must comply with the requirements in this standard” table. PSE’s were
removed from the standard and should be removed from the implementation plan.
Response: The RCSDT thanks you for your comment. The applicability of COM-002 has been revised. COM-001, and COM-002 are now
applicable to the RC, TOP, BA, GOP and DP only.
The RCSDT has revised the implementation plans appropriately to address your comment.
Dominick
Grasso
Public
Service
Enterprise
Group
Incorporated
5
Negative
COM-001-2 implementation plan lists that this is applicable to PSE’s and LSE’s
however, PSE’s and LSE’s were removed from the actual standard. The
implementation plan should be revised. COM-002-3 standard continues to include
PSE. PSE’s do not play an active role in operating the BES and have no authority
or ability to perform reliability coordination related tasks as may be directed by a
RC. PSE’s should be removed from the standard.
IRO-001-2 references PSE’s in the implementation for R2, R3, R4 and “Functions
that must comply with the requirements in this standard” table. PSE’s were
removed from the standard and should be removed from the implementation plan.
Response: The RCSDT thanks you for your comment. The applicability of COM-002 has been revised. COM-001, and COM-002 are now
applicable to the RC, TOP, BA, GOP and DP only.
76
The RCSDT has revised the implementation plans appropriately to address your comment.
Steven Grega
Public Utility
District No. 1
of Lewis
County
5
Negative
These changes do not recognize that many small utilities do not have 24-hour
dispatch, do not have SCADA systems or do not man generation plants 24-hours a
day. Specific exception should be writen into the standards to provide relief for
small GO, GOP, LSE and DP. The standard changes need to address notifications
if personnel are only available on a on-call basis.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Heber
Carpenter
Raft River
Rural Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
77
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Anthony E
Jablonski
ReliabilityFirst
Corporation
10
Negative
1. General comments a. The standards should be balloted individually rather that
balloted as a group.
Response: The SDT agrees, and will be balloting the standards individually.
2. COM-001-2 a. The “R” should be removed from all sub requirements (they
should be referenced as parts)
A Response: The SDT agrees. This has been corrected.
3. IRO-005-4 a. Fix typo in R1. Insert the word “and” between the words “notify
issue” b.
Response: This typo has been addressed through other edits
4. IRO-001-2 a. The Electric Reliability Organization (ERO) listed in the Applicability
78
section and R1 is neither a user, owner nor operator of the BES and such should
not be subject to Reliability Standards.
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
Response: The RCSDT thanks you for your comment. Please see responses above.
Ken Dizes
Salmon River
Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
79
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
80
Carter B.
Edge
SERC
Reliability
Corporation
10
Negative
If the following issues are addressed in the standards revisions I should be able to
cast an affirmative vote:
COM-001-2
o Each sub-requirement should not have an “R” in front of the number in order to be
consistent with NERC’s August 10, 2009 filing at FERC on this subject.
Response: The SDT agrees. This has been corrected.
o Requirement R3 and R4 should include adjacent TOPs as a sub-requirement.
Response: The SDT agrees. The SDT modified R3 and R4 to add adjacent TOPs
o Requirements R5 and R6 should include adjacent BAs as a sub-requirement.
Response: The SDT added adjacent Balancing Authorities to Requirements R4,
R5 and R6.
o “to exchange Interconnection and operating information” should be deleted from
requirements R1 through R8 as it is redundant with the definition of Interpersonal
Communications
Response: The SDT agrees. The SDT adopted this suggestion and deleted this
phrase.
o The last page of the Implementation Plan includes LSEs, PSE, and TSPs as
being responsible entities under this standard, yet the standard does not include
them. Please correct the implementation plan.
Response: The implementation plan was corrected as proposed.
TOP-001-1,
o Requirement R3, which is what the SDT appears to be using as its justification for
not adding a requirement here is proposed to be deleted by the RTO-SDT on
Project 2007-03.
IRO-001-2 R2-R4 deal with complying with directives or instruction and is the
justification for retiring TOP-001, R3.
IRO-001-2
o I’m unclear on the language of R1. I think you are attempting to create a
81
requirement similar to BAL-005, R1 where all generation, transmission, and load
operating within an Interconnection must be included within the metered boundaries
of a Balancing Authority Area. If that is the case, suggested language could be “All
Balancing Areas and Transmission Operators must be under the authority of a
Reliability Coordinator certified by the ERO to continuously assess transmission
reliability and coordinate emergency operations within each region and across the
regional boundaries"
Response: Many commenters suggested removing the requirement because it is
addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
o Please remove the yellow box on page 1 indicating this standard will be retired.
Response: The SDT agrees, and has made the change.
Additional comments:
o Reliability Directives may be issued by blast calls from Reliability Coordinators. It
is inefficient and may be a hindrance to reliability to require 3-part communications
in these instances.
Response: The RCSDT agrees that the use of Blast Call’s to issue Reliability
Directives, in mass, is efficient and effective. However the essence of accurately
implementing Reliability Directives is accomplished by use of 3-part
communications. The RCSDT believes Reliability Directives issued in mass should
be defined by procedure, and that the procedure would establish a method of
affirmation and notice of implementation. As envisioned, communications protocols
such as the procedure you’ve proposed will be addressed in the COM-003 standard
being developed in Project 2007-02.
o There are several organizations registered as BAs, RCs and TOPs. It is not
uncommon for those entities to be distributed across multiple desks in the same
control room without regard to how an entity is registered. Thus, a single System
Operator may perform functions that are categorized under two or more of those
functional entities. The drafting team should clarify that under no circumstances
should that System Operator be required to issue a Reliability Directive to himself.
This is a corporate governance issue.
Response: COM-002 does not preclude text or other forms of communication for
issuing Reliability Directives. However, entities still must comply with the
requirements of COM-002. Further, the RCSDT believes it to be equally
imperative that each NERC registered function hold the authority to issue
82
Reliability Directives, and the ability to receive Reliability Directives, whether
those Reliability Directives are issued to subordinate registered functions within a
vertically integrated utility, or to registered entities that are corporately separate.
The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity
communication
between
and
among
functions.
Face-to-face
communication of Reliability Directives are subject to the requirements of
COM-002 and can be measured for COM-002 by allowing Operator Logs
as possible evidence to support compliance.”
The use of operator logs to memorialize and provide evidence of compliance is
directly specific to those Reliability Directives issued and received within the same
control room or operations center. The RCSDT believes that any Registered Entity
or person operating as such must understand the intent of the issued Reliability
Directive, and that the issuer of the Reliability Directive believe that the Reliability
Directive was correctly received. COM-002 should not be construed to mean that
an individual serving in two functions be required to issue a Reliability Directive to
himself, but rather it is expected that such an individual would appropriately
address the reliability issues as required by the function they are serving and its
subsequent responsibilities.
o In IRO-014, R1, delete sub-requirement 1.7. The requirement for weekly
conference calls related to operating procedures is duplicative to R4 and could be
burdensome while adding very little value under certain circumstances.
R1, Part 1.7 indicates that the Operating Plan, process or Procedure is to include
how the entity will accomplish these calls. R4 requires the entity to actually perform
them.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific
activities with other impacted Reliability Coordinators. These activities are listed as
Parts. Part 1.7 is requires you to have a procedure relating to weekly conference
calls while R4 requires participation in weekly calls. Further the RCSDT believes
that it is prudent that Reliability Coordinators talk at least once a week to verify
viability of mutual plans, procedures or processes.
o In IRO-014, R4, delete the phrase “(per Requirement 1, Part 1.7)” as a
conforming change.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific
activities with other impacted Reliability Coordinators, these activities are listed as
sub requirements. Part 1.7 is requires you to have a procedure relating to weekly
83
conference calls while R4 requires participation in weekly calls. Further the RCSDT
believes that it is prudent that Reliability Coordinators talk at least once a week to
verify viability of mutual plans, procedures or processes.
o I believe that the intent of IRO-014, Requirements R6-R8 is to require
conservative operation by all affected Reliability Coordinators if any Reliability
Coordinator detects an Adverse Reliability Impact. It could be read to allow at least
the theoretical possibility that an RC may determine an Adverse Reliability Impact
in another RC’s area that the other RC neither can see nor believes that any action
should be taken. R7 puts the burden on the first RC to develop a plan that it cannot
implement because it has no agreement with the BAs and TOPs in the other RC
area and thus could be ineffective. Alternately, it could be read that the identifying
RC must take action in its own area to mitigate the Adverse Reliability Impact
identified in another area much like the “general prudential rule” in the Coast
Guard’s Rules of the Road where regardless of what the rules state if action can be
taken to avoid a collision at sea, that action must be taken. Please clarify.
Response: Requirements R6-R8 are translated from IRO-016-1, Requirement R1.
If an RC sees a problem and another does not see the same problem, then there
may be an issue with someone’s model or processes or procedures. The RC’s are
supposed to have coordinated Operating Plans, Processes or Procedures to
operate reliably. R6-R8 are only applicable if one of the two (or more) RCs do not
see that a problem exists. It would be a detriment to reliability for both RCs to take
no action. RCs are required to coordinate actions under existing IRO-016-1, R1. If
one RC identifies a problem and provides an action plan to another RC to mitigate
the problem, the second RC is obligated under R8 to implement it. We have
revised the R8 to clarify this intent.
IRO-014-2, Revised R8. During those instances where Reliability
Coordinators disagree on the existence of an Adverse Reliability Impact ,
each Reliability Coordinator shall implement the action plan developed by
the Reliability Coordinator that identified the Adverse Reliability Impact
unless such actions would violate safety, equipment, regulatory or statutory
requirements.
o Please review all the implementation plans to be sure the applicable entities
match those in the standards.
Response: The Implementation Plans have been modified to address this concern.
84
Response: The RCSDT thanks you for your comment. Please see responses above.
Paul
Benjamin
Kerr
Shell Energy
North
America (US),
L.P.
6
Affirmative
The introduction of the definition of “Reliability Directive” and its connection to the
definition of “Emergency” within this Project brings much needed clarity for the
sector and will promote consistency between Regional Entities and within the audits
of Registered Entities. Shell Energy supports the removal of Purchasing Selling
Entities as a function to which IRO-001 applies. This removal recognizes that PSEs
do not play a role in reliability coordination under this standard since they have no
authorities and no abilities to assume or perform responsibilities associated with
reliability coordination. This conclusion is reinforced by the adoption of the defined
term “Reliability Directive”. Where a RC, TOP, or BA needs to address an
Emergency they do not contact, consult, or direct a PSE to take action that would
address the Emergency. Rather, where the PSE is a user of the grid to perform or
execute transactions, it is subject to the actions of these other entities that have the
authority to stop, curtail, or alter the submitted transactions of the PSE in a way that
aids in resolving the problem. With the fitting adoption of “Reliability Directive” into
COM-002 as well, Shell Energy does not believe it is necessary or appropriate for
the applicability of this standard to include Purchasing Selling Entities, as is
contained in the current draft proposal. This standard does not apply to PSEs
today, however, during the progression of Project 2006-06 this applicability was
added to an early draft version that preceded the discussions and clarification that
comes from the definition of a Reliability Directive in the standard. Shell Energy
does not support the inclusion of PSEs in the current draft version of COM-002, and
feels that it should be removed. The purpose of this standard is, “To ensure
Emergency communications between operating personnel are effective” and relates
directly to the capabilities and authorities established for the RC, TOP, or BA that
requires actions to be taken by a recipient of a Reliability Directive. As noted
previously, PSEs are acted upon by the entities with the necessary authority, and
are not in a role that would initiate or fulfil the required actions. As additional
matters related to the clarification and cleanup of the standards in this project, the
implementation plans for both IRO-001 and COM-001 erroneously contain
references to PSEs in the sections “Functions that Must Comply with the
Requirements”. These references need to be removed.
Response: The RCSDT thanks you for your comment. The applicability of COM-001, and COM-002 were revised to be consistent and only
include the RC, TOP, BA, DP and GOP. The Implementation Plans have been corrected.
Robert A
Schaffeld
Southern
Company
1
Affirmative
Please see comments
85
Services, Inc.
Response: The RCSDT thanks you for your comment. Please see response to those comments.
Ronald L
Donahey
Tampa
Electric Co.
3
Negative
Our only disagreement is with the use of the term “Reliability” in defining a directive.
Response: The RCSDT thanks you for your comment. The term “Reliability Directive” was chosen to specifically delineate between other types
of directives, such as market directives. It is imperative that reliability standards relate to reliability concerns.
Steve Eldrige
Umatilla
Electric
Cooperative
3
Negative
Thank you for the opportunity to comment and for your hard work on this project:
While we agree that effective Interpersonal Communications capability are integral
to reliability, many Distribution Providers (DP) are small entities that do not maintain
a 24-7 dispatch desk capable of receiving or responding to emergency reliability
directives in a timely manner. It is our belief that some of the proposals in this
project could unnecessarily force small entities to make investments that will not
enhance reliability. Many DPs rely on answering services to address customerservice issues during non-business hours. On-call personnel are contacted in the
event of an outage or emergency and crews are dispatched as appropriate. It is
difficult to envision a BA or TOP issuing an Emergency Reliability Directive to a
small entity (25 MW or so) which would require these smaller entities to comply with
COM-001. Order 693 directs the inclusions of DPs in the COM-001-2 standard but
it is our belief that the Commission offered language that GOs and DPs need not
have redundant communications, training unrelated to normal/emergency
operations, and that telecommunications requirements for entities will vary
according to their function. We believe those intentions should be reflected in the
language of this standard. We would suggest adding wording such as in the
applicability section, "Distribution Providers who maintain a 24-7 control centers
with the ability to manually shed load of at least 100 MW within a 15-minute
operational window." Also, a note that smaller, rural entities can be dependent on a
phone system provider that will not allow for backup communications. Should the
communication line(s) be dependent on one main phone trunk line, the failure due
to an issue on this main line will make it impossible to notify anyone of its failure
short of physically traveling to an area where phone service is available. For some
rural areas, this will exceed the one hour time limit to report the communication
outage. Forcing smaller entities to acquire satellite phone service to mitigate for a
phone outage is a high price to pay when no reliability improvement will be
achieved. Suggested change could be: "... shall notify impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
86
that lasts 30 minutes or longer where alternate forms of communication are
available within a 15 minute access time. Should alternate forms of communication
not be available within the 15 minute access time, then upon reestablishment of
Communication capabilities impacted entities will be notified of the past loss and
current status of Communication." We’ve heard many representatives from FERC
and NERC indicate that the standards development process has led the industry to
take action in many cases for the sake of compliance while not necessarily
enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including
smaller entities that will NEVER receive an emergency reliability directive might be
an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have communications
capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to impose needless
communications requirements. The purpose of COM-002 is, “to ensure emergency communications between operating personnel are effective.”
It’s not a proxy requirement to establish 24/7 operating personnel at small distribution providers. The intent is to establish a method of
communicating Reliability Directives during Emergencies. While it is true that many small Distribution Providers are not staffed 24x7, it is typical
that they have a means of communication - in many cases this may be via a receptionist or answering service. It is the expectation that an issuer
of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the Reliability Directive. If this
return call would not be timely enough, then the issuer would determine a different mitigation plan.
Jonathan
Appelbaum
United
Illuminating
Co.
1
Negative
See UI Comment form, In General:
1. COM-001-2 does not specify the amount of time a DP has to reestablish the
Interpersonal Communication Capability after the capability fails before it is
assessed non-compliance for not having the communication.
Response: The DP or GOP has access to additional Interpersonal
Communications, in all likelihood, to make notifications for failure. There is not a
requirement for an alternative, but it is highly unlikely that someone couldn’t use
their cell phone to make the notification. The RCSDT is proposing to add Part 7.3
and 8.3 to the requirements as follows:
7.3 Each Distribution Provider that experiences a failure of its
Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority to determine a mutually
agreeable time to restore its Interpersonal Communication capability.
8.3 Each Generator Operator that experiences a failure of its
Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority to determine a mutually
agreeable time to restore its Interpersonal Communication capability.
87
2. VSL for R7 should have a time component
Response: The VSL represents a single violation of the requirement. For this
requirement, the DP must have Interpersonal Communication with its TOP and
BA. The VSL was revised to remove “or more” to conform to the requirement.
Because the Requirement does not have a time component, the SDT cannot add
a time component to the VSL – this would violate one of the FERC Guidelines for
setting VSLs.
3. R7 should address the instance if the DP is not required to have communication
with the BA, because the BA communicates thru the TOP.
Response: The RCSDT believes that Interpersonal Communication between the
DP and its BA and the TOP is required for reliability.
4. COM-002 R2 seems awkwardly worded. R2 as it is written says the repeat is
confirming the accuracy of the message itself. I think it is agreed that the repeat
back in R2 is to allow the issuer of the Directive to confirm that the message was
received accurately understood by the recipient.
Response: The RCSDT has revised the requirement and has removed “with
enough details that the accuracy of the message was confirmed” from the
requirement.
5. The VSL for Com-002 R2 is severe and states "The responsible entity that was
the recipient of a Reliability Directive failed to repeat, restate, rephrase or
recapitulate the Reliability Directive with enough details that the accuracy of the
message was confirmed." The purpose of the R2 repeat-back is to allow the Issuer
verify the message was accurately received. This VSL penalizes the responsible
entity for not accurately receiving the message. The VSL should penalize the
refusal of the registered entity to repeat back the message not for receiving the
message incorrectly.
Response: The RCSDT agrees and has removed “with enough details that the
accuracy of the message was confirmed” from the VSL.
Response: The RCSDT thanks you for your comment. Please see responses above.
Allen Klassen
Westar
Energy
1
Negative
The new definition of Alternative Interpersonal Communication in COM-001
appears to rule out the use of redundant systems that happen to be used daily,
which might be done to ensure that they function when needed.
88
Response: The RCSDT thanks you for your comment. The intent of Alternative Interpersonal Communication (AIC) is to make sure there is an
alternative in case the Interpersonal Communication fails. If you have two, you may designate one as the AIC regardless of how often you use
it.
Forrest Brock
Western
Farmers
Electric Coop.
1
Negative
COM-001 - Definition of Interpersonal Communication needs more clarification. For
example, would this include data exchanged via ICCP? Examples of what
constitutes "Interconnection and operating information" would help as much
"information" can be interpreted as fitting into this - or not.
Response: Interpersonal Communication does not include data exchange.
Severe VSL for R9 - second part after the "OR" is a virtual repetition of the wording
in the Lower VSL for R9.
Response: The Severe VSL was revised to remove “within 2 hours”. It now
reads:
“The responsible entity tested the Alternative Interpersonal
Communications capability and identified a problem but didn’t initiate action
to repair or designate a replacement Alternative Interpersonal
Communications.”
COM-003 - R3 contains a typographical or grammar error. "...Reliability Directive as
per Requirement R2 IS correct..." not AS correct...
Response: Assuming you meant COM-002-3, the SDT agrees and has made the
correction.
Response: The RCSDT thanks you for your comment. Please see responses above.
Anthony
Jankowski
Wisconsin
Energy Corp.
4
Affirmative
Please correct the clean version of IRO-005 R1 to match the red-line.
Response: The RCSDT thanks you for your comment. We have made the corrections.
Michael Ibold
Xcel Energy,
Inc.
3
Affirmative
While we appreciate the drafting team's efforts to clarify the multiple effective dates,
we feel it is still daunting and complex, which leaves too much room for
miscalculation. We recommend that NERC and/or the drafting team publish what
the actual effective dates are, as soon as FERC (and again when the other
regulatory authorities) have approved it. This could either be done in the effective
89
date section of the standard itself, or as a stand-alone reference document posted
along with the standard on NERC's website.
Response: The RCSDT thanks you for your comment. We will pass your comment on the NERC Standards Process Manager for
consideration.
James A
Maenner
8
Negative
In comments (Reliability Coordination - Project 2006-06) Midwest ISO raised a
number of issues that need to be addressed prior to passage of these standards.
Response: The RCSDT thanks you for your comment. Please see responses to comments made by MISO on the initial ballot as well as the
regular comment form.
END OF REPORT
90
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Reliability Coordination — Project 2006-06
The Reliability Coordination Drafting Team thanks all commenters who submitted comments
on the proposed revisions to COM-001-2, IRO-001-2, IRO-002-2 and IRO-005-4. These
standards were posted for a 30-day public comment period from February 25, 2011 through
March 7, 2011. The stakeholders were asked to provide feedback on the standards through
a special Electronic Comment Form. There were 41 sets of comments, including comments
from more than 168 different people from approximately 112 companies representing 9 of
the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1
Summary Consideration:
The RCSDT thanks all stakeholders for their comments. Many stakeholders provided comments
suggesting revisions to the standards. Many of these suggestions were incorporated into the standards.
As a result of the revisions, the RCSDT is moving COM-001-2, COM-002-3 and IRO-001-2 to a
successive ballot. The RCSDT made a few clarifying edits to the remaining standards based on
stakeholder comments. Therefore, IRO-002-3, IRO-005-4 and IRO-014-2 are being moved to
recirculation ballot. Because of this approach, the SDT will be proposing an interim change to IRO-001:
the elimination of Requirement R7, as it is duplicative of one of the requirements in IRO-014-2.
For the COM-001 standard, several commenters had suggestions for improvements to the requirement
language and applicability. The RCSDT believes the standard correctly and adequately requires each
applicable entity that would have capability to receive Interconnection and operating information to have
Interpersonal Communications and Alternative Interpersonal Communications to be used when the
Interpersonal Communication is not available. The RCSDT has addressed the applicability of the
standards and implementation plans by aligning COM-001-2, and COM-002-3 to include the same entities
and by removing LSE, PSE and TSP from the COM standards.
Many comments were concerned about both the medium (e.g. cellular, satellite, etc.) and media (e.g.
voice, email, etc.) used for Interpersonal Communications. The current language avoids being
prescriptive and allows each entity to determine what is suitable. Interpersonal Communication and
Alternative Interpersonal Communication is between the applicable entities which may include multiple
locations (e.g. a primary and back-up control center).
The RCSDT added the following Requirement Parts at the suggestion of stakeholders:
3.5 Adjacent Transmission Operators synchronously connected within the same Interconnection
4.3 Adjacent Transmission Operators synchronously connected within the same Interconnection
5.6 Adjacent Balancing Authorities
6.3 Adjacent Balancing Authorities
The RCSDT agrees with the many industry comments and removed the phrase "to exchange
Interconnection and operating information" in requirements R1 through R8. This removal clarifies that
the intent of this capability is NOT for the exchange of data.
1
The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
A few commenters also expressed concerns about the frequency of testing Alternative Interpersonal
Communications capability. The RCSDT believes that the proposed testing frequency is supported by
the majority of stakeholders and is not overly burdensome.
Several commenters suggested that VSLs should be written based on the percent of entities rather than
by an occurrence of a violation. VSLs must be written on a violation occurrence basis in accordance with
FERC guidelines. The requirements specify which entities must be included in communications
capabilities. If a single entity is missing, this is a violation of the requirement. According to VSL
guidelines, if missing any part of the requirement could have the same reliability outcome as missing the
entire requirement, the requirement is binary and the VSL must be severe.
A new requirement was added to COM-001 for clarity regarding responsibilities of the Distribution
Provider and the Generator Operator when either entity experiences a failure of its Interpersonal
Communication capability:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its
Interpersonal Communication capabilities shall consult with its Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
This requirement requires collaboration between entities to restore a failed communications capability.
The RCSDT asked stakeholders if they believed that the requirements of TOP-001-1 obviate the need to
develop additional requirements to address Xcel’s comment as directed in FERC Order 693. The original
justification that the RCSDT posited for not adding a requirement to directly address Xcel Energy’s
comments in paragraph 516 and FERC’s related recommendation in paragraph 523 was that TOP-001-1
R3 was considered to address this concern. Since that time, the RTO SDT has proposed to retire TOP001-1 R3. However, NERC has since retired IRO-004-1 R3 and R5 along with IRO-005-3 R5. Because
these are retired, there are no longer any requirements that would force a TOP to wait for a delayed RC
response during an emergency. Therefore the question is resolved, albeit differently than it was proposed
to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirements,” the TOP may
respond to the RC that it cannot comply.
Stakeholders were asked if they agree with the revision to IRO-001, R1 for certifying Reliability
Coordinators. Many commenters suggested removing the requirement because it is addressed in the
NERC Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
A significant revision to IRO-001-2 was made by removing the Interchange Coordinator from the
standard. The RCSDT made this revision because the Balancing Function is responsible for
implementing interchange (see NERC Reliability Functional Model, version 5, page 32, item 7) and to
operate the Balancing Authority Area to maintain load-interchange-generation balance (item 3).
The RCSDT asked stakeholders if they agree with moving two requirements from IRO-001 back to IRO002 relating to Analysis Tool outages. All stakeholders that responded agreed and there were no
comments received.
The RCSDT asked stakeholders if they agree with moving two requirements from IRO-001 back to IRO005 relating to Reliability Coordinator notifications. Several commenters noted a typographical error in
R1 which was corrected to read:
When the results of an Operational Planning Analysis or Real-time Assessment indicate an
expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator
Area, each Reliability Coordinator shall notify issue an alert to all impacted Transmission
Operators and Balancing Authorities in its Reliability Coordinator Area. [Violation Risk Factor:
High] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]”
One commenter also asked that an errant yellow text box be removed from Page 1, which was also done.
The RCSDT received a number of comments regarding the applicability of COM-001, and COM-002. The
RCSDT agrees with these comments and has removed PSE and LSE from the COM-001-2
implementation plan. The RCSDT also addressed minor issues involving typos, formatting and style.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The RCSDT received comments suggesting clarification of COM-002-3. The RCSDT intends the
communication of Reliability Directives to be person-to-person and in such a manner that the Reliability
Directive is understood and not necessarily repeated verbatim. COM-002-3 is not intended to be
prescriptive on how the Reliability Directive is issued. Spoken or written communications are valid
methods (i.e. using the telephone, radio, electronic texting, email, etc.). The purpose of COM-002-3 is to
ensure emergency communications between operating personnel are effective. There is no proxy
requirement for 24/7 operating personnel regarding small entities. Only “capability” as provided for in
COM-001-2 is applicable. The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in
mass, is efficient and effective. The RCSDT believes Reliability Directives issued in mass should be
defined by procedure, and that the procedure would establish a method of affirmation and notice of
implementation. As envisioned, communications protocols would be addressed in the COM-003 standard
being developed in Project 2007-02.
Some commenters suggested revisions to IRO-014, requirement R8 to conform to similar requirements
R6 and R7. The RCSDT made the suggested revision by re-ordering R8:
R8. During those instances where Reliability Coordinators disagree on the existence of an
Adverse Reliability Impact, each Reliability Coordinator shall implement the action plan developed
by the Reliability Coordinator that identified the Adverse Reliability Impact unless such actions
would violate safety, equipment, regulatory or statutory requirements. [Violation Risk Factor:
High][Time Horizon: Operations Planning, Same Day Operations and Real-time Operations]
IRO-014-2, requirement R4 is applicable to those Reliability Coordinators engaged in activities related to
requirement R1 and part 1.7. It is unlikely that Reliability Coordinators geographically and electrically
distant from one another will have mutually agreed upon operating procedures (per requirement R1), and
therefore requirement R4 would not be applicable. The RCSDT believes IRO-014-2, requirement R4
(which requires weekly communication) provides reasonable contact and flexibility – and this requirement
is in effect today.
The RCSDT coordinated the use of the NERC Glossary term “Adverse Reliability Impact” with the RealTime Operations team and continues the practice of informing all RCs of Adverse Reliability Impacts in
requirement R5.
The RCSDT has revised IRO-014-2, requirements R6-R8 to clarify that when one RC identified a problem
and presents an action plan for another RC, the second RC is obligated to implement the action plan. The
RCSDT will forward the concern about RC's identifying themselves and the receiver to establish authority
to the Project 2007-02, Operating Personnel Communications Protocols SDT. The Project 2007-02 team
is developing a standard that includes requirements for use of specific communications protocols.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments on Reliability Coordination — Project 2006-06
Index to Questions, Comments, and Responses
1.
2.
3.
4.
5.
6.
Do you agree with COM-001 requirements for Interpersonal Communications
capability and Alternative Interpersonal Communications capability (R1-R8)?
If not, please explain in the comment area below. ......................................... 14
The RCSDT believes that the requirements of TOP-001-1 obviate the need to
develop additional requirements to address Xcel’s comment. Do you agree? If
not, please explain in the comment area below. ............................................. 39
Do you agree with the revision to IRO-001, R1 for certifying Reliability
Coordinators? If not, please explain in the comment area below. .................. 45
Do you agree with moving two requirements from IRO-001 back to IRO-002 relating to
Analysis Tool outages? If not, please explain in the comment area below. ...................... 51
Do you agree with moving two requirements from IRO-001 back to IRO-005
relating to Reliability Coordinator notifications? If not, please explain in the
comment area below. ..................................................................................... 55
Do you have any other comment, not expressed in questions above, for the RC
SDT? ............................................................................................................... 58
July 14, 2011
Consideration of Comments on Reliability Coordination — Project 2006-06
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
3
4
5
6
7
8
9
10
X
Region Segment Selection
1. Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Kurtis Chong
Independent Electricity System Operator
NPCC 2
4. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5. Bohdan M. Dackow
US Power Generating Company (USPG)
NPCC NA
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
7. Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
8. Dean Ellis
Dynegy Generation
NPCC 5
9. Brian Evans-Mongeon Utility Services
NPCC 8
10. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
11. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
12. Kathleen Goodman
ISO - New England
NPCC 2
13. Chantel Haswell
FPL Group, Inc.
NPCC 5
14. David Kiguel
Hydro One Networks Inc.
NPCC 1
15. Michale R. Lombardi
Northeast Utilities
NPCC 1
July 14, 2011
2
5
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
16. Rnady MacDonald
New Brunswick System Operator
NPCC 2
17. Bruce Metruck
New York Power Authority
NPCC 6
18. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
19. Robert Pellegrini
The United Illuminating Company
NPCC 1
20. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
21. Saurabh Saksena
National Grid
NPCC 1
22. Michael Schiavone
National Grid
NPCC 1
23. Peter Yost
Consolidated Edison co. of New York, Inc. NPCC 3
24. Ben Wu
2.
Group
Additional Member
Orange and Rockland Utilities
Ron Sporseen
4
5
6
7
8
9
10
X
X
X
Region Segment Selection
1. Bud Tracy
Blachly-Lane Electric Cooperative WECC 3
2. Dave Markham
Central Electric Cooperative
WECC 3
3. Dave Hagen
Clearwater Power
WECC 3
4. Roman Gillen
Consumer's Power Inc.
WECC 1, 3
5. Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6. Dave Sabala
Douglas Electric Cooperative
WECC 8
7. Bryan Case
Fall River Electric Cooperative
WECC 3
8. Rick Crinklaw
Lane Electric Cooperative
WECC 3
9. Michael Henry
Lincoln Electric Cooperative
WECC 3
10. Richard Reynolds
Lost River Electric Cooperative
WECC 8
11. Jon Shelby
Northern Lights
WECC 3
12. Ray Ellis
Okanogan Electric Cooperative
WECC 8
13. PNGC Power
Rick Paschall
WECC 8
14. Heber Carpenter
Raft River Electric Cooperative
WECC 3
15. Ken Dizes
Salmon River Electric Cooperative WECC 1, 3
16. Steve Eldrige
Umatilla Electric Cooperative
17. Marc Farmer
West Oregon Electric Cooperative WECC 8
July 14, 2011
3
NPCC 1
PNGC Power member owners
Additional Organization
2
WECC 1, 3
6
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
BPA, Transmission Control Center PSC WECC 1
2. Tedd Snodgrass
BPA, Transmission Dispatch
Group
3
4
5
6
X
X
X
X
X
X
X
X
X
X
X
7
8
9
10
Region Segment Selection
1. Paul Blake
4.
X
2
WECC 1
Brenda Truhe
PPL
X
Additional Member Additional Organization Region Segment Selection
1. Annette Bannon
PPL Generation
RFC
2. Annette Bannon
PPL Generation
WECC 5
3. Mark Heimbach
PPL EnergyPlus
MRO
4. Mark Heimbach
PPL EnergyPlus
NPCC 6
5. Mark Heimbach
PPL EnergyPlus
RFC
6
6. Mark Heimbach
PPL EnergyPlus
SERC
6
7. Mark Heimbach
PPL EnergyPlus
SPP
6
8. Mark Heimbach
PPL EnergyPlus
WECC 6
5.
Group
Patricia Hervochon
5
6
PSEG
Additional Member Additional Organization Region Segment Selection
1. Kenneth Brown
PSE&G
RFC
1
2. Jeffrey Mueller
PSE&G
RFC
3
3. Kenneth Petroff
PSEG Nuclear
RFC
5
4. Peter Dolan
PSEG ER&T
RFC
6.
Group
Louis Slade
Additional Member Additional Organization Region
6
Dominion
Segment
Selection
1.
Mike Garton
MRO
2.
Connie Lowe
SERC
3.
Michael Gildea
ERCOT
July 14, 2011
7
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Group
Jim Case
SERC OC Standards Review Group
2
X
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Rene’ Free
Santee Cooper
SERC
1, 3, 5, 9
2. Glenn Stephens
Santee Cooper
SERC
1, 3, 5, 9
3. Gerry Beckerle
Ameren
SERC
1, 3
4. Tim Hattaway
PowerSouth
SERC
1, 3, 5, 9
5. Mike Hardy
Southern
SERC
1, 3, 5
6. Joel Wise
TVA
SERC
1, 3, 5, 9
7. Jake Miller
Dynegy
SERC
5
8. Eugene Warnecke
Ameren
SERC
1, 3
9. Andy Burch
EEI
SERC
1, 5
10. Gene Delk
SCE&G
SERC
1, 3, 5
11. Robert Thomasson
BREC
SERC
1, 3, 5, 9
e1
Brad Young
2.
LGE/KU
SERC
1, 3, 5
13. Marc Butts
Southern
SERC
1, 3, 5
14. Larry Rodriquez
Entegra Power
SERC
5
15. Alvis Lanton
SIPC
SERC
1, 3, 5
16. Randall Haynes
Alcoa
SERC
1, 5
17. Connie Lowe
Dominion VP
SERC
1, 3
18. Melinda Montgomery Entergy
SERC
1, 3
19. Mike Oatts
Southern
SERC
1, 3, 5
20. Jason Marshall
MISO
SERC
2
21. John Troha
SERC
SERC
10
8.
Group
Albert DiCaprio
IRC Standards Review Committee
Additional Member Additional Organization Region
Segment
Selection
1.
Patrick Brown
PJM
2.
Matt Goldberg
ISO-NE NPCC
July 14, 2011
X
RFC
2
2
8
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Dan Rochester
IESO
4.
Steve Myers
ERCOT ERCOT
2
5.
Mark Thompson
AESO
WECC
2
6.
Greg Van Pelt
CAISO WECC
2
7.
Charles Yeung
SPP
SPP
2
8.
Terry Bilke
MISO
RFC
2
9.
Greg Campoli
NYISO NPCC
2
10.
Kathleen Goodman
ISO-NE NPCC
2
11.
Ben Li
IESO
NPCC
2
12.
Jason Marshall
MISO
RFC
2
13.
Don Weaver
NBSO
NPCC
2
9.
Group
Additional Member
NPCC
Carol Gerou
4
5
6
7
8
9
10
X
Region Segment Selection
1. Mahmood Safi
Omaha Public Utility District
MRO
1, 3, 5, 6
2. Chuck Lawrence
American Transmission Company
MRO
1
3. Tom Webb
Wisconsin Public Service Corporation MRO
3, 4, 5, 6
4. Jason Marshall
Midwest ISO Inc.
MRO
2
5. Jodi Jenson
Western Area Power Administration
MRO
1, 6
6. Ken Goldsmith
Alliant Energy
MRO
4
7. Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
8. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
9. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
10. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
11. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
12. Scott Nickels
Rochester Public Utilties
MRO
4
13. Terry Harbour
MidAmerican Energy Company
MRO
1, 3, 5, 6
14. Richard Burt
Minnkota Power Cooperative, Inc.
MRO
1, 3, 5, 6
July 14, 2011
3
2
MRO's NERC Standards Review
Subcommittee
Additional Organization
2
9
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10.
Group
Sam Ciccone
FirstEnergy
2
X
3
4
5
X
X
X
X
X
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Dave Folk
FE
RFC
1, 3, 4, 5, 6
2. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
3. Brian Orians
FE
RFC
5
4. John Reed
FE
RFC
1
5. Andy Hunter
FE
RFC
1
6. Bil Duge
FE
RFC
5
11.
Group
Jason Marshall
Midwest ISO Standards Collaborators
Additional Member Additional Organization
Region
X
Segment
Selection
1.
Robert Thomasson
Big Rivers Electric Cooperative
SERC
1, 3
2.
Joe O'Brien
NIPSCo
RFC
1, 3, 5, 6
3.
Bob Thomas
Illinois Municipal Electric Agency RFC
4
4.
Kirit Shah
Ameren
SERC
1
5.
Joe Knight
Great River Energy
MRO
1, 3, 5, 6
6.
Mike Moltane
ITC Holdings
MRO
1
12.
Group
Robert Rhodes
SPP Standards Development
Additional Member Additional Organization
X
Region
Segment
Selection
1.
Fred Meyer
Empire District Electric
SPP
1
2.
Gregory McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
3.
John Allen
City Utilities of Springfield, MO
SPP
1, 4
4.
Kyle McMenamin
Xcel Energy
SPP
1, 3, 5
5.
Michelle Corley
Cleco
SPP
1, 3, 5
6.
Rick Brenneman
Xcel Energy
SPP
1, 3, 5
7.
Sean Simpson
Board of Public Utilities of Kansas City, KS SPP
1, 3, 5
8.
Forrest Brock
Western Farmers Electric Cooperative
1, 3, 5
July 14, 2011
X
SPP
10
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Jim Usleldinger
13.
Group
Additional Member
Kansas City Power & Light
Michael Gammon
SPP
Kansas City Power & Light
2
3
4
5
6
9
10
1, 3, 5
X
X
X
X
1, 3, 5, 6
14.
Individual
Jack Cashin
Competitive Suppliers
15.
Individual
John Bee
Exelon
X
X
X
X
16.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
17.
Individual
Janet Smith
Arizona Public Service Company
X
X
X
X
18.
Individual
Brent Ingebrigtson
LG&E and KU Energy
19.
Individual
Cindy Martin
Southern Company
Individual
Greg Froehling
Green Country Energy, Green Country
Operating Services
21.
Individual
Steve Alexanderson
Central Lincoln
22.
Individual
Mace Hunter
Lakeland Electric
X
X
X
23.
Individual
Joe Petaski
Manitoba Hydro
X
X
X
X
24.
Individual
Brian J Murphy
NextEra Energy, Inc.
X
X
X
X
25.
Individual
Jonathan Appelbaum
United Illuminating Company
X
July 14, 2011
8
Additional Organization Region Segment Selection
1. Jennifer Flandermeyer Kansas City Power & Light SPP
20.
7
X
X
X
X
X
X
X
11
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
26.
Individual
Paul Kerr
Shell Energy North America (US), L.P.
27.
Individual
Thad Ness
American Electric Power
X
X
28.
Individual
David Thorne
Pepco Holdings Inc
X
X
29.
Individual
Andrew Pusztai
American Transmission Company
X
30.
Individual
Kathleen Goodman
ISO New England
X
31.
Individual
Steve Myers
ERCOT ISO
X
32.
Individual
Steve Rueckert
WECC
33.
Individual
Bill Keagle
BGE
34.
Individual
Brenda Powell
Constellation Energy Commodities Group
35.
Individual
Greg Rowland
Duke Energy
36.
Individual
CJ Ingersoll
CECD
37.
Individual
Rex A Roehl
Indeck Energy Services
Individual
Shaun Anders
City of Springfield, IL - City Water Light and
Power (CWLP)
X
X
X
39.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
X
40.
Individual
Dan Rochester
Independent Electricity System Operator
38.
July 14, 2011
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
12
Consideration of Comments on Reliability Coordination — Project 2006-06
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
41.
Individual
July 14, 2011
Alice Ireland
Xcel Energy
X
2
3
X
4
5
X
6
7
8
9
10
X
13
Consideration of Comments on Reliability Coordination — Project 2006-06
1. Do you agree with COM-001 requirements for Interpersonal Communications capability and Alternative
Interpersonal Communications capability (R1-R8)? If not, please explain in the comment area below.
Summary Consideration:
For the COM-001 standard, several commenters had suggestions for improvements to the requirement language and applicability. The RCSDT
believes the standard correctly and adequately requires each applicable entity that would have capability to receive Interconnection and operating
information to have Interpersonal Communications and Alternative Interpersonal Communications to be used when the Interpersonal
Communication is not available. The RCSDT has addressed the applicability of the standards and implementation plans by aligning COM-001-2,
and COM-002-3 to include the same entities and by removing LSE, PSE and TSP from the COM standards.
Many comments were concerned about both the medium (e.g. cellular, satellite, etc.) and media (e.g. voice, email, etc.) used for Interpersonal
Communications. The current language avoids being prescriptive and allows each entity to determine what is suitable. Interpersonal
Communication and Alternative Interpersonal Communication is between the applicable entities which may include multiple locations (e.g. a
primary and back-up control center).
The RCSDT added the following Requirement Parts at the suggestion of stakeholders:
3.5 Adjacent Transmission Operators synchronously connected within the same Interconnection
4.3 Adjacent Transmission Operators synchronously connected within the same Interconnection
5.6 Adjacent Balancing Authorities
6.3 Adjacent Balancing Authorities
The RCSDT agrees with the many industry comments and removed the phrase "to exchange Interconnection and operating information" in
requirements R1 through R8. This removal clarifies that the intent of this capability is NOT for the exchange of data.
A few commenters also expressed concerns about the frequency of testing Alternative Interpersonal Communications capability. The RCSDT
believes that the proposed testing frequency is supported by the majority of stakeholders and is not overly burdensome.
Several commenters suggested that VSLs should be written based on the percent of entities rather than by an occurrence of a violation. VSLs
must be written on a violation occurrence basis in accordance with FERC guidelines. The requirements specify which entities must be included in
communications capabilities. If a single entity is missing, this is a violation of the requirement. According to VSL guidelines, if missing any part of
the requirement could have the same reliability outcome as missing the entire requirement, the requirement is binary and the VSL must be severe.
A new requirement was added for clarity regarding responsibilities of the Distribution Provider and the Generator Operator when either entity
experiences a failure of its Interpersonal Communication capability:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication capabilities
shall consult with its Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
July 14, 2011
14
Consideration of Comments on Reliability Coordination — Project 2006-06
This requirement requires collaboration between entities to restore a failed communications capability.
Organization
ERCOT ISO
July 14, 2011
Yes or No
Question 1 Comment
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might
inadvertently include data. The SDT responded that it does not by referring to Interpersonal in the name of the
definition. Clearly, you cannot refer to the word you are defining in order to define it. However, it is possible
“allows two or more individuals to ...” may solve this problem. Clarity should be sought in the next posting, if
possible.
This standard does not comport with the informational filing that NERC submitted to FERC on
August 10, 2009 regarding its discontinued use of sub-requirements in standards development activities. We
request the sub-requirements be modified into bulleted lists.
Consider striking “to exchange
Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to the use of
Interpersonal Communications “to interact, consult, or exchange information” in the definition.
Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of
Alternative Interpersonal Communications which uses Interpersonal Communications in its definition.
Interpersonal Communications includes “to interact, consult, or exchange information” in its definition.
For
R2, why is Interchange Coordinator excluded? It is included in the Requirement R1 which deals with the
Interpersonal Communications. Communications would need to be maintained with the Interchange
Coordinator in the event of a failure of the Interpersonal Communications.
For R3, affected neighboring
Transmission Operators should be included.
For R4 and R6, the sub-requirement list is different than for
than for the associated Interpersonal Communications requirements R3 and R5 respectively. We believe
these should be duplicate. That is the sub-requirement list for R4 should match R3 and the R6 should match
R5. In the event of a failure of the Interpersonal Communications, the Transmission Operator and Balancing
Authority both would need to maintain communications to the same entities as in the requirement to have
Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists.
For R5, why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact
with Interchange Coordinator within same Interconnection. They certainly need to be able to contact one
another to identify discrepancies in scheduling and sources of meter error that could lead to deviations in
ACE.
Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In R1, R3 and R5, the
requirement is “shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one is for the
Interpersonal Communications and the other is for the Alternative Interpersonal Communications, it seems
the same wording should be used.
We do not believe R2.2 and R1.2 should be limited to Reliability
Coordinators in the same Interconnection only. We suggest modifying “within the same Interconnection” to
“within the same Interconnection, and, as appropriate, between a-synchronously connected RCs which are
not precluded by law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since
reliability coordination may be required among the RCs on both sides of an Interconnection boundary.
The VSLs for R1 through R8 should be expanded to include multiple levels based on the number of entities
that the functional entity does not have Interpersonal Communications or Alternative Interpersonal
15
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Communications. FERC specified their general preference for gradated in paragraph 27 of their June 19,
2008 order on VSLs.
The second half of the Severe VSL for R9 is almost a duplicate to the Lower VSL.
There are some small changes in the wording but both situations deal with the case where there is a problem
that has been identified with the Interpersonal Communications system and it takes more than two hours to
initiate repair.
ISO New England
July 14, 2011
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might
inadvertently include data. The SDT responded that it does not by referring to Interpersonal in the name of
the definition. Clearly, you cannot refer to the word you are defining in order to define it. However, it is
possible “allows two or more individuals to ...” may solve this problem. Clarity should be sought in the next
posting, if possible. This standard does not comport with the informational filing that NERC submitted to
FERC on August 10, 2009 regarding its discontinued use of sub-requirements in standards development
activities. We request the sub-requirements be modified into bulleted lists. Consider striking “to exchange
Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to the use of
Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of
Alternative Interpersonal Communications which uses Interpersonal Communications in its definition.
Interpersonal Communications includes “to interact, consult, or exchange information” in its definition. For R2,
why is Interchange Coordinator excluded? It is included in the Requirement R1 which deals with the
Interpersonal Communications. Communications would need to be maintained with the Interchange
Coordinator in the event of a failure of the Interpersonal Communications. For R3, affected neighboring
Transmission Operators should be included. For R4 and R6, the sub-requirement list is different than for than
for the associated Interpersonal Communications requirements R3 and R5 respectively. We believe these
should be duplicate. That is the sub-requirement list for R4 should match R3 and the R6 should match R5. In
the event of a failure of the Interpersonal Communications, the Transmission Operator and Balancing
Authority both would need to maintain communications to the same entities as in the requirement to have
Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists. For
R5, why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact with
Interchange Coordinator within same Interconnection. They certainly need to be able to contact one another
to identify discrepancies in scheduling and sources of meter error that could lead to deviations in ACE.
Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is
“shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one is for the Interpersonal
Communications and the other is for the Alternative Interpersonal Communications, it seems the same
wording should be used. We do not believe R2.2 and R1.2 should be limited to Reliability Coordinators in the
same Interconnection only. We suggest modifying “within the same Interconnection” to “within the same
Interconnection, and, as appropriate, between a-synchronously connected RCs which are not precluded by
law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since reliability
16
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
coordination may be required among the RCs on both sides of an Interconnection boundary. The VSLs for
R1 through R8 should be expanded to include multiple levels based on the number of entities that the
functional entity does not have Interpersonal Communications or Alternative Interpersonal Communications.
FERC specified their general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs.
The second half of the Severe VSL for R9 is almost a duplicate to the Lower VSL. There are some small
changes in the wording but both situations deal with the case where there is a problem that has been
identified with the Interpersonal Communications system and it takes more than two hours to initiate repair.
IRC Standards Review
Committee
July 14, 2011
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might
inadvertently include data. The SDT responded that it does not by referring to Interpersonal in the name of
the definition. Clearly, you cannot refer to the word you are defining in order to define it. However, it is
possible “allows two or more individuals to ...” may solve this problem. Clarity should be sought in the next
posting, if possible. This standard does not comport with the informational filing that NERC submitted to
FERC on August 10, 2009 regarding its discontinued use of sub-requirements in standards development
activities. We request the sub-requirements be modified into bulleted lists. Consider striking “to exchange
Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to the use of
Interpersonal Communications “to interact, consult, or exchange information” in the definition. Consider
striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to the use of
Alternative Interpersonal Communications which uses Interpersonal Communications in its definition.
Interpersonal Communications includes “to interact, consult, or exchange information” in its definition. For
R2, why is Interchange Coordinator excluded? It is included in the Requirement R1 which deals with the
Interpersonal Communications. Communications would need to be maintained with the Interchange
Coordinator in the event of a failure of the Interpersonal Communications. For R3, affected neighboring
Transmission Operators should be included. For R4 and R6, the sub-requirement list is different than for than
for the associated Interpersonal Communications requirements R3 and R5 respectively. We believe these
should be duplicate. That is the sub-requirement list for R4 should match R3 and the R6 should match R5. In
the event of a failure of the Interpersonal Communications, the Transmission Operator and Balancing
Authority both would need to maintain communications to the same entities as in the requirement to have
Interpersonal Communications. Again, we would suggest replacing sub-requirements with bulleted lists. For
R5, why are neighboring Balancing Authorities not included? Additionally R5 should only read Contact with
Interchange Coordinator within same Interconnection. They certainly need to be able to contact one another
to identify discrepancies in scheduling and sources of meter error that could lead to deviations in ACE.
Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is
“shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one is for the Interpersonal
Communications and the other is for the Alternative Interpersonal Communications, it seems the same
wording should be used. We do not believe R2.2 and R1.2 should be limited to Reliability Coordinators in the
same Interconnection only. We suggest modifying “within the same Interconnection” to “within the same
17
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Interconnection, and, as appropriate, between a-synchronously connected RCs which are not precluded by
law from scheduling interchange energy (for schedule changes, curtailments, etc.)” since reliability
coordination may be required among the RCs on both sides of an Interconnection boundary. The VSLs for
R1 through R8 should be expanded to include multiple levels based on the number of entities that the
functional entity does not have Interpersonal Communications or Alternative Interpersonal Communications.
FERC specified their general preference for gradated in paragraph 27 of their June 19, 2008 order on VSLs.
The second half of the Severe VSL for R9 is almost a duplicate to the Lower VSL. There are some small
changes in the wording but both situations deal with the case where there is a problem that has been
identified with the Interpersonal Communications system and it takes more than two hours to initiate repair.
Midwest ISO Standards
Collaborators
July 14, 2011
No
We expressed in the last posting that we felt the definition of Interpersonal Communications might
inadvertently include data. The drafting team responded that it does not by referring to Interpersonal in the
name of the definition. Clearly, you cannot refer the word you are defining to define it. However, it is possible
“allows two or more individuals to ...” may solve this problem. What are the drafting team’s thoughts on this
issue? This standard does not comport with the informational filing that NERC submitted to FERC on August
10, 2009 regarding its discontinued use of sub-requirements in standards development activities. Consider
striking “to exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is redundant to
the use of Interpersonal Communications “to interact, consult, or exchange information” in the definition.
Consider striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to
the use of Alternative Interpersonal Communications which uses Interpersonal Communications in its
definition. Interpersonal Communications includes “to interact, consult, or exchange information” in its
definition. For R2, why is Interchange Coordinator excluded? It is included in the Requirement R1 which
deals with the Interpersonal Communications. Communications would need to be maintained with the
Interchange Coordinator in the event of a failure of the Interpersonal Communications. For R3, neighboring
Transmission Operators should be included. For R4 and R6, the sub-requirement list is different than for than
for the associated Interpersonal Communications requirements R3 and R5 respectively. They should be
duplicate. That is the sub-requirement list for R4 should match R3 and the R6 should match R5. In the event
of a failure of the Interpersonal Communications, the Transmission Operator and Balancing Authority both
would need to maintain communications to the same entities as in the requirement to have Interpersonal
Communications. For R5, why are neighboring Balancing Authorities not included? They certainly need to be
able to contact one another to identify discrepancies in scheduling and sources of meter error that could lead
to deviations in ACE. Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In R1, R3 and R5,
the requirement is “shall have” while in R2, R4, and R6, the requirement is “shall designate”. Since one is for
the Interpersonal Communications and the other is for the Alternative Interpersonal Communications, it
seems the same wording should be used. Should R2.2 and R1.2 be limited to Reliability Coordinators in the
same Interconnection only? The VSLs for R1 through R8 should be expanded to include multiple levels
based on the number of entities that the functional entity does not have Interpersonal Communications or
18
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Alternative Interpersonal Communications. FERC specified their general preference for gradated in
paragraph 27 of their June 19, 2008 order on VSLs. The second half of the Severe VSL for R9 is almost
duplicate to the Lower VSL. There are some small changes in the wording but both situations deal with the
case where there is a problem that has been identified with the Interpersonal Communications system and it
takes more than two hours to initiate repair.
Northeast Power Coordinating
Council
No
It was expressed in the last posting that the definition of Interpersonal Communications might inadvertently
include data. The SDT responded that it does not by referring to Interpersonal in the wording of the definition.
The word being defined shouldn’t be in the definition. However, incorporating “allows two or more individuals
to ...” is an option that may solve this problem. The next posting should clarify this.
Response: The RCSDT has clarified in previous responses to comments that the requirements of COM-001
do not apply to data. The current proposed definition of Interpersonal Communications includes the phrase
“allows two or more individuals to…”. In an effort to make this more clear, the RCSDT has revised
Requirements R1-R8 to remove the phrase “to exchange Interconnection and operating information” as you
and others have suggested. This will provide the needed clarity for stakeholders that COM-001 does not
include “data exchange.”
This standard does not comport with the informational filing that NERC submitted to FERC on August 10,
2009 regarding its discontinued use of sub-requirements in standards development activities. The subrequirements should be modified into bulleted lists.
Response: The information filing did not propose to eliminate the use of numbered items altogether, but
proposed changing the manner in which they were numbered. Bulleted lists are used to indicate sets of
options; numbered lists are used when each of the listed items are required.
Consider striking “to exchange Interconnection and operating information” in R1, R3, R5, R7, and R8. It is
redundant to the use of Interpersonal Communications “to interact, consult, or exchange information” in the
definition.
Response: The RCSDT agrees and we have removed the phrase “to exchange Interconnection and
operating information from R1-R8. This helps clarify the intent that the capability is NOT for data exchange as
data is covered under the provisions of the recently approved IRO-010-1a.
Consider striking “to exchange Interconnection and operating information” in R2, R4, R6. It is redundant to
the use of Alternative Interpersonal Communications which uses Interpersonal Communications in its
definition. Interpersonal Communications includes “to interact, consult, or exchange information” in its
definition.
Response: The RCSDT agrees and we have removed the phrase “to exchange Interconnection and
July 14, 2011
19
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
operating information from R1-R8. This helps clarify the intent that the capability is NOT for data exchange as
data is covered under the provisions of the recently approved IRO-010-1a.
For R2, why is Interchange Coordinator excluded? It is included in the Requirement R1 which deals with the
Interpersonal Communications. Communications would need to be maintained with the Interchange
Coordinator in the event of a failure of the Interpersonal Communications.
Response: R1 is dealing with the “normal” communications. R2 deals with the default reliability needs. The
normal communications include Interchange Coordinators because they are part of the administration of
Interchange. The SDT predicated R2 on being in an unusual situation in which only the basic reliability
functions were needed. In such times, the Interchange Function is seen as sacrificial because the BA itself
could operate reliably (not necessarily efficiently) by simply dealing with it is adjacent BAs and “scheduling”
interchange on a BA to BA basis (as opposed to a PSE to PSE basis). The Interchange Coordinator is only
needed to ensure all of the commercial arrangements are validated by all parties. In stressed conditions those
checkouts can be by-passed and dealt with after-the-fact. That does not mean that when an entity goes to
backup is expected to bypass the Interchange Coordinator. The requirement R2 merely focused on the worst
case situation.
This requirement is not meant to define the alternate backup system; it is merely mandating the lowest
mandatory requirements on the backup system. For example during the Y2K operations backup systems
included satellite phones which did not cover all entities involved in normal operations. The SDT wrote the
requirements to assure that such an event would not cause all RCs, BAs and TOPs to be non-compliant.
For R3, affected neighboring Transmission Operators should be included.
Response: The SDT has included the following Part 3.5 of Requirement R3:
3.5 Adjacent Transmission Operators synchronously connected within the same Interconnection
For R4 and R6, the sub-requirement list is different from the associated Interpersonal Communications
requirements R3 and R5 respectively. These should be duplicate. The sub-requirement list for R4 should
match R3, and the sub-requirement list for R6 should match R5. In the event of a failure of the Interpersonal
Communications, the Transmission Operator and Balancing Authority both would need to maintain
communications to the same entities as in the requirement to have Interpersonal Communications.
Response: The SDT has included the following Part 4.3 of Requirement R4:
4.3 Adjacent Transmission Operators synchronously connected within the same Interconnection
The SDT has included the following Part 6.3 of Requirement R6:
6.3 Adjacent Balancing Authorities
July 14, 2011
20
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
The RCSDT asserts the standard meets FERC Order 693 regarding DP and GOP entities by requiring these
entities to have Interpersonal Communication capability. Not requiring DP and GOP entities to have
Alternative Interpersonal Communication capability meets FERC’s intention as stated here: “We (FERC)
clarify that the NOPR did not propose to require redundancy on generator operators’ or distribution providers’
telecommunication facilities…” (Order 693, RM06-16-000, Paragraph 487).
The sub-requirements should be bulleted lists.
Response: Bulleted lists are used to indicate sets of options; numbered lists are used when each of the listed
items are required.
For R5, why are neighboring Balancing Authorities not included?
Response: The SDT has included the following Part 5.6 of Requirement R5:
5.6 Adjacent Balancing Authorities
Note that this is a defined term in the glossary: “A Balancing Authority Area that is interconnected (to)
another Balancing Authority Area either directly or via a multi-party agreement or transmission tariff.”
Additionally, R5 should only read Contact with Interchange Coordinator within the same Interconnection.
They need to be able to contact one another to identify discrepancies in scheduling and sources of meter
error that could lead to deviations in ACE.
Response: The RCSDT has removed the Interchange Coordinator from the standard (R1 and R5) as the BA
is responsible for the reliability implications of Interchange. The reliability relationship lies between BA’s.
Should R2, R4 and R6 be constructed parallel to R1, R3, and R5? In R1, R3 and R5, the requirement is “shall
have” while in R2, R4, and R6, the requirement is “shall designate”. Since one is for the Interpersonal
Communications and the other is for the Alternative Interpersonal Communications, the same wording should
be used.
Response: The SDT inserted the different terminology because there may be more than one type backup
system, Some entities have land lines; cell phones; satellite phones; voice over internet; and/or
teleconferencing. The language is intended to provide flexibility to allow entities to have one or more types of
backup while designating one for Alternative Interpersonal Communications.
R2.2 and R1.2 should not be limited to Reliability Coordinators in the same Interconnection only. Modify
“within the same Interconnection” to “within the same Interconnection, and, as appropriate, between asynchronously connected RCs which are not precluded by law from scheduling interchange energy (for
schedule changes, curtailments, etc.)” since reliability coordination may be required among the RCs on both
sides of an Interconnection boundary.
July 14, 2011
21
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Response: The requirement proposed by NPCC is predicated on “as appropriate.” Such subjective phrases
cannot be used in a standard. The issue of asynchronous entities is not germane to the requirement but the
requirement does not preclude additional coordination to meet the specifics of ERCOT, HQ and WECC. A
regional variance may be an option for you to consider.
The VSLs for R1 through R8 should be expanded to include multiple levels based on the number of entities
that the functional entity does not have Interpersonal Communications or Alternative Interpersonal
Communications with. FERC specified their general preference for gradated in paragraph 27 of their June 19,
2008 order on VSLs.
Response: Each entity listed in Requirements R1-R8 is required to meet the contents with respect to each
other entity listed in the requirement. Failure to have the capability with a single entity is a single violation of
the requirement. For example, if an RC has 5 BA’s within it Area and fails to have Interpersonal
Communications with two of them, then the RC has violated the requirement twice. The VSLs are written to
address each violation of the Requirement. We have removed the words “or more” from the VSLs.
The second half of the Severe VSL for R9 is almost a duplicate of the Lower VSL. There are some small
changes in the wording but both situations deal with the case where there is a problem that has been
identified with the Interpersonal Communications system and it takes more than two hours to initiate repair.
Response: The R9 Severe VSL was revised to remove “within 2 hours”. It now reads:
“The responsible entity tested the Alternative Interpersonal Communications capability and identified a
problem but didn’t initiate action to repair or designate a replacement Alternative Interpersonal
Communications.”
Response: The RCSDT thanks you for your comment. Please see responses embedded above.
PNGC Power member owners
July 14, 2011
No
Thank you for the opportunity to comment and for your hard work on this project: While we agree that
effective Interpersonal Communications capability are integral to reliability, many Distribution Providers (DP)
are small entities that do not maintain a 24-7 dispatch desk capable of receiving or responding to emergency
reliability directives in a timely manner. It is our belief that some of the proposals in this project could
unnecessarily force small entities to make investments that will not enhance reliability. Many DPs rely on
answering services to address customer-service issues during non-business hours. On-call personnel are
contacted in the event of an outage or emergency and crews are dispatched as appropriate. It is difficult to
envision a BA or TOP issuing an Emergency Reliability Directive to a small entity (25 MW or so) which would
require these smaller entities to comply with COM-001. Order 693 directs the inclusions of DPs in the COM001-2 standard but it is our belief that the Commission offered language that GOs and DPs need not have
redundant communications, training unrelated to normal/emergency operations, and that telecommunications
22
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
requirements for entities will vary according to their function. We believe those intentions should be reflected
in the language of this standard. We would suggest adding wording such as in the applicability section,
"Distribution Providers who maintain a 24-7 control centers with the ability to manually shed load of at least
100 MW within a 15-minute operational window."Also, a note that smaller, rural entities can be dependent on
a phone system provider that will not allow for backup communications. Should the communication line(s) be
dependent on one main phone trunk line, the failure due to an issue on this main line will make it impossible
to notify anyone of its failure short of physically traveling to an area where phone service is available. For
some rural areas, this will exceed the one hour time limit to report the communication outage. Forcing smaller
entities to acquire satellite phone service to mitigate for a phone outage is a high price to pay when no
reliability improvement will be achieved. Suggested change could be: "... shall notify impacted entities within
60 minutes of the detection of a failure of its Interpersonal Communications capabilities that lasts 30 minutes
or longer where alternate forms of communication are available within a 15 minute access time. Should
alternate forms of communication not be available within the 15 minute access time, then upon
reestablishment of Communication capabilities impacted entities will be notified of the past loss and current
status of Communication."We’ve heard many representatives from FERC and NERC indicate that the
standards development process has led the industry to take action in many cases for the sake of compliance
while not necessarily enhancing reliability. As has been stated many times, the process should be about
improving reliability, not about complying with standards. Unnecessarily including smaller entities that will
NEVER receive an emergency reliability directive might be an example of the former.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support, the requirement is to have communications capability. The type
of system (i.e. On-Call) is not prescribed in the standard and the standard is designed not to impose needless communications requirements. The purpose of
COM-002 is “To ensure emergency communications between operating personnel are effective.” It is not a proxy requirement to establish 24/7 operating
personnel at small distribution providers. The intent is to establish a method of communicating Reliability Directives during Emergencies. While it is true that many
small Distribution Providers are not staffed 24x7, it is typical that they have a means of communication, in many cases this may be via a receptionist, or answering
service. It is the expectation that an issuer of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the
Reliability Directive. If this return call would not be timely enough, then the issuer would determine a different mitigation plan.
PPL
Yes
PSEG
No
Com-001-2 implementation plan lists that this is applicable to PSE’s and LSE’s however, PSE’s and LSE’s
were removed from the actual standard. The implementation plan should be revised.
Response: The RCSDT thanks you for your comment. We have revised as you suggested.
Dominion
July 14, 2011
No
The monthly testing requirement for Alternative Interpersonal Communications is overly burdensome without
any evidence to support that it is necessary to insure reliability. We believe that an entity will take necessary
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
steps to insure the Alternative Interpersonal Communications is functioning properly, especially if it
experiences problems with its Interpersonal Communications, it. We can support quarterly testing as we
believe it strikes a reasonable balance.
Response: The RCSDT thanks you for your comment. The drafting team has not received a large number of comments that suggest that the frequency of the
testing is burdensome and believes that the testing could occur in the normal course of daily activities. Therefore, the SDT believes the frequency of testing will
not be burdensome.
South Carolina Electric and Gas
No
Each sub-requirement should not have an “R” in front of the number in order to be consistent with NERC’s
August 10, 2009 filing at FERC on this subject. Requirement R3 and R4 should include adjacent TOPs as a
sub-requirement. Requirements R5 and R6 should include adjacent BAs as a sub-requirement. ”to exchange
Interconnection and operating information” should be deleted from requirements R1 through R8 as it is
redundant with the definition of Interpersonal Communications. The last page of the Implementation Plan
includes LSEs, PSE, and TSPs as being responsible entities under this standard, yet the standard does not
include them. Please correct the implementation plan.
SERC OC Standards Review
Group
No
Each sub-requirement should not have an “R” in front of the number in order to be consistent with NERC’s
August 10, 2009 filing at FERC on this subject.
Response: The RCSDT agrees and this change has been made.
Requirement R3 and R4 should include adjacent TOPs as a sub-requirement.
Response: The SDT has included the following Part 3.5 of Requirement R3 and 4.3 of R4:
Adjacent Transmission Operators synchronously connected within the same Interconnection
Requirements R5 and R6 should include adjacent BAs as a sub-requirement.
Response: The SDT has included the following Part 5.6 of Requirement R5 and Part 6.3 of R6:
Adjacent Balancing Authorities
Note that this is a defined term in the glossary: “A Balancing Authority Area that is interconnected to another
Balancing Authority Area either directly or via a multi-party agreement or transmission tariff.”
”to exchange Interconnection and operating information” should be deleted from requirements R1 through R8
as it is redundant with the definition of Interpersonal Communications.
Response: The RCSDT agrees and we have removed the phrase “to exchange Interconnection and
operating information from R1-R8.
July 14, 2011
24
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
The last page of the Implementation Plan includes LSEs, PSE, and TSPs as being responsible entities under
this standard, yet the standard does not include them. Please correct the implementation plan.
Response: The RCSDT agrees and we have made the revision.
Response: The RCSDT thanks you for your comment. Please see responses above.
MRO's NERC Standards Review
Subcommittee
No
A. R5.5 states a BA shall have Interpersonal Communications with each Interchange Coordinator within its
BA area and adjacent Interchange Coordinators. NERC Registry Criteria (v5) uses the term “Interchange
Authority” not Interchange Coordinator, please clarify.
Response: The RCSDT has removed the Interchange Coordinator from the standard based on stakeholder
feedback.
B. Upon review of the NERC Compliance Registry, there are only 56 BA’s that are also registered as an IA
but 138 total BA’s within the registry. R5.5 is not clearly written because many BA’s do not have an IA within
their BA area. Though a BA will use an IA to schedule interchange, a possible rewrite of R5.5 may be “Each
Interchange Authority that the BA actively uses to arrange Interchange”.
Response: The RCSDT has removed the Interchange Coordinator from the standard based on stakeholder
feedback.
C. R10 states that the RC, TOP, BA, DP and GOP shall notify “impacted entities” within 60 minutes... Please
clarify if the SDT means the entities within the applicability section or is this to be determined by the entity. A
possible rewrite may be; “Each RC shall notify TOP’s, BA’s, and IA’s within its RC area along with adjacent
RC’s within the same Interconnection”. This break down would need to be required for each affected entity
and would provide clarity to the industry.
Response: R10 specifies only “impacted entities”. That phrase is used to limit the scope of the requirement. If
an entity has a failure of its Interpersonal Communications capability with only one entity, then that entity is
the “impacted entity” and they should be notified of the failure.
D. We do not agree with a DP and GOP need to be held to the same level of compliance as a RC, BA or
TOP. FERC Order 693 (paragraph 487) directed the DP and GOP to be included in this standard by stating:”
We expect the telecommunication requirements for all applicable entities will vary according to their roles and
that these requirements will be developed under the Reliability Standards development process”. A DP and
GOP may not be staffed 24 hours a day like a BA or TOP and the SDT did not take this into consideration.
Response: There is no requirement that requires identical communications systems. The requirement is to
have “a” communication capability. The RCSDT asserts the standard meets FERC Order 693 regarding DP
and GOP entities by requiring these entities to have Interpersonal Communication capability. Not requiring DP
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
and GOP entities to have Alternative Interpersonal Communication capability meets FERC’s intention as
stated here: “We (FERC) clarify that the NOPR did not propose to require redundancy on generator operators’
or distribution providers’ telecommunication facilities…” (Order 693, RM06-16-000, Paragraph 487). A new
requirement was also added concerning the failure of a DP or GOP Interpersonal Communications capability:
R11 Each Distribution Provider and Generator Operator that experiences a failure of any of its
Interpersonal Communication capabilities shall consult with its Transmission Operator or Balancing
Authority as applicable to determine a mutually agreeable time to restore the Interpersonal
Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
E. We understand that the DP and GOP need a means of communicating with their BA and TOP (R7 and R8)
but would this not be the same Interpersonal Communications capability that as stated in R3 and R5 for the
TOP and BA? Example: If the BA uses a phone line as their Interpersonal Communication medium to
contact the DP wouldn’t the DP also use the same medium to communicate with their BA? Yes, there could
be different mediums but 99% of the time it will be the same medium.
Response: The RCSDT agrees with your assumption; however a reciprocal requirement is necessary.
Without R7 and R8, there would be no requirement for the DP or GOP.
F. R10 could mean that if there is a logging system that detects an Interpersonal Communication failure, then
all applicable entities will need to monitor that monitoring device. Since this requirement applies to all
applicable entities, and Interpersonal Communication mediums will most likely be the same, there will always
be two entities found non compliant if the 60 minute threshold is passed.
Response: There is no requirement to monitor or log Interpersonal Communications capability, only to test.
R10 requires the entity to notify the impacted entities upon a failed test or the detection of a failure.
Response: The RCSDT thanks you for your comment. Please see responses above.
FirstEnergy
No
It is not clear from the definition of Interpersonal Communications if certain communications “mediums” such
as email, instant messaging, etc. are included.
Response: The requirements are for communications between two or more persons. Mediums are not listed
to avoid being prescriptive in the requirement. The measures provide examples of mediums.
Furthermore, the Measures for these requirements all include “electronic communications” as acceptable
evidence. If the drafting team does not intend these mediums be included, then it should be clarified in the
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
definition. We suggest the following wording of the definition: Interpersonal Communication: Any medium that
allows two or more individuals to interact, consult, or exchange information. This interaction consists of verbal,
spoken words exchanged in Real-time.
Response: The use of verbal communication only is not the intent of the requirement. Written
communication is also an acceptable form of Interpersonal Communication.
Response: The RCSDT thanks you for your comment. Please see responses above.
SPP Standards Development
No
We would suggest that the applicability of COM-001-2 be expanded to that listed in COM-002-3. How can the
directives to be issued in COM-002 be delivered and confirmed without having Interpersonal Communications
capability?
Response: The RCSDT has revised the applicability of COM-001 and COM-002 such that they contain the
same functional entities. These are: RC, TOP, BA, GOP, and DP.
All of the functional entities listed in R1.1 should also be listed in R2.1. Similarly the sub-requirements of R3
should also be applied to R4. The same holds true for R5 and R6.
Response: The requirements for Alternative Interpersonal Communications are different than for
Interpersonal Communications. There is not necessarily a reliability need to have redundant capability with
each and every entity such as DP and GOP.
If the SDT intends to exclude data communications from Interpersonal Communications and Alternative
Interpersonal Communications, we suggest the SDT be more specific in the definition to specifically exclude
data communications in the definition. It is not readily apparent that these terms do not apply to data
communications and without a clarification, confusion exists.
Consider
Response: The RCSDT agrees and have removed the phrase “to exchange Interconnection and operating
information from R1-R8. This helps clarify the intent that the capability is NOT for data exchange, as data is
covered under the provisions of the recently approved IRO-010-1a.
Response: The RCSDT thanks you for your comment. Please see responses above.
Kansas City Power & Light
July 14, 2011
No
These requirements require TOP’s, BA’s, and GOP’s to establish alternative means of “interpersonal”
communications with other BA’s, GOP’s, and BA’s respectively without regard to the reliability impact each
TOP, BA or GOP has on the interconnection. Why would it be necessary for a TOP with one 161kv
transmission line or a BA with 100 MW of total load, or one GOP with a 30MW unit to realize additional costs
27
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
when the facilities they operate have little reliability impact?
Response: The RCSDT believes that any NERC Registered Entity capable of issuing or receiving a directive
is an applicable party to COM-001.
In addition, most RC’s have established satellite telephone systems as back-up communication with TOP’s.
RC’s may have to establish additional communication systems with BA’s as these requirements impose to
avoid Standards of Conduct issues.
Response: It is unclear how this scenario would present Standards of Conduct issues for communication
between reliability entities. The requirements pertain to reliability functions, not commercial functions or the
way in which entities are structured internally.
R9 - considering the reliability of communication systems, a 2 hour response to a problem with the alternative
means of communication is over sensitive. Allowing for sometime in an operating shift would be more in line,
such as 8 hours.
Response: The requirement is to initiate action within 2 hours, not complete it. The two hour time reference
aligns with the timing shown in EOP-008 for back-up facilities.
Response: The RCSDT thanks you for your comment. Please see responses above.
Competitive Suppliers
Exelon
No
1. COM-001-2, 4.4 - Distribution Providers and 4.5, Generation Operators should be highlighted and
communicated as a substantive change since entities may not be aware that they are being added to the
applicability section of the standard.
Response: These revisions were done based on FERC Order 693 directives. They have been widely
distributed in redline form. NERC will ensure that the change in applicability is highlighted in the
announcement of the next posting.
2. COM-001-2, R10 - should have the following underlined clarifying text added, shall notify impacted entities
within 60 minutes of the detection of a failure “of all primary and alternative “ Interpersonal Communications
capabilities that lasts 30 minutes or longer. Exelon believes that the intent of R10 is for complete loss of
communication ability and should not be applied to facilities that have multiple backups.
Response: The RCSDT developed R10 based on R3 of COM-001-1. The intent is to ensure that entities
know not to use the primary and to use the alternative.
3. COM-001-2, M1 thru 9 - Suggest that network diagrams and / or communications schematics be added as
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
suggested evidence.
Response: The measure only provides examples of the types of evidence that may be used for compliance
and the list is not all inclusive. The term “…evidence that could include, but is not limited to…” addresses
your suggestion.
4. COM-001-2, VSL for R9 - Regarding failure to test the Alternative Interpersonal Communication, the
Severity Level does not align with the potential impact to the BES. The Severity Level for simply missing a
test should be revised to a High VSL.
Response: The VSL does not relate to risk to the BES (this is covered in the Violation Risk Factor). The VSL
only indicates how badly an entity missed the mark with respect to the requirement. A Severe VSL is
appropriate.
Response: The RCSDT thanks you for your comment. Please see responses above.
PacifiCorp
Yes
Arizona Public Service Company
Yes
Southern Company
No
Comments: Standard COM-001-2R10. Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider, and Generator Operator shall notify impacted entities within 60 minutes of the
detection of a failure of its Interpersonal Communications capabilities that lasts 30 minutes or longer.
Comment: It is not clear whether the notification requirements identified in R10 apply to failure of ALL
available Interpersonal Communications or ANY Interpersonal Communications. We suggest that the
existence of functioning Alternative Interpersonal Communications precludes the requirement for notification
of impacted entities.
Response: The intent of R10 is to ensure that entities know not to use the primary and to use the alternative.
Notification is required for the failure of the primary capability.
D. Compliance 1. Compliance Monitoring Process 1.3 Data Retention Each Generator Operator shall keep
the most recent twelve months of historical data (evidence) for Requirements R8 and R10, Measures M8 and
M10.Comment: The data retention requirements specified for the Generator Operator in Para. 1.3 (above) are
not consistent with the 3-year audit interval for the GOP. Question: When audited on this Standard is the
expectation that the GOP will have 12 months of evidence or 36 months of evidence?
Response: The Data Retention section of the standard conforms to the NERC guidelines. The RCSDT has
also added the following to the data retention section:
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
The following evidence retention periods identify the period of time an entity is required to retain
specific evidence to demonstrate compliance. For instances where the evidence retention period
specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may
ask an entity to provide other evidence to show that it was compliant for the full time period since the
last audit.
Standard COM-002-3R2. Each Balancing Authority, Transmission Operator, Generator Operator,
Transmission Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that
is the recipient of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or
recapitulate the Reliability Directive with enough details that the accuracy of the message has been
confirmed. Comment: The term “Reliability Directive” is currently not defined in the NERC Glossary of Terms.
However, in the Implementation Plan for COM-002-3 the RC SDT proposes a definition for Reliability
Directive. It is implied in the standard that the Reliability Directive is issued as a voice command which
precludes the use of our preferred method of Interpersonal Communication. However, this is not definitively
stated in either the standard or the proposed definition. I think this needs to be made clearer if the Reliability
Directive must be issued as a voice command.
Response: The RCSDT disagrees with your assumption that the requirement implies that a Reliability
Directive must be issued verbally. In a previous version of the draft standard, the RCSDT had included
“verbal” issuance of directives. This was removed to allow the use of other than voice capability to issue a
Reliability Directive.
Response: The RCSDT thanks you for your comment. Please see responses above.
Green Country Energy, Green
Country Operating Services
No
COM-001 General question/comment. The reference to infrastructure should be removed and just keep the
word “medium”. Here's why: What communication medium (infrastructure) does not use satellite at some
point unless entities are within a close geographical proximity? How likely is it to have 2 different mediums? o
Local phone and fax hard-wire likely. o Long distance phone and fax - satellite o Cell phone - satellite o
Internet - satellite o Radio - antenna The reason for mentioning this is, if all we have is satellite then the
reference to infrastructure should be removed and just keep the word “medium”.
Response: The RCSDT thanks you for your comment. The RCSDT believes that the language of the definition is clearer with the existing verbiage.
Central Lincoln
No
See Q 6 below.
Response: The RCSDT thanks you for your comment. Please see responses to Q6.
July 14, 2011
30
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Lakeland Electric
Yes
Manitoba Hydro
Yes
NextEra Energy, Inc.
No
Question 1 Comment
As drafted, COM-001 is not clear or complete. At this stage in the evolution of compliance with the mandatory
Reliability Standards, it is important that any new or revised Reliability Standard clearly articulate all
compliance obligations and tasks consistent with Sections 302 (6) and (8) of the NERC Rules of Procedure.
Thus, NextEra Energy Inc. (NextEra) has numerous recommended corrections to provide clarity and
completeness to COM-001. For example, the requirement to designate an Alternative Interpersonal
Communication capability is not clear. Does the designator solely designate for the designator’s knowledge
or does the designator need to inform the entity on the other end of the connection. In R2, for instance, the
Reliability Coordinator must designate, but it is also not clear whether the Reliability Coordinator must inform
the Balancing Authorities or Transmission Operators. It is further unclear whether the designation must be
documented, or if any informing of the Balancing Authorities or Transmission Operators must be documented.
Thus, it is recommended that the drafters decide what was intended regarding the designation and clearly
state the requirements.
Response: The Requirement R2 is for the RC to designate an Alternative Interpersonal Communication and
inform the other entity (BA, TOP, etc.) as to what that Alternative Interpersonal Communication is. The
Measure M2 provides examples of the types of evidence which may be used to prove compliance with the
requirement.
In R9 it states that “. . . on at least a monthly basis.” There are two issues to consider here. If the sentence
stays, grammatically it should read “. . . on, at least, a monthly basis. . . However, from a compliance and
technical perspective, the term “at least” has no significance and should be deleted. The requirement is to
test on a monthly basis - the phrase “at least” only introduces ambiguity and implies that the party should
consider every two or three weeks. If the drafting team believes a best practice is less than a month, there
are other NERC educational tools to explain a best practice.
Response: The RCSDT used this term to allow more frequent testing to be performed.
In R10, it states “. . . shall notify the impacted entity . . .” It would be clearer to state: “. . . shall notify the
impacted Reliability Coordinator, Transmission Operator, Balancing Authority, Distribution Provider or
Generator Operator . . .”
Response: The RCSDT believes your suggestion adds unnecessary verbiage to the requirement and does
not provide additional clarity.
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
Response: The RCSDT thanks you for your comment. Please see responses above.
United Illuminating Company
No
COM-001-2 does not specify the amount of time a DP has to reestablish the Interpersonal Communication
Capability after the capability fails before it is assessed non-compliance for not having the communication. Is
an entity non-compliant the minute the communication capability is unavailable? If so, then to be compliant a
tertiary (or secondary capability for DP) must be installed by the entity. Something similar was discussed with
EOP-008 R3: "To avoid requiring a tertiary facility, a backup facility is not required during: o Planned outages
of the primary or backup facilities of two weeks or less o Unplanned outages of the primary or backup
facilities". UI suggests the drafting team incorporate something similar.
Response: The RCSDT is proposing a new requirement to address your concerns for the DP. We have
included the GOP as well:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its
Interpersonal Communication capabilities shall consult with their Transmission Operator or Balancing
Authority as applicable to determine a mutually agreeable time to restore the Interpersonal
Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
The VSL for R7 is severe only and states: "The Distribution Provider failed to have Interpersonal
Communications capability with one or more of the entities listed in Parts 7.1 or 7.2.".I believe there should be
a time component to the VSL and the VSL staged. For example, failure to have communication established
for less than 60 minutes would be Lower, anything over 1 hour severe. Also needed is a phrase to state when
the violation begins. Does the violation begin when the loss of Communication Capability is detected or when
it occurred? In other words, does the violation start when the operator attempts to use the phone and it is not
functional, or did it occur when the phone line functionality failed but was not yet detected because no attempt
to use the phone was made. So the VSL for R7 would follow a format of: "The Distribution Provider failed to
have Interpersonal Communication Capability with one or more entities listed in Parts 7.1 or 7.2 for a
continual 60 minutes period as measured from the time the ICC failure was detected". An alternative remedy
is to alter the language of R7 to allow for unplanned outage.
Response: The VSL represents a single violation of the requirement. For this requirement, the DP must
have Interpersonal Communication with its TOP and BA. The VSL was revised to remove “or more” to
conform to the requirement.
NERC does not have a Reliability Requirement for a DP to staff a control room 24/7. COM-0001 can be
interpreted to imply that a DP needs to be staffed 24/7 to facilitate interpersonal communications. If NERC
wants to extend the requirement for a 24/7 staffed operating position at the DP then the appropriate method is
July 14, 2011
32
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
thru a SAR to PER-002.
Response: COM-001 is not intended to imply a 24/7 requirement.
COM-001 R7 should have a sub-requirement added recognizing that DP’s are not required to staff 24/7 and
many do not staff overnight. UI suggests adding R7.3: DP’s will notify their TOP and/or BA when it is not
staffing an operating desk.
Response: While the SDT does not disagree this would be good practice, other methods of addressing this
situation (e.g., having an answering service, an on –call staff, or something similar) would be valid as well.
The SDT does not believe it would be appropriate to limit this to only one method.
R7: Should address the instance if the DP is not required to have communication with the BA, because the
BA communicates thru the TOP.
Response: The intent of the standard is that the DP will have communication with their BA. Ti is not
prescriptive as to how that communication will be implemented.
Response: The RCSDT thanks you for your comment. Please see responses above.
American Electric Power
No
The applicability of COM-001 and COM-002 appear to be at odds with each other. The requirements may
need to be re-written so that they are in sync.
Response: The RCSDT thanks you for your comment. The RCSDT has made revisions to COM-001 and COM-002 such that the applicability is compatible.
Pepco Holdings Inc
Yes
American Transmission
Company
Yes
ATC agrees with the understanding that the line of demarcation is up to the point where ATC owns the
equipment.
Response: The RCSDT thanks you for your comment.
WECC
Yes
BGE
Yes
Constellation Energy
Commodities Group
Yes
July 14, 2011
BGE has no additional comments.
33
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Duke Energy
No
Question 1 Comment
o We question how far the definition of Alternative Interpersonal Communication goes in requiring separate
infrastructure from Interpersonal Communication. For example, wireless communications sometime utilize
fiber optic networks.
Response: The definition requires the use of different infrastructure (medium) than the Interpersonal
Communication used for day to day ops. The RCSDT cannot be prescriptive regarding the specific medium
to be employed. This is intended to apply to assets and access to media that is within the control of the entity
responsible for complying with the Requirement. For example, the way cell phone signals are routed is not
within your control.
o We question why the requirements state that entities must “have” Interpersonal Communications capability,
but must “designate” Alternative Interpersonal Communications capability?
Response: Many entities have multiple Alternative Interpersonal Communication capabilities. Allowing them
to designate which one they want to employ allows for flexibility in which one they use for AIC.
o R1.2 and R2.2 - Why is this limited to the same interconnection?
Response: The phrase “within the same interconnection” is added for the case of ERCOT, which has only DC
tie lines with the Eastern Interconnection and has minimal interchange.
o R3 - need to add neighboring TOPs.
Response: Agreed.
o R5 - need to add adjacent BAs.
Response: Agreed.
o Interchange Coordinator - Add IC to the Applicability Section, and add a requirement that the IC have
Interpersonal Communication capability with its BA and adjacent BAs.
Response: The RCSDT has eliminated the Interchange Coordinator from COM-001-2 based on other
stakeholder comments..
o Requirements to “designate” Alternative Interpersonal Communication should carry a “Medium” VRF
instead of “High”, because they are a backup capability. The word “designate” carries the connotation that
these are documentation requirements.
Response: The requirement to designate is for the entity to have an Alternative Interpersonal
Communications capability and to designate what that is. In many cases, an entity will have multiple
July 14, 2011
34
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
alternatives and neighboring entities need to know how to contact them in case of a failure of the primary. If
an entity does not designate its AIC, in an emergency it may not be able to issue or comply with directions or
instructions which could directly contribute to BES instability, separation, or cascading failure.” The VRF
should remain as high.
o R9 requires a monthly test of Alternative Interpersonal Communications capability. This was quarterly in the
last draft. We question how these requirements for “Alternative Interpersonal Communications” capability are
related to requirements for “backup functionality” in EOP-008-1, which requires an annual test of backup
functionality. Clarity on the relationship between “Interpersonal Communications”, “Alternative Interpersonal
Communications”, “primary control center functionality” and “backup control center functionality” would be
appreciated.
Response: Interpersonal Communication and Alternative Interpersonal Communication should be in both the
primary and back up control center. IC and AIC are between entities as well. These capabilities are in the
primary and back up control centers. The requirement applies to the primary control center. EOP-008
applies to the back up control center. An entity may test its AIC in the normal course of daily activities.
o R11 - is this requirement being moved to COM-003?
Response: The OPCP SDT is vetting this requirement and it will be in COM-003.
o Data Retention - Is data retention really going to be just 12 months? Most auditors seem to be asking for
everything since the last audit.
Response: The Data Retention section of the standard conforms to the NERC guidelines. The RCSDT has
also added the following to the data retention section:
The following evidence retention periods identify the period of time an entity is required to retain
specific evidence to demonstrate compliance. For instances where the evidence retention period
specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may
ask an entity to provide other evidence to show that it was compliant for the full time period since the
last audit.
Response: The RCSDT thanks you for your comment. Please see responses above.
CECD
No
July 14, 2011
Based on the drafting teams response that the definition of Interpersonal" clarifies the exclusion of media
dedicated to Telemetering or other data exchange, the term Interpersonal Communication should be replaced
with verbal communication capabilities. The term Alternative Interpersonal Communication should be
replaced with alternative verbal communication capability that is able to serve as a substitute for and does not
35
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
utilize the same infrastructure (medium) as verbal communications capabilities used for day-to-day
operations.
Response: The RCSDT thanks you for your comment. The RCSDT wrote the definitions to include verbal as well as written communication, and the Measures
provide examples of person to person communications.
Indeck Energy Services
No
City of Springfield, IL - City Water
Light and Power (CWLP)
No
The definition of “Interpersonal Communications” is overly broad and does not address the functional needs
of reliability coordination. The definition should be limited to systems utilized for essential reliability functions.
While the Purpose statement in the standard does address this intent, the explicit inclusion in the definition
removes all ambiguity. Further, the definition of “Alternative Interpersonal Communications” without
corresponding explicit definition of Primary Interpersonal Communications may lead to confusion and
unnecessary duplication of efforts in testing and maintenance.
Response: The RCSDT thanks you for your comment. The overall mission of reliability standards is for entities to address essential reliability functions.
Independent Electricity System
Operator
No
(1) NERC filed with FERC on August 10, 2009 indicating that it would discontinue the use of subrequirements in standards. All draft standards posted since have the format of Part Numbers within each main
Requirement. Please revise the standards in this project accordingly.
Response: The RCSDT agrees and this revision will be made.
(2) Having defined the terms Interpersonal Communication and Alternative Interpersonal Communication, the
phrase “to exchange Interconnection and operating information” in a number of requirements is redundant
and can be removed. Further, for R1, we suggest removing the phrase “within the same Interconnection since
there RCs between two Interconnections still need to communication with each other for reliability
coordination (e.g. curtailment of interchange transactions crossing Interconnection boundary, as stipulated in
IRO-006).
Response: The RCSDT agrees and have removed the phrase “to exchange Interconnection and operating
information” from R1-R8. This helps clarify the intent that the capability is NOT for data exchange, as data is
covered under the provisions of the recently approved IRO-010-1a.
The phrase “within the same interconnection” is added for the case of ERCOT which has only DC tie lines
with the Eastern Interconnection and has minimal interchange.
(3) R2: Suggest to add Purchasing-Selling Entity and Interchange Authority (INT-004 and INT-005 have
requirements for communication between the RC and the PSE and IA), and remove the phrase “within the
July 14, 2011
36
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
same Interconnection since there RCs between two Interconnections still need to communication with each
other for reliability coordination (e.g. curtailment of interchange transactions crossing Interconnection
boundary, as stipulated in IRO-006).
Response: The applicability of COM-001 and COM-002 were revised to include the same reliability entities:
RC, TOP, BA, DP and GOP. LSE, PSE and TSP were removed from the applicability of these standards per
stakeholder suggestion.
The phrase “within the same interconnection” is added for the case of ERCOT which has only DC tie lines
with the Eastern Interconnection and has minimal interchange.
(4) R3: Suggest to add adjacent Transmission Operator and Purchasing-Selling Entity (the latter needed for
meeting INT-004 requirements).
Response: The SDT has included the following Part 3.5 of Requirement R3:
3.5 Adjacent Transmission Operators synchronously connected within the same Interconnection
The applicability of COM-001 and COM-002 were revised to include the same reliability entities: RC, TOP,
BA, DP and GOP. LSE, PSE and TSP were removed from the applicability of these standards per
stakeholder suggestion.
(5) The list of entities in R4 and R6 is different from those in R3 and R5. They should be the same for having
Alternative Interpersonal Communication capability.
Response: The RCSDT asserts the standard meets FERC Order 693 regarding DP and GOP entities by
requiring these entities to have Interpersonal Communication capability. Additionally requiring DP and GOP
entities to have Alternative Interpersonal Communication capability only imposes more cost on smaller DP
and GOP entities that have little or no risk impact to the bulk electric system.
(6) R5: Suggest to add adjacent Balancing Authority as adjoining BAs need to communication with each to
check schedules and other balancing information.
Response: The SDT has included the following Part 5.6 of Requirement R5:
5.6 Adjacent Balancing Authorities
Note that this is a defined term in the glossary: “A Balancing Authority Area that is interconnected (to)
another Balancing Authority Area either directly or via a multi-party agreement or transmission tariff.”
(7) There are a number of parts in Requirements R1 to R8 each of which must be complied with. However,
the VSLs for R1 to R8 are binary which do not provide any distinction in partial failure of each of these
requirements. We suggest the SDT to apply the VSL guideline and re-establish the various levels of violation
July 14, 2011
37
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 1 Comment
severity for these requirements.
Response: Each entity listed in Requirements R1-R8 is required to meet the contents with respect to each
other entity listed in the requirement. Failure to have the capability with a single entity is a single violation of
the requirement. For example, if an RC has 5 BA’s within it Area and fails to have Interpersonal
Communications with two of them, then the RC has violated the requirement twice. The VSLs are written to
address each violation of the Requirement. We have removed the words “or more” from the VSLs.
Response: The RCSDT thanks you for your comment. Please see responses above.
Bonneville Power Administration
Yes
Xcel Energy
No
We feel that either the definitions, or the requirements, should make it clear whether data is included.
Response: The RCSDT thanks you for your comment. The SDT has made modifications to attempt to make this as clear as possible.
July 14, 2011
38
Consideration of Comments on Reliability Coordination — Project 2006-06
2. The RCSDT believes that the requirements of TOP-001-1 obviate the need to develop additional requirements to
address Xcel’s comment. Do you agree? If not, please explain in the comment area below.
Summary Consideration:
The original justification that the RCSDT posited for not adding a requirement to directly address Xcel Energy’s comments in paragraph 516 and
FERC’s related recommendation in paragraph 523 was that TOP-001-1 R3 was considered to address this concern. Since that time, the RTO
SDT has proposed to retire TOP-001-1 R3. However, FERC has since retired IRO-004-1 R3 and R5 along with IRO-005-3 R5. Because these
are retired, there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP
that the TOP considered “would violate safety, equipment, regulatory, or statutory requirements,” the TOP may respond to the RC that it cannot
comply.
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 2 Comment
If the requirement were going to remain, but the Project 2007-03 Real-Time Operations SDT proposed to
retire that requirement during their last posting. There needs to be better coordination with that SDT.
Response: The RCSDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
Bonneville Power Administration
Yes
PPL
Yes
Dominion
Yes
SERC OC Standards Review
Group
No
Top-001-1, Requirement R3, which is what the SDT appears to be using as its justification for not adding a
requirement here is proposed to be deleted by the RTO-SDT on Project 2007-03.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
July 14, 2011
39
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
IRC Standards Review
Committee
Yes or No
Question 2 Comment
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed
to retire that requirement during their last posting. We believe there needs to be better coordination with that
SDT.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
MRO's NERC Standards Review
Subcommittee
No
A. Agree that a receiving entity should not be held accountable until such time that they are required to take
such action.
B. It might if the requirement were going to remain but the Project 2007-03 (“Real-Time Operations SDT”)
proposed to retire that requirement during their last posting. This needs to be coordinated with that SDT.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
FirstEnergy
Yes
Midwest ISO Standards
Collaborators
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed
to retire that requirement during their last posting. This needs to be coordinated with that SDT.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
SPP Standards Development
Yes
In fact, we believe that R1, R2 and R5 more specifically put that requirement on the TOP. The TOP doesn’t
have to wait for the RC and any directive that may be associated with R3 prior to taking action to mitigate an
emergency condition.
Response: The SDT thanks you for your comment.
July 14, 2011
40
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Kansas City Power & Light
Yes
Exelon
Yes
PacifiCorp
Yes
Arizona Public Service Company
Yes
Southern Company
No
Question 2 Comment
Comments: I see no connection between XCELs comment on COM-001-1. The requirements of COM-001-1
require the RCs, TOPs, and BAs to have a primary interpersonal communications method and to designate
an alternative. I believe that if the requirements for the entity to have both primary and alternative methods of
interpersonal communications this objection could be cleared. For example, R2 Each Reliability Coordinator
shall designate have an Alternative Interpersonal Communications capability with the following entities to
exchange Interconnection and operating information
Response: Thank you for your comment. We agree that there is no connection between Xcel’s concern and COM-001-1.
Green Country Energy, Green
Country Operating Services
No Comment
Manitoba Hydro
Yes
NextEra Energy, Inc.
No
As stated in response to number 1, Reliability Standards are to be clear and complete. If a Transmission
Operator is not responsible for a delay caused by a Reliability Coordinator, the Standard should specifically
state that the Transmission Operator does not need to wait for an assessment or approval of a Reliability
Coordinator to take actions pursuant to TOP-001-1 R3. Since the Reliability Coordinator is atop the reliability
hierarchy, such a statement provides clarity and completeness to understanding a Transmission Operators
rights. Thus, TOP-001-1 R3 should be revised to lead with: “Without any obligation to first seek and obtain
an assessment or approval from its Reliability Coordinator, each Transmission Operator . . . .”
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
July 14, 2011
41
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
United Illuminating Company
Yes
American Electric Power
Yes
Pepco Holdings Inc
Yes
American Transmission
Company
Yes
ISO New England
No
Question 2 Comment
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed
to retire that requirement during their last posting. We believe there needs to be better coordination with that
SDT.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
ERCOT ISO
No
It might if the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed
to retire that requirement during their last posting. We believe there needs to be better coordination with that
SDT.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
WECC
Yes
BGE
Yes
BGE has no additional comments.
Response: Thank you for your comment.
Constellation Energy
Commodities Group
July 14, 2011
Yes
42
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Duke Energy
No
Question 2 Comment
Requirements of TOP-001-1 are being revised under Project 2007-03, which may not continue to adequately
address Xcel’s concern.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
Indeck Energy Services
Yes
City of Springfield, IL - City Water
Light and Power (CWLP)
No
TOP-001 is in the process of being substantially modified by Project 2007-03. These changes may conflict
with the matter addressed by Xcel’s comment. Thus, Xcel’s concern should be addressed independently but
in the context of the TOP-001-2 revisions proposed by Project 2007-03.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
South Carolina Electric and Gas
No
Top-001-1, Requirement R3, which is what the SDT appears to be using as its justification for not adding a
requirement here is proposed to be deleted by the RTO-SDT on Project 2007-03.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
Independent Electricity System
Operator
No
TOP-001 is being revised and some of the requirements that fulfill this need may have been removed. We
suggest the SDT check with the latest draft version of TOP-001 and coordinate with the Real-time Operation
SDT to ensure there are not gaps.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
July 14, 2011
43
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Xcel Energy
Yes or No
Question 2 Comment
No
We are concerned that the drafting team may not have understood Xcel Energy’s comments and FERC’s
directive in Order 693. FERC had asked that NERC consider Xcel Energy’s suggestion. This consideration
does not necessarily equate to the development of additional requirements, however that may be the solution.
We recognize that R1 and R2 of TOP-001-1 give the TOP authority to take immediate actions necessary to
alleviate operating emergencies. We were concerned with the potential situation where the RC’s directive
(R3 of IRO-001-2) may conflict with actions the TOP has ALREADY taken. In this situation, we do not feel the
TOP should be held at fault for the actions it took prior to the RC's directive. (R3 of IRO-001-2 is currently in
effect under TOP-001-1 R3.) Additionally, R1 and R2 of TOP-001-1 have been removed from the latest draft
of version 2. So, if TOP-001-2 and IRO-001-2 are approved as drafted, it would appear that all rights and
protections of the TOP to take immediate actions will be removed and our initial issue, as detailed in Order
693, still exists.
Response: The SDT thanks you for your comment. The RTO SDT proposes to retire TOP-001-1 R3. However, since NERC has retired IRO-004-1 R3 and R5
along with IRO-005-3 R5 , there are no longer any requirements that would force a TOP to wait for a delayed RC response during an emergency, therefore the
question is resolved, albeit differently than it was proposed to be resolved in this posting. If an RC were to give a Reliability Directive to a TOP that the TOP
considered “would violate safety, equipment, regulatory, or statutory requirement,” the TOP may respond to the RC that it cannot comply.
The SDT appreciates this clarification by Xcel Energy. At any time in the future, Reliability Directives may be received that, based on the best available
information at the time, change or reverse operating actions taken in the past, even the immediate past. The TOP is not held at fault for past actions that it took to
protect the BES by any current or proposed NERC requirements. As written in TOP-001-2 R1, R3 and R4 as proposed by the RTO SDT, the TOP is not
prevented from acting or telling the RC that for specific safety, equipment, regulatory or statutory reasons, it cannot comply.
July 14, 2011
44
Consideration of Comments on Reliability Coordination — Project 2006-06
3. Do you agree with the revision to IRO-001, R1 for certifying Reliability Coordinators? If not, please explain in
the comment area below.
Summary Consideration: Stakeholders were asked if they agree with the revision to IRO-001, R1 for certifying Reliability Coordinators. Many
commenters suggested removing the requirement because it is addressed in the NERC Rules of Procedure. The RCSDT concurs and has
removed R1 from IRO-001-2.
Organization
ERCOT ISO
Yes or No
No
Question 3 Comment
The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect what the enforceability of the standards are meant to be.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES is covered under a Reliability Coordinator.
In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
ISO New England
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect what the enforceability of the standards are meant to be.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES is covered under a Reliability Coordinator.
In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
IRC Standards Review
Committee
No
The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect what the enforceability of the standards are meant to be.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES is covered under a Reliability Coordinator.
In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
July 14, 2011
45
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 3 Comment
The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect what the enforceability of the standards are meant to be.
Response: Many commenters suggested removing the requirement because it is addressed in the NERC
Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES are covered under a Reliability Coordinator.
Response: R1 has been removed from the standard based on stakeholder comments.
In R2, should “of” be “to”? Reliability Directives are issued to TOPs, BA, etc.
Response: The requirement was rewritten for clarity as follows:
R2. Each Reliability Coordinator shall take actions or direct actions (which could include issuing
Reliability Directives) by Transmission Operators, Balancing Authorities, Generator Operators, and
Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the
magnitude or duration of actual events that result in Adverse Reliability Impacts.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
Response: R1 has been removed from the standard based on stakeholder comments.
Response: The RCSDT thanks you for your comment.
Bonneville Power Administration
Yes
PPL
Yes
SERC OC Standards Review
Group
No
We think you are attempting to create a requirement similar to BAL-005, R1. That language copied here is
clear and concise - All generation, transmission, and load operating within an Interconnection must be
included within the metered boundaries of a Balancing Authority Area.
Response: The RCSDT thanks you for your comment. Many commenters suggested removing the requirement because it is addressed in the NERC Rules of
Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
MRO's NERC Standards Review
July 14, 2011
No
A. R1, As written it is unclear what level of certification this will entail? Presently written within the NERC
Reliability Standards, responsibility is given to RC’s to manage the reliability of their areas. Recommend
46
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
Subcommittee
deleting this requirement. The ERO has pushed back in other Standards to having a responsibility for any
NERC Requirements, since they are not a user, owner, or operator of the BES (see EOP-004-2).
Response: Many commenters also suggested removing the requirement because it is addressed in the
NERC Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
If this does move forward and an RC is certified by the ERO and then the RC is found non-compliant by a
Regional Entity, for an associated certified item, will the ERO be held responsible, too?
Response: The RCSDT has removed R1 from IRO-001-2.
If the SDT selects to keep R1, there are some issues with how the requirement is written. The
requirement places emphasis on regions and regional boundaries when no emphasis should be placed
there. There are multiple Reliability Coordinators the span multiple regions.
Response: The RCSDT has removed R1 from IRO-001-2.
The language “to continuously assess transmission reliability” should be changed to “to continuously
assess Bulk Electric System reliability” to reflect on what the standards are enforceable.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES is covered under a Reliability Coordinator.
B. In R2, should “of” be “to”. Reliability Directives are issued to TOPs, BA, etc.
C. The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
Response: Please see the response to the comments from NPCC above on these same topics..
Response: The RCSDT thanks you for your comment.
FirstEnergy
Yes
Midwest ISO Standards
Collaborators
No
In general, we are not opposed to the concept of the ERO certifying the Reliability Coordinators; however,
there are some issues with how the requirement is written.
Response: Thank you.
The requirement places emphasis on regions and regional boundaries when no emphasis should be placed
July 14, 2011
47
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
there. There are multiple Reliability Coordinators that span multiple regions.
Response: Many commenters suggested removing the requirement because it is addressed in the NERC
Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
The language “to continuously assess transmission reliability” should be changed to “to continuously assess
Bulk Electric System reliability” to reflect on what the standards are enforceable.
The requirement on the ERO should also be expanded similar to BAL-005-0.1b R1 to ensure that all
operating entities and the entire BES is covered under a Reliability Coordinator Area.
In R2, should “of” be “to”. Reliability Directives are issued to TOPs, BA, etc.
The VSL for R1 is not consistent with the requirement. The requirement applies to the ERO but the VSL
applies to the Regional Entity.
Response: Please see the response to the comments from NPCC above on these same topics..
Response: The RCSDT thanks you for your comment.
SPP Standards Development
No
Is this more of a registry question than a standards issue? While we agree that there needs to be a
requirement somewhere that establishes the need for Reliability Coordinators, isn’t there also a similar need
for other functional entities such as Transmission Operators, Balancing Authorities, etc? Should these be
captured in standards or in the certification/registration process?
Response: The RCSDT thanks you for your comment. Many commenters suggested removing the requirement because it is addressed in the NERC Rules of
Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Kansas City Power & Light
Yes
Exelon
No comment - only applicable to RC
PacifiCorp
Yes
Southern Company
No
July 14, 2011
Comments: This would allow NERC to designate one entity to be the Reliability Coordinator for an entire
interconnection or the entire continent. This would reduce the Regional Reliability Organizations to
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
compliance entities.
Response: The RCSDT thanks you for your comment. Many commenters suggested removing the requirement because it is addressed in the NERC Rules of
Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Green Country Energy, Green
Country Operating Services
No Comment
Manitoba Hydro
Yes
United Illuminating Company
Yes
American Electric Power
No
This is out of scope with the standard, as it is currently addressed through the NERC certification process that
the NERC reliability coordinators are subject to.
Response: The RCSDT thanks you for your comment. Many commenters suggested removing the requirement because it is addressed in the NERC Rules of
Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Pepco Holdings Inc
Yes
American Transmission
Company
Yes
WECC
Yes
BGE
Yes
Constellation Energy
Commodities Group
Yes
Duke Energy
No
BGE has no additional comments.
How is NERC going to certify the RCs?
Response: R1 is a revision of an existing requirement in IRO-001-1.1. Many commenters suggested
removing the requirement because it is addressed in the NERC Rules of Procedure. The RCSDT concurs
and has removed R1 from IRO-001-2. The NERC Rules of Procedure define the certification process and the
level of certification.
July 14, 2011
49
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 3 Comment
Also, we believe the word “all” should be inserted after the word “among”, so that it is clear that all generation,
transmission and load must be included.
Response: Many commenters suggested removing the requirement because it is addressed in the NERC
Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Response: The RCSDT thanks you for your comment.
CECD
Yes
Indeck Energy Services
No
City of Springfield, IL - City Water
Light and Power (CWLP)
Yes
South Carolina Electric and Gas
No
We think you are attempting to create a requirement similar to BAL-005, R1. That language copied here is
clear and concise - All generation, transmission, and load operating within an Interconnection must be
included within the metered boundaries of a Balancing Authority Area.
Response: The RCSDT thanks you for your comment. Many commenters suggested removing the requirement because it is addressed in the NERC Rules of
Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Independent Electricity System
Operator
No
1. R2: The word “of” before Transmission Operators should be “to”.
Response: The requirement was rewritten for clarity as follows:
R2. Each Reliability Coordinator shall take actions or direct actions (which could include issuing
Reliability Directives) by Transmission Operators, Balancing Authorities, Generator Operators, and
Distribution Providers within its Reliability Coordinator Area to prevent identified events or mitigate the
magnitude or duration of actual events that result in Adverse Reliability Impacts.
2. The VSL for R1 should be revised to replace Regional Entities with ERO.
Response: Many commenters suggested removing the requirement because it is addressed in the
NERC Rules of Procedure. The RCSDT concurs and has removed R1 from IRO-001-2.
Response: The RCSDT thanks you for your comment.
July 14, 2011
50
Consideration of Comments on Reliability Coordination — Project 2006-06
4.
July 14, 2011
51
Consideration of Comments on Reliability Coordination — Project 2006-06
Do you agree with moving two requirements from IRO-001 back to IRO-002 relating to Analysis Tool outages? If not, please explain
in the comment area below.
Summary Consideration: There were no comments on this question. The SDT thanks you for your consideration of and agreement with this
position.
Organization
Yes or No
Northeast Power Coordinating
Council
Yes
Bonneville Power Administration
Yes
PPL
Yes
SERC OC Standards Review
Group
Yes
IRC Standards Review
Committee
Yes
MRO's NERC Standards Review
Subcommittee
Yes
FirstEnergy
Yes
Midwest ISO Standards
Collaborators
Yes
SPP Standards Development
Yes
Kansas City Power & Light
Yes
Exelon
Question 4 Comment
Comments: No comment - only applicable to RC
PacifiCorp
July 14, 2011
Yes
52
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Arizona Public Service Company
Yes
Southern Company
Yes
Green Country Energy, Green
Country Operating Services
No Comment
Manitoba Hydro
Yes
United Illuminating Company
Yes
Pepco Holdings Inc
Yes
American Transmission
Company
Yes
ISO New England
Yes
ERCOT ISO
Yes
WECC
Yes
BGE
Yes
Constellation Energy
Commodities Group
Yes
Duke Energy
Yes
CECD
Yes
Indeck Energy Services
Yes
South Carolina Electric and Gas
Yes
July 14, 2011
Question 4 Comment
BGE has no additional comments.
53
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Independent Electricity System
Operator
July 14, 2011
Yes or No
Question 4 Comment
Yes
54
Consideration of Comments on Reliability Coordination — Project 2006-06
5. Do you agree with moving two requirements from IRO-001 back to IRO-005 relating to Reliability Coordinator
notifications? If not, please explain in the comment area below.
Summary Consideration: Commenters noted a typographical error in R1 which was corrected to read
R1. When the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or actual condition with Adverse
Reliability Impacts within its Reliability Coordinator Area, each Reliability Coordinator shall notify issue an alert to all impacted
Transmission Operators and Balancing Authorities in its Reliability Coordinator Area. [Violation Risk Factor: High] [Time Horizon: Realtime Operations, Same Day Operations and Operations Planning]”
One commenter also asked that an errant yellow text box be removed from Page 1, which was also done.
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 5 Comment
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an
expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each
Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing
Authorities in its Reliability Coordinator Area.” The word “notify” should be struck.
Response: The SDT thanks you for your comment and will correct this typographical error to remove the words “issue an alert.”
Bonneville Power Administration
Yes
PPL
Yes
SERC OC Standards Review
Group
Yes
Please remove the yellow box on page 1 indicating this standard will be retired.
Response: The SDT thanks you for your comment and will remove the yellow box on page 1.
IRC Standards Review
Committee
Yes
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an
expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each
Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing
Authorities in its Reliability Coordinator Area.” The word “notify” should be struck.
Response: The SDT thanks you for your comment and will correct this typographical error to remove the words “issue an alert.”
July 14, 2011
55
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
MRO's NERC Standards Review
Subcommittee
Yes
FirstEnergy
Yes
Midwest ISO Standards
Collaborators
Yes
SPP Standards Development
Yes
Kansas City Power & Light
Yes
Exelon
Question 5 Comment
Comments: No comment - only applicable to RC
PacifiCorp
Yes
Arizona Public Service Company
Yes
Southern Company
Yes
Green Country Energy, Green
Country Operating Services
No Comment
Manitoba Hydro
Yes
United Illuminating Company
Yes
Pepco Holdings Inc
Yes
American Transmission
Company
Yes
ISO New England
Yes
July 14, 2011
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an
expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each
Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing
56
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 5 Comment
Authorities in its Reliability Coordinator Area.” The word “notify” should be struck.
Response: The SDT thanks you for your comment and will correct this typographical error to remove the words “issue an alert.”
ERCOT ISO
Yes
R1 states “When the results of an Operational Planning Analysis or Real-time Assessment indicate an
expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area, each
Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing
Authorities in its Reliability Coordinator Area.” The word “notify” should be struck.
Response: The SDT thanks you for your comment and will correct this typographical error to remove the words “issue an alert.”
WECC
Yes
BGE
Yes
Constellation Energy
Commodities Group
Yes
Duke Energy
Yes
CECD
Yes
Indeck Energy Services
Yes
South Carolina Electric and Gas
Yes
Independent Electricity System
Operator
Yes
July 14, 2011
BGE has no additional comments.
57
Consideration of Comments on Reliability Coordination — Project 2006-06
6. Do you have any other comment, not expressed in questions above, for the RC SDT?
Summary Consideration:
The RCSDT received comments suggesting clarification of COM-002-3. The RCSDT intends the communication of Reliability Directives to be
person-to-person and in such a manner that the Reliability Directive is understood and not necessarily repeated verbatim. COM-002-3 is not
intended to be prescriptive on how the Reliability Directive is issued. Spoken or written communications are valid methods (i.e. using the
telephone, radio, electronic texting, email, etc.). The purpose of COM-002-3 is to ensure emergency communications between operating
personnel are effective. There is no proxy requirement for 24/7 operating personnel regarding small entities. Only “capability” as provided for in
COM-001-2 is applicable. The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient and effective. The
RCSDT believes Reliability Directives issued in mass should be defined by procedure, and that the procedure would establish a method of
affirmation and notice of implementation. As envisioned, communications protocols would be addressed in the COM-003 standard being
developed in Project 2007-02.
Some commenters suggested revisions to IRO-014, requirement R8 to conform to similar requirements R6 and R7. The RCSDT made the
suggested revision by re-ordering R8:
R8. During those instances where Reliability Coordinators disagree on the existence of an Adverse Reliability Impact, each Reliability
Coordinator shall implement the action plan developed by the Reliability Coordinator that identified the Adverse Reliability Impact unless
such actions would violate safety, equipment, regulatory or statutory requirements. [Violation Risk Factor: High][Time Horizon: Operations
Planning, Same Day Operations and Real-time Operations]
IRO-014-2, requirement R4 is applicable to those Reliability Coordinators engaged in activities related to requirement R1 and part 1.7, it is
unlikely that Reliability Coordinators geographically and electrically distant from one another will have mutually agreed upon operating procedures
(per requirement R1), and therefore requirement R4 would not be applicable. The RCSDT believes IRO-014-2, requirement R4 which requires
weekly communication provides reasonable contact and flexibility – and this requirement is in effect today. The RCSDT coordinated the use of the
NERC Glossary term “Adverse Reliability Impact” with the Real-Time Operations team and continues the practice of informing all RCs of Adverse
Reliability Impacts in requirement R5. The RCSDT has revised IRO-014-2, requirements R6-R8 to clarify that when one RC identified a problem
and presents an action plan for another RC, the second RC is obligated to implement the action plan. The RCSDT will forward the concern about
RC's identifying themselves and the receiver to establish authority to the Project 2007-02, Operating Personnel Communications Protocols SDT.
The Project 2007-02 team is developing a standard that includes requirements for use of specific communications protocols.
Organization
Northeast Power Coordinating
July 14, 2011
Yes or No
Question 6 Comment
The SDT did not address all concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
58
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Council
Yes or No
Question 6 Comment
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving as the Transmission Operator or Balancing Authority. It should never be necessary for
these System Operators to issue Reliability Directives to themselves in the first example or to their co-worker
in the second example to demonstrate compliance to NERC standards. How the entity coordinates its actions
among its Reliability Coordinator, Balancing Authority and Transmission Operator roles is a corporate
governance issue that should not be confused or complicated by the NERC standards. Thus, standards
should be made clear that the Reliability Directive is directed to another company. In place of requiring an
operator, in real-time, to state “this is a Reliability Directive,” there should be an allowance for an entity to
develop procedures indicating, in advance, their expectations for three-part communications to their suboperating entities.
Therefore, we suggest modifying R1 to be
“When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be
executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority
shall identify the action, either verbally, when the communication is issued, or in advance through
documented procedures, as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
Real-Time.]”
Response: COM-002 does not preclude text or other forms of communication for issuing Reliability
Directives. However, entities still must comply with the requirements of COM-002. Further, the RCSDT
believes it to be equally imperative that each NERC registered function hold the authority to issue Reliability
Directives, and the ability to receive Reliability Directives, whether those Reliability Directives are issued to
subordinate registered functions within a vertically integrated utility, or to registered entities that are
corporately separate. The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Face-to-face communication of Reliability Directives are subject to the requirements of COM002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support
compliance”.
The use of operator logs to memorialize and provide evidence of compliance is directly specific to those
Reliability Directives issued and received within the same control room or operations center. The RCSDT
believes that any Registered Entity or person operating as such must understand the intent of the issued
Reliability Directive, and that the issuer of the Reliability Directive believe that the Reliability Directive was
correctly received. COM-002 should not be construed to mean that an individual serving in two functions be
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
required to issue a Reliability Directive to himself, but rather it is expected that such an individual would
appropriately address the reliability issues as required by the function they are serving and its subsequent
responsibilities.
Also, the definition of Emergency as currently cited in these draft Standards and included in the existing
NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to make
the Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time Operations SDT
proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the
change to the definition should be coordinated with that team.
Response: With respect to the suggestion of modifying the definition of Emergency. The RCSDT believes
that the term Emergency relates to the actual state of the system, including local and wide area, while an
Adverse Reliability Impact is the impact resulting from an event resulting in instability or cascading that affects
a widespread area of an Interconnection. There could be an Emergency that is local, or that threatens
equipment but which does not necessarily result in cascading or instability; it is in this regard that the RCSDT
believes that the definition of Emergency should not be dependent upon or pertain only to Adverse Reliability
Impact events. The RCSDT coordinated the use of Adverse Reliability Impacts with the Real-Time
Operations team.
There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain
requirements in the standard and various other associated documentation that indicates requirements are
being move to this standard. Delete the text box.
Response: We have deleted the text box.
Strike IRO-014-2 Part 1.7. There is no need to have a weekly conference to discuss every Operating
Procedure, Operating Process and Operating Plan. As this requirement is written, a conference call would be
necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have weekly conference
calls that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures, Processes and
Plans likely will not need to be discussed weekly as it only requires an annual update.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific activities with other
impacted Reliability Coordinators. These activities are listed as sub requirements. R1.7 requires you to have
a procedure relating to weekly conference calls while R4 requires participation in weekly calls. Further, the
RCSDT believes that it is prudent that Reliability Coordinators talk at least once a week to verify viability of
mutual plans, procedures or processes.
With respect to the relation of IRO-14-2 R1.7 and R4. R1.7 is requires you to have a procedure relating to
July 14, 2011
60
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
weekly conference calls while R4 requires participation in weekly calls.
Requirement R2 in IRO-001 contains the words “which could include issuing Reliability Directives”, but
Reliability Directives are not referenced anywhere else in the standard. This inclusion seems unnecessary
since without it, R2 already requires that the RC take actions or direct actions by others to prevent identified
events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts.
Whether or not a Reliability Directive is issued is irrelevant in this requirement. These words should be
removed. Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability
Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is
unnecessary.
Response: R2 requires the Reliability Coordinator to act. These actions could include Reliability Directives in
the case of an Emergency; however, issuing Reliability Directives might not always be necessary, as the
Reliability Coordinator may be acting proactively well in advance of an emergency. R2 promotes this
proactive approach, but reserves the use of Reliability Directives for circumstances that require its use.
Response: The RCSDT thanks you for your comments.
PPL
We are providing the following comments for the Standards Drafting Team to consider.
1) Consider changing R1 to ‘Each RC shall have the capability for Interpersonal Communications with the
following entities to exchange Interconnection and operating information...’ for clarity as Interpersonal
Communications and capability are both nouns.
Response: Thank you for your suggestion to modify the sentence structure into a noun phrase, however the
RCSDT believes the current form is unambiguous.
2) We feel changing the applicability of the standard is important to the accuracy of the standard. The
purpose of COM-002 is ‘To ensure emergency communications between operating personnel are effective’.
Since operating personnel are covered by the applicability of RC, BA, TOP and GOP, we suggest the
applicability to TSP, LSE, and PSE be removed from COM-002-3.
Response: We agree and have removed those entities
3) Additionally, we would like to bring to the attention of the Standards Drafting Team, that the
implementation plan for COM-001-2 and IRO-001-2 still includes TSP, LSE, and PSE although the revised
standard does not include these entities in the Applicability Section. For COM-001-2 refer to the
implementation plan, page 1. For IRO-001-2 refer to the implementation plan for new R2, new R3, new R4
July 14, 2011
61
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
and the chart on the last page. Thank you for your consideration in addressing these comments.
Response: The RCSDT has revised the applicability of COM-001, COM-002 and IRO-001 to align with each
other. TSP, LSE and PSE are no longer in either standard.
Response: The RCSDT thanks you for your comments.
PSEG
IRO COM-002-3 standard continues to include PSE. PSE’s do not play an active role and have no authority
or ability to perform reliability coordination. PSE’s should be removed from the standard.-001-2 references
PSE’s in the implementation for R2, R3, R4 and “Functions that must comply with the requirements in this
standard” table. PSE’s were removed from the standard and should be removed from the implementation
plan.
Response: The RCSDT thanks you for your comments. The RCSDT has revised the applicability of COM-001 and COM-002 to align with each other. TSP, LSE
and PSE are no longer in either standard.
Dominion
We do not agree with the addition of weekly conference calls as required in R4. We believe that RCs should
schedule calls as needed but do not agree that a weekly scheduled call improves reliability.
Response: The RCSDT thanks you for your comments. The requirement for weekly conference calls exists in IRO-015-1.
requirement and incorporated it into proposed IRO-014-2.
The RCSDT has revised the
R2. The Reliability Coordinator shall participate in agreed upon conference calls and other communication forums with adjacent Reliability Coordinators.
R2.1. The frequency of these conference calls shall be agreed upon by all involved Reliability Coordinators and shall be at least weekly.
SERC OC Standards Review
Group
Reliability Directives may be issued by blast calls from Reliability Coordinators. It is inefficient and may be a
hindrance to reliability to require 3-part communications in these instances.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient
and effective. However the essence of accurately implementing Reliability Directives is accomplished by use
of 3-part communications. The RCSDT believes Reliability Directives issued in mass should be defined by
procedure, and that the procedure would establish a method of affirmation and notice of implementation.
There are several organizations registered as BAs, RCs and TOPs. It is not uncommon for those entities to
be distributed across multiple desks in the same control room without regard to how an entity is registered.
July 14, 2011
62
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
Thus, a single System Operator may perform functions that are categorized under two or more of those
functional entities. The drafting team should clarify that under no circumstances should that System Operator
be required to issue a Reliability Directive to himself. This is a corporate governance issue.
Response: COM-002 does not preclude text or other forms of communication for issuing Reliability
Directives. However, entities still must comply with the requirements of COM-002. Further, the RCSDT
believes it to be equally imperative that each NERC registered function hold the authority to issue Reliability
Directives, and the ability to receive Reliability Directives, whether those Reliability Directives are issued to
subordinate registered functions within a vertically integrated utility, or to registered entities that are
corporately separate. The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Face-to-face communication of Reliability Directives are subject to the requirements of COM002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support
compliance”.
The use of operator logs to memorialize and provide evidence of compliance is directly specific to those
Reliability Directives issued and received within the same control room or operations center. The RCSDT
believes that any Registered Entity or person operating as such must understand the intent of the issued
Reliability Directive, and that the issuer of the Reliability Directive believe that the Reliability Directive was
correctly received. COM-002 should not be construed to mean that an individual serving in two functions be
required to issue a Reliability Directive to himself, but rather it is expected that such an individual would
appropriately address the reliability issues as required by the function they are serving and its subsequent
responsibilities.
In IRO-014, R1, delete sub-requirement 1.7. The requirement for weekly conference calls related to operating
procedures is duplicative to R4 and could be burdensome while adding very little value under certain
circumstances. In IRO-014, R4, delete the phrase “(per Requirement 1, Part 1.7)” as a conforming change.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific activities with other impacted
Reliability Coordinators. These activities are listed as sub requirements. R1.7 requires you to have a
procedure relating to weekly conference calls while R4 requires participation in weekly calls. Further, the
RCSDT believes that it is prudent that Reliability Coordinators talk at least once a week to verify viability of
mutual plans, procedures or processes.
In IRO-014, Requirements R6-R8 allow at least the theoretical possibility that an RC may determine an
Adverse Reliability Impact in another RC’s area that the other RC neither can see nor believes that any
July 14, 2011
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Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
action should be taken. R7 puts the burden on the first RC to develop a plan that it cannot implement
because it has no agreement with the BAs and TOPs in the other RC area. As such, this requirement is
unenforceable.
Response: Requirements R6-R8 are translated from IRO-016-1, Requirement R1. If an RC sees a problem
and another does not see the same problem, then there may be an issue with someone’s model or processes
or procedures. The RC’s are supposed to have coordinated Operating Plans, Processes or Procedures to
operate reliably. R6-R8 are only applicable if one of the two (or more) RCs do not see that a problem exists.
It would be a detriment to reliability for both RCs to take no action. RCs are required to coordinate actions
under existing IRO-016-1, R1. If one RC identifies a problem and provides an action plan to another RC to
mitigate the problem, the second RC is obligated under R8 to implement it. We have revised the R8 to clarify
this intent. R8. During those instances where Reliability Coordinators disagree on the existence of an
Adverse Reliability Impact , each Reliability Coordinator shall implement the action plan developed by the
Reliability Coordinator that identified the Adverse Reliability Impact unless such actions would violate safety,
equipment, regulatory or statutory requirements.
IRO-014-2, Revised R8. During those instances where Reliability Coordinators disagree on the existence of
an Adverse Reliability Impact, each Reliability Coordinator shall implement the action plan developed by the
Reliability Coordinator that identified the Adverse Reliability Impact unless such actions would violate safety,
equipment, regulatory or statutory requirements.
Please review all the implementation plans to be sure the applicable entities match those in the standards.
Response: These have been updated.
”The comments expressed herein represent a consensus of the views of the above named members of the
SERC OC Standards Review group only and should not be construed as the position of SERC Reliability
Corporation, its board or its officers.”
Response: The RCSDT thanks you for your comments.
IRC Standards Review
Committee
July 14, 2011
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving the as the Transmission Operator or Balancing Authority. We believe that it should never be
necessary for these System Operators to issue Reliability Directives to themselves in the first example or to
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their co-worker in the second example to demonstrate compliance to NERC standards. How the entity
coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles
is a corporate governance issue that should not be confused or complicated by the NERC standards. Thus,
we believe that standards should be made clear that the Reliability Directive is directed to another company.
Response: COM-002 does not preclude text or other forms of communication for issuing Reliability
Directives. However, entities still must comply with the requirements of COM-002. Further, the RCSDT
believes it to be equally imperative that each NERC registered function hold the authority to issue Reliability
Directives, and the ability to receive Reliability Directives, whether those Reliability Directives are issued to
subordinate registered functions within a vertically integrated utility, or to registered entities that are
corporately separate. The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Face-to-face communication of Reliability Directives are subject to the requirements of COM002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support
compliance”.
The use of operator logs to memorialize and provide evidence of compliance is directly specific to those
Reliability Directives issued and received within the same control room or operations center. The RCSDT
believes that any Registered Entity or person operating as such must understand the intent of the issued
Reliability Directive, and that the issuer of the Reliability Directive believe that the Reliability Directive was
correctly received. COM-002 should not be construed to mean that an individual serving in two functions be
required to issue a Reliability Directive to himself, but rather it is expected that such an individual would
appropriately address the reliability issues as required by the function they are serving and its subsequent
responsibilities.
We believe that, in place of requiring an operator, in real-time, to state “this is a Reliability Directive,” there
should be an allowance for an entity to develop procedures indicating, in advance, their expectations of threepart to their sub-operating entities. Therefore, we suggest modifying R1 to be
“When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be
executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority
shall identify the action, either verbally, when the communication is issued, or in advance through
documented procedures, as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
Real-Time.]”
Response: In regards to your suggested modification of R1 to include “or in advance through documented
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procedures”, the intent of R1 in its current form is to provide that ability, as such any documented procedure
would require stating such implemented action is considered a response to a Reliability Directive. And would
follow acknowledge and confirmation requirements.
Also, we believe that the definition of Emergency, as currently cited in these draft Standards and included in
the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability
Impact to make the Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time
Operations SDT proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the
last posting, the change to the definition should be coordinated with that team.
Response: The RCSDT believes that the term Emergency relates to the actual state of the system, including
local and wide area, while an Adverse Reliability Impact is the impact resulting from an event resulting in
instability or cascading that affects a widespread area of an Interconnection. There could be an Emergency
that is local, or that threatens equipment but which does not necessarily result in cascading or instability; it is
in this regard that the RCSDT believes that the definition of Emergency should not be dependent upon or
pertain only to Adverse Reliability Impact events. The RCSDT coordinated the use of Adverse Reliability
Impacts with the Real-Time Operations team.
There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain
requirements in the standard and various other associated documentation indicates requirements are being
move to this standard.
Response: The text box was removed.
Please delete the text box. IRO-014-2 R4 already includes a requirement to have weekly conference calls
that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures, Processes and
Plans likely will not need to be discussed weekly as it only requires an annual update.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific activities with other impacted
Reliability Coordinators, these activities are listed as sub requirements. Further the RCSDT believes that it is
prudent that Reliability Coordinators talk at least once a week to verify viability of mutual plans, procedures or
processes. The relation of IRO-14-2 R1.7 to R4 is that R1.7 requires having a conference call, R4 requires
participation by all impacted Reliability Coordinators, as such, neither replaces the other.
In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
reliability constraint or a declared Emergency”. The RCSDT believes that reliability constraint is ambiguous
and undefined, thus introducing confusion. Further modifying Reliability Directive by including “declared
Emergency” would add unnecessary step in mitigation of the Emergency
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Further, Requirement R2 in IRO-001 contains the words “which could include issuing Reliability Directives”
but Reliability Directives are not referenced anywhere else in the standard. This inclusion seems
unnecessary since without it, R2 already requires that the RC take actions or direct actions by others to
prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse
Reliability Impacts. Whether or not a Reliability Directive is issued is irrelevant in this requirement. We
suggest that these words be removed. Note that COM-002 already stipulates the requirement for 3-part
communication when a Reliability Directive is issued. The inclusion of “which could include issuing Reliability
Directives” in IRO-001 is unnecessary.
Response: R2 requires the Reliability Coordinator to act, these actions could in include Reliability Directives
in the case of an Emergency, however issuing Reliability Directives it might not always be necessary, as the
Reliability Coordinator may be acting pro-active well in advance of an emergency. R2 promotes this pro-active
approach, but reserves the use of Reliability Directives for circumstances that require its use.
Response: The RCSDT thanks you for your comments.
Midwest ISO Standards
Collaborators
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving the as the Transmission Operator or Balancing Authority. We believe that it should never be
necessary for these System Operators to issue Reliability Directives to themselves in the first example or to
their co-worker in the second example to demonstrate compliance to NERC standards. How the entity
coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles
is a corporate governance issue that should not be confused or complicated by the NERC standards. Thus,
we believe that standards should be made clear that the Reliability Directive is directed to another company.
Response: COM-002 does not preclude text or other forms of communication for issuing Reliability
Directives. However, entities still must comply with the requirements of COM-002. Further, the RCSDT
believes it to be equally imperative that each NERC registered function hold the authority to issue Reliability
Directives, and the ability to receive Reliability Directives, whether those Reliability Directives are issued to
subordinate registered functions within a vertically integrated utility, or to registered entities that are
corporately separate. The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Face-to-face communication of Reliability Directives are subject to the requirements of COM-
July 14, 2011
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Question 6 Comment
002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support
compliance”.
The use of operator logs to memorialize and provide evidence of compliance is directly specific to those
Reliability Directives issued and received within the same control room or operations center. The RCSDT
believes that any Registered Entity or person operating as such must understand the intent of the issued
Reliability Directive, and that the issuer of the Reliability Directive believe that the Reliability Directive was
correctly received. COM-002 should not be construed to mean that an individual serving in two functions be
required to issue a Reliability Directive to himself, but rather it is expected that such an individual would
appropriately address the reliability issues as required by the function they are serving and its subsequent
responsibilities.
We also are concerned about the need to conduct three-part communications for a Reliability Directive issued
through a blast call. Under these circumstances, the need for immediate action of multiple parties may
require a blast call and there may not be time for all parties to complete three-part communications before
initiating actions. Thus, we believe blast calls should be treated separately and that should be made clear.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient
and effective. However the essence of accurately implementing Reliability Directives is accomplished by use
of 3-part communications. The RCSDT believes Reliability Directives issued in mass should be defined by
procedure, and that the procedure would establish a method of affirmation and notice of implementation.
COM-002-3 R2 needs to be rewritten as it is too verbose. The point is for the recipient of the original
message to get the issuer to confirm that the message was understood. We suggest rewording R2 to “Each
Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient
of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the
Reliability Directive.” Once the receiver has completed this requirement, the ball is in the issuer’s court per
Requirement R3. No additional words are necessary in the requirement.
Response: The RCSDT believes that the additional verbiage is necessary to ensure that an entity
understands the Reliability Directive and is able to communicate that understanding back to the Reliability
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Coordinator. It is not necessary to repeat the exact same verbiage of the Reliability Directive, but rather the
intent of the actions required. Having to repeat verbiage of the Reliability Directive word-for-word could be an
impediment to achieving the reliability intent of the Reliability Directive when the focus is on repeating
verbatim.
Per COM-002-3 R1, who decides that actions need to be issued as a Reliability Directive? Shouldn’t it be the
responsible entity? Thus, can we assume that if the responsible entity does not identify a communication as
a Reliability Directive that it is not a Reliability Directive per the requirement? After all, why would an entity
require actions but not issue a Reliability Directive. Following this logic, the VSL for R1 would never apply.
Would a compliance auditor second guess if an action required a Reliability Directive?
Response: Those orders issued as a Reliability Directive, and identified as such, will heighten awareness,
tighten communications and require the receiver of the Reliability Directive to prioritize its response.
Moreover, linking Reliability Directives to Emergencies establishes that normal non-Emergency operating
communications or actions are not applicable to COM-002.
Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the definition of Adverse
Reliability Impact in TOP-001-2 R5 during the last posting, the change to the definition should be coordinated
with that team.
Response: The RCSDT coordinated the use of Adverse Reliability Impacts with the Real-Time Operations
team
There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain
requirements in the standard and various other associated documentation indicates requirements are being
move to this standard. Please delete the text box.
Response: The text box has been removed.
Please strike part IRO-014-2 Part 1.7. There is no need to have a weekly conference to discuss every
Operating Procedure, Operating Process and Operating Plan. As this requirement is written, a conference
call would be necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have weekly
conference calls that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures,
Processes and Plans likely will not need to be discussed weekly as it only requires an annual update.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific activities with other impacted
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Reliability Coordinators, these activities are listed as sub requirements. R1.7 is requires you to have a
procedure relating to weekly conference calls while R4 requires participation in weekly calls. Further the
RCSDT believes that it is prudent that Reliability Coordinators talk at least once a week to verify viability of
mutual plans, procedures or processes.
IRO-014-2 R4 is overly broad and would require Reliability Coordinators that will not impact one another to
participate on conference calls with one another without any reliability benefit. The issue is created by the
addition of the clause “within the same Interconnection” to the requirement. ISO-NE, FRCC, Midwest ISO,
and SPP are all in the same Interconnection. It is hard to fathom there being reliability benefit to SPP and
ISO-NE conversing weekly or Midwest ISO and FRCC conversing weekly. We suggest limiting the
requirement to adjacent Reliability Coordinators.
Response: IRO-14-2 R4 is applicable to those Reliability Coordinators engaged in activities related to R1 and
subsequently R1.7, it is unlikely that Reliability Coordinators whom are geographically and electrically distant
will have mutually agreed upon operating procedures (per R1), and as such they are not applicable to R4.
For IRO-014-2 R5, we suggest replacing “other” with “impacted” to limit the notification of Adverse Reliability
Impacts to only those Reliability Coordinators that need to know. Because the definition of Adverse Reliability
Impact includes “Bulk Electric System instability or Cascading”, it is possible that the cascading of 138 kV
lines serving a load pocket or generator outlet stability issues could require a Reliability Coordinator to notify
all other Reliability Coordinators regardless of impact. This would include Reliability Coordinators outside of
the Interconnection with the problem. It would also include Reliability Coordinators that are not impacted. For
instance, an issue in New England that would not pose a threat outside the northeast would require ISO-NE
to notify SPP and FRCC and Reliability Coordinators in the Western Interconnection. There is no reliability
benefit to this notification.
Response: This requirement continues the current practice of informing all RCs of ARIs. Due to the nature of
an ARI, this requirement is typically implemented as an RCIS message or a hotline call to all RC’s. This is
intended to make all RCs aware of ARIs and support situational awareness.
IRO-014-2 R6-R8 are problematic and need to be refined to make clear that the Reliability Coordinators shall
operate to the most conservative limit. It should not require a Reliability Coordinator that disagrees with an
action plan to implement the action plan. The Reliability Coordinator will be disagreeing with the action plan
for reliability reasons. Assuming they are correct, the requirement to implement said action plan will actually
put the Interconnection at greater risk. These requirements inappropriately attempt to codify the debate and
analysis that occurs between and within Reliability Coordinators when there are differing results in reliability
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analysis. This is part of the problem with having a Wide Area view that results in Reliability Coordinators
having a view into other Reliability Coordinator Areas. Their results and conclusions may be different. There
should be a hierarchical structure for whose results should be used. It should the Reliability Coordinator with
primary responsibility unless the other Reliability Coordinator has evidence to demonstrate that the Reliability
Coordinator with primary responsibility is incorrect. What this should do is to trigger both to review their
models and data to assess the problem. None of this needs to be codified in the standards though.
Response: Requirements R6-R8 are translated from IRO-016-1, Requirement R1. If an RC sees a problem
and another does not see the same problem, then there may be an issue with someone’s model or processes
or procedures. The RC’s are supposed to have coordinated Operating Plans, Processes or Procedures to
operate reliably. R6-R8 are only applicable if one of the two (or more) RCs do not see that a problem exists.
It would be a detriment to reliability for both RCs to take no action. RCs are required to coordinate actions
under existing IRO-016-1, R1. If one RC identifies a problem and provides an action plan to another RC to
mitigate the problem, the second RC is obligated under R8 to implement it. We have revised the R8 to clarify
this intent.
In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
declared Emergency”. This would help limit second guessing for a situation where a System Operator took
action because he truly believed he was an Emergency but after the fact analysis demonstrates there really
was not an Emergency.
Response: Modifying Reliability Directive by including “declared Emergency” would add an unnecessary step
in mitigation of the Emergency. The act of issuing a Reliability Directive to address an Emergency (per the
proposed definition) is sufficient.
The drafting team should expand its rationale for deleting IRO-002-1 R3. Currently, TOP-005 R1 is
referenced. The Real-Time Operations drafting team proposed to retire TOP-005-2 R1 in its most recent
posting.
Response: The data provisions are covered in recently approved IRO-010-1, R1-R3 which replaced TOP005-1, R1. The secure network provisions are covered in the CIP body of standards.
We disagree with deleting IRO-002-1 R5 and R7 which establish tools and monitoring capabilities. There
should be basic tools requirements established for Reliability Coordinators. Project 2009-02 Real-time
Reliability Monitoring and Analysis Capabilities will be addressing these issues in more detail. Thus, it does
not make sense to delete these requirements until that drafting team completes its task.
Response: Each RC has been certified to continue operations as an RC or been certified prior to beginning
operations as an RC. The minimum set of tools and capabilities for an RC are “checked off” during the
certification process. The reliability objective of R5 and R7 is to perform analyses to ensure reliability of the
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BES by specifying capability rather than mandating specific tools. The analysis provisions of R5 and R7 are
covered under IRO-008-1, Requirements R1 (perform Operational Planning Analysis) and R2 (perform Realtime Analysis). It is anticipated that Project 2009-02 team will address this issue more fully.
MRO's NERC Standards Review
Subcommittee
A. COM-002-3, R2 As stated in FERC Order 693, section 512, it is essential that RCs, BA’s and TOP’s have
communications with DPs. R2 also applies to TSPs, LSEs and PSEs. There is no directive for this and it is
going to be almost impossible to communicate with a DP since DPs are usually not operated 24 hours per day
as like a RC, TOP, or BA. Many DPs have answering services that will relay a message once they receive it
and then pass it along to someone. An answering company could repeat the directive word for word but this
will not add to any reliability level. The SDT should reconsider the applicability section of this Standard to only
apply to a RC, TOP and BA for the issuance of a Reliability Directive. BA’s should have the responsibility to
have an Interpersonal Communication medium with DPs in their BA area per COM-001-2.
Response: The purpose of COM-002 is “To ensure emergency communications between operating personnel
are effective.” It is not a proxy requirement to establish 24/7 operating personnel at small distribution providers.
The intent is to establish a method of communicating Reliability Directives during Emergencies. While it is true
that many small Distribution Providers are not staffed 24x7, it is typical that they have a means of
communication, in many cases this may be via a receptionist, or answering service. It is the expectation that an
issuer of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then
issue the Reliability Directive. If this return call would not be timely enough, then the issuer would determine a
different mitigation plan.
B. IRO-002-2, R1, Recommend that “System Operators” be replaced with “system operators” since NERC
has defined System Operator to be an individual at a control center (BA, TOP, GOP, or RC). The lower
cased system operator will only point to the RC system operator that will have this R1 authority.
Response: IRO-002-2 is applicable only to Reliability Coordinators, as such the using System Operator as it
defined by the NERC Glossary of terms is appropriate.
C.The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving the as the Transmission Operator or Balancing Authority. We believe that it should never be
necessary for these System Operators to issue Reliability Directives to themselves in the first example or to
their co-worker in the second example to demonstrate compliance to NERC standards. How the entity
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coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles
is a corporate governance issue that should not be confused or complicated by the NERC standards. Thus, we
believe that standards should be made clear that the Reliability Directive is directed to another company.
Response: COM-002 does not preclude text or other forms of communication for issuing Reliability
Directives. However, entities still must comply with the requirements of COM-002. Further, the RCSDT
believes it to be equally imperative that each NERC registered function hold the authority to issue Reliability
Directives, and the ability to receive Reliability Directives, whether those Reliability Directives are issued to
subordinate registered functions within a vertically integrated utility, or to registered entities that are
corporately separate. The RCSDT believes the following response to draft 3 comments still holds true:
“The way that COM-002 is crafted, it focuses on functional entity communication between and among
functions. Face-to-face communication of Reliability Directives are subject to the requirements of COM002 and can be measured for COM-002 by allowing Operator Logs as possible evidence to support
compliance”.
The use of operator logs to memorialize and provide evidence of compliance is directly specific to those
Reliability Directives issued and received within the same control room or operations center. The RCSDT
believes that any Registered Entity or person operating as such must understand the intent of the issued
Reliability Directive, and that the issuer of the Reliability Directive believe that the Reliability Directive was
correctly received. COM-002 should not be construed to mean that an individual serving in two functions be
required to issue a Reliability Directive to himself, but rather it is expected that such an individual would
appropriately address the reliability issues as required by the function they are serving and its subsequent
responsibilities.
D. We also are concerned about the need to conduct three-part communications for a Reliability Directive
issued through a blast call. Under these circumstances, the need for immediate action of multiple parties may
require a blast call and there may not be time for all parties to complete three-part communications before
initiating actions. Thus, we believe blast calls should be treated separately and that should be made clear.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is efficient
and effective. The RCSDT believes Reliability Directives issued in mass should be defined by procedure, and
that the procedure would establish a method of affirmation and notice of implementation.
E. COM-002-3 R2 needs to be rewritten as it is too verbose. The point is for the recipient of the original
message to get the issuer to confirm that the message was understood. We suggest rewording R2 to
“Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient
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of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the
Reliability Directive.”
Once the receiver has completed this requirement, the ball is in the issuer’s court per Requirement R3. No
additional words are necessary in the requirement.
Response: The RCSDT believes that the additional verbiage is necessary to ensure that an entity understands
the Reliability Directive and is able to communicate that understanding back to the Reliability Coordinator. It is
not necessary to repeat the exact same verbiage of the Reliability Directive, but rather the intent of the actions
required. Having to repeat verbiage of the Reliability Directive word-for-word could be an impediment to
achieving the reliability intent of the Reliability Directive when the focus is on repeating verbatim.
F. Per COM-002-3 R1, who decides that actions need to be issued as a Reliability Directive? Shouldn’t it be
the responsible entity? Thus, can we assume that if the responsible entity does not identify a communication
as a Reliability Directive that it is not a Reliability Directive per the requirement? After all, why would an entity
require actions but not issue a Reliability Directive. Following this logic, the VSL for R1 would never apply.
Would a compliance auditor second guess if an action required a Reliability Directive?
Response: Those orders issued as a Reliability Directive, and identified as such, will heighten awareness,
tighten communications and require the receiver of the Reliability Directive to prioritize its response.
Moreover, linking Reliability Directives to Emergencies establishes that normal non-Emergency operating
communications or actions are not applicable to COM-002.
G. Because the Project 2007-03 (“Real-Time Operations SDT”) proposed to utilize the definition of Adverse
Reliability Impact in TOP-001-2 R5 during the last posting, the change to the definition should be coordinated
with that team.
Response: The RCSDT coordinated the use of Adverse Reliability Impacts with the Real-Time Operations
team
H. There is a text box in IRO-005-4 that indicates this standard will be retired. Yet, there still remain
requirements in the standard and various other associated documentation indicates requirements are being
move to this standard. Please delete the text box.
Response: The text box has been removed.
I. Please strike part IRO-014-2 Part 1.7. There is no need to have a weekly conference to discuss every
Operating Procedure, Operating Process and Operating Plan. As this requirement is written, a conference call
would be necessary for each. Furthermore, IRO-014-2 R4 already includes a requirement to have weekly
conference calls that should suffice. IRO-014-2 R2 seems to recognize that these Operating Procedures,
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Processes and Plans likely will not need to be discussed weekly as it only requires an annual update.
Response: The intent of R1 is for Reliability Coordinators to coordinate specific activities with other impacted
Reliability Coordinators, these activities are listed as sub requirements. R1.7 is requires you to have a
procedure relating to weekly conference calls while R4 requires participation in weekly calls. Further the
RCSDT believes that it is prudent that Reliability Coordinators talk at least once a week to verify viability of
mutual plans, procedures or processes.
J. IRO-014-2 R4 is overly broad and would require Reliability Coordinators that will not impact one another to
participate on conference calls with one another without any reliability benefit. The issue is created by the
addition of the clause “within the same Interconnection” to the requirement. ISO-NE, FRCC, Midwest ISO, and
SPP are all in the same Interconnection. It is hard to fathom there being reliability benefit to SPP and ISO-NE
conversing weekly or Midwest ISO and FRCC conversing weekly. We suggest limiting the requirement to
adjacent Reliability Coordinators.
Response: IRO-14-2 R4 is applicable to those Reliability Coordinators engaged in activities related to R1 and
subsequently R1.7, it is unlikely that Reliability Coordinators whom are geographically and electrically distant
will have mutually agreed upon operating procedures (per R1), and as such they are not applicable to R4.
K. For IRO-014-2 R5, we suggest replacing “other” with “impacted” to limit the notification of Adverse Reliability
Impacts to only those Reliability Coordinators that need to know. Because the definition of Adverse Reliability
Impact includes “Bulk Electric System instability or Cascading”, it is possible that the cascading of 138 kV lines
serving a load pocket or generator outlet stability issues could require a Reliability Coordinator to notify all other
Reliability Coordinators regardless of impact. This would include Reliability Coordinators outside of the
Interconnection with the problem. It would also include Reliability Coordinators that are not impacted. For
instance, an issue in New England that would not pose a threat outside the northeast would require ISO-NE to
notify SPP and FRCC and Reliability Coordinators in the Western Interconnection. There is no reliability benefit
to this notification.
Response: This requirement continues the current practice of informing all RCs of ARIs. Due to the nature of
an ARI, this requirement is typically implemented as an RCIS message or a hotline call to all RC’s. This is
intended to make all RCs aware of ARIs and support situational awareness.
L. IRO-014-2 R6-R8 are problematic and need to be refined to make clear that the Reliability Coordinators shall
operate to the most conservative limit. It should not require a Reliability Coordinator that disagrees with an
action plan to implement the action plan. The Reliability Coordinator will be disagreeing with the action plan for
a reliability reasons. Assuming they are correct, the requirement to implement said action plan will actually put
the Interconnection at greater risk. These requirements inappropriately attempt to codify the debate and
analysis that occurs between and within Reliability Coordinators when there are differing results in reliability
analysis. This is part of the problem with having a Wide Area view that results in Reliability Coordinators
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having a view into other Reliability Coordinator Area. Their results and conclusions may be different. There
should be a hierarchical structure for whose results should be used. It should be the Reliability Coordinator
with primary responsibility unless the other Reliability Coordinator has evidence to demonstrate that the
Reliability Coordinator with primary responsibility is incorrect. What this should do is, to trigger both to review
their models and data to assess the problem. None of this needs to be codified in the standards though.
Response: Requirements R6-R8 are translated from IRO-016-1, Requirement R1. If an RC sees a problem
and another does not see the same problem, then there may be an issue with someone’s model or processes
or procedures. The RC’s are supposed to have coordinated Operating Plans, Processes or Procedures to
operate reliably. R6-R8 are only applicable if one of the two (or more) RCs do not see that a problem exists.
It would be a detriment to reliability for both RCs to take no action. RCs are required to coordinate actions
under existing IRO-016-1, R1. If one RC identifies a problem and provides an action plan to another RC to
mitigate the problem, the second RC is obligated under R8 to implement it. We have revised the R8 to clarify
this intent.
M. In the definition of Reliability Directive, we suggest changing “to address an Emergency” to “to address a
declared Emergency”. This would help limit second guessing for a situation where a System Operator took
action because he truly believed he was in an Emergency but after the fact analysis demonstrates there really
was not an Emergency.
Response: Modifying Reliability Directive by including “declared Emergency” would add an unnecessary step
in mitigation of the Emergency. The act of issuing a Reliability Directive to address an Emergency (per the
proposed definition) is sufficient.
N. The drafting team should expand its rationale for deleting IRO-002-1 R3. Currently, TOP-005 R1 is
referenced. The project 2007-03 (“Real-Time Operations SDT”) proposed to retire TOP-005-2 R1 in its most
recent posting.
Response: The data provisions are covered in recently approved IRO-010-1, R1-R3 which replaced TOP005-1, R1. The secure network provisions are covered in the CIP body of standards.
O. We disagree with deleting IRO-002-1 R5 and R7 which establishes tools and monitoring capabilities. There
should be basic tool requirements established for Reliability Coordinators. The project 2009-02 (“Real-time
Reliability Monitoring and Analysis Capabilities”) will be addressing these issues in more detail. Thus, it does
not make sense to delete these requirements until that drafting team completes its task.
Response: Each RC has been certified to continue operations as an RC or been certified prior to beginning
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operations as an RC. The minimum set of tools and capabilities for an RC are “checked off” during the
certification process. The reliability objective of R5 and R7 is to perform analyses to ensure reliability of the
BES by specifying capability rather than mandating specific tools. The analysis provisions of R5 and R7 are
covered under IRO-008-1, Requirements R1 (perform Operational Planning Analysis) and R2 (perform Realtime Analysis). It is anticipated that Project 2009-02 team will address this issue more fully.
Response: The RCSDT thanks you for your comments.
FirstEnergy
FirstEnergy offers the following additional comments:
1. The effective dates of the standards indicate an effective date of the first day of the first calendar quarter
following regulatory approval. The changes to these standards will require changes to existing compliance
evidence, as well as the creation of compliance evidence for some entities such as the Generator Operator
which is a new applicable entity in COM-001. Therefore, to give entities ample time to get their compliance
evidence in place, we suggest the effective state “the first day of the second quarter after regulatory
approval”.
Response: The RCSDT agrees and will change the implementation plan to reflect the “first day of the second
quarter after regulatory approval.”
3. With regard to the requirements for Alternative Interpersonal Communications, we question why the
Generator Operator or Distribution Provider is not required to have backup communication. It would be
difficult for a Reliability Coordinator, for instance, to contact a Generator Operator whose primary
communications have been disabled if that entity does not have a backup. We suggest that the drafting
team consider adding the GOP and DP as applicable entities requiring alternative communications.
Response: The RCSDT asserts the standard meets FERC Order 693 regarding DP and GOP entities by
requiring these entities to have Interpersonal Communication capability. Not requiring DP and GOP entities to
have Alternative Interpersonal Communication capability meets FERC’s intention as stated here: “We (FERC)
clarify that the NOPR did not propose to require redundancy on generator operators’ or distribution providers’
telecommunication facilities…” (Order 693, RM06-16-000, Paragraph 487).
Response: The RCSDT thanks you for your comments.
SPP Standards Development
July 14, 2011
IRO-001-2, R2 implies that the RC could interrupt the normal chain of command from the TOP and/or BA to
their respective GOPs, ICs and DPs thereby circumventing the coordinating process that currently exists. In
fact, these entities may not even know their RCs nor be able to identify them and as such any directive from
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the RC may not be implemented in a timely manner. We would like to see a qualifier on this requirement that
does not remove the normal coordination role from the TOP with his DP, etc.
Response: There may be unusual circumstances whereby the requirement may indeed circumvent the
normal coordinating process in the interest of time / reliability. The RC has the ultimate authority with respect
to BES reliability.
We would suggest that "with enough details that the accuracy of the message has been confirmed" be
deleted from COM-002-3, R2.
Response: The RCSDT believes that the additional verbiage is necessary to ensure that an entity
understands the Reliability Directive and is able to communicate that understanding back to the Reliability
Coordinator. It is not necessary to repeat the exact same verbiage of the Reliability Directive, but rather the
intent of the actions required. Having to repeat verbiage of the Reliability Directive word-for-word could be an
impediment to achieving the reliability intent of the Reliability Directive when the focus is on repeating
verbatim.
We would suggest the use of the term 'instruction" and its derivatives rather than 'direct' in IRO-001-2, R2, R3
and R4.
Response: This proposed change is stylistic in nature. Stakeholder consensus indicates that this is not an
issue for the overwhelming majority of commenters.
Delete ‘issue an alert to’ in IRO-005-4, R1.There are yellow boxes in IRO-005-4, redline versions, which
indicate that this standard is being retired, but it isn’t because two requirements from IRO-001 are being
returned to this standard.
Response: These are typos and have been corrected as noted.
Response: The RCSDT thanks you for your comments.
Kansas City Power & Light
July 14, 2011
There are more requirements that are being removed in the IRO standards than are currently proposed. It
would be helpful if the SDT would consider a mapping of each requirement that is being eliminated and
whether the requirement is duplicated elsewhere, moved elsewhere and where, or is deemed not needed
would be helpful in judging if the changes are appropriate. Without this mapping it is difficult to fully support
all the proposed changes to all these Standards.
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Response: The RCSDT thanks you for your comments. The implementation plan contains the requested mapping.
Competitive Suppliers
EPSA is the trade association for competitive suppliers including both generators and marketers that
represent over 700 entities in the NERC compliance registry. As such, the EPSA membership includes
members registered as Purchasing Selling Entities (PSE) in each NERC region. Moreover, many of EPSA’s
members are also registered as LSEs in several regions. In general, EPSA supports the progress made in
revising COM-001, COM-002 and IRO-001 in Project 2006-06, particularly the improvements made to the
definition of Reliability Directive.
However, EPSA also has concerns with some proposed changes to the applicability sections of the revised
standards. In addition, EPSA requests that the implementation plans be be changed so that they are
consistent with the standard.
Regarding applicability, EPSA agrees that COM-001 should continue to not apply to Purchasing Selling Entity
(PSE) and Load Serving Entity (LSE) functions.
However, the implementation plan for COM-001-2 still includes a reference that PSEs and LSEs must comply
(page 11 of the implementation plan). Additionally, EPSA supports the removal of LSEs and PSEs from IRO001-2. Much like the situation with COM-001-2, the implementation plan for IRO-001-2 still includes a
reference that LSEs and PSEs must comply (page 11 of the implementation plan). In both the
implementation plans for COM-001-2 and IRO-001-2 these references should be removed. For reasons
similar to those underlying why COM-001-2 and IRO-001-2 do not apply to PSEs and LSEs, EPSA opposes
the addition of PSEs to the COM-002-3 applicability. The purpose of the emergency communications in these
standards is "To ensure emergency communications between operating personnel are effective." The removal
would recognize that PSEs and LSEs do not play an active role in reliability coordination under this standard
since they have no authority, nor ability to assume or perform responsibilities associated with reliability
coordination. When a RC, TOP, or BA needs to address an Emergency they do not contact, consult, or direct
a PSE to take action to address the Emergency. Reliability is neither improved nor degraded by having these
Standards applicable to PSEs or LSEs; therefore,COM-001, COM-002 and IRO-001 need not be applicable to
PSEs or LSEs. Thanks to the drafting team members for their effort on revising the Project 2006-06
standards.
Response: The RCSDT thanks you for your comments.
The RCSDT has removed the PSE and LSE from the COM-001-2 and IRO-001-2 implementation plans.
For COM-002, the RCSDT believes that all registered NERC entities engaged in daily operational activities must adhere to requirements related to Reliability
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Directives. While LSE and PSE’s are not engaged in coordination activities, they are engaged in load serving, as well as purchasing and selling activities on a
daily basis. These activities could be subject to Reliability Directives, either in the form of load reduction, or schedule curtailments.
Exelon
1. COM-002-2, R2 - Remove the word “recapitulate”, feel that “restate or rephrase” is adequate. The word
"recapitulate" is not commonly used and is somewhat obscure.
Response: The proposed changes are stylistic in nature. The RCSDT included the phrase including
“recapitulate” at the suggestion of another stakeholder, and has decided to leave the phrase “restate,
rephrase, or recapitulate” intact as suggested by the other stakeholder.
2. COM-002-2, R3 - Suggest using the words “repeat back” rather then “state or respond that” to more
clearly identify the expectation with more commonly used language.
Response: The proposed changes are stylistic in nature. The RCSDT included the phrase including
“recapitulate” at the suggestion of another stakeholder, and has decided to leave the phrase “restate,
rephrase, or recapitulate” intact as suggested by the other stakeholder.
3. IRO-001-2, R3 - While we appreciate that the SDT has defined the term "directive" as a much needed
definition, IRC-001-2 R.3 now introduces a new term “direction”, what is a "direction" and how does it differ
from "directive"? If a new term is going to be introduced it needs to be defined, if the intent was to use the
word “directive” then “direction” should be replaced with “directive.”
Response: The requirement language specifically ties back to Requirement R2 which states that the RC
“shall take actions or direct actions, which could include issuing Reliability Directives, “. This is the
“direction in accordance with Requirement R2” stated in R3 and the “direction in accordance with
Requirement R3” stated in R4.
3. IRO-001-2, R4 - Again the term “as directed” is confusing, recommend that the text be changed to align
with the term directive, “unable to perform the directive per Requirement R3.”
Response: The requirement language specifically ties back to Requirement R2 which states that the RC
“shall take actions or direct actions, which could include issuing Reliability Directives, “. This is the
“direction in accordance with Requirement R2” stated in R3 and the “direction in accordance with
Requirement R3” stated in R4.
Response: The RCSDT thanks you for your comments.
PacifiCorp
July 14, 2011
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Arizona Public Service Company
LG&E and KU Energy
1) LG&E/KU suggests that the definitions and related Reliability Standards be edited to provide a clearer
understanding of what is required. When used in the requirements of COM-001, the proposed definitions for
Interpersonal Communication and Alternative Interpersonal Communication read improperly (i.e., a “medium
capability”). This may cause confusion as to what is required by the Applicable entities. Any further use of
these terms may cause greater confusion. Suggested Alternative: Interpersonal Communication: Any
instance where two or more individuals interact, consult, or exchange information. The definition of
“Alternative Interpersonal Communication” would not have to be changed since it is dependent upon the
definition of “Interpersonal Communication.”The change of the definitions of Interpersonal Communication
and Alternative Interpersonal Communication shifts their focus to the communication itself-the event. This
makes the Requirements themselves much clearer since the Requirements focus on the need that entities
have the capabilities-the medium. It appears the SDT’s intent is to ensure that the event takes place by
requiring that the medium for those events are in place. This is much clearer if there is a distinction between
the two (the event and the medium) than if they have similar definitions (a medium and a “medium
capability”).
Response: The RCSDT chose to use “medium” so as to not preclude the use of text, voice, electronic or
other technology. The intent of the definition as well as the requirements is to require that functional entities
have a means to communicate.
2) LG&E/KU question the consistency of the Applicability sections as they pertain to the TSP, LSE and PSE
functions between COM-001 and COM-002. The deletion of the TSP, LSE and PSE from COM-001 is
supported, but if these entities are not required to establish Interpersonal Communication (or Alternative
Interpersonal Communication) capability with reliability entities (RC, BA, TOP), should they still be required to
follow the reliability directive process of COM-002? If the probability of issuing a Reliability Directive to a TSP,
LSE or PSE is so low that Interpersonal Communications capabilities with reliability entities is not justified
under COM-001, why are the TSP, LSE and PSE still held to the
3 way communication requirements of COM-002? Suggest the Applicability of COM-002 to TSP, LSE and
PSE and associated requirements be deleted.
Response: The RCSDT has revised the applicability of COM-001 and COM-002 such that they contain the
same functional entities. These are: RC, TOP, BA, GOP, and DP.
Response: The RCSDT thanks you for your comments.
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Southern Company
Yes or No
Question 6 Comment
Comments: It appears that the requirements for entities designated in the IRO standards to have tools to
access and/or monitor the system have been moved to pending standards that are not enforceable. It seems
that if the newest revisions of the IRO standards are not implemented as a group there will be either missing
requirements or duplicate requirements in the IRO standards.
Response: The RCSDT thanks you for your comments. The implementation plans note prerequisite approvals that must occur prior to retiring requirements.
FERC recently approved IRO-008, 009 and 010. The standards under this project will be filed together with FERC.
Green Country Energy, Green
Country Operating Services
IRO-001-2 as proposed does not include the PSE in the applicability, nor does it require the PSE to respond
to a directive. However, COM-002 requires them to repeat the directive back... If the directive is that
important to repeat back should they not have to act upon the directive? I think the PSE should be included in
IRO-001-2 this standard as they represent and direct generation facility deployment in many cases. Including
the PSE in COM-001 may be a good idea too, just for the situations listed above.
Response: The RCSDT thanks you for your comments. The RCSDT has revised the applicability of COM-001 and COM-002 such that they contain the same
functional entities. These are: RC, TOP, BA, GOP, and DP.
Central Lincoln
The stated purpose of COM-002 is:
“To ensure emergency communications between operating personnel are effective.” As written, the standard
fails to meet this purpose because the three requirements only deal with communications at the entity level.
There is no requirement for the directing entity to even try to reach operating personnel at the receiving entity.
The directing entity may follow all the requirements of this standard by following R1 and R3 with the receiving
entity’s receptionist, answering service, janitor, night watchman, etc. The receiving entity only needs to meet
R2, parroting the directive. Again this could be accomplished by anyone with no assurance the directive
reaches the operating personnel who can implement it. When we stated a similar objection during the last
comment period, The SDT’s answer suggested this was a PER staffing issue, but none of the PER
requirements even apply to DP/LSE directive recipients. We suggest the entity issuing the directive should be
required to make an attempt to get it to those who are competent to understand and implement the directive.
This is not a staffing, training, or credentials issue; it is a performance issue that falls squarely within the
stated purpose of this standard.
COM-001 R10 presents a paradoxical situation to an entity attempting to comply. Consider an interpersonal
communication capability failure that lasts longer than 60 minutes past initial detection. At or before 60
minutes, the affected entity is expected to notify impacted entities. If it has no interpersonal communication
capability, how shall it make this notification? And if the entity does manage to make such a notification, it has
thereby proven that it does have interpersonal communication capability making such notification
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unnecessary.
Response: The DP or GOP has access to additional Interpersonal Communications, in all likelihood, to make
notifications for failure. There is not a requirement for an alternative, but it is highly unlikely that someone
couldn’t use their cell phone to make the notification.
We again ask the SDT to consider that not all the entities in the applicability sections of COM-001 and 002
have 24/7 dispatch centers. These are typically smaller entities that were required to register because they
exceed 25 MW or were asked in the past to voluntarily provide UFLS. They do not and do not need to
continuously communicate with TOPs, BAs, RCs, etc; and a “reliability directive” is a theoretical thing that has
never happened during the memories of thirty year employees. The directive issuing entities simply realize
the limitations around the receiving entities and work around them. The financial burden on these small
entities and their customers to go to 24/7 dispatch will not have a corresponding reliability benefit. And while
the two COM standards do not explicitly state that entities must maintain 24/7 dispatch, when all the
requirements and definitions and time horizons are taken together 24/7 continuous competent communication
is implied. During the last comment period, the SDT suggested this was a registration issue beyond their
control. We submit instead that this is a standard applicability question that the SDT does have control over,
since it is right there in Section A.4 of the two COM standards. While we appreciate that the SDT is
responding to FERC order 693 to include DPs, we note that FERC also stated: Paragraph 487: “We expect
the telecommunication requirements for all applicable entities will vary according to their roles and that these
requirements will be developed under the Reliability Standards development process.” Paragraph 6: “A
Reliability Standard may take into account the size of the entity that must comply and the costs of
implementation” Paragraph 141: “...the Commission clarifies that it did not intend to ... impose new
organizational structures...”Paragraph 31: “We emphasize that we are not, at this time, mandating a particular
outcome by way of these directives, but we do expect the ERO to respond with an equivalent alternative and
adequate support that fully explains how the alternative produces a result that is as effective as or more
effective that the Commission’s example or directive. We ask the SDT to exclude DPs, LSEs, and PSEs that
do not have 24/7 dispatch centers from the applicability of these two standards in order to meet FERC order
693.
Response: The RCSDT thanks you for your comments. There is no requirement for 24/7 support - the requirement is to have communications capability. The
type of system (e.g., On-Call) is not prescribed in the standard and the standard is designed not to impose needless communications requirements. The purpose
of COM-002 is “To ensure emergency communications between operating personnel are effective.” It is not a proxy requirement to establish 24/7 operating
personnel at small distribution providers. The intent is to establish a method of communicating Reliability Directives during Emergencies. While it is true that many
small Distribution Providers are not staffed 24x7, it is typical that they have a means of communication, in many cases this may be via a receptionist, or answering
service. It is the expectation that an issuer of a Reliability Directive would request a return call by the Distribution Provider operating personnel, then issue the
Reliability Directive. If this return call would not be timely enough, then the issuer would determine a different mitigation plan.
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Lakeland Electric
Yes or No
Question 6 Comment
COM-002-3 R2. Each Balancing Authority, Transmission Operator, Generator Operator, Transmission
Service Provider, Load-Serving Entity, Distribution Provider, and Purchasing-Selling Entity that is the recipient
of a Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the
Reliability Directive with enough details that the accuracy of the message can be confirmed by the originator.
(Replace ‘has been’ with ‘can be’ and add ‘by the originator’ to better fit into the sequence with R3.)
Response: The RCSDT thanks you for your comments. The RCSDT agrees with the intent of your comment and has modified R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the recipient of a Reliability Directive issued in
accordance with Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability Directive with enough details that the accuracy of the
message is confirmed.
Manitoba Hydro
-The current data retention requirement of 90 days is more than adequate. Increasing this period to 12
months would result in a significant amount of work with no benefit to reliability. -Clarification required on the
VSL for R9 - there appears to be no
Response: The RCSDT thanks you for your comment. The data retention periods for the set of standards proposed is consistent with the guidelines provided in
the NERC Drafting team Guidelines. Your second comment is incomplete and does not reference specific standard(s) or requirement(s).
NextEra Energy, Inc.
July 14, 2011
At this stage in evolution of compliance with the mandatory Reliability Standards, it is important that any new
or revised Reliability Standard clearly articulate all compliance obligations and tasks consistent with Sections
302 (6) and (8) of the NERC Rules of Procedure. COM-002, IRO-001, IRO-002 and IRO-014 do not meet this
threshold. Thus, NextEra has numerous recommended corrections to provide clarity and completeness to
these Reliability Standards.COM-002 R1The addition of defined terms for Reliability Directive and Emergency
is a very good approach that helps provides clarity. Hence, it is also be appropriate to make the language in
the requirement as clear as possible, and not add other implied or unexplained notions. Also, at times, in
those regions with markets, it is not always clear whether a requirement to curtail for reliability reasons is
being issued pursuant to market rules or from the Reliability Coordinator or Transmission Operator under the
Reliability Standards. Therefore, it is also appropriate that the Reliability Coordinator, Transmission Operator,
Balancing Authority be required to identify themselves;, and if they fail to identify themselves or fail to use the
term Reliability Directive, the registered entity receiving the flawed issuance should not be consider in
violation of a Reliability Standard for failing to act. Accordingly, R1 would be clearer and have the same
intent, if it stated as follows:”A Reliability Coordinator, Transmission Operator or Balancing Authority have the
authority to issue an oral or written Reliability Directive as authorized in [list the specific Reliability Standard
requirements such as IRO-001 R8 and TOP-001 R3]. The issuance of an oral of written Reliability Directive,
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by a Reliability Coordinator, Transmission Operator or Balancing Authority shall: (1) use the term ‘Reliability
Directive;’ and (2) identify the issuer of the Reliability Directive as a Reliability Coordinator, Transmission
Operator or Balancing Authority. If a Reliability Coordinator, Transmission Operator or Balancing Authority
issues an oral or written directive without using the term “Reliability Directive” or failing to indentify itself as a
Reliability Coordinator, Transmission Operator or Balancing Authority, the registered entity receiving the
directive cannot be considered in violation for its failure to act.”
Response: Only reliability entities can issue Reliability Directives and only reliability entities are held
compliant to NERC reliability standards. COM-002, R1 requires the issuer of a Reliability Directive to identify
the action as a “Reliability Directive”, it is incumbent on the issuer or receiver to identify themselves in order
establish authority, the RCSDT disagrees that identification should be part of the COM-002 standard,
however, the RCSDT will pass this concern to Project 2007-02, Operating Personnel Communications
Protocols SDT. Furthermore, your suggested revision is a compound requirement, making the requirement
indistinct and difficult to measure and in contradiction with SAR. The RCSDT agrees that if an action is not
identified as a “Reliability Directive” then the receiving entity cannot be held in violation of failing to follow a
Reliability Directive.
IRO-001The definition of Adverse Reliability Impacts uses the term “instability.” It is important that this term
be technically defined in the same way “Cascading” is defined, otherwise the new requirement is not adding
clarity; rather, it is maintaining the ambiguous term “instability” that will likely lead to confusion and debate.
Response: The RCSDT disagrees that the term “instability” is ambiguous, and further believes the term is
understood in the industry. The majority of stakeholder comments do not indicate that the definition is
confusing.
R1 Similar to the comments set forth with respect to COM-001 (question #1), the term “at least” should be
deleted from R1 - it serves no useful purpose from a technical or compliance perspective; instead, it will add
unnecessary ambiguity to the requirement.
Response: The RCSDT agrees and has removed “at least” for IRO-OO1, R1.
R2, as drafted, states:”Each Reliability Coordinator shall take actions or direct actions, which could include
issuing oral or written Reliability Directives, of Transmission Operators, Balancing Authorities, Generator
Operators, Interchange Coordinators and Distribution Providers within its Reliability Coordinator Area to
prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse
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Reliability Impacts. “This long sentence has several significant grammatical errors that result in the reader not
being able to discern the meaning of the requirement. It also unnecessarily adds verbiage that detracts from
its primary focus. It is, therefore, recommended that R2 be revised as follows:
“Each Reliability Coordinator shall take all necessary actions to prevent identified Emergencies or
Adverse Reliability Impacts. These Reliability Coordinator actions shall include, to the extent
necessary, the issuing of oral or written Reliability Directives to Transmission Operators, Balancing
Authorities, Generator Operators, Interchange Coordinators and Distribution Providers located within its
Reliability Coordinator Area.
Response: The RCSDT disagrees that the suggested revisions adds clarity, and in fact removes directing
actions “to mitigate the magnitude or duration of actual events” which weakens the requirement. Phrases
such as “to the extent necessary” and “necessary actions” are not measurable and lead to a more confusing
requirement. Stakeholders generally agree with the proposed verbiage of the proposed requirement.
“R3, as drafted, is confusing and inconsistent with R2, and, thus, R3 should be revised to read as follows:
”Upon receipt of a Reliability Directive issued pursuant to R2, a Transmission Operator, Balancing
Authority, Generator Operator, Interchange Coordinator and Distribution Provider shall comply with the
Reliability Directive, unless compliance would violate safety, equipment, regulatory or statutory
requirements. In the event that a Transmission Operator, Balancing Authority, Generator Operator,
Interchange Coordinator or Distribution Provider determines that compliance with a Reliability Directive
would violate safety, equipment, regulatory or statutory requirements, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution Provider shall, within
10 minutes after the determination, inform the Reliability Coordinator of its inability to comply.”
Response: The RCSDT disagrees with the suggested revision to R3. The revision creates a compound
requirement with a specific time requirement. Upon recognition of the inability to perform a directed action, the
receiver should immediately inform the Reliability Coordinator. Typically this would be during the original
communication of the directive. The suggested 10 minute time is not technically justified and provides no
reliability benefit beyond the currently worded requirement and only serves to extend the time before an RC is
notified.
IRO-002R1 and R2, as written, are confusing. It is recommended that R1 and R2 be combined to read as
follows: “Pursuant to a written procedure to mitigate the impact of a Reliability Coordinator’s analysis tool
outage, a Reliability Coordinator’s System Operator shall also have the authority to approve, deny or cancel a
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planned outage for its analysis tool.”
Response: The suggested revision to IRO-002-2 creates a compound requirement, which is indistinct and
difficult to measure and in contradiction with SAR. The SAR for this project directs the team to “Improve clarity
of, improve measurability of, and remove ambiguity from the requirement”.
IRO-014It is unclear why the terms Operating Procedure, Operating Process or Operating Plan needs to be
plural, as currently written in the Standard. Hence, it is recommended that these terms be made singular,
otherwise a violation may be inferred for not having more than one Procedure, Process or Plan.
Response: IRO-014, R1, The RCSDT disagrees with making Procedures, Processes, or Plans non-plural;
this could lead to entities being audited on a procedure by procedure basis. In other words, it is meant that
the weekly conference calls create an opportunity to discuss all of the Procedures, Processes, or Plans, and
to not require a call for each.
1.1 Insert the word “applicable” before “Reliability Coordinator.”
Response: The RCSDT disagrees with the use of applicable, as the 1.1 is subordinate to R1, which notes
impacted Reliability Coordinators.
2.1, as written, is confusing. Recommend that 2.1 read as follows:
”Review and update, if an update is necessary, on an annual basis. Annual basis means the review
shall be within one month plus or minus that date of the last review.”
Response: The RCSDT disagrees, and believes the suggested revision is unclear. In its current draft form,
the plan or procedure is required to be reviewed every 15 months, if the review indicates that there are no
changes required, and then the update would simply be to change the revision date on the published
procedure.
R3 This requirement uses a very vague term “reliability-related information,” which, also, does not track the
language used in R1 -- “information.” It is recommended that R1 and R3 use the same terms and read “ . . .
information, as defined by the Reliability Coordinator, . . “
Response: The RCSDT believes the reference to R1 within R3 clearly is representative of exchange of
information related to R1.
R4 As stated above, “at least” does not add value, and, therefore, should be deleted.
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Response: The RCSDT disagrees. The inclusion of “at least” allows the calls take place every day or multiple
times within a week if desired, and adds flexibility. e.g. if there was scheduled weekly call, however due to
system conditions an interim call was held, during this interim call all of the necessary information for the
week was exchanged, thus removing the need to the scheduled call, the use of “at least” allows for this kind
of flexibility. R4 is applicable to those Reliability Coordinators engaged in activities related to R1 and
subsequently R1.7, it is unlikely that Reliability Coordinators whom are geographically and electrically distant
will have mutually agreed upon operating procedures (per R1), and as such they are not applicable to R4.
R5, as written, is confusing. The recommended fix is to delete “all other” and replace with “impacted”.
Response: This requirement continues the current practice of informing all RCs of ARIs. Due to the nature of
an ARI, this requirement is typically implemented as an RCIS message or a hotline call to all RC’s. This is
intended to make all RCs aware of ARIs and support situational awareness.
Response: The RCSDT thanks you for your comments.
United Illuminating Company
Comments: 1. COM-002 R2 seems awkwardly worded.
R2. Each [Entity] that is the recipient of a Reliability Directive issued per Requirement R1, shall repeat,
restate, rephrase or recapitulate the Reliability Directive with enough details that the accuracy of the message
has been confirmed. " R2 as it is written says the repeat is confirming the accuracy of the message itself. I
think it is agreed that the repeat back in R2 is to allow the issuer of the Directive to confirm that the message
was received accurately understood by the recipient. I suggest:R2. Each [Entity] that is the recipient of a
Reliability Directive issued per Requirement R1, shall repeat, restate, rephrase or recapitulate the Reliability
Directive with enough details to allow the Issuer to confirm that the directive recipient accurately understands
the Directive"
Response: The RCSDT agrees with the intent of your comment and has modified COM-002-3, R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider
that is the recipient of a Reliability Directive issued in accordance with Requirement R1, shall repeat,
restate, rephrase or recapitulate the Reliability Directive.
2. The VSL for R2 is severe and states "The responsible entity that was the recipient of a Reliability Directive
failed to repeat, restate, rephrase or recapitulate the Reliability Directive with enough details that the accuracy
of the message was confirmed." The purpose of the R2 repeat-back is to allow the Issuer verify the message
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was accurately received. This VSL penalizes the responsible entity for not accurately receiving the message.
The VSL should penalize the refusal of the registered entity to repeat back the message not for receiving the
message incorrectly. Suggested rewording:"The responsible entity that was the recipient of a Reliability
Directive failed to repeat, restate, rephrase or recapitulate the Reliability Directive with enough details that the
accuracy of the message can be evaluated by the entity issuing the Reliability Directive"3. United
Illuminating does agree with the definition of Reliability Directive and Emergency.
Response: The RCSDT agrees and has revised the VSL to:
The responsible entity that was the recipient of a Reliability Directive failed to repeat, restate, rephrase or
recapitulate the Reliability Directive. with enough details that the accuracy of the message was confirmed.
Response: The RCSDT thanks you for your comments.
Shell Energy North America (US),
L.P.
July 14, 2011
The introduction of the definition of “Reliability Directive” and its connection to the definition of “Emergency”
within this Project brings much needed clarity for the sector and will promote consistency between Regional
Entities and within the audits of Registered Entities. Shell Energy supports the removal of Purchasing Selling
Entities as a function to which IRO-001 applies. This removal recognizes that PSEs do not play a role in
reliability coordination under this standard since they have no authorities and no abilities to assume or
perform responsibilities associated with reliability coordination. This conclusion is reinforced by the adoption
of the defined term “Reliability Directive”. Where a RC, TOP, or BA needs to address an Emergency they do
not contact, consult, or direct a PSE to take action that would address the Emergency. Rather, where the
PSE is a user of the grid to perform or execute transactions, it is subject to the actions of these other entities
that have the authority to stop, curtail, or alter the submitted transactions of the PSE in a way that aids in
resolving the problem. With the fitting adoption of “Reliability Directive” into COM-002 as well, Shell Energy
does not believe it is necessary or appropriate for the applicability of this standard to include Purchasing
Selling Entities, as is contained in the current draft proposal. This standard does not apply to PSEs today,
however, during the progression of Project 2006-06 this applicability was added to an early draft version that
preceded the discussions and clarification that comes from the definition of a Reliability Directive in the
standard. Shell Energy does not support the inclusion of PSEs in the current draft version of COM-002, and
feels that it should be removed. The purpose of this standard is, “To ensure Emergency communications
between operating personnel are effective” and relates directly to the capabilities and authorities established
for the RC, TOP, or BA that requires actions to be taken by a recipient of a Reliability Directive. As noted
previously, PSEs are acted upon by the entities with the necessary authority, and are not in a role that would
initiate or fulfill the required actions. As additional matters related to the clarification and cleanup of the
standards in this project, the implementation plans for both IRO-001 and COM-001 erroneously contain
references to PSEs in the sections “Functions that Must Comply with the Requirements”. These references
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need to be removed.
Response: The RCSDT thanks you for your comments. The applicability of COM-001 and COM-002 were revised to be consistent and only include the RC, TOP,
BA, DP and GOP.
American Electric Power
The language used in COM-002-3 R2 including “with enough details that the accuracy of the message has
been confirmed” is subjective and ambiguous.
Response: The RCSDT agrees with the intent of your comment and has modified COM-002-3, R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider
that is the recipient of a Reliability Directive issued in accordance with Requirement R1, shall repeat,
restate, rephrase or recapitulate the Reliability Directive.
IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower case (while it appears
that “Directives” is a subset of “directions”). We believe that this muddies the waters and could bring
numerous conversations and dialog into scope unnecessarily. The end result is that the RC has the right to
issue and use “Directives” and anything short of this could just be communications. For example, a number of
entities that are Reliability Coordinators also facilitate energy markets. There are many communications
related to markets that probably should be out of scope with respect to the standards. Furthermore, it might
not be clear what role (eg Reliability Coordinator, market operator, etc) the staff at these entities are fulfilling.
Response: IRO-001 is written so that typical daily operating orders or directives could be used, and also to
cover emergency scenarios, but stating the use of Reliability Directives is included. The requirement
language specifically ties back to Requirement R2 which states that the RC “shall take actions or direct
actions, which could include issuing Reliability Directives, “. This is the “direction in accordance with
Requirement R2” stated in R3 and the “direction in accordance with Requirement R3” stated in R4.
Response: The RCSDT thanks you for your comments.
American Transmission
Company
July 14, 2011
None
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ISO New England
July 14, 2011
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The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving the as the Transmission Operator or Balancing Authority. We believe that it should never be
necessary for these System Operators to issue Reliability Directives to themselves in the first example or to
their co-worker in the second example to demonstrate compliance to NERC standards. How the entity
coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles
is a corporate governance issue that should not be confused or complicated by the NERC standards. Thus,
we believe that standards should be made clear that the Reliability Directive is directed to another
company.We believe that, in place of requiring an operator, in real-time, to state “this is a Reliability Directive,”
there should be an allowance for an entity to develop procedures indicating, in advance, their expectations of
three-part to their sub-operating entities. Therefore, we suggest modifying R1 to be “When a Reliability
Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action,
either verbally, when the communication is issued, or in advance through documented procedures, as a
Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time.]” Also, we believe
that the definition of Emergency, as currently cited in these draft Standards and included in the existing NERC
Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to make the
Standards more crisp, clear and enforceable. Because the Project 2007-03 Real-Time Operations SDT
proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the
change to the definition should be coordinated with that team. There is a text box in IRO-005-4 that indicates
this standard will be retired. Yet, there still remain requirements in the standard and various other associated
documentation indicates requirements are being move to this standard. Please delete the text box.IRO-014-2
R4 already includes a requirement to have weekly conference calls that should suffice. IRO-014-2 R2 seems
to recognize that these Operating Procedures, Processes and Plans likely will not need to be discussed
weekly as it only requires an annual update. In the definition of Reliability Directive, we suggest changing “to
address an Emergency” to “to address a reliability constraint or a declared Emergency”. Further,
Requirement R2 in IRO-001 contains the words “which could include issuing Reliability Directives” but
Reliability Directives are not referenced anywhere else in the standard. This inclusion seems unnecessary
since without it, R2 already requires that the RC take actions or direct actions by others to prevent identified
events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts.
Whether or not a Reliability Directive is issued is irrelevant in this requirement. We suggest that these words
be removed. Note that COM-002 already stipulates the requirement for 3-part communication when a
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Reliability Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is
unnecessary.
Response: The RCSDT thanks you for your comments. See response to MRO above.
ERCOT ISO
July 14, 2011
The SDT did not address all of our concerns with COM-002-3 from the last posting. For entities registered as
multiple functions, the combination of the definition of Reliability Directive and Requirement R1 could be
confused to require a company to issue directives to itself. There are several organizations registered as a
Reliability Coordinator, Transmission Operator and Balancing Authority. In these companies, it is not
uncommon for those responsibilities to be distributed across multiple desks. Thus, for certain situations, a
single System Operator may actually be the Reliability Coordinator and the Transmission Operator. In other
situations, the System Operator serving the Reliability Coordinator function may be adjacent to the System
Operator serving the as the Transmission Operator or Balancing Authority. We believe that it should never be
necessary for these System Operators to issue Reliability Directives to themselves in the first example or to
their co-worker in the second example to demonstrate compliance to NERC standards. How the entity
coordinates its actions among its Reliability Coordinator, Balancing Authority and Transmission Operator roles
is a corporate governance issue that should not be confused or complicated by the NERC standards. Thus,
we believe that standards should be made clear that the Reliability Directive is directed to another company.
We believe that, in place of requiring an operator, in real-time, to state “this is a Reliability Directive,” there
should be an allowance for an entity to develop procedures indicating, in advance, their expectations of threepart to their sub-operating entities. Therefore, we suggest modifying R1 to be “When a Reliability Coordinator,
Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action, either verbally,
when the communication is issued, or in advance through documented procedures, as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time.]” Also, we believe that the definition of
Emergency, as currently cited in these draft Standards and included in the existing NERC Glossary should be
modified to include the NERC Glossary term Adverse Reliability Impact to make the Standards more crisp,
clear and enforceable.
Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the
definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting, the change to the definition
should be coordinated with that team.
There is a text box in IRO-005-4 that indicates this standard will be
retired. Yet, there still remain requirements in the standard and various other associated documentation
indicates requirements are being move to this standard. Please delete the text box.
IRO-014-2 R4
already includes a requirement to have weekly conference calls that should suffice. IRO-014-2 R2 seems to
recognize that these Operating Procedures, Processes and Plans likely will not need to be discussed weekly
as it only requires an annual update.
In the definition of Reliability Directive, we suggest changing “to
address an Emergency” to “to address a reliability constraint or a declared Emergency”. Further, Requirement
R2 in IRO-001 contains the words “which could include issuing Reliability Directives” but Reliability Directives
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are not referenced anywhere else in the standard. This inclusion seems unnecessary since without it, R2
already requires that the RC take actions or direct actions by others to prevent identified events or mitigate
the magnitude or duration of actual events that result in Adverse Reliability Impacts. Whether or not a
Reliability Directive is issued is irrelevant in this requirement. We suggest that these words be removed. Note
that COM-002 already stipulates the requirement for 3-part communication when a Reliability Directive is
issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is unnecessary.
Response: The RCSDT thanks you for your comments. See response to MRO above.
WECC
Suggested minor revision to the definition of Reliability Directive as follows (change in caps)A communication,
IDENTIFIED AS A RELIABILITY DIRECTIVE, initiated by a Reliability Coordinator, Transmission Operator, or
Balancing Authority where action by the recipient is necessary to address an Emergency. Clearly identifying a
communication as a Reliability Directive provides immediate information to the recipient as to the nature of
the communications.
Response: The RCSDT thanks you for your comments. The RCSDT believes embedding the term in “Reliability Directive” in the definition is a not proper method
for defining a term.
BGE
BGE has no additional comments.
Duke Energy
o COM-002-3 contains the proposed definition “Reliability Directive”. We continue to believe Requirement R1
should be deleted and that this definition should contain the phrase “identified as a Reliability Directive to the
recipient”. Otherwise, compliance controversies will arise when auditors second-guess the RC, TOP or BA’s
judgment regarding whether or not an abnormal system condition met the definition of “Emergency”, and
warranted a “Reliability Directive” with 3-part communication. A conforming change will need to be made to
R2, since it refers to R1. This change in the definition of “Reliability Directive” is also needed because this
term is used in other standards such as IRO-001-2, and without repeating a similar requirement to COM-0023 requirement R1 in IRO-001-2, there is potential for confusion.
Response: The RCSDT disagrees as the suggestion embeds a requirement in a definition. The SDT
believes the requirements of COM-002 are clear as written.
o We disagree with the VSL for COM-002-3. This is clearly a requirement with two possible compliance
failures: Failure to acknowledge a correct repeat-back, and failure to resolve an incorrect repeat-back. These
failures have dramatically different consequences, which the drafting team should recognize via a graduated
VSL. We think that the failure to acknowledge should either be “Lower” or “Medium”.
Response: The RCSDT contends that missing the requirement is a binary violation that results in a severe
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VSL. You are including risk to the BES in your proposal for the VSL. Risk to the BES is captured in VRFs,
while VSLs consider the degree to which the entity failed to meet the Requirement..
O Requirement R2 of IRO-001-2 is unclear and should be reworded as follows:
“Each Reliability Coordinator shall take actions or direct actions (which could include issuing Reliability
Directives to Transmission Operators, Balancing Authorities, Generator Operators, Interchange Coordinators
and Distribution Providers within its Reliability Coordinator Area) to either prevent identified events that could
result in an Adverse Reliability Impact, or mitigate the magnitude or duration of actual events that result in
Adverse Reliability Impacts.”
Response: The RCSDT believes that the suggested revision does not add further clarity to the requirement.
o Various changes have been made to the defined term “Adverse Reliability Impact” as this project has
progressed. We believe the latest change should not be made, and the Phrase “uncontrolled separation”
should be reinserted in the definition, because that phrase is part of the EPAct 2005 legislation definition of
“reliable operation”. Here is the text from the legislation: “The term ‘reliable operation’ means operating the
elements of the bulk-power system within equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cyber security incident, or unanticipated failure of system elements.”
Response: During the last posting of the proposed definition, the RCSDT received the following comment
and revised the definition appropriately: “This change is problematic in that any automatic protective element
operation that trips a BES element could be construed to be an Adverse Reliability Impact.”. The modification
eliminated the phrase “that affects a widespread area of the Interconnection” which clarified the scope of the
definition. “Uncontrolled separation” has been deleted from the definition, as it is included in the definition of
Cascading.
Response: The RCSDT thanks you for your comments. Please see responses above.
CECD
1. COM-002 R2 states that "the recipient of a Reliability Directive issued per Requirement R1, shall repeat,
restate, rephrase or recapitulate the Reliability Directive with enough details that the accuracy of the message
has been confirmed." Recommend a change to "the recipient of a Reliability Directive issued per Requirement
R1, shall repeat, restate, rephrase or recapitulate the Reliability Directive with enough details that the desired
outcome of the message is clear".
Response: The RCSDT agrees with the intent of your comment and has modified COM-002-3, R2 as:
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider that is
the recipient of a Reliability Directive issued in accordance with Requirement R1, shall repeat, restate,
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rephrase or recapitulate the Reliability Directive.
2. IRO-001 R2 states "Each Reliability Coordinator shall take actions or direct actions which could include
issuing Reliability Directives of Transmission Operators, ...." Recommend a change to "Each Reliability
Coordinator shall take actions or direct actions which could include issuing Reliability Directives [See COM002] to Transmission Operators, ..."
Response: Based on feedback from other stakeholders, the RCSDT believes that the existing verbiage is
clear and does not require further revision.
3. IRO-001 R4 states entities "shall inform its Reliability Coordinator upon recognition of its inability to
perform as directed per Requirement R3." Recommend a change to, entities "shall inform its Reliability
Coordinator upon recognition of its inability to perform as directed."
Response: Based on feedback from other stakeholders, the RCSDT believes that the existing verbiage is
clear and does not require further revision.
Response: The RCSDT thanks you for your comments.
Indeck Energy Services
City of Springfield, IL - City Water
Light and Power (CWLP)
CWLP generally concurs with and supports comments previously submitted by the SERC Operating
Committee where those comments are not in conflict with the specific comments above.
Response: The RCSDT thanks you for your comments.
South Carolina Electric and Gas
1.
Reliability Directives may be issued by blast calls from Reliability Coordinators. It is inefficient and may
be a hindrance to reliability to require 3-part communications in these instances.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is
efficient and effective. The RCSDT believes Reliability Directives issued in mass should be defined by
procedure, and that the procedure would establish a method of affirmation and notice of implementation.
2.
July 14, 2011
There are several organizations registered as BAs, RCs and TOPs. It is not uncommon for those entities
to be distributed across multiple desks in the same control room without regard to how an entity is
registered. Thus, a single System Operator may perform functions that are categorized under two or more
of those functional entities. The drafting team should clarify that under no circumstances should that
System Operator be required to issue a Reliability Directive to himself. This is a corporate governance
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issue.
Response: The RCSDT believes that any Registered Entity or person operating as such must
understand the intent of the issued Reliability Directive, and that the issuer of the Reliability Directive
believe that the Reliability Directive was correctly received. COM-002 should not be construed to mean
that an individual serving in two functions be required to issue a Reliability Directive to himself, but rather
it is expected that such an individual would appropriately address the reliability issues as required by the
function they are serving and its subsequent responsibilities
3.
In IRO-014, R1, delete sub-requirement 1.7. The requirement for weekly conference calls related to
operating procedures is duplicative to R4 and could be burdensome while adding very little value under
certain circumstances.
Response: R1, Part 1.7 requires an entity to address how and when they will hold conference calls in
their Operating Plans, Processes or Procedures. R4 requires the participation in those calls.
4.
In IRO-014, R4, delete the phrase “(per Requirement 1, Part 1.7)” as a conforming change.
Response: R1, Part 1.7 requires an entity to address how and when they will hold conference calls in
their Operating Plans, Processes or Procedures. R4 requires the participation in those calls.
5. In IRO-014, Requirements R6-R8 allow at least the theoretical possibility that an RC may determine an
Adverse Reliability Impact in another RC’s area that the other RC neither can see nor believes that any
action should be taken. R7 puts the burden on the first RC to develop a plan that it cannot implement
because it has no agreement with the BAs and TOPs in the other RC area. As such, this requirement is
unenforceable.
Response: You are correct. Requirements R6-R8 are translated from IRO-016-1, Requirement R1. If an
RC sees a problem and another does not see the same problem, then there may be an issue with
someone’s model or processes or procedures. The RC’s are supposed to have coordinated Operating
Plans, Processes or Procedures to operate reliably. R6-R8 are only applicable if one of the two (or more)
RCs do not see that a problem exists. It would be a detriment to reliability for both RCs to take no action.
RCs are required to coordinate actions under existing IRO-016-1, R1. If one RC identifies a problem and
provides an action plan to another RC to mitigate the problem, the second RC is obligated under R8 to
implement it. We have revised the R8 to clarify this intent.
Revised R8. During those instances where Reliability Coordinators disagree on the existence of an
Adverse Reliability Impact, each Reliability Coordinator shall implement the action plan developed by
the Reliability Coordinator that identified the Adverse Reliability Impact unless such actions would
violate safety, equipment, regulatory or statutory requirements.
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6. Please review all the implementation plans to be sure the applicable entities match those in the
standards.
Response: We have revised the implementation plans to reflect the appropriate applicability.
Response: The RCSDT thanks you for your comments.
Independent Electricity System
Operator
1. IRO-001: Reliability Directive: We do not agree with the proposed definition since it addresses
Emergencies only. There are situations where a Reliability Directive is issued such that the directed action
must be taken by the receiving entity to address a reliability constraint or any condition on the BES which if
left unattended could, in the judgment of the issuing entity, lead to an Emergency. These conditions
themselves do not constitute an Emergency which is defined as “Any abnormal system condition that requires
automatic or immediate manual action to prevent or limit the failure of transmission facilities or generation
supply that could adversely affect the reliability of the Bulk Electric System.” There could be no abnormal
condition but the actions must nevertheless be taken promptly to prevent the bulk electric system from
entering into an abnormal condition. We therefore suggest the term Reliability Directive be revised to:
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator or
Balancing Authority where action by the recipient is necessary to address a reliability constraint or an
Emergency.
Response: The RCSDT believes that your comment concerns “directives” or “instructions” for normal
operational activities rather than a Reliability Directive. There is no requirement preventing an entity from
issuing either directives or instructions for the situations you mention. The intent of creating a Reliability
Directive definition is to ensure that communications is tightened during Emergencies (per blackout report).
When an RC issues a Reliability Directive, the RC has made a deliberate decision to formally end
collaboration and require specific action(s).
2. IRO-001, Requirement R2: This requirement contains the words “which could include issuing Reliability
Directives” which is not referenced anywhere else in the standard. We do not think this inclusion is necessary
since without it, R2 already requires that the RC take actions or direct actions by others to prevent identified
events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts.
Whether or not a Reliability Directive is issued is irrelevant in this requirement. We suggest to remove these
words. Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability
Directive is issued. The inclusion of “which could include issuing Reliability Directives” in IRO-001 is
unnecessary. We suggest replacing “identified events” with “anticipated events”. This requirement also lists
Interchange Coordinators as one of the recipients of Reliability Directives which is not consistent with the
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implementation plan.
Response: R2 requires the Reliability Coordinator to act. These actions could in include Reliability Directives
in the case of an Emergency. However, issuing Reliability Directives might not always be necessary, as the
Reliability Coordinator may be acting proactively well in advance of an emergency. R2 promotes this
proactive approach, but reserves the use of Reliability Directives for circumstances that require its use. Your
suggested edits are not supported by the majority of stakeholder comments. The Interchange Coordinator
has been removed from the standard.
3. IRO-014: R4 as written creates unnecessary requirements for an RC to participate in conference calls for
issues that may not affect the RC itself. We suggest to reinstate the original word “impacted” as opposed to
“other”, and remove the words “within the same Interconnection” since such calls and coordination may be
required for RCs on both side of the Interconnection boundary. Same change suggested for R5, i.e. replace
“other” with “impacted”.
Response: The requirement for weekly conference calls exists in IRO-015-1. The RCSDT has revised the
requirement and incorporated it into proposed IRO-014-2. IRO-14-2, R4 is applicable to those Reliability
Coordinators engaged in activities related to R1 and subsequently R1.7, it is unlikely that Reliability
Coordinators that are geographically and electrically distant will have mutually agreed upon operating
procedures (per R1), and as such they are not applicable to R4. If RCs in different interconnections have
operating procedures (per R1) with each other, then these operating procedures may include specifications
for conference calls at least weekly.
4. If an entity provides Interpersonal Communication for day-to-day communication using two different media,
e.g. radio and telephone, the proposed definition of Alternative Interpersonal Communication suggests that it
would not be possible for one medium to be used as the Alternative Interpersonal Communication for the
other since the two media are both used every day.
Response: The intent of AIC is to make sure there is an alternative in case the IC fails. If you have two, you
may designate one as the AIC regardless of how often you use it.
5. COM-001-2 R10 suggests that the responsible entity must wait for at least 30 minutes before notifying
other entities of the failure of its Interpersonal Communication capability. We recommend changing “that lasts
30 minutes” to “that lasts or is expected to last 30 minutes”. This allows responsible entities to start notifying
other entities earlier.
July 14, 2011
98
Consideration of Comments on Reliability Coordination — Project 2006-06
Organization
Yes or No
Question 6 Comment
Response: The requirement is written such that an outer bound is set for notifications. An entity does not
have to wait and can begin notifications immediately if it knows that an outage will last more than 30 minutes.
6. In IRO-005-4 R1: Delete “notify”.
Response: The phrase “issue an alert” was removed in the redline version but was not removed from the
clean version. This was corrected.
Response: The RCSDT thanks you for your comments.
July 14, 2011
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 3, 2010.
11. Initial Ballot conducted February 25 through March 7, 2011.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the initial ballot. The team is posting for a
successive ballot.
Future Development Plan:
Anticipated Actions
1. Post Standards for a successive ballot.
2. Respond to comments on Successive ballot
3. Standards posted for recirculation ballot
Draft 5:
December 29, 2011
Anticipated Date
January-February
2012
March - April 2012
May 2012
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4. Standards to be sent to BOT for approval.
June 2012
5. Standards filed with regulatory authorities.
August 2012
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any medium that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal
Communications used for day-to-day operation.
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A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To establish Interpersonal Communication capabilities for the exchange of
Interconnection and operating information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter following applicable
regulatory approval – or in those jurisdictions where no regulatory approval is required,
the first day of the first calendar quarter following Board of Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal Communications capability with
the following entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
R1.2.
Adjacent Reliability Coordinators within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communications capability with the following entities: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
R2.2.
Adjacent Reliability Coordinators within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communications capability with
the following entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
Draft 5:
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission Operator Area.
R3.3.
Each Distribution Provider within its Transmission Operator Area.
R3.4.
Each Generator Operator within its Transmission Operator Area.
R3.5.
Adjacent Transmission Operators synchronously connected within the same
Interconnection.
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R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communications capability with the following entities: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission Operator Area.
R4.3.
Adjacent Transmission Operators synchronously connected within the same
Interconnection.
R5. Each Balancing Authority shall have Interpersonal Communications capability with the
following entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R5.1.
Its Reliability Coordinator.
R5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
R5.3.
Each Distribution Provider within its Balancing Authority Area.
R5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
R5.5.
Adjacent Balancing Authorities.
R6. Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area).
R6.3.
Adjacent Balancing Authorities.
R7. Each Distribution Provider shall have Interpersonal Communications capability with
the following entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communications capability with the
following entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communications capability at least once per calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
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designate a replacement Alternative Interpersonal Communications capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1 through R6 within 60 minutes of the
detection of a failure of its Interpersonal Communications capabilities that lasts 30
minutes or longer. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of
its Interpersonal Communication capabilities shall consult with their Transmission
Operator or Balancing Authority as applicable to determine a mutually agreeable time
for the restoration of Interpersonal Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communications capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. Evidence could include, but
is not limited to:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communications capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with adjacent Reliability Coordinators within the same Interconnection.
Evidence could include, but is not limited to
Draft 5:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts
of voice recordings
•
electronic communications
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•
or equivalent evidence. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communications capability with its Reliability Coordinator, and within
its Transmission Operator Area each Balancing Authority, Distribution Provider and
Generator Operator. Evidence could include, but is not limited to
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts
of voice recordings,
•
electronic communications
•
or equivalent evidence. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communications capability with its Reliability
Coordinator and with each Balancing Authority within its Transmission Operator Area
and adjacent Transmission Operators synchronously connected within the same
Interconnection. Evidence could include, but is not limited to
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts
of voice recordings
•
electronic communications
•
or equivalent evidence. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communications capability with its Reliability Coordinator, each
Transmission Operator that operates Facilities within its Balancing Authority Area,
each Distribution Provider within its Balancing Authority Area, each Generator
Operator that operates Facilities within its Balancing Authority Area, and each adjacent
Balancing Authority. Evidence could include, but is not limited to
Draft 5:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
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•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence . (R5)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communications capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and adjacent Balancing Authorities. Evidence could include, but is not
limited to
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence (R6)
M7. Each Distribution Provider shall have and provide upon request evidence that that it
has Interpersonal Communications capability with its Transmission Operator and its
Balancing Authority. Evidence could include, but is not limited to
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence (R7)
M8. Each Generator Operator shall have and provide upon request evidence that that it has
Interpersonal Communications capability with its Balancing Authority and its
Transmission Operator. Evidence could include, but is not limited to
Draft 5:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
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•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence (R8)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least on a monthly basis, its
Alternative Interpersonal Communications capabilities designated in R2, R4 or R6. If
the test was unsuccessful, the entity shall have and provide upon request evidence that
it initiated action to repair or designated a replacement Alternative Interpersonal
Communications capability within 2 hours. Evidence could include, but is not limited
to dated test records, dated operator logs, dated voice recordings or dated transcripts of
voice recordings, electronic communications, or equivalent evidence. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasted 30 minutes or longer. Evidence could include, but is not limited to dated
operator logs, dated voice recordings or dated transcripts of voice recordings,
electronic communications, or equivalent evidence. (R10.)
M11. Each Distribution Provider and Generator Operator shall have and provide upon
request evidence that it consulted with their Transmission Operator or Balancing
Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. Evidence could include, but is not limited to
dated operator logs, dated voice recordings or dated transcripts of voice recordings,
electronic communications, or equivalent evidence. (R11.)
M12.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
For entities that do not work for the Regional Entity, the Regional Entity shall
serve as the Compliance Enforcement Authority.
For Reliability Coordinators that work for their Regional Entity, the ERO or a
Regional Entity approved by the ERO and FERC or other applicable
governmental authorities shall serve as the Compliance Enforcement Authority.
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Violation Investigation
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Self-Reporting
Complaint
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
o Each Reliability Coordinator shall keep the most recent twelve months of
historical data (evidence) for Requirements R1, R2, R9 and R10,
Measures M1, M2, M9, and M10.
o Each Transmission Operator shall keep the most recent twelve months of
historical data (evidence) for Requirements R3, R4, R9 and R10,
Measures M3, M4, M9 and M10.
o Each Balancing Authority shall keep the most recent twelve months of
historical data (evidence) for Requirements R5, R6, R9, and R10,
Measures M5, M6, M9, and M10.
o Each Distribution Provider shall keep the most recent twelve months of
historical data (evidence) for Requirements R7 and R11, Measures M7
and M11.
o Each Generator Operator shall keep the most recent twelve months of
historical data (evidence) for Requirements R8 and R11, Measures M8
and M11.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider or Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliance until the
Compliance Enforcement Authority finds it compliant or for the time period
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 5:
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2.
R#
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
N/A
N/A
N/A
The Reliability Coordinator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 1.1 or 1.2.
R2
N/A
N/A
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
2.1 or 2.2.
R3
N/A
N/A
N/A
The Transmission Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 3.1, 3.2, 3.3,
3.4, or 3.5.
R4
N/A
N/A
N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
4.1 or 4.2.
N/A
N/A
N/A
The Balancing Authority failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 5.1, 5.2, 5.3,
5.4 or 5.5.
N/A
N/A
N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
R5
R6
Draft 5: December 29, 2011
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R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
6.1, 6.2 or 6.3.
R7
N/A
N/A
N/A
The Distribution Provider failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 7.1 or 7.2.
R8
N/A
N/A
N/A
The Generator Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 8.1 or 8.2.
R9
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications in
more than 2 hours and less than or
equal to 4 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications in
more than 4 hours and less than or
equal to 6 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications in
more than 6 hours and less than or
equal to 8 hours.
The responsible entity failed to test
the Alternative Interpersonal
Communications capability on at
least a monthly basis.
The responsible entity failed to notify
the impacted entities in more than 60
minutes but less than or equal to 70
minutes.
The responsible entity failed to notify
the impacted entities in more than 70
minutes but less than or equal to 80
minutes.
The responsible entity failed to notify
the impacted entities in more than 80
minutes but less than or equal to 90
minutes.
The responsible entity failed to notify
the impacted entities in more than 90
minutes.
R10
OR
The responsible entity tested the
Alternative Interpersonal
Communications capability and
identified a problem but didn’t initiate
action to repair or designate a
replacement Alternative Interpersonal
Communications in more than 8
hours.
OR
The responsible entity failed to notify
any impacted entities of the failure of
its Interpersonal Communications
capabilities.
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its
Draft 5: December 29, 2011
OR
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
Interpersonal Communications
capabilities within 60 minutes.
R11
N/A
Draft 5: December 29, 2011
N/A
N/A
The responsible entity failed to
consult with their Transmission
Operator or Balancing Authority
as applicable to determine a
mutually agreeable time to restore
the Interpersonal Communication
capability.
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E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
Draft 5: December 29, 2011
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007
2. Draft SAR Version 1 Comment Period ended February 14, 2007
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007
4. Draft Version 2 SAR comment period ended April 17, 2007
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 3, 2010.
11. Initial Ballot conducted February 25 through March 7, 2011.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contains revisions based on stakeholder comments on the third draft.initial ballot. The team is
posting for a 30 day pre-successive ballot review.
Future Development Plan:
Anticipated Actions
1. Respond to comments on third postingPost Standards for a
successive ballot.
2. Post Standards for pre-Respond to comments on Successive ballot
period.
Draft 4:
November 23, 20105:
December 29, 2011
Anticipated Date
March 2010JanuaryFebruary 2012
January 2011March
- April 2012
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3. Standards posted for initial and recirculation ballots.ballot
February 2011May
2012
4. Standards to be sent to BOT for approval.
March 2011June
2012
5. Standards filed with regulatory authorities.
June 2011August
2012
Draft 4:
November 23, 20105:
December 29, 2011
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Interpersonal Communication: Any mediumthodmedium that allows two or more individuals
to interact, consult, or exchange information.
Alternative Interpersonal Communication: Any method Interpersonal Communication that is
able to serve as a substitute for, and is redundant to normal Interpersonal Communication and
does not utilize the same infrastructure (medium) as, normal Interpersonal Communications used
for day-to-day operation.
Draft 4:
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A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To ensure that operating entities have adequateestablish Interpersonal
Communication capabilities for the exchange of Interconnection and operating
information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.Operator
4.2. Balancing Authorities.Authority
4.3. Reliability Coordinators.Coordinator
4.4. Distribution Providers.Provider
4.5. Generator Operators..Operator
5.
Effective Date:
The first day of the firstsecond calendar quarter following
applicable regulatory approval – or in those jurisdictions where no regulatory approval
is required, the first day of the first calendar quarter following Board of Trustees
adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
identify and test, on a quarterly basis, its Alternative Interpersonal Communications
capability used for communicating real-time operating information. If the test is
unsuccessful, the entity shall take action within 60 minutes to restore the identified
alternative or identify a substitute Alternative Interpersonal Communications
capability. [Violation Risk Factor: High][Time Horizon: Real-time Operations]
R1. Each Reliability Coordinator shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information:
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:]
R1.1.
All Transmission Operators, and Balancing Authorities and Interchange
Coordinators within its Reliability Coordinator Area.
R1.2.
Adjacent Reliability Coordinators within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]: ]
Draft 4:
R2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
R2.2.
Adjacent Reliability Coordinators within the same Interconnection.
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R3. Each Transmission Operator shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information:
[Violation Risk Factor: High][Time Horizon: Real-time Operations]:]
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission Operator Area.
R3.3.
Each Distribution Provider within its Transmission Operator Area.
R3.4.
Each Generator Operator within its Transmission Operator Area.
R3.5.
Adjacent Transmission Operators synchronously connected within the same
Interconnection.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission Operator Area.
R4.3.
Adjacent Transmission Operators synchronously connected within the same
Interconnection.
R5. Each Balancing Authority shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]:]
R5.1.
Its Reliability Coordinator.
R5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
R5.3.
Each Distribution Provider within its Balancing Authority Area.
R5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
R5.5.
Each Interchange Coordinator within its Balancing Authority area as well as
adjacent Interchange Coordinators.
R5.5.
Adjacent Balancing Authorities.
R6. Each Balancing Authority shall designate an Alternative Interpersonal
Communications capability with the following entities to exchange Interconnection and
operating information: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]:]
Draft 4:
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area)).
R6.3.
Adjacent Balancing Authorities.
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R7. Each Distribution Provider shall have Interpersonal Communications capability with
the following entities to exchange Interconnection and operating information:
[Violation Risk Factor: High][Time Horizon: Real-time Operations]
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communications capability with the
following entities to exchange Interconnection and operating information: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall,
on at least a monthly basis, test its Alternative Interpersonal Communications
capability. at least once per calendar month. If the test is unsuccessful, the responsible
entity shall initiate action to repair or designate a replacement Alternative Interpersonal
Communications capability within 2 hours. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority,
Distribution Provider, and Generator Operator shall notify impacted entities as
identified in Requirements R1 through R6 within 60 minutes of the detection of a
failure of its Interpersonal Communications capabilities that lasts 30 minutes or longer.
[Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
R11. Unless dictated by law or otherwise agreed to, each Reliability Coordinator,Each
Distribution Provider and Generator Operator that experiences a failure of any of its
Interpersonal Communication capabilities shall consult with their Transmission
Operator, or Balancing Authority, Generator Operator, Transmission Service Provider,
Load-Serving Entity, Purchasing-Selling Entity and Distribution Provider shall use
English as the language applicable to determine a mutually agreeable time for
communications between functional entities. the restoration of Interpersonal
Communication capability. [Violation Risk Factor: Medium] [][Time Horizon: Realtime Operations][SC1]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it has Interpersonal Communications
capability with all Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area and with adjacent Reliability Coordinators within the
same Interconnection. Evidence could include, but is not limited to :
Draft 4:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records,
•
dated operator logs,
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•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings,
•
electronic communications,
M1.•
or equivalent, that it identified and tested, on a quarterly basis,
alternative Interpersonal Communications capabilities used for communicating
real-time operating information. If the test was unsuccessful, the entity shall have
and provide upon request evidence that it took action within 60 minutes to restore
the identified alternative or identified a substitute Interpersonal Communications
capability. . (R1.)
M1. Each Reliability Coordinator shall have and provide upon request evidence that could
include, but is not limited to physical assets, dated equipment specifications and
installation documentation, dated test records, dated operator logs, dated and
timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent, that it has Interpersonal
Communications capability with all Transmission Operators, Balancing Authorities
and Interchange Coordinators within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. (R1.)
M1.M2.
Each Reliability Coordinator shall have and provide upon request
evidence that could include, but is not limited to physical assets, dated equipment
specifications and installation documentation, dated test records, dated operator logs,
dated and timestamped voice recordings or dated and timestamped transcripts of voice
recordings, electronic communications, or equivalent,Each Reliability Coordinator
shall have and provide upon request evidence that it designated an Alternative
Interpersonal Communications capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with adjacent
Reliability Coordinators within the same Interconnection. (R2.) Evidence could
include, but is not limited to
•
Each Transmission Operator shall have and provide upon request evidence that
could include, but is not limited to physical assets,
•
dated equipment specifications and installation documentation,
•
dated test records,
•
dated operator logs,
•
dated and timestampedtime-stamped voice recordings or dated and
timestampedtime-stamped transcripts of voice recordings,
•
electronic communications,
•
or equivalent, evidence. (R2.)
M2.M3.
Each Transmission Operator shall have and provide upon request
evidence that it has a Interpersonal Communications capability with its Reliability
Coordinator, with each Balancing Authority and each Distribution Provider and each
Generator Operatorand within its Transmission Operator Area. (R3.) each Balancing
Draft 4:
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Authority, Distribution Provider and Generator Operator. Evidence could include, but
is not limited to
•
Each Transmission Operator shall have and provide upon request evidence that
could include, but is not limited to physical assets,
•
dated equipment specifications and installation documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings or dated and time-stamped transcripts
of voice recordings,
•
electronic communications,
•
or equivalent, that evidence. (R3.)
M3.M4.
Each Transmission Operator shall have and provide upon request
evidence that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator, and with each Balancing Authority within its
Transmission Operator Area. (R4.) and adjacent Transmission Operators
synchronously connected within the same Interconnection. Evidence could include,
but is not limited to
•
Each Balancing Authority shall have and provide upon request evidence that
could include, but is not limited to physical assets,
•
dated equipment specifications and installation documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings or dated and time-stamped transcripts
of voice recordings,
•
electronic communications,
•
or equivalent, evidence. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communications capability with its Reliability Coordinator, each
Transmission Operator that operates Facilities within its Balancing Authority Area,
each Distribution Provider within its Balancing Authority Area, each Generator
Operator that operates Facilities within its Balancing Authority Area, and each adjacent
Balancing Authority. Evidence could include, but is not limited to
Draft 4:
•
physical assets
•
dated equipment specifications and installation documentation
•
dated test records
•
dated operator logs
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings
•
electronic communications
•
or equivalent evidence . (R5)
M4.M6.
Each Balancing Authority shall have and provide upon request
evidence that it designated an Alternative Interpersonal Communications capability
with its Reliability Coordinator, each Transmission Operator that operates Facilities
within its Balancing Authority Area, and each Generator Operator that operates
Facilities within its Balancing Authority Area and each Distribution Provider within its
Balancing Authority Area, and each Interchange Coordinator within its Balancing
Authority area as well as adjacent Interchange Coordinators. (R5)adjacent Balancing
Authorities. Evidence could include, but is not limited to
•
Each Balancing Authority shall have and provide upon request evidence that could
include, but is not limited to physical assets,
•
dated equipment specifications and installation documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings,
•
electronic communications,
M5.•
or equivalent, that it designated an Alternative Interpersonal
Communications capability with its Reliability Coordinator and each Transmission
Operator that operates Facilities within its Balancing Authority Area. evidence
(R6)
M6.M7.
Each Distribution Provider shall have and provide upon request
evidence that could include, but is not limited to physical assets, dated equipment
specifications and installation documentation, dated test records, dated operator logs,
dated voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent, that it has Interpersonal Communications capability
with its Transmission Operator and its Balancing Authority. (R7) Evidence could
include, but is not limited to
Draft 4:
•
Each Generator Operator shall have and provide upon request evidence that could
include, but is not limited to physical assets,
•
dated equipment specifications and installation documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings,
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•
electronic communications,
•
or equivalent, evidence (R7)
M7.M8.
Each Generator Operator shall have and provide upon request
evidence that that it has Interpersonal Communications capability with its Balancing
Authority and its Transmission Operator. (R8) Evidence could include, but is not
limited to
•
Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall have and provide upon request evidence that could include, but is not limited
tophysical assets
•
dated equipment specifications and installation documentation
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings or dated and time-stamped transcripts of
voice recordings,
•
electronic communications,
•
or equivalent, that evidence (R8)
M8.M9.
Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall have and provide upon request evidence that it tested, at least on a
monthly basis, its Alternative Interpersonal Communications capabilities designated in
R2, R4 or R6. If the test was unsuccessful, the entity shall have and provide upon
request evidence that it initiated action to repair or designated a replacement
Alternative Interpersonal Communications within 2 hours.capability within 2 hours.
Evidence could include, but is not limited to dated test records, dated operator logs,
dated voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent evidence. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall
have and provide upon request evidence that it notified impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasted 30 minutes or longer. Evidence could include, but is not limited to dated
operator logs, dated voice recordings or dated transcripts of voice recordings,
electronic communications, or equivalent evidence. (R10.)
M9.M11.
Each Distribution Provider and Generator Operator shall have and
provide upon request evidence that it consulted with their Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. Evidence could include, but is not limited to
dated operator logs, dated voice recordings or dated transcripts of voice recordings,
electronic communications, or equivalent, it notified impacted entities within 60
minutes of the detection of a failure of its Interpersonal Communications capabilities
that lasted 30 minutes or longer. (R10 evidence. (R11.)
M12.
Draft 4:
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
For entities that do not work for the Regional Entity, the Regional Entity shall
serve as the Compliance Enforcement Authority.
For Reliability Coordinators that work for their Regional Entity, the ERO or a
Regional Entity approved by the ERO and FERC or other applicable
governmental authorities shall serve as the Compliance Enforcement Authority.
1.2. Compliance Monitoring and Enforcement Processes
Compliance AuditsAudit
Self-CertificationsCertification
Spot Checking
Compliance Violation InvestigationsInvestigation
Self-Reporting
Complaints
Complaint
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
o Each Reliability Coordinator, shall keep the most recent twelve months of
historical data (evidence) for Requirements R1, R2, R9 and R10,
Measures M1, M2, M9, and M10.
o Each Transmission Operator, and shall keep the most recent twelve
months of historical data (evidence) for Requirements R3, R4, R9 and
R10, Measures M3, M4, M9 and M10.
o Each Balancing Authority shall keep the most recent twelve months of
historical data (evidence) for Requirements R1, R2, R3, R4, R5, R6, R9,
Draft 4:
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and R10, Measures M1, M2, M3, M4, M5, M6, M9, and M10 as
applicable...
o Each Distribution Provider shall keep the most recent twelve months of
historical data (evidence) for Requirements R7 and R10R11, Measures M7
and M10M11.
o Each Generator Operator shall keep the most recent twelve months of
historical data (evidence) for Requirements R8 and R10R11, Measures M8
and M10M11.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider or Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliance until the
Compliance Enforcement Authority finds it compliant or for the time period
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None
Draft 4:
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
2.
R#
R1
Violation Severity Levels
Lower VSL
The responsible entity tested
Alternative Interpersonal
Communications capability but failed
to take action within 60 minutes to
restore the identified alternative
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The responsible entity failed to test
its Alternative Interpersonal
Communications capability on a
quarterly basis.
OR
Failed to identify a substitute
Alternative Interpersonal
Communications capability
R1
N/A
N/A
N/A
The Reliability Coordinator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 1.1 or 1.2.
R2
N/A
N/A
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
2.1 or 2.2.
R3
N/A
N/A
N/A
The Transmission Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 3.1, 3.2, 3.3,
3.4, or 3.45.
R4
N/A
N/A
N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
4.1 or 4.2.
Draft 4: November 23, 20105: December 29, 2011
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R5
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
N/A
The Balancing Authority failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 5.1, 5.2, 5.3,
5.4 or 5.5.
R6
N/A
N/A
N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communications capability with one
or more of the entities listed in Parts
6.1, 6.2 or 6.23.
R7
N/A
N/A
N/A
The Distribution Provider failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 7.1 or 7.2.
R8
N/A
N/A
N/A
The Generator Operator failed to
have Interpersonal Communications
capability with one or more of the
entities listed in Parts 8.1 or 8.2.
R9
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications
withinin more than 2 hours and less
than or equal to 4 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications within
12 hours.in more than 4 hours and
less than or equal to 6 hours.
The responsible entity tested the
Alternative Interpersonal
Communications capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communications within
24 hours.in more than 6 hours and
less than or equal to 8 hours.
The responsible entity failed to test
the Alternative Interpersonal
Communications capability on at
least a monthly basis.
Draft 4: November 23, 20105: December 29, 2011
OR
The responsible entity tested the
Alternative Interpersonal
Communications capability and
identified a problem but didn’t initiate
action to repair or designate a
replacement Alternative Interpersonal
Communications within 2in more than
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R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
8 hours.
R10
The responsible entity failed to notify
the impacted entities in more than 60
minutes but less than or equal to 70
minutes.
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its normal
Interpersonal Communications
capabilities within 60 minutes.
The responsible entity failed to notify
the impacted entities in more than 80
minutes but less than or equal to 90
minutes.
OR
OR
The responsible entity failed to notify
the impacted entities in more than 90
minutes.
The responsible entity failed to notify
the impacted entities in more than 70
minutes but less than or equal to 80
minutes.
OR
The responsible entity failed to notify
any impacted entities of the failure of
its Interpersonal Communications
capabilities.
OR
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its
Interpersonal Communications
capabilities within 60 minutes.
R11
N/A
N/A
Draft 4: November 23, 20105: December 29, 2011
The responsible entity failed to notify
any impacted entities of the failure of
its normal Interpersonal
Communications capabilities.
N/A
The responsible entity failed to
consult with their Transmission
Operator or Balancing Authority
as applicable to determine a
mutually agreeable time to restore
the Interpersonal Communication
capability.
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E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised per SAR for Project 2006-06,
RC SDT
Revised
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e
Implementation Plan and Mapping Document for COM-001-2 – Communications
Approvals Requested
The RC SDT requests the approval of COM-001-2 – Communications and two new NERC
Glossary terms.
Prerequisite Approvals
•
None
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communications used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
• None.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1 standard and is proposing retiring four requirements (R1, R4,
R5 and R6). COM-001-1 requirement R1 is proposed to be replaced with COM-001-2 requirements
R1, R2, R3, R4, R5, R6, R7 and R8 to achieve clarity to which entities were required to have to
reliable communications. Requirement R2 in COM-001-1 will become requirement R9 in COM001-2. Requirement R3 in COM-001-1 has been included within R1 of COM-001-2. Requirement
R4 will remain enforceable until its inclusion into COM-003 being revised under Project 2007-02
Operating Personnel Communication Protocols and becomes mandatory and enforceable.
Requirement R5 in COM-001-1 is redundant with EOP-008-0, R1 and EOP-008-1, R1 and will be
retired upon the effective date of COM-001-2. COM-001-1, requirement R6 will be retired as it is
an ERO procedural requirement and does not impact reliability. Changes were made to eliminate
redundancies between standards (existing and proposed), to align with the ERO Rules of Procedure
and to address issues in FERC Order 693.
116-390 Village Blvd.
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609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan and Mapping Document for COM-001-2 Communications
Effective Dates
The first day of the second calendar quarter following applicable regulatory approval – or in those
jurisdictions where no regulatory approval is required, the first day of the first calendar quarter
following Board of Trustees adoption.
Retirements
COM-001-1.1 will be retired at midnight the day before COM-001-2 becomes effective with the
exception of Requirement R4. This requirement is being revised and will be included in Standard
COM-003-1, Operating Personnel Communications Protocols. COM-001-1.1, Requirement R4 will
be retired at midnight the day before COM-003-1 becomes effective.
July 10, 2009
2
Implementation Plan and Mapping Document for COM-001-2 Communications
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall
provide adequate and reliable
telecommunications facilities for the exchange
of Interconnection and operating information:
[Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor:
High]
R1.2.
Between the Reliability Coordinator
and its Transmission Operators and
Balancing Authorities. [Violation Risk
Factor: High]
R1.3.
R1.4.
June 8 2011
COM-001-2
R1.
R2.
With other Reliability Coordinators,
Transmission Operators, and
Balancing Authorities as necessary to
maintain reliability. [Violation Risk
Factor: High]
Where applicable, these facilities shall
be redundant and diversely routed.
[Violation Risk Factor: High]
R3.
Each Reliability Coordinator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R1.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R2.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R2.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Transmission Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
3
Implementation Plan and Mapping Document for COM-001-2 Communications
R4.
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission
Operator Area.
R3.3.
Each Distribution Provider within its Transmission
Operator Area.
R3.4.
Each Generator Operator within its Transmission
Operator Area.
R3.5.
Adjacent Transmission Operators synchronously
connected within the same Interconnection.
Each Transmission Operator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission
Operator Area.
R4.3.
Adjacent Balancing Authorities.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable
communications.
Proposed Replacement Requirement(s)
Already Approved Standard
COM-001-1.1
June 8 2011
4
Implementation Plan and Mapping Document for COM-001-2 Communications
R1.
Each Reliability Coordinator, Transmission
COM-001-2
Operator and Balancing Authority shall provide
R5. Each Balancing Authority shall have Interpersonal
adequate and reliable telecommunications facilities
Communications capability with the following entities:
for the exchange of Interconnection and operating
[Violation Risk Factor: High][Time Horizon: Real-time
information: [Violation Risk Factor: High]
Operations]
R1.1.
Internally. [Violation Risk
R5.1. Its Reliability Coordinator.
Factor: High]
R5.2. Each Transmission Operator that operates Facilities
R1.2.
Between the Reliability
within its Balancing Authority Area
Coordinator and its Transmission
Operators and Balancing Authorities.
R5.3. Each Distribution Provider within its Balancing
[Violation Risk Factor: High]
Authority Area
R1.3.
R1.4.
With other Reliability
Coordinators, Transmission Operators,
and Balancing Authorities as
necessary to maintain reliability.
[Violation Risk Factor: High]
R6.
Where applicable, these
facilities shall be redundant and
diversely routed. [Violation Risk
Factor: High]
R7.
June 8 2011
R5.4.
Each Generator Operator that operates Facilities
within its Balancing Authority Area
R5.5.
Adjacent Balancing Authorities.
Each Balancing Authority shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area).
R6.3.
Adjacent Balancing Authorities.
Each Distribution Provider shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
5
Implementation Plan and Mapping Document for COM-001-2 Communications
R8.
Each Generator Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable interpersonal
communications. R7 and R8 were created to address the FERC directive to “expands the applicability to include generator
operators and distribution providers and includes Requirements for their telecommunications facilities”
Already Approved Standard
COM-001-1.1
R2.
Each Reliability Coordinator,
Transmission Operator, and Balancing
Authority shall manage, alarm, test and/or
actively monitor vital telecommunications
facilities. Special attention shall be given to
emergency telecommunications facilities and
equipment not used for routine
communications. [Violation Risk Factor:
Medium]
Proposed Replacement Requirement(s)
COM-001-2
R9.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall, on at least a monthly basis, test its
Alternative Interpersonal Communications capability. If the test
is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal
Communications capability within 2 hours. [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
Notes:
Already Approved Standard
COM-001-1.1
R3.
Each Reliability Coordinator, Transmission
June 8 2011
Proposed Replacement Requirement(s)
COM-001-2
R1.
Each Reliability Coordinator, Transmission Operator, Balancing
6
Implementation Plan and Mapping Document for COM-001-2 Communications
Operator and Balancing Authority shall provide a
means to coordinate telecommunications among
their respective areas. This coordination shall
include the ability to investigate and recommend
solutions to telecommunications problems within
the area and with other areas. [Violation Risk
Factor: Lower]
Authority, Distribution Provider, and Generator Operator shall
notify impacted entities within 60 minutes of the detection of a
failure of its Interpersonal Communications capabilities that
lasts 30 minutes or longer. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability
None - retire
Coordinator, Transmission Operator, and
This requirement is being vetted by the OPCPSDT in COMBalancing Authority shall use English as the
003. This requirement and measure will be removed from
language for all communications between and
COM-001-1.1 upon the effective date of COM-003-1.
among operating personnel responsible for the realtime generation control and operation of the
interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities
may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Notes:
Already Approved Standard
June 8 2011
Proposed Replacement Requirement(s)
7
Implementation Plan and Mapping Document for COM-001-2 Communications
COM-001-1.1
R5.
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities.
[Violation Risk Factor: Lower]
EOP-008-0
R1. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall have a plan to continue reliability
operations in the event its control center becomes inoperable. The
contingency plan must meet the following requirements:
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be
viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that
there is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control
of critical transmission facilities, generation control,
voltage control, time and frequency control, control of
critical substation devices, and logging of significant power
system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with
other areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure
viability of the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating
personnel are able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take
more than one hour to implement the contingency plan for
June 8 2011
8
Implementation Plan and Mapping Document for COM-001-2 Communications
loss of primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and
Transmission Operator shall have a current Operating Plan describing
the manner in which it continues to meet its functional obligations
with regard to the reliable operations of the BES in the event that its
primary control center functionality is lost. This Operating Plan for
backup functionality shall include the following, at a minimum:
[Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
1.1. The location and method of implementation for providing
backup functionality for the time it takes to restore the primary
control center functionality.
1.2. A summary description of the elements required to support
the backup functionality. These elements shall include, at a
minimum:
1.2.1. Tools and applications to ensure that System Operators
have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
1.3. An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4. Operating Procedures, including decision authority, for use in
determining when to implement the Operating Plan for backup
functionality.
1.5. A transition period between the loss of primary control center
June 8 2011
9
Implementation Plan and Mapping Document for COM-001-2 Communications
functionality and the time to fully implement the backup
functionality that is less than or equal to two hours.
1.6. An Operating Process describing the actions to be taken
during the transition period between the loss of primary control
center functionality and the time to fully implement backup
functionality elements identified in Requirement R1, Part 1.2. The
Operating Process shall include at a minimum:
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the
transition from primary to backup functionality as well as
during outages of the primary or backup functionality.
1.6.3. Identification of the roles for personnel involved
during the initiation and implementation of the Operating
Plan for backup functionality.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1 as well as EOP-008-1
R1 which replaces it.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to
the requirements in Attachment 1-COM-001,
“NERCNet Security Policy.” [Violation Risk
Factor: Lower]
None - retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability
standard. It should be included in the ERO Rules of Procedure.
June 8 2011
10
Implementation Plan and Mapping Document for COM-001-2 Communications
Already Approved Standard
None
Proposed Replacement Requirement(s)
New Requirement
R11. Each Distribution Provider and Generator
Operator that experiences a failure of any of its
Interpersonal Communication capabilities shall
consult with their Transmission Operator or Balancing
Authority as applicable to determine a mutually
agreeable time to restore the Interpersonal
Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
June 8 2011
11
Implementation Plan and Mapping Document for COM-001-2 Communications
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
X
X
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
Communications
June 8 2011
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan for COM-001-2 – Communications
Approvals Requested
The RC SDT requests the approval of COM-001-2 – Communications and two new NERC
Glossary terms.
Prerequisite Approvals
•
None
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communications used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
• None.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1 standard and is proposing retiring three four requirements (R1,
R4, R5 and R6). COM-001-1 requirement R1 is proposed to be replaced with COM-001-2
requirements R1, R2, R3, R4, R5, R6, R7 and R8 to achieve clarity to which entities were required
to have to reliable communications. Requirement R2 in COM-001-1 will become requirement R9 in
COM-001-2. Requirement R3 in COM-001-1 has been included within R1 of COM-001-2.
Requirement R4 will remain enforceable until its inclusion into COM-003 being revised under
Project 2007-02 Operating Personnel Communication Protocols and becomes mandatory and
enforceable. Requirement R5 in COM-001-1 is redundant with EOP-008-0, R1 and EOP-008-1, R1
and is will be retired upon the effective date of COM-001-2. COM-001-1, requirement R6 will be
retired as it is an ERO procedural requirement and does not impact reliability. Changes were made
to eliminate redundancies between standards (existing and proposed), to align with the ERO Rules
of Procedure and to address issues in FERC Order 693.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Effective Dates
The first day of the first second calendar quarter following applicable regulatory approval – or in
those jurisdictions where no regulatory approval is required, the first day of the first calendar
quarter following Board of Trustees adoption.
Retirements
COM-001-1.1 will be retired at midnight the day before COM-001-2 becomes effective with the
exception of Requirement R4. This requirement is being revised and will be included in Standard
COM-003-1, Operating Personnel Communications Protocols. COM-001-1.1, Requirement R4 will
be retired at midnight the day before COM-003-1 becomes effective.
November 30, 2011
2
Mapping Document for COM-001-2
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard is implemented. If
the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall
provide adequate and reliable
telecommunications facilities for the exchange
of Interconnection and operating information:
[Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor:
High]
R1.2.
Between the Reliability Coordinator
and its Transmission Operators and
Balancing Authorities. [Violation Risk
Factor: High]
R1.3.
R1.4.
COM-001-2
R1.
R2.
With other Reliability Coordinators,
Transmission Operators, and
Balancing Authorities as necessary to
maintain reliability. [Violation Risk
Factor: High]
Where applicable, these facilities shall
be redundant and diversely routed.
[Violation Risk Factor: High]
R3.
Each Reliability Coordinator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R1.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R2.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R2.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Transmission Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission
Operator Area.
R3.3.
Each Distribution Provider within its Transmission
Operator Area.
R3.4.
Each Generator Operator within its Transmission
Operator Area.
R3.5.
Adjacent Transmission Operators synchronously
connected within the same Interconnection.
Each Transmission Operator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission
Operator Area.
R4.3.
Adjacent Balancing Authorities.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to
reliabilityreliable communications.
Already Approved Standard
R3.1.
Proposed Replacement Requirement(s)
COM-001-1.1
November 30, 2011
2
R1.
Each Reliability Coordinator, Transmission
COM-001-2
Operator and Balancing Authority shall provide
R5. Each Balancing Authority shall have Interpersonal
adequate and reliable telecommunications facilities
Communications capability with the following entities:
for the exchange of Interconnection and operating
[Violation Risk Factor: High][Time Horizon: Real-time
information: [Violation Risk Factor: High]
Operations]
R1.1.
Internally. [Violation Risk
R5.1. Its Reliability Coordinator.
Factor: High]
R5.2. Each Transmission Operator that operates Facilities
R1.2.
Between the Reliability
within its Balancing Authority Area
Coordinator and its Transmission
Operators and Balancing Authorities.
R5.3. Each Distribution Provider within its Balancing
[Violation Risk Factor: High]
Authority Area
R1.3.
R1.4.
With other Reliability
Coordinators, Transmission Operators,
and Balancing Authorities as
necessary to maintain reliability.
[Violation Risk Factor: High]
R6.
Where applicable, these
facilities shall be redundant and
diversely routed. [Violation Risk
Factor: High]
R7.
R5.4.
Each Generator Operator that operates Facilities
within its Balancing Authority Area
R5.5.
Adjacent Balancing Authorities.
Each Balancing Authority shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area).
R6.3.
Adjacent Balancing Authorities.
Each Distribution Provider shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R7.1.
November 30, 2011
Its Transmission Operator.
3
R7.2.
R8.
Its Balancing Authority.
Each Generator Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for to reliabilityreliable
interpersonal communications. R7 and R8 were 8 is created to address the FERC directive to “expands the applicability to include
generator operators and distribution providers and includes Requirements for their telecommunications facilities”
Already Approved Standard
COM-001-1.1
R2.
Each Reliability Coordinator,
Transmission Operator, and Balancing
Authority shall manage, alarm, test and/or
actively monitor vital telecommunications
facilities. Special attention shall be given to
emergency telecommunications facilities and
equipment not used for routine
communications. [Violation Risk Factor:
Medium]
Proposed Replacement Requirement(s)
COM-001-2
R9.
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall, on at least a monthly basis, test its
Alternative Interpersonal Communications capability. If the test
is unsuccessful, the entity shall initiate action to repair or
designate a replacement Alternative Interpersonal
Communications capability within 2 hours. [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
Notes:
Already Approved Standard
COM-001-1.1
November 30, 2011
Proposed Replacement Requirement(s)
COM-001-2
4
R3.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide a
means to coordinate telecommunications among
their respective areas. This coordination shall
include the ability to investigate and recommend
solutions to telecommunications problems within
the area and with other areas. [Violation Risk
Factor: Lower]
R1.
Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider, and Generator Operator shall
notify impacted entities within 60 minutes of the detection of a
failure of its Interpersonal Communications capabilities that
lasts 30 minutes or longer. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability
None - retire
Coordinator, Transmission Operator, and
This requirement is being vetted by the OPCPSDT in COMBalancing Authority shall use English as the
003. This requirement and measure will be removed from
language for all communications between and
COM-001-1.1 upon the effective date of COM-003-1.
among operating personnel responsible for the realtime generation control and operation of the
interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities
may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Notes:
Already Approved Standard
November 30, 2011
Proposed Replacement Requirement(s)
5
COM-001-1.1
R5.
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall have
written operating instructions and procedures to
enable continued operation of the system during
the loss of telecommunications facilities.
[Violation Risk Factor: Lower]
EOP-008-0
R1. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall have a plan to continue reliability
operations in the event its control center becomes inoperable. The
contingency plan must meet the following requirements:
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be
viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that
there is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control
of critical transmission facilities, generation control,
voltage control, time and frequency control, control of
critical substation devices, and logging of significant power
system events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with
other areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure
viability of the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating
personnel are able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take
November 30, 2011
6
more than one hour to implement the contingency plan for
loss of primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and
Transmission Operator shall have a current Operating Plan describing
the manner in which it continues to meet its functional obligations
with regard to the reliable operations of the BES in the event that its
primary control center functionality is lost. This Operating Plan for
backup functionality shall include the following, at a minimum:
[Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
1.1. The location and method of implementation for providing
backup functionality for the time it takes to restore the primary
control center functionality.
1.2. A summary description of the elements required to
support the backup functionality. These elements shall include, at
a minimum:
1.2.1. Tools and applications to ensure that System Operators
have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
1.3. An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4. Operating Procedures, including decision authority, for use in
determining when to implement the Operating Plan for backup
November 30, 2011
7
functionality.
1.5. A transition period between the loss of primary control center
functionality and the time to fully implement the backup
functionality that is less than or equal to two hours.
1.6. An Operating Process describing the actions to be taken
during the transition period between the loss of primary control
center functionality and the time to fully implement backup
functionality elements identified in Requirement R1, Part 1.2. The
Operating Process shall include at a minimum:
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the
transition from primary to backup functionality as well as
during outages of the primary or backup functionality.
1.6.3. Identification of the roles for personnel involved
during the initiation and implementation of the Operating
Plan for backup functionality.
Notes: The RC SDT proposes retiring COM-001-1 R5 as it is redundant with EOP-008-0 Requirement R1 as well as EOP-008-1
R1 which replaces it.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
R6.
Each NERCNet User Organization shall adhere to
the requirements in Attachment 1-COM-001,
“NERCNet Security Policy.” [Violation Risk
Factor: Lower]
November 30, 2011
None - retire
8
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability
standard. It should be included in the ERO Rules of Procedure.
Already Approved Standard
None
Proposed Replacement Requirement(s)
New Requirement
R11. Each Distribution Provider and Generator Operator that
experiences a failure of any of its Interpersonal Communication
capabilities shall consult with their Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable
time to restore the Interpersonal Communication capability. [Violation
Risk Factor: Medium][Time Horizon: Real-time Operations]
Notes:
November 30, 2011
9
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Reliability
Coordinator
Balancing
Authority
X
X
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
Communications
November 30, 2011
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Unofficial Comment Form
Reliability Coordination (Project 2006-06)
Please DO NOT use this form to submit comments. Please use the electronic comment form to
submit comments on the first formal posting for Project 2006-06—Reliability Coordination. The
electronic comment form must be completed by February 8, 2011.
2006-06 Project Page
If you have questions please contact Stephen Crutchfield at [email protected] or by
telephone at 609-651-9455.
Background
The RCSDT has revised the COM-001-2, COM-002-3 and IRO-001-1 standards based on
stakeholder comments received during the initial ballot and formal comment period and quality
reviews of each standard.
The RCSDT has addressed comments on the applicability of all three standards and implementation
plans by aligning COM-001-2, COM-002-3, and IRO-001-2 to apply to the same entities and by
removing LSE, PSE and TSP as applicable entities from the COM standards. Additionally, the
Interchange Coordinator has been removed as an applicable entity from the standards and
implementation plans.
Several commenters had suggestions for improvements to the requirement language and
applicability of COM-001-2. The RCSDT believes the standard correctly and adequately requires
each applicable entity that would have capability to receive Interconnection and operating
information to have Interpersonal Communications, and Alternative Interpersonal Communications
to be used when the Interpersonal Communication is not available. The RCSDT made the following
changes to COM-001-2 based on stakeholder suggestions:
1. The following Requirement parts were added to COM-001-2:
•
3.5 Adjacent Transmission Operators synchronously connected within the same
Interconnection
•
4.3 Adjacent Transmission Operators synchronously connected within the same
Interconnection
•
5.5 Adjacent Balancing Authorities
•
6.3 Adjacent Balancing Authorities
2. The phrase "to exchange Interconnection and operating information" was removed from
requirements R1 through R8 to clarify that the intent of this capability is NOT for the
exchange of data.
3. A new requirement was added for clarity regarding what is required of Distribution Providers
and Generator Operators (i.e., collaboration between entities to restore a failed
communications capability):
R11. Each Distribution Provider and Generator Operator that experiences a failure of
any of its Interpersonal Communication capabilities shall consult with their Transmission
Operator or Balancing Authority as applicable to determine a mutually agreeable time to
Unofficial Comment Form
Project 2006-06 Reliability Coordination
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
restore the Interpersonal Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
The proposed definition of Reliability Directive shown in COM-002-3 was revised to include Adverse
Reliability Impact as shown to more fully address emergencies or events that might lead to
instability or Cascading:
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission
Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.
As a reference, we have included the existing definition of Emergency and the BOT approved
definition of Adverse Reliability Impact 1:
Emergency: Any abnormal system condition that requires automatic or immediate manual
action to prevent or limit the failure of transmission facilities or generation supply that could
adversely affect the reliability of the Bulk Electric System.
Adverse Reliability Impact: The impact of an event that results in Bulk Electric System
instability or Cascading.
Based on stakeholder feedback regarding IRO-001, the RCSDT removed Requirement R1. Other
requirements were removed from IRO-001 and placed in more appropriate standards. These
requirements did not fit with the purpose statement of IRO-001. Requirements R5 and R6 were
removed from IRO-001 and placed in IRO-005-4. Requirements R7 and R8 were removed from
IRO-001 and placed in IRO-002-2. These requirements were balloted and approved by
stakeholders in July of 2011 and subsequently approved by the NERC BOT on August 4, 2011.
In addition, minor clarifications were made to the language of requirements and measures in COM002-3 and IRO-001-3 based on suggestions from quality reviews of those standards.
1
This definition was approved by the NERC Board of Trustees on August 4, 2011. Filing with regulatory authorities is
pending.
Unofficial Comment Form
Project 2006-06 Reliability Coordination
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You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. The RCSDT has revised the applicability of the standards and implementation plans by aligning
COM-001-2, COM-002-3, and IRO-001-2 to apply to the same entities and by removing LSE,
PSE and TSP as applicable entities from the COM standards. Additionally, the Interchange
Coordinator has been removed as an applicable entity from the standards. Do you agree with
this change in applicability to the three standards? If not, please explain in the comment area
below.
Yes
No
Comments:
2. Do you agree with the addition of “Adjacent” entities in COM-001-2, Parts 3.5, 4.3, 5.5 and 6.3
of COM-001-2? If not, please explain in the comment area below
Yes
No
Comments:
3. The RCSDT removed the phrase "to exchange Interconnection and operating information" in
COM-001-2, Requirements R1 through R8 based on stakeholder comments. Do you agree with
the revision? If not, please explain in the comment area below.
Yes
No
Comments:
4. A new requirement was added for clarity regarding what is required of Distribution Providers
and the Generator Operators:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of
its Interpersonal Communication capabilities shall consult with their Transmission Operator
or Balancing Authority as applicable to determine a mutually agreeable time to restore the
Interpersonal Communication capability. [Violation Risk Factor: Medium][Time Horizon:
Real-time Operations]
This requirement requires collaboration between entities to restore a failed communications
capability. Do you agree with the new requirement? If not, please explain in the comment
area below
Yes
No
Comments:
Unofficial Comment Form
Project 2006-06 Reliability Coordination
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5. The proposed definition of Reliability Directive shown in COM-002-3 was revised to include
Adverse Reliability Impact as shown to more fully address emergencies or events that might
lead to instability or Cascading:
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission
Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.
Do you agree with the proposed definition? If not, please explain in the comment area below
Yes
No
Comments:
6. Do you have any other comment, not expressed in questions above, for the RC SDT?
Comments:
Unofficial Comment Form
Project 2006-06 Reliability Coordination
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Standard COM-001-1.1 — Telecommunications
A. Introduction
1.
Title:
Telecommunications
2.
Number:
COM-001-1.1
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
Effective Date:
May 13, 2009
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall use English as the language for all communications between and
among operating personnel responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and Balancing Authorities may
use an alternate language for internal operations.
R5.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
written operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilities.
R6.
Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM001, “NERCNet Security Policy.”
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Standard COM-001-1.1 — Telecommunications
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. The Reliability Coordinator, Transmission Operator or Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent, that
will be used to determine compliance to Requirement 4.
M3. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy that will be used to confirm that it meets Requirement 5.
M4. The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to documented procedures, operator logs, voice recordings or
transcripts of voice recordings, electronic communications, etc that will be used to determine if
it adhered to the (User Accountability and Compliance) requirements in Attachment 1-COM001. (Requirement 6)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2 each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall keep 90 days of historical data (evidence).
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Standard COM-001-1.1 — Telecommunications
For Measure 3, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 5.
For Measure 4, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.2
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities as
specified in R5.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Standard COM-001-1.1 — Telecommunications
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Standard COM-001-1.1 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Standard COM-001-1.1 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
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Violation Risk Factor and Violation Severity Level Assignments
This document provides the drafting team’s justification for assignment of violation risk
factors (VRFs) and violation severity levels (VSLs) for each requirement in
COM-001-2 — Telecommunications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These
elements support the determination of an initial value range for the Base Penalty Amount
regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors in COM-001-2
The SDT applied the following NERC criteria when proposing VRFs for the requirements in
COM-001-2:
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would
not be expected to adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor and control the bulk electric system; or, a
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
requirement that is administrative in nature and a requirement in a planning time frame
that, if violated, would not, under the emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. A planning requirement that is administrative in nature.
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for
setting VRFs: 1
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical
impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
violations could severely affect the reliability of the Bulk-Power System: 2
−
−
−
−
−
−
−
−
−
−
−
−
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation
Risk Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶
61,145 (2007) (“VRF Rehearing Order”).
2
Id. at footnote 15.
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Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor
Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One
Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser
risk reliability objective, the VRF assignment for such Requirements must not be watered
down to reflect the lower risk level associated with the less important objective of the
Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2
through 5. The team did not address Guideline 1 directly because of an apparent conflict
between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics that encompass
nearly all topics within NERC’s Reliability Standards and implies that these requirements should
be assigned a “High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a
specific requirement to the reliability of the system. The SDT believes that Guideline 4 is
reflective of the intent of VRFs in the first instance and therefore concentrated its approach on
the reliability impact of the requirements.
VRF for COM-001-2:
There are eleven requirements in COM-001-2. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 were assigned a “High” VRF while the other three
requirements were given a “Medium” VRF.
VRF for COM-001-2, Requirements R1-R6:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. Each requirement
specifies which functional entities that are required to have Interpersonal Communications
capability and Alternative Interpersonal Communications capability. The VRFs for each
requirement are consistent with each other and are only applied at the Requirement level.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. These requirements are
facility requirements that provide communications capability between functional entities.
There are no similar facility requirements in the standards. The approved VRF for COM001-1.1, R1 (which proposed R1-R6 replaces) is High and therefore the proposed VRF for
R1-R6 is consistent.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability and Alternative Interpersonal Communications
capability could limit or prevent communication between entities and directly affect the
electrical state or the capability of the bulk power system and could lead to bulk power
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
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system instability, separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirements R1-R6 contain only one objective, therefore only one
VRF was assigned.
VRF for COM-001-2, Requirement R7:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R7 is an analog to Parts 3.3 and 5.3 and they have the same VRF (High).
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability could limit or prevent communication between
entities and directly affect the electrical state or the capability of the bulk power system and
could lead to bulk power system instability, separation, or cascading failures. Therefore, this
requirement was assigned a High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R7 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R8:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R8 is an analog to Parts 3.4 and 5.4 and they have the same VRF (High).
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability could limit or prevent communication between
entities and directly affect the electrical state or the capability of the bulk power system and
could lead to bulk power system instability, separation, or cascading failures. Therefore, this
requirement was assigned a High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R8 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R9:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R9 is a requirement for entities to test their Alternative Interpersonal
Communications capability and to take restorative action should the test fail and is a
replacement requirement for COM-001-1.1, R2, which has an approved VRF of Medium.
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•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R9 is a requirement for entities to test their Alternative Interpersonal
Communications capability and to take restorative action should the test fail. The act of
testing in and of itself is not likely to “directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk electric
system instability, separation, or cascading failures…” Therefore, this requirement was
assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R9 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R10:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R10 is a new requirement that was assigned a Medium VRF. When evaluating
the VRF to be assigned to this requirement, the SDT took into account that this requirement
is a notification item, not an actual action that has a direct impact on the bulk power system.
Therefore, the simple act of failing to notify another entity of the failure of Interpersonal
Communications capability, while it may impair the entity’s ability communicate, does not,
in itself, lead to bulk power system instability, separation, or cascading failures. Therefore,
this requirement was assigned a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R10 mandates that entities notify entities of a failure of Interpersonal
Communications capability. Bulk power system instability, separation, or cascading failures
are not likely to occur due to a failure to notify another entity of the failure. Therefore, this
requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 - Treatment of Requirements that Co-mingle More Than One Objective.
TOP-001-2, Requirement R10 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R11:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R11 is a new requirement that was assigned a Medium VRF. When evaluating
the VRF to be assigned to this requirement, the SDT took into account that this requirement
is a consultation item, not an actual action that has a direct impact on the bulk power system.
Therefore, the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may impair the entity’s
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ability communicate, does not, in itself, lead to bulk power system instability, separation, or
cascading failures. Therefore, this requirement was assigned a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R11 mandates that entities consult with other entities regarding restoration of
Interpersonal Communications capability. Bulk power system instability, separation, or
cascading failures are not likely to occur due to a failure to consult with another entity on
restoration times. Therefore, this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 - Treatment of Requirements that Co-mingle More Than One Objective.
TOP-001-2, Requirement R11 addresses a single objective and has a single VRF.
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Justification for Assignment of Violation Severity Levels for COM-001-2
In developing the VSLs for the TOP standard, the SDT anticipated the evidence that would be
reviewed during an audit, and developed its VSLs based on the noncompliance an auditor may
find during a typical audit. The SDT based its assignment of VSLs on the following NERC
criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs
proposed for each requirement in TOP-xxx-x meet the FERC Guidelines for assessing VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes
that may encourage a lower level of compliance than was required when levels of noncompliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement.
November 30, 2011
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that
assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
November 30, 2011
8
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirements R1 through R6:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations
The proposed VSL uses the
same terminology as used
in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based on a
single violation and not
cumulative violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R1R6.
Meets NERC’s
VSL guidelines Severe: The
performance or
product measured
does not
substantively meet
the intent of the
requirement.
November 30, 2011
The proposed
requirement is a revision
of COM-001-1.1, R1 and
its subrequirements.
Each subrequirement was
separated out into a new
stand-alone requirement.
The VSLs for the
approved
subrequirements are
binary and this is
reflected in the proposed
VSLs.
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and
consistency in the determination of
similar penalties for similar
violations.
9
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirement R7:
Compliance
with NERC’s
VSL Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations
The proposed VSLs use
the same terminology as
used in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are based
on a single violation
and not cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R7.
Meets NERC’s
VSL guidelines
- Severe: The
performance or
product
measured does
not
substantively
meet the intent
of the
requirement.
November 30, 2011
The most comparable VSLs for
a similar requirement are for the
proposed analog requirement
and its parts COM-001-2, Part
3.3 and Part 5.3. This
requirement specifies the two
way nature of entities having
Interpersonal Communications
capability. In other words, if
one entity is required to have
Interpersonal Communications
capability with another entity,
then the reciprocal should also
be required or the onus would
be exclusively on one entity.
Since Requirement 3 and
The proposed VSLs do not use
any ambiguous terminology,
thereby supporting uniformity
and consistency in the
determination of similar
penalties for similar violations.
10
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
Compliance
with NERC’s
VSL Guidelines
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
R#
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 4
Violation Severity
Level Assignment
Should Be Based on A
Single Violation, Not
on A Cumulative
Number of Violations
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Requirement 5 are assigned
binary VSLs, it appropriate for
Requirement 7 to also be
assigned a binary VSL.
November 30, 2011
11
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirement R8:
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative Number
of Violations
The proposed VSLs use the
same terminology as used
in the associated
requirement, and are,
therefore, consistent with
the requirement.
The VSLs are
based on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R8.
Meets NERC’s
VSL guidelines Severe: The
performance or
product measured
does not
substantively meet
the intent of the
requirement.
November 30, 2011
The most comparable
VSLs for a similar
requirement are for the
proposed analog
requirement and its parts
COM-001-2, Part 3.4 and
Part 5.4. This
requirement specifies the
two way nature of entities
having Interpersonal
Communications
capability. In other
words, if one entity is
required to have
Interpersonal
Communications
capability with another
The proposed VSLs do not use any
ambiguous terminology, thereby
supporting uniformity and
consistency in the determination of
similar penalties for similar
violations.
12
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
Compliance with
NERC’s Revised
VSL Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Guideline 4
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative Number
of Violations
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
entity, then the reciprocal
should also be required or
the onus would be
exclusively on one entity.
Since Requirement 3 and
Requirement 5 are
assigned binary VSLs, it
appropriate for
Requirement 7 to also be
assigned a binary VSL.
November 30, 2011
13
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirement R9:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based
on A Single
Violation, Not on A
Cumulative Number
of Violations
The proposed VSL uses the
same terminology as used
in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based
on a single
violation and not
cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R9.
Meets NERC’s
VSL guidelines.
There is an
incremental aspect
to the violation
and the VSLs
follow the
guidelines for
incremental
violations.
November 30, 2011
The proposed
requirement is a new and
there are no comparable
VSLs.
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and
consistency in the determination of
similar penalties for similar
violations.
14
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirement R10:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
The proposed VSL uses the
same terminology as used
in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based on
a single violation
and not cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R10. Meets NERC’s
VSL guidelines.
There is an
incremental
aspect to the
violation and the
VSLs follow the
guidelines for
incremental
violations.
November 30, 2011
The proposed
requirement is new and
there are no comparable
VSLs.
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and
consistency in the determination of
similar penalties for similar
violations.
15
Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project 2006-06 – Reliability Coordination
VSLs for COM-001-2 Requirement R11:
Compliance with
NERC’s VSL
Guidelines
R#
Guideline 1
Guideline 2
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of
Lowering the Current
Level of Compliance
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary" Requirements
Is Not Consistent
Guideline 3
Guideline 4
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations
The proposed VSL uses the
same terminology as used
in the associated
requirement, and is,
therefore, consistent with
the requirement.
The VSL is based on
a single violation
and not cumulative
violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
R11. Meets NERC’s
VSL guidelines.
This is a binary
requirement and
the VSL is
severe.
November 30, 2011
The proposed
requirement is new and
there are no comparable
existing VSLs.
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and
consistency in the determination of
similar penalties for similar
violations.
16
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 Reliability Coordination
Three Ballot Windows Extended, Three Non-binding poll Windows Extended One Day
Formal Comment Period Extended One Day
Through 8 p.m. Eastern TODAY (Thursday, February 9, 2012)
Now Available
Three non-binding polls of the VRFs and VSLs associated with the standards listed below failed to
achieve a quorum and have been extended by one day. In addition, to accommodate ballot pool
members and other stakeholders affected by a brief unavailability of NERC web services at the end of
the ballot and comment period window, the formal comment period and three ballots of these
standards and their associated implementation plans will also be extended one day. The non-binding
polls, ballots, and formal comment period will close at 8 p.m. Eastern TODAY, Thursday, February 9,
2012.
• COM-001-2 – Communications
• COM-002-3 – Communication and Coordination
• IRO-001-3 – Reliability Coordination – Responsibilities and Authorities
Please log in and cast your ballots for these standards, and opinions in the non-binding polls, if you
have not already done so.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 Reliability Coordination
Three Ballot Windows and Three Non-binding Poll Windows Now Open
January 30 - February 8, 2012
Now Available
Ballot windows are open through 8 p.m. Eastern on Wednesday, February 8, 2012 for three successive
ballots (one for each of the following standards and the associated implementation plans) and three nonbinding polls of the VRFs and VSLs associated with each standard:
• COM-001-2 – Communications
• COM-002-3 – Communication and Coordination
• IRO-001-3 – Reliability Coordination – Responsibilities and Authorities
Clean and redline versions of each standard and the associated implementation plan and VRFs and VSLs
are posted on the project webpage. In addition, the following supporting materials have been posted on
the project page:
• Mapping Document for each standard - Identifies each requirement in the approved version of
the standard and how the requirement has been treated in the current draft.
• VRF and VSL Justification – Identifies how the proposed VRFs and VSLs for each standard meet
NERC and FERC guidelines.
• Last approved versions of COM-001 and COM-002 – Because the changes from the last
approved versions of these two standards are so extensive, a redline showing changes against
that last approved version is not useful. The last approved versions are posted as a convenience
to stakeholders.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their votes for the
standards and opinions for the non-binding polls from the following page:
https://standards.nerc.net/CurrentBallots.aspx.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Wednesday, February 8, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page.
Special Instructions for Submitting Comments With a Ballot or Non-binding Poll
Please note that comments submitted during the formal comment period, the ballots for the standards,
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
and the non-binding polls of VRFs and VSLs all use the same electronic form, and will be compiled into a
single report with duplicate comments submitted by the same entity removed and duplicate comments
submitted by multiple entities consolidated. Therefore, it is NOT necessary for ballot pool members to
submit more than one set of comments. The drafting team requests that all stakeholders (ballot pool
members as well as other stakeholders) submit all comments through the electronic comment form.
Next Steps
The drafting team will consider all comments submitted to determine whether to make additional
revisions to the standards.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measurable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; and 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope
overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC
Order 693 associated with standard IRO-003-2.
The following three standards that are part of this project were approved by the ballot pool and were
adopted by the NERC Board of Trustees in August 2012: IRO-002-3 Reliability Coordination – Analysis
Tools; IRO-005-4 - Reliability Coordination-Current Day Operations; and IRO-014-2 – Coordination Among
Reliability Coordinators. Additional information is available on the project webpage.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation.
We extend our thanks to all those who participate. For more information or assistance, please contact
Monica Benson at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2006-06
Reliability Coordination
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 Reliability Coordination
Formal Comment Period Open January 9 – February 8, 2012
Three Ballot Windows and Three Non-binding Poll Windows Open
January 30 - February 8, 2012
Now Available
The following standards, and the associated implementation plans and VRFs and VSLs, have been
posted for a formal comment period through 8 p.m. Eastern on Wednesday, February 8, 2012:
• COM-001-2 – Communications
• COM-002-3 – Communication and Coordination
• IRO-001-3 – Reliability Coordination – Responsibilities and Authorities
Clean and redline versions of each standard and the associated implementation plan and VRFs and VSLs
are posted on the project webpage. In addition, the following supporting materials have been posted
on the project page:
• Mapping Document for each standard - Identifies each requirement in the approved
version of the standard and how the requirement has been treated in the current draft.
• VRF and VSL Justification – Identifies how the proposed VRFs and VSLs for each standard
meet NERC and FERC guidelines.
• Last approved versions of COM-001 and COM-002 – Because the changes from the last
approved versions of these two standards are so extensive, a redline showing changes
against that last approved version is not useful. The last approved versions are posted as a
convenience to stakeholders.
Three successive ballots (one for each standard and its implementation plan) and three nonbinding
polls of the VRFs and VSLs associated with each standard will be conducted beginning on Monday,
January 30, 2012 through 8 p.m. Eastern on Wednesday, February 8, 2012.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Wednesday, February 8, 2012. Please
use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the
comment form is posted on the project page.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Special Instructions for Submitting Comments with a Ballot or Non-binding Poll
Please note that comments submitted during the formal comment period, the ballots for the
standards, and the non-binding polls of VRFs and VSLs all use the same electronic form, and will be
compiled into a single report with duplicate comments submitted by the same entity removed and
duplicate comments submitted by multiple entities consolidated. Therefore, it is NOT necessary for
ballot pool members to submit more than one set of comments. The drafting team requests that all
stakeholders (ballot pool members as well as other stakeholders) submit all comments through the
electronic comment form.
Next Steps
The drafting team will consider all comments submitted to determine whether to make additional
revisions to the standards.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measurable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; and 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to scope
overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from FERC
Order 693 associated with standard IRO-003-2. Additional information is available on the project
webpage.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Standards Announcement: Project 2006-06
Reliability Coordination
2
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2006-06 Reliability Coordination COM-001-2 Jan 2012_in
Password
Ballot Period: 1/30/2012 - 2/9/2012
Ballot Type: Initial
Log in
Total # Votes: 279
Register
Total Ballot Pool: 341
Quorum: 81.82 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
54.64 %
Vote:
Ballot Results: The drafting team is considering comments.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
88
11
85
24
69
44
0
8
4
8
341
#
Votes
1
0.8
1
1
1
1
0
0.6
0.2
0.6
7.2
#
Votes
Fraction
41
4
36
10
32
24
0
4
1
1
153
Negative
No
# Votes Vote
Fraction
0.672
0.4
0.522
0.476
0.615
0.649
0
0.4
0.1
0.1
3.934
Abstain
20
4
33
11
20
13
0
2
1
5
109
0.328
0.4
0.478
0.524
0.385
0.351
0
0.2
0.1
0.5
3.266
7
2
1
0
4
2
0
0
1
0
17
20
1
15
3
13
5
0
2
1
2
62
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Member
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
Scott J Kinney
Gregory S Miller
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
Ballot
Comments
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Bonneville Power Administration
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Joseph S Stonecipher
Donald S. Watkins
Kevin L Howes
Affirmative
Affirmative
Negative
Chang G Choi
Affirmative
Randall McCamish
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Gordon Pietsch
View
Affirmative
Affirmative
Affirmative
Affirmative
View
Affirmative
Negative
View
Abstain
Negative
Affirmative
Affirmative
Affirmative
View
View
Robert Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Negative
View
Negative
View
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Abstain
Negative
View
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Robert Ganley
Joe D Petaski
Danny Dees
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch
Randy MacDonald
Arnold J. Schuff
David Boguslawski
Kevin M Largura
John Canavan
Marvin E VanBebber
Doug Peterchuck
Michael T. Quinn
Brad Chase
Daryl Hanson
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F Afranji
David Thorne
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Catherine Koch
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
View
View
View
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Sierra Pacific Power Co.
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Leesburg
City of Redding
Clearwater Power Co.
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
Georgia System Operations Corporation
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Rich Salgo
Richard McLeon
Dana Cabbell
Robert Schaffeld
William G. Hutchison
James Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Charles B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Kelly Nguyen
Steven Norris
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Affirmative
Affirmative
View
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
View
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
View
View
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
View
View
View
View
View
View
View
Dave Markham
Negative
View
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Phil Janik
Bill Hughes
Dave Hagen
Michelle A Corley
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
Scott S. Barfield-McGinnis
Negative
View
Negative
Affirmative
Affirmative
Affirmative
View
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
View
View
View
View
View
View
View
View
View
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Northern Lights Inc.
Okanogan County Electric Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
Sam Kokkinen
David Kiguel
Shaun Jensen
Garry Baker
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Daniel D Kurowski
Richard Reynolds
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Jon Shelby
Ray Ellis
David Burke
Ballard K Mutters
John Apperson
Terry L Baker
Robert Reuter
Jeffrey Mueller
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Marc M Farmer
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Tim Beyrle
Affirmative
Negative
View
View
Negative
Affirmative
Negative
Negative
Negative
View
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
View
View
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
View
View
View
View
View
View
View
Negative
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph DePoorter
Douglas Hohlbaugh
Aleka K Scott
Henry E. LuBean
John D Martinsen
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
View
View
Affirmative
View
Negative
View
Negative
Negative
Negative
Affirmative
Negative
Affirmative
View
View
View
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group Incorporated
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul Cummings
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Max Emrick
Affirmative
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
David Gordon
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
View
View
View
View
View
View
View
View
View
Negative
Negative
Negative
Negative
View
View
View
Affirmative
Negative
View
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
View
View
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Shell Energy North America (US), L.P.
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
Brandy D Olson
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Claire Warshaw
Steven J Hulet
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Paul Kerr
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Peter H Kinney
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Jim Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
View
Negative
Affirmative
Negative
Affirmative
Affirmative
View
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
View
View
View
View
View
View
View
View
View
View
View
View
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Donald Nelson
Negative
Diane J Barney
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
View
View
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
9
9
10
10
10
10
10
10
10
10
Oregon Public Utility Commission
Snohomish County PUD No. 1
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity
Western Electricity Coordinating Council
Jerome Murray
William Moojen
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Larry D. Grimm
Louise McCarren
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
Copyright © 2010 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=a3ed2eb9-3d45-45a7-b184-04000fefdf1d[2/10/2012 1:49:18 PM]
View
View
View
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project 2006-06 Non-binding Poll
COM-001-2
Ballot Results
Non-binding Poll
Project 2006-06 Non-binding COM-001-2
Name:
Poll Period: 1/30/2012 - 2/9/2012
Total # Votes: 274
Total Ballot Pool: 341
80.35% of those who registered to participate provided an opinion or
Ballot Results: abstention; 71.35% of those who provided an opinion or abstention indicated
support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company,
LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Central Maine Power Company
City of Tacoma, Department of
Public Utilities, Light Division, dba
Tacoma Power
City of Vero Beach
City Water, Light & Power of
Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Member
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Comments
Abstain
Negative
View
Abstain
Robert Smith
Scott J Kinney
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Kevin L Howes
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Chang G Choi
Affirmative
Randall McCamish
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Consolidated Edison Co. of New York
Graffenried
Dayton Power & Light Co.
Hertzel Shamash
Dominion Virginia Power
Michael S Crowley
Duke Energy Carolina
Douglas E. Hils
East Kentucky Power Coop.
George S. Carruba
Empire District Electric Co.
Ralph F Meyer
Project 2006-06 Non-binding Results
COM-001-2
Opinions
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
View
Abstain
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative
Assoc.
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New
Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of
Okanogan County
Puget Sound Energy, Inc.
Project 2006-06 Non-binding Results
COM-001-2
George R. Bartlett
Robert Martinko
Affirmative
Affirmative
Dennis Minton
Affirmative
Gordon Pietsch
Affirmative
View
Robert Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Abstain
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Robert Ganley
Joe D Petaski
Danny Dees
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch
Randy MacDonald
Arnold J. Schuff
David Boguslawski
Kevin M Largura
John Canavan
Marvin E VanBebber
Doug Peterchuck
Michael T. Quinn
Brad Chase
Daryl Hanson
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F Afranji
David Thorne
Larry D Avery
Brenda L Truhe
Negative
View
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Abstain
View
View
Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Laurie Williams
Kenneth D. Brown
Abstain
Dale Dunckel
Abstain
Catherine Koch
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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2
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission
Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
California ISO
Electric Reliability Council of Texas,
Inc.
Independent Electricity System
Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System
Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc.
1
2
2
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2
2
2
2
2
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Project 2006-06 Non-binding Results
COM-001-2
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Richard McLeon
Dana Cabbell
Robert Schaffeld
William G. Hutchison
James Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
View
Negative
View
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Abstain
Abstain
Charles B Manning
Affirmative
Kim Warren
Affirmative
Kathleen Goodman
Jason L Marshall
Alden Briggs
Affirmative
Abstain
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Kelly Nguyen
Steven Norris
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Dave Markham
View
View
Abstain
Affirmative
Affirmative
View
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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3
(Redmond, Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Leesburg
City of Redding
Clearwater Power Co.
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
Georgia System Operations
Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water &
Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of
Project 2006-06 Non-binding Results
COM-001-2
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Phil Janik
Bill Hughes
Dave Hagen
Michelle A Corley
Bruce Krawczyk
Peter T Yost
Carolyn Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
Scott S. BarfieldMcGinnis
Sam Kokkinen
David Kiguel
Shaun Jensen
Garry Baker
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Abstain
Negative
Affirmative
Abstain
Affirmative
View
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
View
Affirmative
Affirmative
Affirmative
Affirmative
View
Negative
View
Affirmative
Abstain
View
Negative
Affirmative
Negative
Affirmative
Affirmative
View
Daniel D Kurowski
Affirmative
Richard Reynolds
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
Affirmative
Negative
Abstain
Affirmative
Affirmative
View
View
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northern Indiana Public Service Co.
Northern Lights Inc.
Okanogan County Electric
Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative,
Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Project 2006-06 Non-binding Results
COM-001-2
John S Bos
Tony Eddleman
Marilyn Brown
Abstain
Abstain
Affirmative
Michael Schiavone
Affirmative
William SeDoris
Jon Shelby
Affirmative
Affirmative
Ray Ellis
Affirmative
David Burke
Ballard K Mutters
John Apperson
Terry L Baker
Robert Reuter
Jeffrey Mueller
Abstain
Abstain
Affirmative
Abstain
Abstain
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Marc M Farmer
Affirmative
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Timothy Beyrle
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Affirmative
Negative
View
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Georgia System Operations
Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating
Cooperative
Public Utility District No. 1 of
Douglas County
Public Utility District No. 1 of
Snohomish County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of
Public Utilities, Light Division, dba
Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source
Generation, Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and
Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Project 2006-06 Non-binding Results
COM-001-2
Guy Andrews
Negative
Bob C. Thomas
Joseph DePoorter
Douglas Hohlbaugh
Abstain
Abstain
Affirmative
Aleka K Scott
Affirmative
Henry E. LuBean
Affirmative
John D Martinsen
Abstain
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul Cummings
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Max Emrick
Affirmative
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
View
View
Abstain
Negative
Abstain
Affirmative
Abstain
Negative
Abstain
Negative
Affirmative
View
Affirmative
Affirmative
Martin Kaufman
Abstain
Kenneth Dresner
David Schumann
Affirmative
Negative
View
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group
Incorporated
Public Utility District No. 1 of Lewis
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Project 2006-06 Non-binding Results
COM-001-2
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
View
View
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
Negative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
View
View
Abstain
Negative
View
Abstain
Negative
View
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
View
Abstain
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Abstain
View
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities
Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L.
Florida Municipal Power Agency
Montgomery
Florida Municipal Power Pool
Thomas Washburn
Florida Power & Light Co.
Silvia P. Mitchell
Great River Energy
Donna Stephenson
Kansas City Power & Light Co.
Jessica L Klinghoffer
Lakeland Electric
Paul Shipps
Lincoln Electric System
Eric Ruskamp
Manitoba Hydro
Daniel Prowse
MidAmerican Energy Co.
Dennis Kimm
Muscatine Power & Water
Brandy D Olson
New York Power Authority
William Palazzo
Northern Indiana Public Service Co. Joseph O'Brien
Omaha Public Power District
David Ried
PacifiCorp
Scott L Smith
Platte River Power Authority
Carol Ballantine
PPL EnergyPlus LLC
Mark A Heimbach
Progress Energy
John T Sturgeon
PSEG Energy Resources & Trade LLC Peter Dolan
Sacramento Municipal Utility District Claire Warshaw
Salt River Project
Steven J Hulet
Santee Cooper
Suzanne Ritter
Seattle City Light
Dennis Sismaet
Seminole Electric Cooperative, Inc. Trudy S. Novak
Shell Energy North America (US),
Paul Kerr
L.P.
South California Edison Company
Lujuanna Medina
Tacoma Public Utilities
Michael C Hill
Tampa Electric Co.
Benjamin F Smith II
Tennessee Valley Authority
Marjorie S. Parsons
Western Area Power Administration Peter H Kinney
UGP Marketing
Xcel Energy, Inc.
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Project 2006-06 Non-binding Results
COM-001-2
Affirmative
Affirmative
Affirmative
Abstain
Abstain
View
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
View
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
View
View
View
View
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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8
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9
9
9
9
10
10
10
10
10
10
10
10
JDRJC Associates
Pacific Northwest Generating
Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory
Utility Commissioners
Oregon Public Utility Commission
Snohomish County PUD No. 1
Florida Reliability Coordinating
Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating
Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity
Western Electricity Coordinating
Council
Project 2006-06 Non-binding Results
COM-001-2
Jim Cyrulewski
Affirmative
Margaret Ryan
Abstain
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
Affirmative
Donald Nelson
Negative
Diane J Barney
Abstain
Jerome Murray
William Moojen
Abstain
View
Linda Campbell
James D Burley
Alan Adamson
Negative
Guy V. Zito
Negative
Anthony E Jablonski
Carter B. Edge
Larry D. Grimm
Negative
Abstain
Negative
Louise McCarren
View
Affirmative
9
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Name (40 Responses)
Organization (40 Responses)
Group Name (22 Responses)
Lead Contact (22 Responses)
Question 1 (55 Responses)
Question 1 Comments (62 Responses)
Question 2 (50 Responses)
Question 2 Comments (62 Responses)
Question 3 (52 Responses)
Question 3 Comments (62 Responses)
Question 4 (53 Responses)
Question 4 Comments (62 Responses)
Question 5 (55 Responses)
Question 5 Comments (62 Responses)
Question 6 (0 Responses)
Question 6 Comments (62 Responses)
Individual
Jennifer Wright
San Diego Gas & Electric
Yes
Yes
Yes
Yes
Yes
Individual
Steve Alexanderson
Central Lincoln
Yes
Yes
No
The new requirement presents us with a paradoxical situation. The communication has failed, so we must consult; yet consultation requires communication. We note that the SDT used the word “any”,
implying that multiple communication paths are required. The reality of the situation at Central Lincoln, due to our remote location, is that a single back hoe incident at the right location can take out all of
our of our communication capability (including the terrestrial portion of the cellular networks) with our BA/TO; making this requirement impossible to meet for this circumstance using our present
capabilities. We also note that no time limit was indicated. Most interruptions are brief, and fixed before consultation could reasonably take place. CEAs will be finding entities non-compliant for quickly
fixing problems at their end without first consulting to ensure the restoration time was agreeable. To avoid non-compliance, entities will be forced delay repairs while they investigate alternative
communication paths for consultation purposes. We fail to see how such an outcome improves reliability. The new requirement is one sided, requiring the DP and GOP to consult with no corresponding
requirement for the TO or BA to have personnel available for such a consultation. Consultation failure or failure to mutually agree due to actions or inactions on the part of the TO or BA should not result in
an enforcement action against the DP or GOP, yet that is how the requirement is written. The new requirement fails to add any “clarity” to the other requirements, and we don’t see that the stakeholders
thought there was a problem with DP/GOP obligation clarity. Instead, it adds new obligations with no justification for how they enhance reliability. We suggest removing the requirement.
Yes
As stated in our prior comments, we continue to have problems with COM-002 R2 and R3 as written. The SDT’s answer (“It is the expectation that an issuer of a Reliability Directive would request a return
call by the Distribution Provider operating personnel, then issue the Reliability Directive”) addresses our concern perfectly, and we would agree with such an expectation. Unfortunately, the expressed
expectation is not in the proposed standard or even in a proposed guideline for the standard.
Group
SERC OC Standards Review Group
Gerald Beckerle
Yes
No
We are concerned regarding communications between Transmission Operators on opposite ends of DC ties which may or may not be in the same interconnection. Similarly, COM-001, R1.2 limits the
requirement of adjacent Reliability Coordinators to the same interconnection and this should not be limited to the same interconnection whether it is synchronous or non-synchronous. The measures
should also be verified to ensure that they align properly with the final requirements.
Yes
We suggest that this phrase should also be removed from the “Purpose” statement.
No
We suggest Requirement 11 should be deleted as the generic nature of the term “…any of its Interpersonal Communications capabilities….” could be interpreted to include communications capabilities used
for internal DP/GO purposes. Such DP/GO internal communications capability would not be critical to BES reliability. Also, no BES reliability benefit is realized by the parties simply agreeing to a time for
the restoration of the failed Interpersonal Communication capability.
No
We suggest adding the words “and identified as a reliability directive to the recipient” at the end of the definition of Reliability Directive. As written, this definition could lead to a dispute of what
communications are Reliability Directives; leading to further dispute as to what Requirements are applicable. By adding this clarity in the definition of this term, clarity will not be needed in the application
of this definition as is proposed in COM-002-3, Req 1. This would allow the removal of R1 from COM-002-3
COM-001-2 Comments Definition of Alternative Interpersonal Communication: The proposed definition uses the term “medium”. What is the scope of that? Telephony is a “medium” but there is wired,
wireless, satellite, etc. Was “medium” intended to differentiate voice, paper, text, email, teletype, or something else? Does the qualifying term “same” when modifying infrastructure mean something like
voice versus written? What about situations where the primary telephone system is Voice Over Internet Protocol (VOIP) and it is using the same computer network infrastructure as an email or messaging
system. That is the “same infrastructure” but a different “medium” R1 and R2 - We suggest the drafting team look at Standard EOP-008, Requirements R3 and R8 and add appropriate language in
Standard COM-001-2, to avoid instantaneous non-compliance for loss of Interpersonal Communications and/or alternate Interpersonal communications. R1 - In later requirements it is proposed that the
entity “…shall designate an…”. It is suggested that for consistently and audit ability, this concept be used for R1, R3, R5, R7 and R8. In addition, the qualifier of “primary” should be used such that the
requirements read “… shall have designated, primary Interpersonal Communications capability with the following entities:” Although it is appropriate that “Alternative” be capitalized since it is used in a
defined term (i.e. Alternative Interpersonal Communication”) that bounds acceptable alternative methods , we do not see the need to capital “primary”. R9 - The requirement is unclear if the required
monthly test is a general functionality test or if there is the expectation of testing the designated Alternative Interpersonal Communications with all of the entities defined in the sub-requirements of R2,
R4, and R6. There is no expectation of testing the primary Interpersonal Communications - is this intentional or an oversight? Although functional testing of this should be done as a normal course of
business, should an explicit test be required with each entity in the sub-requirements of R1, R3, R5, R7 and R8 to insure, for example, that all the phone numbers are correct? R10 - The following scenario
seems plausible: The Interpersonal Communications fails and is detected at 14:00 and gets fixed at 14:35. It lasted more than 30 minutes but is fixed. As written the requirement would require the
responsible entity to notify entities identified in R1 through R6 by 15:00 (i.e. 60 minutes from detection) even though the problem no longer exists. Is that the expectation? Does COM-001 apply only to
primary control centers or back-ups, per EOP-008, as well? M9 reads “at least on a monthly basis”. We suggest that this be changed to “at least once per calendar month” as written in R9. This change
should also be corrected in the VSLs. M8 - We suggest removing the second “that” in the first sentence of the measure. M10 - We suggest this be revised to coincide with changes made in R10 (deleting
impacted and adding as identified in Requirements R1 through R6), therefore M10 should read: “Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall have and provide upon
request evidence that it notified entities as identified in Requirements R1 through R6 within 60 minutes of the detection of a failure of its Interpersonal Communications capabilities that lasted 30 minutes
or longer. Evidence could include, but is not limited to dated operator logs, dated voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent evidence. (R10.) “ M12
needs to be removed. We question why the first paragraph of Section 1.3 – Data Retention has been included in each of these three standards. We suggest that it should be removed from each standard.
COM-002-3 Comments R2 – We recommend that the following phrase (in quotes) be added to R2: Each Balancing Authority, Transmission Operator and Distribution Provider that is the recipient of a
Reliability Directive shall repeat, restate, rephrase or recapitulate the Reliability Directive “immediately upon receiving it.” As written, there is no limit as to when the entity must repeat it (i.e. they could
wait 2 hours) The Standard is not clear as to what each entity is to do when more than one entity receives a Reliability Directive at the same time (e.g. during a RC area teleconference call). For example,
is a roll call of receiving entities expected to be held so that they individually can repeat, restate, rephrase or recapitulate the Reliability Directive followed by individual confirmation required in R3? IRO001-3 Comments We recommend that where the verb “direct/directed” or noun “direction” is used in Purpose, R1, R2 and R3, that it be replaced with the verb “instruct/instructed” or noun “instruction”, as
appropriate. This would help the industry avoid confusion often referred to as “big D” or “little d” directives. It is noted that the term “Reliability Directive” does that to a great degree but avoiding the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
verb/noun “direct/direction” would augment the difference. R1 - At what point in time is “identified” referring to in “…to prevent identified events or…”? Is it referring to current or future events? One might
assume both since the “Time Horizon” is defined as Real-time Operations, Same Day Operations and Operations Planning, but the requirement may be enhanced if explicitly stated (“…to prevent events
identified in real-time or in the future or to mitigate the magnitude….”). For clarity, the scope of the authority should be limited to the Reliability Coordinator Area (“….that result in an Emergency or
Adverse Reliability Impacts within its Reliability Coordinator Area”). As written, it implies the authority should extend outside its RC Area. R2 – We question the phrase “physically implemented” and
recommend that the intent be clarified in the language. We note the following comment and response posted under Consideration of Comments on Initial Ballot — Reliability Coordination (Project 2006-06)
Date of Initial Ballot: February 25 – March 7, 2011: “IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower case (while it appears that “Directives” is a subset of “directions”).
We believe that this muddies the waters and could bring numerous conversations and dialog into scope unnecessarily. The end result is that the RC has the right to issue and use “Directives” and anything
short of this could just be communications. For example, a number of entities that are Reliability Coordinators also facilitate energy markets. There are many communications related to markets that
probably should be out of scope with respect to the standards. Furthermore, it might not be clear what role (eg Reliability Coordinator, market operator, etc) the staff at these entities is fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios and also emergency scenarios. The required performance encompasses issuing and responding to Reliability Directives as well
as other directions. The requirement language specifically ties back to Requirement R2 which states that the RC “shall take actions or direct actions, which could include issuing Reliability Directives, “. This
is the “direction in accordance with Requirement R2” stated in R3 and the “direction in accordance with Requirement R3” stated in R4.” We believe the entity’s comments remain valid and the response
provided by the SDT does not address all aspects of the concern. We suggest that the language be changed to “Reliability Directive” consistent with COM-002. R3 - The requirement states the responsible
entities shall “inform” its RC when unable to perform as directed but it is unclear when the notification needs to take place. Although the term “as soon as practical” may seem be unmeasureable, as
written now there is no time deadline to perform the notification – i.e. it could be 4 hours later after recognition. M2 – need to add the following words “compliance with, physically, unless” which were
included in R2, therefore M2 should read “Each Transmission Operator, Balancing Authority, Generator Operator, Interchange Coordinator and Distribution Provider shall have and provide evidence which
may include, but is not limited to dated operator logs, dated records, dated and time -stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent
documentation, that will be used to determine that it complied with its Reliability Coordinator's direction(s) per Requirement R1 unless compliance with the direction per Requirement R1 could not be
physically implemented or unless such actions would have violated safety, equipment, regulatory or statutory requirements. In such cases, the Transmission Operator, Balancing Authority, Generator
Operator, Interchange Coordinator or Distribution Provider shall have and provide copies of the safety, equipment, regulatory or statutory requirements as evidence for not complying with the Reliability
Coordinator’s direction. (R2) “ Section 1.3, the second bullet; need to add calendar to 12 calendar months “The comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Standards Review group only and should not be construed as the position of SERC Reliability Corporation, its board or its officers.”
Group
Salt River Project
Chris Chavez
Yes
Yes
Yes
Yes
Yes
Group
Pacific Northwest Generating Cooperative
Ron Sporseen
Yes
Yes
Yes
No
As per COM-001-2, R7, “Each Distribution Provider shall have Interpersonal Communications capability with the following entities…” R11 states that the DP or GO that experiences a failure of its
Interpersonal Communications ability shall consult with TOPs and BAs and agree on how to restore Interpersonal Communications. We believe better language might be, “Restore Interpersonal
Communications with your TOP/BA as soon as operationally feasible."
Yes
The PNGC Comment Group believes COM-002-3, R2, lacks justification for applicability to a Distribution Provider (DP). RCs in the WECC region do not communicate reliability directives to DP only entities.
Having this requirement apply to DPs seems to indicate that we will need 24/7 communications capability to record and respond to calls that will never come in order to satisfy the requirement with no
improvement to reliability. The SDT’s response from the last round of comments: “It is the expectation that an issuer of a Reliability Directive would request a return call by the Distribution Provider
operating personnel, then issue the Reliability Directive”. Nowhere is this expectation provided for in the written standard. If the issuer of a reliability directive has already called the DP, are they going to
then re-issue the reliability directive after the DP calls them back?
Individual
Paul Kerr
Shell Energy North America
Yes
Yes
Individual
Keira Kazmerski
Xcel Energy
Yes
No
In COM-001-2, R4.3. Adjacent Transmission Operators synchronously connected within the same Interconnection. This new requirement has a term that is not defined Adjacent Transmission Operators.
Yes
Yes
Yes
Group
Northeast Power Coordinating Council
Guy Zito
No
NERC uses the terms “adjacent” and “neighboring” in various standards. It is generally believed that those terms have the same meanings, but there are those who believe those terms, as used, are
intended to have different meanings. To ensure a consistent usage and understanding, the definition of the term adjacent must be made known before its addition to the standard. Consideration should be
given to using only one term in all standards if adjacent and neighboring are intended to mean the same thing. Both terms are used in NERC Standards, sometimes both in the same standard. For
example, EOP-001-2b uses “neighboring” in R5, and “adjacent” in R3.3.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For COM-001: 1. R1.2 and R2.2: The phrase “within the same Interconnection” is improper; it needs to be removed. RCs between two Interconnections still need to communicate with each other for
reliability coordination (e.g. between Quebec and the other RCs in the NPCC region to coordinate reliability issues including curtailing interchange transactions crossing an Interconnection boundary). The
SDT’s response to industry comments on the previous posting that the phrase was added to address the ERCOT situation (that ERCOT does not need to communicate with other RCs and that such
coordination takes place between TOPs) leaves a reliability gap. 2. R3.5 and R4.3: The phrase “synchronously connected within the same Interconnection” is also improper; it needs to be removed. TOPs
do communicate with other TOPs including those asynchronously connected and in another Interconnection (e.g. between Quebec and all of its asynchronously interconnected neighbors). The reason that
was used in response to the above comments (coordination among TOPs for DC tie operation) contradicts with the inclusion of this phrase in R3.5 and R4.3. 3. R4 and R6: Not requiring an Alternative
Interpersonal Communication capability between the BAs and the DP and GOP can result in a reliability gap. If Interpersonal Communication capability between the BAs and these entities is required to
begin with to enable BAs to communicate with these entities (such as operating instructions or Reliability Directives) to ensure reliable operations, then an alternative capability is also needed to ensure
this objective is achieved when the primary capability fails. 4. To preclude the possibility of problems arising from having different languages spoken between entities, COM-001-1.1 R4 should remain as it
was or those ideas kept in the revised requirement. R4 read: “R4. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use English as the
language for all communications between and among operating personnel responsible for the real-time generation control and operation of the interconnected Bulk Electric System. Transmission Operators
and Balancing Authorities may use an alternate language for internal operations.” 5. Measure M3 does not cover the added R3.5 condition (having Interpersonal Communications capability with each
adjacent TOP). M3 needs to be revised. For IRO-001: The Data Retention Section does not reflect the revised requirements. As examples: the Electric Reliability Organization is no longer a responsible
entity; the Reliability Coordinator should replace the ERO for keeping data for R1. Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider should replace the Reliability
Coordinator for keeping data for R2. And, in the Data Retention Section, R4 and M4 are mentioned. However, there are only three requirements with their corresponding measures in the standard.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
No
There is a risk of not properly identifying an abnormal condition (Emergency or Adverse Reliability Impact) in time to require specific use of the statement ‘this is a Reliability Directive’ when issuing
switching on the system in the event of an emergency. This is a deviation from consistently using 3-way communication when an emergency occurs. It may not be apparent that an emergency exists and
breaking from consistent use of expected 3-way communication could cause confusion.
Individual
Edward J Davis
Entergy Services, Inc
No
R3 adds additional responsibilities for the TOP to have Interpersonal Communications capability with EACH DP and GOP in its footprint. Similarly, R4 gives the TOP responsibility to have alternative
communications capability with each of these entities. This is a significant additional responsibility for the TOP to document and perhaps arrange for additional means of communication with these entities.
The short time frame provided for implementation of these requirements is not consistent with the additional effort and compliance documentation that is necessary to implement these requirements.
Entergy recommends that the implementation time frame for these new requirements that apply to new entities, or expand the application of COM-001 for existing entities have an effective date 12
months beyond the applicable regulatory approval. Additionally, the implementation of the requirements that apply to the DP and GOP will represent an increase in the amount of documentation that must
be retain to demonstrate compliance, and in some cases may also result in their having to purchase equipment or install new alternate means of communication. What is the improvement in reliability
expected as a result of these new requirements?
Yes
Entergy agrees with the inclusion of the term “Adjacent” in these requirements to limit the entities that the BA or TOP must have communications capability with to those that they border.
Yes
Yes, the requirements of this standard pertain to having communications capability. The specific content of that communication should not be the subject of the standard.
No
The DP or GOP should have to notify the TOP and BA of its communications failure, similar to the requirement in R10 for TOP and BA. The DP or GOP should restore the communications capability as soon
as possible. Entergy does not agree that the TOP or BA should have to negotiate the restoration time with the DP or GOP. This is an unreasonable burden on the BA and TOP.
No
An Adverse Reliability Impact is a type of Emergency. Including a new term for Adverse Reliability Impact and including both terms in the definition for Reliability Directive doesn’t add clarity. I suggest
changing the definition for Reliability Directive to remove phrase “or Adverse Reliability Impact.”
Entergy does not agree with including the DP and GOP in this standard. However, if they are to be included and are required to have the communications capability indicated, they should be included in
R10. Why would it be important for the TOP to notify the DP that their communications method has failed, but it is not important for the DP to notify the TOP when their communications method has failed.
The distinction doesn’t seem reasonable or meaningful. Additionally, in the draft of COM-002-3 requirement 2 contains the language that the recipient of the directive shall “repeat, restate, rephrase or
recapitulate” the directive. Why are so many synonyms of repeat necessary. Repeat or restate should be sufficient to get the point across.
Individual
Michael Falvo
Independent Electricity System Operator
No
In COM-001, we commented earlier that the entities in R4 and R6 (now R5 and R6) should be the same, i.e. the BA needs to have the Interpersonal Communication capability as well as the Alternative
Interpersonal Communication capability with the same entities. The SDT’s response indicates that the suggested change is not needed since additionally requiring DP and GOP entities to have Alternative
Interpersonal Communication capability would impose more cost on smaller DP and GOP entities that have little or no risk impact to the bulk electric system. We disagree with this assessment since the
need to have Alternative Interpersonal Communication capability should be assessed from the viewpoint that whether or not the absence of such capability can adversely affect reliability. If Interpersonal
Communication capability is needed between a BA and a DP/GOP to communicate reliability instructions or directives, then it is deemed necessary that such communication be provided at all times, which
indicates the need for an alternative capability. We once again urge the SDT to make the list of entities in R5 and R6 to be the same.
No
(1) We agree with the addition of “Adjacent” entities in the quoted parts except the qualifier “synchronously connected within the same Interconnection” need to be removed from Parts 3.5 and 4.3 since
TOPs do communicate with other TOPs even in another Interconnection (e.g. between Quebec and all of its asynchronously interconnected neighbors). Even in the case of ERCOT, TOPs on the two sides of
a DC tie do communicate with each other for daily operations. (2) Measure M3 does not cover the added R3.5 condition (having Interpersonal Communications capability with each adjacent TOP). M3
needs to be revised.
No
In the last posting, we suggest removing the phrase “within the same Interconnection” from R1 (now R2.2) since there are RCs between two Interconnections that need to communication with each other
for reliability coordination (e.g. between Quebec and the RCs the Northeast such as IESO, NYISO, NBSO and ISO-NE, and between the RCs in WECC with the RCs in the Eastern Interconnection). Such
coordination may include but not limited to curtailing interchange transactions crossing Interconnection/RC boundary, as stipulated in IRO-006. The SDT’s response to our comments citing that the phrase
was added to address the ERCOT situation leaves a reliability gap to the other situations. We again urge the SDT to remove the phrase. If necessary, the ERCOT situation can be addressed by a regional
variance.
Yes
Yes
(1) The proposed implementation plan conflicts with Ontario regulatory practice respecting the effective date of the standard. It is suggested that this conflict be removed by appending to the
implementation plan wording, after “applicable regulatory approval” in the Effective Dates Section A5 on P. 4 of the draft standard COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s
Implementation Plan and P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following effect: “, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.” (2) COM-001: Measure M9: - “monthly basis”. Suggest changing “monthly basis” to “at least once per calendar month” to be consistent the wording in R9. (3) IRO-001: Measures M1, M2, M3
– The types of evidence are listed in paragraph form. This is not consistent with presentation style in COM-001-2 Measures, where evidence is listed in bullet format. Suggest using bullet form for
consistency. (4) IRO-001, Data Retention Section: i. The retention requirements do not reflect the revised requirements. For example: the Electric Reliability Organization is no longer a responsible entity;
the Reliability Coordinator should replace the ERO for keeping data for R1; Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider should replace the Reliability
Coordinator for keeping data for R2; and there is no R4/M4. ii. Section 1.3, second paragraph: “The Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, or Distribution
Provider... shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an
investigation:” The word “or” between Generator Operator and Distribution Provider should be changed to “and”.
Group
MRO NSRF
Will Smith
Yes
No
NERC has formally defined “Adjacent Balancing Authority” in the NERC Glossary of Terms, but not “Adjacent Transmission Operator”. The MRO NSRF recommends that“Adjacent Transmission Operator” be
defined similar to the “Adjacent Balancing Authority” definition in the NERC Glossary of Terms.
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Yes
No
Please note that the use of the word “any” as in “Each Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication capabilities…” will be viewed as
meaning every Interpersonal Communication medium that an Entity has or uses. The NSRF recommends that the word “any” be removed from this Requirement The NSRF recommends that R11 be
revised to read: “Each Distribution Provider and Generator Operator that experiences a failure of anyof its primary (or defined) Interpersonal Communication capabilities with its Transmission Operator or
Balancing Authority... “. In that way it focuses it down to the communications issues with the TOP or BA. In lieu of “primary” the SDT could state “defined” as long as it is not meant to be “any”. The latter
part of R11 states; “…shall consult with their Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to restore the Interpersonal Communication capability.”
This ambiguous statement does not support reliability. Consulting with a TOP or BA does not solve the problem of the lack of Interpersonal Communication capabilities. The NSRF recommends this be
rewritten as: “…shall consult with inform their Transmission Operator or Balancing Authority as applicable as to the status of the Interpersonal Communication capability”. So the new R11 would read:
“Each Distribution Provider and Generator Operator that experiences a failure of its primary (or designated) Interpersonal Communication with their Transmission Operator or Balancing Authority shall
inform them, as applicable, as to the status of the Interpersonal Communication capability.”
Yes
Has the SDT looked at combining COM-002-3 and IRO-001-3 into a single Standard? It would allow Entities a one stop shopping place to refer to issuing and receiving a Reliability Directive. The definition
of Interpersonal Communication is: “Any medium that allows two or more individuals to interact, consult, or exchange information”. As stated in Question 4, the use of the word any will bring in mediums
that are outside the scope of this Standard. The NSRF recommends the following: Interpersonal Communication: The primary (or designated) medium that allows two or more individuals to interact,
consult, or exchange information. In Standard COM-002-3 the MRO NSRF recommends that the Effective Date be the first day of the second calendar quarter after applicable regulatory approval, to be the
same as COM-001-2 and IRO-001-3. In that way all 3 standards would be effective at the same time, making implementation much smoother. The below section will lead to entities hold evidence past the
12 month retention period. This ambiguous wording will force entities to hold data past the 12 month period as stated in the following paragraph, after the below sighting. Recommend that the first
paragraph within 1.3 be deleted in its entirety. 1.3. Data Retention The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate
compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other
evidence to show that it was compliant for the full time period since the last audit.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
For COM-001: R1.2 and R2.2: The phrase “within the same Interconnection” is improper; it needs to be removed. RCs between two Interconnections still need to communicate with each other for
reliability coordination (e.g. between Quebec and the other RCs in the NPCC region to coordinate reliability issues including curtailing interchange transactions crossing an Interconnection boundary). The
SDT’s response to industry comments on the previous posting that the phrase was added to address the ERCOT situation (that ERCOT does not need to communicate with other RCs and that such
coordination takes place between TOPs) leaves a reliability gap. 2. R3.5 and R4.3: The phrase “synchronously connected within the same Interconnection” is also improper; it needs to be removed. TOPs
do communicate with other TOPs including those asynchronously connected and in another Interconnection (e.g. between Quebec and all of its asynchronously interconnected neighbors). The reason that
was used in response to the above comments (coordination among TOPs for DC tie operation) contradicts with the inclusion of this phrase in R3.5 and R4.3. 3. R4 and R6: Not requiring an Alternative
Interpersonal Communication capability between the BAs and the DP and GOP can result in a reliability gap. If Interpersonal Communication capability between the BAs and these entities is required to
begin with to enable BAs to communicate with these entities (such as operating instructions or Reliability Directives) to ensure reliable operations, then an alternative capability is also needed to ensure
this objective is achieved when the primary capability fails. 4. To preclude the possibility of problems arising from having different languages spoken between entities, COM-001-1.1 R4 should remain as it
was or those ideas kept in the revised requirement. R4 read:“R4. Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use English as the language
for all communications between and among operating personnel responsible for the real-time generation control and operation of the interconnected Bulk Electric System. Transmission Operators and
Balancing Authorities may use an alternate language for internal operations.” 5. Measure M3 does not cover the added R3.5 condition (having Interpersonal Communications capability with each adjacent
TOP). M3 needs to be revised. For IRO-001: The Data Retention Section does not reflect the revised requirements. As examples: the Electric Reliability Organization is no longer a responsible entity; the
Reliability Coordinator should replace the ERO for keeping data for R1. Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider should replace the Reliability Coordinator
for keeping data for R2. And, in the Data Retention Section, R4 and M4 are mentioned. However, there are only three requirements with their corresponding measures in the standard.
Individual
Daniel Duff
Liberty Electric Power LLC
Yes
Yes
Yes
No
The phrase "mutually agreeable time" needs to be replaced in order to make this standard acceptable. This phrasing creates a potential violation if equipment functionality cannot be restored in the time
frame preferred by another entity, even if the time of repair is beyond the control of the RE. This phrase should be replaced with "inform their TO or BA as applicable of the failure, and provide estimates
as to the time the Interpersonal Communication capabilities will be restored".
Yes
Individual
Joe O'Brien
NIPSCO
Yes
Yes
Yes
If the Interpersonal Communication is down, and no backup is required for the DP and GOP, how are they to consult and collaborate?
The question of whether one is in a state of Emergency or Instability, or in an Abnormal Condition can be still be subjective; it may be difficult to provide evidence for an audit.
In IRO-001 R2 an "and" is missing after Generator Operator, and the comma should be removed. Why are there 3 different Effective Dates for this project, each standard being different? To simplify, can't
they all be made identical?
Group
City of Tacoma, Department of Public Utilities, Light Division, dba Tacoma Power
Claire Lloyd
Yes
Yes
Yes
Yes
Yes
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
Yes
Yes
for COM-001-2 Oncor takes the position that contacting all impacted entities within 60 minutes of the detection of a failure of its Interpersonal Communications capabilities that lasts 30 minutes or longer
as prescribed in R1 through R6 is not doable within the ERCOT interconnect for a Transmission Operator. Oncor takes the position that notification only to the RC and BA is sufficient and that those two
entities have the operational functionality to contact within the prescribed time all affected Distribution Providers, Generator Operators, and other Transmission Operators. R10 - Oncor takes the position
that the word “impacted” added to R10 will clarify that notification only needs to be made to the entities that are effected by the failure of a communication path. This will also more align with the
language in M10 For COM-002-3 Oncor request clarity about what constitutes a “recipient”. For example, if a Transmission Grid Operator performing the functions of a Transmission Operator issues a
Reliability Directive to its own field operations personnel to perform an action on behalf of the same entity, does the field operations personnel as the recipient become in affect a “Transmission Operator”
subject to R2.
Individual
Chris de Graffenried
Conslidated Edison Co. of NY, Inc.
Yes
Yes
Yes
Regarding COM-002 Requirement R1, we recommend that this requirement be reworded as follows: “When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be
executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall require that the Reliability Directive be communicated using three-part communications as
described in Requirements R2 and R3 of this standard”. The reason for this recommended rewording are threefold: 1. Good operating practice calls for use of three-part communications at all times. The
recommended re-write encourages the use of the good operating practice of three-part communications at all times, but does not require it. 2. It is not good operating practice to require that an additional
(unnecessary) phrase be used during emergency situations. During emergency situations, it is best to use standard operating protocols so as to limit unnecessary burdens on operating personnel during
critical and stressful times. 3. By implementing the proposed new R1 requirement, it would effectively weaken the need for rigorous compliance with any and all directives issued by the RC’s, TO’s or BA’s.
Regarding IRO-001 Requirement R1, we recommend that the current requirement R3 be reinstated as the new requirement R1. That is, the new requirement R1 should read as follows: R1. The Reliability
Coordinator shall have clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers,
Load-Serving Entities, and Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions shall be taken without delay,
but no longer than 30 minutes. We do not support any further dilution of Reliability Coordinator authority to enforce Reliability Directives through deletion of the 30 minute maximum response time period.
The timely actions in response to any Reliability Coordinator issued Reliability Directives is an essential part of the process.
Individual
Anthony Jankowski
We Energies
Yes
Yes
Yes
Please add "does not include telemetered or derived data"
No
R11 Implies that R8 and R9 are independent and redundant to R5.3, R5.4 and R3.3 and R3.4. R11 is not clear on the purpose of the statement “ determine a mutually agreeable time for restoration” this
could be driven by forces outside the control any of the entities. I think” provide estimated restoration and actual restoration time and determine mutually agreeable alternative during outage” would be
better. Update M9 accordingly
Yes
The definition is accceptable, but as used may imply that all Emergency communications must be Reliability Directives.
COM-001, Although a great improvement over existing COM-001, and eliminates the data component see comments: •For R5.1 Can the solutions included to meet R1 be included, same R3.2 and R5.2,
same R5.3 and R7.2, same R5.4 and R8.1 •For R5.2 Can the solutions included to meet R2 be included, same R4.2 and R6.2 •R9 a 2 hour response for a once a month test seems extreme, as would
require a secondary Alternate Interpersonal Communications capability •M9 is reasonable, but should include something about communication actual repair and or time estimates •R10 The use of R1
through R6 implies notification of both Interpersonal Communications and Alternate Interpersonal Communications failures. Do you notify if you become aware after the link is back up if it was down for
GT 30 minutes, and Doesn’t address notifying when restored •R11 Implies that R8 and R9 are independent and redundant to R5.3, R5.4 and R3.3 and R3.4. R11 is not clear on the purpose of the
statement “ determine a mutually agreeable time for restoration” this could be driven by forces outside the control any of the entities. I think” provide estimated restoration and actual restoration time and
determine mutually agreeable alternative during outage” would be better. Update M9 accordingly COM-002 •Since all the Requirements are related to Reliability Directives, is it implied that all “Emergency
Communications” are Reliability Directives even if not designated as such per R1. •The M2 measure could be difficult for a recipient such as a Distribution Provider or Generator Operator. A recipient’s
phone may not be recorded but a initiator’s always should. If a receiver refused to meet the R2 requirement, an initiator should have an alternative. i.e. repeat the directive and provide potential penalties
if recipient refuses to comply. Should the initiator have responsibility for providing the entire 3-way evidence as M3 implies? IRO-001, Although a great improvement over existing IRO-001, see comments:
•R2 needs to be clear that it is the Reliability Coordinator’s Reliability Directive that must be complied with not just any Reliability Coordinator’s direction as stated. •The M2 measure could be difficult, as
the operator would have to have access to documents proving the safety, equipment, regulatory or statutory requirements, which may be the assessment of an individual applying the safety rule. Is the
measure requiring a deposition of the individual to be performed for each instance? With an assumed data retention of 90 day (voice) 12 month document retention the deposition would be unlikely to be
acquired prior to the retention period ending. •R3 needs to be clear that it is the inability to perform the Reliability Coordinator’s Reliability Directive that must be communicated not just any “Reliability
Coordinator’s as directed”. •The Data Retention section does not align with the standard: The Reliability Coordinator shall retain its evidence for the most recent 90 calendar days for voice recordings or 12
months for documentation for Requirement R2, Measure M2. R2 and M2 apply to the Transmission Operator, Balancing Authority, Generator Operator, or Distribution Provider. There is no R4 and M4.
Individual
J. S. Stonecipher, PE
City of Jacksonville Beach dba/ Beaches Energy Services
In R5.3, should a BA have communications with a DP or LSE? For the TOP, it is the DP because the load influence is very local; however, for a BA the supply/demand balance is not local and in markets
that allow retail competition, I'm thinking LSE is the right functional entity. For Florida, it doesn't really matter. If the LSE is the "correct" entity, then R7 would need to be changed and a new requirement
specific to LSE's would need to be added
Yes
Yes
Yes
Yes
COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications capability". I would suggest adding the phrase "...to each entity for which Alternative Interpersonal Communications is
required." to add clarity.
Individual
Scott Berry
Indiana Municipal Power Agency
No comment.
No comment.
No comment.
No
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
IMPA does not believe that this requirement is necessary in order to ensure communication lines are restored by Distribution Providers and Generator Operators. If this requirement is kept, IMPA does not
think the use of the words “a failure of any of its Interpersonal Communication capabilities” is acceptable. The wording is too inclusive and should apply to only primary Interpersonal Communication
capabilities. IMPA is also concerned about how entities are supposed to know when the telephone companies may have equipment repaired in order to determine a mutually agreeable time to restore
Interpersonal Communication capability. The entity may have no control over the restoration and hence would not be able to set a time other than whenever the capabilities are restored by for instance
the telephone company. In addition, entities will have to keep evidence to show that a “mutually” agreeable time was reached by two or more entities. The most workable solution would be to require
notification if primary Interpersonal Communication is lost and a follow-up notification when that capability is restored.
No comment.
For R2 in IRO-001-3, the requirement needs to have the entities comply with their Reliability Coordinator’s direction received in R1. Currently, requirement 2 directions are not linked back to R1 which
means entities would have to comply with all Reliability Coordinator’s directions regardless if they are associated with R1. For R7 in COM-001-2, IMPA does not believe that every Distribution Provider
needs to be included in requirement 7. IMPA recommends stating that requirement 7 only applies to Distribution Providers who own an UFLS or UFLS system.
Individual
Jeff Longshore
Luminant Energy Company LLC
Yes
Yes
Yes
Yes
Yes
IRO-001-3 R1 is not consistent with the direction taken in COM-002-3 which requires the Reliability Coordinator to identify Reliability Directive as such. The same approach should be taken with IRO-001-3
R1 so that the Reliability Coordinator is required to identify directions that are made to prevent identified events or mitigate the magnitude or duration of actual events that result in an Emergency or
Adverse Reliability Impacts as such prior to or when issuing the directions. This extra specification is needed to eliminate any possible confusion in areas where the market operator and Reliability
Coordinator are the same entity. In these areas, the Reliability Coordinator/market operator routinely gives directions to other entities that are not to prevent identified events or mitigate the magnitude or
duration of actual events that result in an Emergency or Adverse Reliability Impacts. Without the added clarification the receiving entity may not know the urgency of the situation and may not know to
inform the Reliability Coordinator if they are unable to perform as required by R3.
Group
CCG, CPG, CECD
Brenda Powell
No
As we commented on Project 2007-03 TOP-001-2, the definition of Reliability Directive is an improvement but the definition must capture the identification concept that is reflected in the Requirement
(R1). As a result, when Reliability Directive is used elsewhere, it would be clear that the communication must be identified as a Reliability Directive. We suggest the following revision to the definition and it
should follow through to Project 2006-06 IRO-001-3 and Project 2007-03 TOP-001-2, eventually being added to the Reliability Standards Glossary of Terms. A communication identified as a Reliability
Directive by a Reliability Coordinator, Transmission Operator, or Balancing Authority to initiate action by the recipient to address an Emergency or Adverse Reliability Impact.
Comments: IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3. To avoid confusion with a Reliability Directive (both for auditors and entities), we suggest the following: To establish
the authority of Reliability Coordinators to make requests of other entities to prevent an Emergency or Adverse Reliability Impacts to the Bulk Electric System. R1: Each Reliability Coordinator shall have
the authority to act or request others to act (which could include issuing Reliability Directives)to prevent identified events or mitigate the magnitude or duration of actual events that result in an
Emergency or Adverse Reliability Impacts. R2: Each Transmission Operator, Balancing Authority, Generator Operator, Distribution Provider shall comply with its Reliability Coordinator’s request unless
compliance with the request cannot be physically implemented, or unless such actions would violate safety, equipment, regulatory or statutory requirements, or unless the TOP, BA, GOP or DP convey a
business reason not to comply with the request but express that they will comply if a Reliability Directive is given. R3:Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its inability to perform as requested in accordance with Requirement R2.
Individual
Brian J. Murphy
NextEra Energy, Inc.
Yes
Yes
Yes
No
NextEra Energy, Inc. (NextEra), which includes Florida Power & Light Company, believes that Requirement 11 of COM-001-2, as drafted, is too vague to be adopted as a mandatory Reliability Standard.
For example, it is unclear what is meant by “shall consult.” The North American Electric Reliability Corporation’s (NERC) Rules of Procedure state that a foundation of any Reliability Standard is that: “. . .
[the] reliability standard shall be stated using clear and unambiguous language. Responsible entities, using reasonable judgment and in keeping with good utility practices, are able to arrive at a consistent
interpretation of the required performance.” The term “shall consult” is not a term generally understood or used in the electric utility industry, and, therefore, does not enable a consistent interpretation of
the performance required. Accordingly, NextEra requests that Requirement 11 either: (i) be deleted; or (ii) be redrafted to read more like Requirement 10.
No
NextEra objects to the use of “Adverse Reliability Impact” in Reliability Standards COM-002-3 and IRO-001-3. NextEra requests that the use of Adverse Reliability Impact be revised as suggested below or
it be deleted from the definition of Reliability Directive. NextEra does not agree with the use of Adverse Reliability Impact in the definition of “Reliability Directive” for the following reasons: 1. This term
Adverse Reliability Impact is ambiguous. In part, the term is ambiguous because it includes in its definition the term “instability,” which has lead to considerable misunderstanding and confusion in the
industry. There are also differing views on what is (and is not) Cascading, because the definition is not sufficiently clear. For example, some believe instability and Cascading occur when an event affects
multiple substations of one Transmission Operator, while others believe instability or Cascading only occur when the event affects more than one Transmission Operator’s system. As mentioned in
response to item 4, above, Reliability Standards must be clear and consistently interpreted. It is not appropriate to issue a Standard that perpetuates the use of terms that lack consistent interpretation. 2.
While not perfect, the term Emergency is better understood in the industry, and it may include many or all of the instances of instability or Cascading intended to be captured by Adverse Reliability Impact.
Consequently, it is not advisable to introduce Adverse Reliability Impact as a new term, when it is not clearly distinguishable from Emergency. NextEra is concerned that an unclear and imprecise term,
such as Adverse Reliability Impact, does not promote reliability, and, such a term is particularly troublesome in the context of real time system operations. Therefore, for the reasons stated above, NextEra
believes that the term Adverse Reliability Impact should be deleted from the definition of Reliability Directive. In the alternative, if Adverse Reliability Impact is not deleted from the definition of Reliability
Directive in Reliability Standards COM-002-3 and IRO-001-3, NextEra requests that Adverse Reliability Impact be revised to read: “an event or condition on the Bulk Electric System that may, or is leading
to, Cascading over more than one Bulk Electric System transmission system.”
NextEra has the following additional comments. COM-002-3 The purpose of COM-002-3 is: “To ensure Emergency communications between operating personnel are effective.” This stated purpose is not
the same as the specific requirement that three-way communication is used for a Reliability Directive. Thus, NextEra requests that the purpose be revised to read as follows: “To ensure that when a
Reliability Directive is given that the Reliability Directive is explicitly stated and three-way communication is used.” Consolidation of COM-002-3 and IRO-001-3 NextEra notes a continuing area of concern
with the somewhat unsynchronized approach taken in the drafting process. Reliability Standards COM-002 and IRO-001 are now on version three, and still there is a somewhat unsynchronized approach
being proposed. A clear and consolidated approach seems easily achievable with minimal effort. Thus, as proposed below, NextEra requests that COM-002-3 and IRO-001-3 be combined, which also would
appear to allow for the retirement of certain requirements, such as TOP-001-1 R1-4. NextEra also is concerned that the current approach may have contributed to several significant misstatements in IRO001-3, R1-3, which use the terms “direct,” “direction” and “directed,” instead of the term Reliability Directive as used in COM-002-3. COM-002-3 and IRO-001-3 indicate that three-way communication
only is required when a Reliability Directive is issued. This begs the question of what are the potentially other, lower classes of directives in IRO-001-3 R1-3? And why do they need to be followed with or
without three-way communication? Thus, at a minimum, NextEra requests that the terms direct, direction and directed be deleted from IRO-001-3 R1-3, respectively, and that Reliability Directive be
inserted. This change, and other proposed changes, are reflected in NextEra’s overall proposal to combine COM-002-3 and IRO-001-3 into one COM-002-3 standard: {Note: If the term Adverse Reliability
Impact is revised as proposed by NextEra, then the term would not need to be stricken} R1. Each Reliability Coordinator shall have the authority to act and to issue a Reliability Directive to a Transmission
Operator, Balancing Authority, Generator Operator and Distribution Provider within its operating region to prevent identified events that may lead to, or to mitigate the magnitude or duration of, an
Emergency. [Violation Risk Factor: High][Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] R1.1 Each Transmission Operator shall have the authority to act or issue a
Reliability Directive to a Balancing Authority, Generator Operator and Distribution Provider within its operating region to prevent identified events that may lead to, or to mitigate the magnitude or duration
of, an Emergency. [Violation Risk Factor: High][Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] R1.2 Each Balancing Authority shall have the authority to act or issue
a Reliability Directive to a Generator Operator and Distribution Provider within its balancing region to prevent identified events that may lead to, or to mitigate the magnitude or duration of, an Emergency.
[Violation Risk Factor: High][Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] R2. When a Reliability Coordinator, Transmission Operator or Balancing Authority issues a
Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon:
Real-Time] R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the recipient of a Reliability Directive shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time Horizon: Real-Time] R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a Reliability Directive shall
either [Violation Risk Factor: High][Time Horizon: Real-Time]: • Confirm that the response from the recipient of the Reliability Directive (in accordance with Requirement R2) was accurate, or • Reissue the
Reliability Directive to resolve any misunderstandings. R4. Each Transmission Operator, Balancing Authority, Generator Operator, Distribution Provider shall comply with its Reliability Coordinator’s
Reliability Directive, unless compliance with the Reliability Directive cannot be physically implemented or unless such actions would violate safety, equipment, regulatory or statutory requirements.
[Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] R4.1 Each Transmission Operator, Balancing Authority, Generator Operator, and
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Distribution Provider shall inform its Reliability Coordinator upon recognition of its inability to perform a Reliability Directive in accordance with Requirement R4. [Violation Risk Factor: High] [Time Horizon:
Real-time Operations, Same Day Operations and Operations Planning] R5. Each Balancing Authority, Generator Operator, and Distribution Provider shall comply with its Transmission Operator’s Reliability
Directive, unless compliance with the Reliability Directive cannot be physically implemented or unless such actions would violate safety, equipment, regulatory or statutory requirements. [Violation Risk
Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] R5.1. Each Balancing Authority, Generator Operator, and Distribution Provider shall inform its
Transmission Operator upon recognition of its inability to perform a Reliability Directive in accordance with Requirement R5. [Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same Day
Operations and Operations Planning] R6. Each Generator Operator or Distribution Provider shall comply with its Balancing Authority’s Reliability Directive, unless compliance with the Reliability Directive
cannot be physically implemented or unless such actions would violate safety, equipment, regulatory or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same
Day Operations and Operations Planning] R6.1. Each Generator Operator or Distribution Provider shall inform its Balancing Authority upon recognition of its inability to perform a Reliability Directive in
accordance with Requirement R6. [Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and Operations Planning] Conclusion Given the importance of having clear and
concise Reliability Standards on the issue of directives and three-way communication, until the above concerns raised by NextEra in items 4 through 6 are addressed, NextEra intends to continue to vote
“no” on COM-001-2, COM-002-3 and IRO-001-3.
Individual
David Thorne
Pepco Holdings Inc.
Yes
Yes
Yes
Yes
Yes
Individual
John Bee
Exelon
Yes
No
May have an unintended effect on registrations as some GOPs use a intermediately dispatch organization that perform actions on behalf of the generating units.
Yes
Yes
Yes
Group
LG&E and KU Services Company
Brent Ingebrigtson
Yes
Yes
Yes
No
Regarding R11, as written it is unclear when the DP and GOP are required to consult with their TOP or BA. “[A] failure of any of its Interpersonal Communication capabilities” could be construed to mean
any internal phone line of either the DP or GOP failing. Internal phone lines do not affect either the DP’s or GOP’s ability to communicate with the TOP or BA. It is also unclear whether a failure of an
interpersonal communication capability would require consultation if there were multiple other interpersonal communication capabilities that were still fully functional. Furthermore, what exactly is required
in “consultation” and who would be responsible if the “consulting” entities did not come to a “mutually agreeable time” are questions that are left unanswered. LG&E and KU Services Company suggest the
following language: R11. Each Distribution Provider and Generator Operator that experiences a failure of more than one of its Means for Interpersonal Communications or failure of its Alternative Means for
Interpersonal Communication with their Transmission Operator or Balancing Authority shall notify their Transmission Operator or Balancing Authority regarding the time to restore the impacted Means for
Interpersonal Communication or Alternative Means for Interpersonal Communication.
Yes
COM-001-2 Regarding COM-001-2 and proposed definitions, LG&E and KU Services recommends changing the terms being defined from “Interpersonal Communications” and “Alternative Interpersonal
Communication” to “Means for Interpersonal Communication” and “Alternative Means for Interpersonal Communication.” A communication is an exchange of information, not a medium. The medium is
simply the means. LG&E and KU Services Company further recommend that each requirement be rewritten with these new defined terms as appropriate and that the word “capabilities” currently following
the defined terms be removed from each of the requirements. We suggest the definition for “Means for Interpersonal Communication” be “A medium utilizing electromagnetic energy that allows two or
more individuals to interact, consult or exchange information.” We suggest the definition for “Alternative Means for Interpersonal Communication” be “Any Means for Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as, Means for Interpersonal Communications used for day-to-day operation.” Finally, LG&E and KU Services
Company request clarification that the requirements to have in place Interpersonal Communications and Alternative Interpersonal Communications do no establish noncompliance for the unavailability of
either medium provided the reporting requirements set forth in the standard are otherwise met. All Proposed Standards LG&E and KU Services Company suggest that the first paragraph in section 1.3
Data Retention be removed from all proposed standards. It states: …For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance
Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. While LG&E and KU Services Company is confident that the
SDT intended to clarify entities’ data retention responsibilities, this paragraph could be clarified to indicate that it does not require that any additional evidence be retained and provided beyond that
written in the standard’s requirements
Group
Bonneville Power Administration
Chris Higgins
Yes
Yes
Yes
Yes
Yes
BPA supports COM-001-2, COM-002-3 and IRO-001-3 as written and has no comments or concerns at this time.
Individual
Joe Petaski
Manitoba Hydro
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
No
COM-001-2 R11 does not specify a timeline in which entities have to come up with a ‘mutually agreeable’ time to restore Interpersonal Communication capability. Manitoba Hydro believes this omission
creates a reliability gap and suggests that wording be revised as follows: ‘… shall consult with their Transmission Operator or Balancing Authority as applicable and determine a mutually agreeable time to
restore the Interpersonal Communication capability within 24 hours of experiencing the failure.’
Yes
COM-001-2 -Definition ‘Interpersonal Communication’ - for clarity, the definition should explicitly state that data exchange is not included. -R9 - for clarity, the wording ‘…. within 2 hours’ should be
replaced with ‘... within 2 hours of the unsuccessful test’. Conforming change required to M9 as well. -R10 - for clarity, the wording ‘… as identified in R1 through R6… ’ should be replaced with ‘… with
which it is required to have Interpersonal Communications capability or Alternative Interpersonal Communication capability…’. -M6 - the term ‘Adjacent’ needs to be capitalized in the last sentence of the
paragraph as ‘Adjacent Balancing Authority’ is a NERC defined term. -M7 - ‘that’ in the first line is repeated -M9 - the wording ‘on a monthly basis’ should be replaced with ‘once per calendar month’ to be
consistent with the wording of the R9. -M11 - the words ‘that experiences a failure of any of its Interpersonal Communications capabilities’ should be added after Operator to be consistent with the wording
of the Requirement -Compliance – 1.3 bulleted sentences – the term ‘historical data’ should be removed. The term 'evidence' is sufficiently descriptive and is consistently used in other requirements -Data
Retention (1.3) - The data retention requirements are too uncertain for two reasons. First, the requirement to “provide other evidence” if the evidence retention period specified is shorter than the time
since the last audit introduces uncertainty because a responsible entity has no means of knowing if or when an audit may occur of the relevant standard. Secondly, it is unclear what ‘other evidence’,
besides the specified logs, recordings and emails, an entity may be asked to provide to demonstrate it was compliant for the full time period since their last audit. This comment also applies to COM-002-3
and IRO-001-3. -Data Retention (1.3) - COM-002-3 requires that voice recordings are kept for the most recent 3 calendar months but COM-001-2 requires that they be kept for the most recent 12
calendar months. Manitoba Hydro does not see the reliability benefit of storing voice recordings for longer than 3 months and suggests that voice recordings be removed as evidence for COM-001-2.
Evidence of the availability of Interpersonal Communications and Alternative Interpersonal Communications can be demonstrated using the other forms of evidence listed. -VSLs (general comment) - for
clarity, use for example R1.1 and R1.2 to refer to requirements instead of Part 1.1 and Part 1.2. -VSLs R4 - a reference to R4.3 is missing COM-002-3 -Title - to capture the purpose and intent of the
standard, the title should be changed to ‘Emergency Communications’. -R2 - for clarity, the words ‘back to the sender’ should be added to the end of the sentence -R3 - for clarity, the words ‘to the
recipient’ should be added to both of the bulleted sentences after ‘confirm’ and ‘reissue’. The words ‘evident from the response’ should be added to the end of the second bullet. -A question for the drafting
team: has it been discussed whether there should be an additional requirement which indicates that the Reliability Coordinator, Transmission Operator and Balancing Authority shouldn’t take any action in
a Reliability Directive until such time as it has been confirmed accurate by the sender? If so, does the team feel that its a worthwhile requirement to consider? -M2 - the words ‘restated, rephrased or
recapitulated' should be added after ‘repeated’ to be consistent with wording of the requirement. -M3 - the words ‘to show’ should be deleted from the end of this paragraph. IRO 001-3 -Purpose – the
words ‘to the Bulk Electric System’ already appear in the definitions of Emergency and Adverse Reliability Impact and do not need to be repeated here. -Effective Date - the effective date should be
changed to the 2nd calendar quarter following BOT approval in jurisdictions not requiring regulatory approval to be consistent with jurisdictions requiring regulatory approval. -General comment - There
are repeated references to ‘identified events’ – it is not clear what this is referring to. M1 - M1 refers to Adverse Reliability Impacts “within its Reliability Coordinator Area”. The requirement does not refer
to ‘within its Reliability Coordinator Area’ – the wording in the measure and in the requirement should be consistent. -M2 – missing the word ‘physically’ when describing that a direction could not be
implemented, should be consistent with the wording in the requirement. -Compliance – the entire section needs to be updated as it refers to requirements and measures that don’t exist. -VSLs R2 – the
reference to ‘fully comply’ is very vague. It is only a violation if the entity does not fall within the exception. - R2 VSL - For clarity, change “RC’s directive” to “Reliability Coordinator’s Reliability Directive”.
Group
Southern Company
Antonio Grayson
Yes
No
We are concerned regarding communications between Transmission Operators on opposite ends of DC ties which may or may not be in the same interconnection. Similarly, COM-001, R1.2 limits the
requirement of adjacent Reliability Coordinators to the same interconnection and this should not be limited to the same interconnection whether it is synchronous or non-synchronous. The measures
should also be verified to ensure that they align properly with the final requirements.
Yes
We suggest that this phrase should also be removed from the “Purpose” statement.
No
We suggest the following changes: 1. Requirement 10 should include Distribution Providers and Generator Operators, 2. Entities to be notified should be “as identified in requirements R1 through R8”, 3.
Requirement 11 should be deleted, and, 4. Measures (M10) and VSLs should be adjusted accordingly.
No
This definition would encompass more communication than is now included. The definition now requires that a directive be declared as a part of the three part communication. For example, sending out
the voltage schedule each morning would be included as a directive using the new definition. We suggest adding the words “and identified as a reliability directive to the recipient” at the end of the
definition of Reliability Directive. This would allow the removal of R1 from COM-002-3
We question why the first paragraph of Section 1.3 – Data Retention has been included in each of these three standards. We suggest that it should be removed from each standard. We suggest the
drafting team look at Standard EOP-008, Requirements R3 and R8 and add appropriate language in Standard COM-001-2, to avoid instantaneous non-compliance for loss of Interpersonal Communications
and/or alternate Interpersonal communications (R1 and R2). COM-001-2 Dominion VP: COM-001-2; M9 reads “at least on a monthly basis”, Dominion suggests that this be changed to “at least once per
calendar month” as written in R9. This change should also be corrected in the VSLs. M8 - We suggest removing the second “that” in the first sentence of the measure. M10 - Dominion suggests this be
revised to coincide with changes made in R10 (deleting impacted and adding as identified in Requirements R1 through R6), therefore M10 should read: “Each Reliability Coordinator, Transmission
Operator, and Balancing Authority, shall have and provide upon request evidence that it notified entities as identified in Requirements R1 through R6 within 60 minutes of the detection of a failure of its
Interpersonal Communications capabilities that lasted 30 minutes or longer. Evidence could include, but is not limited to dated operator logs, dated voice recordings or dated transcripts of voice recordings,
electronic communications, or equivalent evidence. (R10.) “ M12 needs to be removed. Southern: Definition of Alternative Interpersonal Communication: Any Interpersonal Communication that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communications used for day-to-day operation. Comments: • The proposed definition uses the term
“medium”. What is the scope of that? Telephony is a “medium” but there is wired, wireless, satellite, etc. Was “medium” intended to differentiate voice, paper, text, email, teletype, or something else? •
Similar to that last question – does the qualifying term “same” when modifying infrastructure mean something like voice versus written? What about situations where the primary telephone system is Voice
Over Internet Protocol (VOIP) and it is using the same computer network infrastructure as an email or messaging system. That is the “same infrastructure” but a different “medium” R1 Each Reliability
Coordinator shall have Interpersonal Communications capability with the following entities: …… Comments • In later requirements it is proposed that the entity “…shall designate an…”. it is suggested that
for consistently and auditability, this concept be used for R1, R3, R5, R7 and R8. In addition, the qualifier of “primary” should be used such that the requirements read “… shall have designated, primary
Interpersonal Communications capability with the following entities:” Although it is appropriate that “Alternative” be capitalized since it is used in a defined term (i.e. Alternative Interpersonal
Communication”) that bounds acceptable alternative methods , we do not see the need to capital “primary”. R9 Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall test its
Alternative Interpersonal Communications capability at least once per calendar month. Comments • The requirement is unclear if the required monthly test is a general functionality test or if there is the
expectation of testing the designated Alternative Interpersonal Communications with all of the entities defined in the subrequirements of R2, R4, and R6. • There is no expectation of testing the primary
Interpersonal Communications is this intentional or an oversight? Although functional testing of this should be done as a normal course of business, should an explicit test be required with each entity in
the subrequirements of R1, R3, R5, R7 and R8 to insure, for example, that all the phone numbers are correct? R10 Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall notify
entities as identified in Requirements R1 through R6 within 60 minutes of the detection of a failure of its\ Interpersonal Communications capabilities that lasts 30 minutes or longer. Comments • The
following scenario seems plausible: The Interpersonal Communications fails and is detected at 14:00 and gets fixed at 14:35. It lasted more than 30 minutes but is fixed. As written the requirement would
require the responsible entity to notify entities identified din R1 through R6 by 15:00 (i.e. 60 minutes from detection) even though the problem no longer exists. Is that the expectation? General Question
• Does COM-001 apply only to primary control centers or back-ups, per EOP-008, as well? COM-002-3 Southern R1 When a Reliability Coordinator, Transmission Operator or Balancing Authority requires
actions to be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the recipient. Comment • It is
recommended that the requirement be clarified that the Reliability Directive be identified as such during its delivery. (e.g. “….shall identify the action as a Reliability Directive to the recipient during its
delivery.”) R2 Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the recipient of a Reliability Directive shall repeat, restate, rephrase or recapitulate
the Reliability Directive. Comment • It is recommended that the requirement be clarified that an entity receiving a Reliability Directive repeat, restate, rephrase or recapitulate it immediately upon
receiving it. (e.g. “….shall shall repeat, restate, rephrase or recapitulate the Reliability Directive immediately upon receiving it.”). As written, there is not limit as to when the entity must repeat it (i.e. they
could wait 2 hours) General Question • The Standard is not clear as to what each entity is to do when more than one entity receives a Reliability Directive at the same time (e.g. during a RC area
teleconference call) . Is, for example, a roll call of receiving entities expected to be held so that they individually can repeat, restate, rephrase or recapitulate the Reliability Directive followed by individual
confirmation required in R3? IRO-001-3 Dominion VP R2 – Dominion questions the phrase “physically implemented” and recommends that the intent be clarified in the language. Dominion notes the
following comment and response posted under Consideration of Comments on Initial Ballot — Reliability Coordination (Project 2006-06) Date of Initial Ballot: February 25 – March 7, 2011: “IRO-001 R2,
R3, and R4 have replaced “Directives” with the word direction in lower case (while it appears that “Directives” is a subset of “directions”). We believe that this muddies the waters and could bring
numerous conversations and dialog into scope unnecessarily. The end result is that the RC has the right to issue and use “Directives” and anything short of this could just be communications. For example,
a number of entities that are Reliability Coordinators also facilitate energy markets. There are many communications related to markets that probably should be out of scope with respect to the standards.
Furthermore, it might not be clear what role (eg Reliability Coordinator, market operator, etc) the staff at these entities are fulfilling. Response: IRO-001 is written to cover both typical daily operating
scenarios and also emergency scenarios. The required performance encompasses issuing and responding to Reliability Directives as well as other directions. The requirement language specifically ties back
to Requirement R2 which states that the RC “shall take actions or direct actions, which could include issuing Reliability Directives, “. This is the “direction in accordance with Requirement R2” stated in R3
and the “direction in accordance with Requirement R3” stated in R4.” Dominion believes the entity’s comments remain valid and the response provided by the SDT does not address all aspects of the
concern. Dominion suggests that the language be changed to “Reliability Directive” consistent with COM-002. M2 – need to add the following words “compliance with, physically, unless” which were
included in R2, therefore M2 should read “Each Transmission Operator, Balancing Authority, Generator Operator, Interchange Coordinator and Distribution Provider shall have and provide evidence which
may include, but is not limited to dated operator logs, dated records, dated and time -stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent
documentation, that will be used to determine that it complied with its Reliability Coordinator's direction(s) per Requirement R1 unless compliance with the direction per Requirement R1 could not be
physically implemented or unless such actions would have violated safety, equipment, regulatory or statutory requirements. In such cases, the Transmission Operator, Balancing Authority, Generator
Operator, Interchange Coordinator or Distribution Provider shall have and provide copies of the safety, equipment, regulatory or statutory requirements as evidence for not complying with the Reliability
Coordinator’s direction. (R2) “ Section 1.3, the second bullet; need to add calendar to 12 calendar months Southern General recommendation • It is recommended that where the verb “direct/directed” or
noun “direction” is used in Purpose, R1, R2 and R3, that it be replaced with the verb “instruct/instructed” or noun “instruction”, as appropriate. This would help the industry avoid confusion often referred
to as “big D” or “little d” directives. It is noted that the term “Reliability Directive” does that to a great degree but avoiding the verb/noun “direct/direction” would augment the difference. R1 Each
Reliability Coordinator shall have the authority to act or direct others to act (which could include issuing Reliability Directives) to prevent identified events or mitigate the magnitude or duration of actual
events that result in an Emergency or Adverse Reliability Impacts. Comment • At what point in time is “identified” referring to in “…to prevent identified events or…” Is it referring to current or future
events? One might assume both since the “Time Horizon” is defined as Real-time Operations, Same Day Operations and Operations Planning but the requirement may be enhanced if explicitly stated (“…to
prevent events identified in real-time or in the future or to mitigate the magnitude….”). • For clarity, the scope of the authority should be limited to the Reliability Coordinator Area (“….that result in an
Emergency or Adverse Reliability Impacts within its Reliability Coordinator Area”). As written, it implies the authority should extend outside its RC Area. R2 Editorial comment – The words “compliance
with” are in a different font in the posted version. R3 Each Transmission Operator, Balancing Authority, Generator Operator, and Distribution Provider shall inform its Reliability Coordinator upon
recognition of its inability to perform as directed in accordance with Requirement R2. Comment The requirement states the responsible entities shall “inform” its RC when unable to perform as directed but
it is unclear when the notification needs to take place. Although the term “as soon as practical” may seem be unmeasureable, as written now there is no time deadline to perform the notification – i.e. it
could be 4 hours later after recognition.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Group
PPL Electric Utilities and PPL Supply NERC Registered Organizations
Annette M. Bannon
No
PPL has concerns with the use of the word “any” in this requirement. PPL recommends striking the words “any of” and instead using “its primary” as follows: Each Distribution Provider and Generator
Operator that experiences a failure of its primary Interpersonal Communication capabilities with its Transmission Operator or Balancing Authority... “. In the current version, it is unclear when the DP and
GOP are required to consult with their TOP or BA. “[A] failure of any of its Interpersonal Communication capabilities” could be construed to mean an internal phone line of either the DP or GOP failing.
Internal phone lines do not affect either the DP’s or the GOP’s ability to communicate with the TOP or BA. It is also unclear whether a failure of an interpersonal communication capability would require
consultation if there were multiple other interpersonal communication capabilities that were still fully functional.
Individual
Michael Brytowski
Great River Energy
Yes
No
"to exchange interconnection and operation information" was removed from the requirements in COM-001-2 but remains in the purpose. For consistency it needs to be removed. It could read "To establish
Interpersonal Communication capabilities for the exchange of information necessary to maintain reliability."
No
Capability is not used consistently in R7 and R11. It changes from singular to plural.
In IRO-001-3 "authority" should be removed and the verbage returned to "shall act." In COM-002-3 R2 and in Applicability we suggest removing the Distribution Provider as the RC would not likely give a
Reliability Directive to a Distribution Provider. The Reliability Directive would more likely come from the Transmission Operator to the Distribution Provider. In COM-002-3 R3 we suggest replacing
"Reissue" with "Restate." You are not technically reissuing the Reliability Directive.
Individual
David Burke
Orange and Rockland Utilities, Inc.
Yes
Yes
Yes
Regarding COM-002 Requirement R1, we recommend that this requirement be reworded as follows: “When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be
executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall require that the Reliability Directive be communicated using three-part communications as
described in Requirements R2 and R3 of this standard”. The reason for this recommended rewording are threefold: 1. Good operating practice calls for use of three-part communications at all times. The
recommended re-write encourages the use of the good operating practice of three-part communications at all times, but does not require it. 2. It is not good operating practice to require that an additional
(unnecessary) phrase be used during emergency situations. During emergency situations, it is best to use standard operating protocols so as to limit unnecessary burdens on operating personnel during
critical and stressful times. 3. By implementing the proposed new R1 requirement, it would effectively weaken the need for rigorous compliance with any and all directives issued by the RC’s, TO’s or BA’s.
Regarding IRO-001 Requirement R1, we recommend that the current requirement R3 be reinstated as the new requirement R1. That is, the new requirement R1 should read as follows: R1. The Reliability
Coordinator shall have clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers,
Load-Serving Entities, and Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These actions shall be taken without delay,
but no longer than 30 minutes. We do not support any further dilution of Reliability Coordinator authority to enforce Reliability Directives through deletion of the 30 minute maximum response time period.
The timely actions in response to any Reliability Coordinator issued Reliability Directives is an essential part of the process.
Group
SPP Standards Review Group
Robert Rhodes
Yes
Yes
We concur with the addition of “Adjacent” but ask that the SDT give some consideration to allowing an exemption in R6.3 for relatively small loads, less than 20 MW, that are pseudo tied into a Balancing
Authority. Loss of these facilities would not place a burden on the BES and should not require Alternative Interpersonal Communications capabilities.
Yes
No
We would suggest deleting the phrase ‘any of’ in the Requirement. It would then read ‘Each DP and GOP that experiences a failure of its Interpersonal Communication…’ Also, how does the DP or GOP
consult with its TOP or BA when it loses its Interpersonal Communications capability? To do this wouldn’t they have to have an Alternative Interpersonal Communications capability?
Yes
COM-001-2: Requirement 10 is too open ended as written. The measure, M10, indicates that only impacted entities need to be notified. The requirement should be changed to make it consistent with the
measure. The requirement would then read ‘Each RC, TOP And BA shall notify impacted entities as identified…’ Requirements 3 and 5 places the responsibility for establishing Interpersonal Communication
capability on the TOP and BA. It is quite conceivable that a TOP or BA may not know all, or newly, registered DPs and GOPs in its respective area. In Requirements 7 and 8, the DP and GOP, respectively,
are in turn responsible for establishing Interpersonal Communication capability. The TOPs/BAs and the DPs/GOPs should not be responsible for this. The DPs and GOPs should be held accountable for
requesting that capability of their TOP and BA. Therefore, we suggest adding the following phrase at the end of Requirements 3.3, 3.4, 5.3 and 5.4 – ‘that has requested Interpersonal Communications
capability.’ Then R3.3 would read ‘Each Distribution Provider within its Transmission Operator Area that has requested Interpersonal Communications capability.’ COM-002-3: Requirement 2/Measure 2:
There is an inconsistency between the requirement and the measure. The requirement allows the recipient to repeat, restate, rephrase or recapitulate the directive. Measure 1 only mentions repeating the
directive.
Group
Dominion
Mike Garton
Yes
Yes
Yes
Yes
Dominion agrees with the intent of R11; however, suggest language changes for consistency with R10 as follows:R11. Each Distribution Provider and Generator Operator that experiences a failure of any
of its Interpersonal Communication capabilities shall consult with their Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to restore the Interpersonal
Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
Yes
: COM-001-2; M9 reads “at least on a monthly basis”, Dominion suggests that this be changed to “at least once per calendar month” as written in R2. M8 Dominion suggests removing the second “that” in
the first sentence of the measure. M10 Dominion suggests this be revised to coincide with changes made in R10 (deleting impacted and adding as identified in Requirements R1 through R6), therefore M10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
should read: “Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall have and provide upon request evidence that it notified entities as identified in Requirements R1 through
R6 within 60 minutes of the detection of a failure of its Interpersonal Communications capabilities that lasted 30 minutes or longer. Evidence could include, but is not limited to dated operator logs, dated
voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent evidence. (R10.) “ M12 needs to be removed. IRO-001-3; R2 – Dominion questions the phrase
“physically implemented” and recommends that the intent be clarified in the language. Dominion notes the following comment and response posted under Consideration of Comments on Initial Ballot —
Reliability Coordination (Project 2006-06) Date of Initial Ballot: February 25 – March 7, 2011: “IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower case (while it appears
that “Directives” is a subset of “directions”). We believe that this muddies the waters and could bring numerous conversations and dialog into scope unnecessarily. The end result is that the RC has the
right to issue and use “Directives” and anything short of this could just be communications. For example, a number of entities that are Reliability Coordinators also facilitate energy markets. There are
many communications related to markets that probably should be out of scope with respect to the standards. Furthermore, it might not be clear what role (eg Reliability Coordinator, market operator, etc)
the staff at these entities are fulfilling. Response: IRO-001 is written to cover both typical daily operating scenarios and also emergency scenarios. The required performance encompasses issuing and
responding to Reliability Directives as well as other directions. The requirement language specifically ties back to Requirement R2 which states that the RC “shall take actions or direct actions, which could
include issuing Reliability Directives, “. This is the “direction in accordance with Requirement R2” stated in R3 and the “direction in accordance with Requirement R3” stated in R4.” Dominion believes the
entity’s comments remain valid and the response provided by the SDT does not address all aspects of the concern. Dominion suggests that the language be changed to “Reliability Directive” consistent
with COM-002. M2 – need to add the following words “compliance with, physically, unless” which were included in R2, therefore M2 should read “Each Transmission Operator, Balancing Authority,
Generator Operator, Interchange Coordinator and Distribution Provider shall have and provide evidence which may include, but is not limited to dated operator logs, dated records, dated and time stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent documentation, that will be used to determine that it complied with its Reliability Coordinator's
direction(s) per Requirement R1 unless compliance with the direction per Requirement R1 could not be physically implemented or unless such actions would have violated safety, equipment, regulatory or
statutory requirements. In such cases, the Transmission Operator, Balancing Authority, Generator Operator, Interchange Coordinator or Distribution Provider shall have and provide copies of the safety,
equipment, regulatory or statutory requirements as evidence for not complying with the Reliability Coordinator’s direction. (R2) “ Section 1.3, the second bullet; need to add calendar to 12 calendar
months
Individual
Michael Schiavone
Niagara Mohawk (dba National Grid)
Yes
Yes
Yes
Yes
No
The "adverse reliability impact" definition is not clear, is this an actual event or contingency? The words imply it is an actual event which is already covered in the "Directive" definition. If the intent is to
apply directives to potential stability or cascading contingencies it should say so.
COM-001-3 - Some requirements are overly prescriptive and not results based. R7 & R8 are not necessary. Every entity at a minimum has a contact with a phone as a thier "Interpersonal Communications
capability". Just need to require that every entity has a plan if they loose thier primary communication channel ("Interpersonal Communications capability"). COM-002-3 - Requiring RCs, TOPs and BAs to
state an action as a "reliability directive" complicates communications during a time when response time and clarity are important. If those issuing a directive don't get a repeat back they just need to ask
for one. The requirement just needs to define "what" is required not "how". This can be handled by procedures and training. - Delete reference to "adverse reliability impact" from the "Directive" defintion.
The "adverse reliability impact" definition is not clear, is this an actual event or contingency? The words imply it is an actual event which is already covered in the "Directive" definition. If the intent is to
apply directives to potential stability or cascading contingencies it should say so.
Group
Western Electricity Coordinating Council
Steve Rueckert
Yes
Yes
Yes
No
We have two concerns with R11 as worded First the term "as applicable" is undefined. Who decides what is applicable. We suggest that words clarifying which entity, TOP or BA, the DP and GO expeiencing
a failure of any of its Interpersonal Communication capabilities must consult with. Second, the inclusion of the "mutually agreeable" time to restore the Interpersonal Communication Capability is
problematic. Although unlikely, two entities could "mutually agree" to an exceptionally long time frame for restoration (two years) and that unreasonalbe timeframe would meet the requirement as long as
they both agreed. Suggest some finite time limit be included.
Yes
Individual
Thad Ness
American Electric Power
Yes
Yes
Yes
No
Regarding COM-001-02 R10 and R11, some of the entity pairs (for example, BA to a GO) are not required to have alternative inter-personnel communication. How can the notification occur with 60
minutes for example, when primary communication is not available for a role that doesn’t require an alternate means of communication? In addition, requiring notification within 60 minutes in
Requirement 10 would not be feasible for larger entities that might have hundreds of contacts to make.
COM-001-02 R9: A two hour limit to repair or designate a replacement Alternative Interpersonal Communications capability is overly aggressive. COM-002-03 R1: Should this requirement also include
references to a manual action? COM-002-03 R3: The text “to resolve any misunderstandings” is unnecessary and should be removed. COM-002-3 VSL’s: As we have stated on previous projects, all
severity levels need to be commensurate with both a) the degree by which the requirement was violated, and b) by the impact of the violation to the BES. In this case, a single VSL of “Severe” violates
both principles. There needs to be more gradients across the severity levels, and the single VSL of “Severe” incorrectly makes the assumption that the impact to the BES was severe. IRO-001-3 R1, R2,
R3: Having this requirement apply to actions and/or directions (which may be different than Reliability Directives) may put the recipient in a position that they are judged on whether or not they acted on
communication that was not a Reliability Directive. The draft states that the purpose of this standard is “To establish the capability and authority of Reliability Coordinators to direct other entities to
prevent an Emergency or Adverse Reliability Impacts to the Bulk Electric System”. The key word used is “direct”, so communications that need to be acted upon should be Reliability Directives only. The
addition of any non-defined term is in conflict with the definition and intent of the term Reliability Directive. This could potentially cause confusion, especially at critical times when communication is key.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
Yes
Yes
Yes
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Jason Snodgrass
Georgia Transmission Corporation
Yes
While we agree with removing LSE, PSE, and TSP, we do not agree with the need to include Distribution Provider in all the standards. For example, in IRO-001-3, the Distribution Provider will likely never
receive a Reliability Directive directly from its Reliability Coordinator. Reliability Directives received by Distribution Providers will be issued by the Transmission Operator or Balancing Authority depending
on if the issue is security or adequacy related. Accordingly, NERC’s Reliability Functional Model V5 describes and identifies the DP’s relationships with other Functional Entities to the TOP and BA with
respect to Real Time. Real Time 7. Implements voltage reduction and sheds load as directed by the Transmission Operator or Balancing Authority. 8. Implements system restoration plans as coordinated
by the Transmission Operator. 9. Directs Load-Serving Entities to communicate requests for voluntary load curtailment. Lastly, we believe that Distribution Providers requirements with respect to
complying with Reliability Directives received by TOPs and BAs are adequately covered by Reliability Standards TOP-001 and COM-002
Yes
No
The intent of this requirement is not yet clear. Technically, the air we breathe, as well as other mediums like “any” cell phone, fax lines, and/or email accounts would qualify under this proposed definition
of Interpersonal Communication. The burden for compliance evidence to demonstrate failure of “any of its Interpersonal Communication capability” would seem unobtainable and could prove to be a daily
occurrence (dropped phone calls, etc.). The following is suggested to utilize the singular form of capability rather than plural form of capabilities: R11. Each Distribution Provider and Generator Operator
that experiences a failure of its Interpersonal Communication capability shall consult with their Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to
restore the Interpersonal Communication capability.
Yes
The following comments are regarding IRO-001-3. Requirement R1 should require the use of Reliability Directives. The requirement compels the Reliability Coordinator “to direct others to act to prevent
identified events or mitigate the magnitude or duration of actual events that result in an Emergency or Adverse Reliability Impact”. Reliability Directives are necessary to address Adverse Reliability
Impacts or Emergencies and trigger the use of three-part communications identified in COM-002-3. COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive for Emergencies
and Adverse Reliability Impacts with the opening clause: “When a Reliability Coordinator, Transmission Operator, or Balancing Authority determines actions need to be executed as a Reliability Directive”.
What else could be more important for a Reliability Coordinator to issue a Reliability Directive than for an Emergency or Adverse Reliability Impact? Thus, not requiring the use of Reliability Directives for
Adverse Reliability Impacts and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. It is recommended that the treatment of Reliability Directives shall be consistent with those being
developed for TOP-001-2 as proposed by the Real-Time Operations drafting team (Project 2007-03). As such, consider using the following language for R2: “Each TOP, BA, and GOP shall comply with each
identified Reliability Directive issued and identified as such by its RC, unless such actions would violate safety, equipment, regulatory, or statutory requirements.” Accordingly, please consider using the
following language for R3: “Each TOP, BA, and GOP shall inform its RC of its inability to perform an identified Reliability Directive issued by that RC.” Again, we do not believe the DP would receive an
identified Reliability Directive directly from the RC and the DP applicability should be removed from this standard. The DP is appropriately captured under COM-002 and TOP-001 with respect to Reliability
Directives. Accordingly, NERC’s Reliability Functional Model V5 describes and identifies the DP’s relationships with other functional entities to TOP and BA with respect to Real Time. Real Time 7.
Implements voltage reduction and sheds load as directed by the Transmission Operator or Balancing Authority. 8. Implements system restoration plans as coordinated by the Transmission Operator. 9.
Directs Load-Serving Entities to communicate requests for voluntary load curtailment. The following comments are regarding COM-001-2. The SDT should include an additional qualifier to Interpersonal
Communications within the context of these requirements, for example (operational or dispatch center communications???). Technically, the air we breathe, as well as other mediums like “any” cell phone,
fax lines, and/or email accounts would qualify under this proposed definition of Interpersonal Communication. Assuming at least one employed individual can speak, all entities could demonstrate
compliance of this capability at all times, therefore, it is not clear the intent of these requirements are accurately being presented. It is recommended to include the use of “signed attestation letters” as
examples of evidence under M4 and M11 and other measures as appropriate.
Individual
Bill Keagle
BGE
Yes
Yes
Yes
Yes
No
BGE would prefer that the definition of Reliability Directive include the requirement to identify the fact that a Reliability Directive is being issued. See the following proposed definition: Reliability Directive:
A communication initiated and identified as a Reliability Directive, by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.
No comment.
Individual
Don Schmit
Nebraska Public Power District
Yes
Yes
Yes
No
We would suggest deleting the phrase ‘any of’ in the Requirement. It would then read ‘Each DP and GOP that experiences a failure of its Interpersonal Communication…’ Also, how does the DP or GOP
consult with its TOP or BA when it loses its Interpersonal Communications capability? To do this wouldn’t they have to have an Alternative Interpersonal Communications capability?
Yes
Comments: COM-001-2: Requirement 10 is too open ended as written. The measure, M10, indicates that only impacted entities need to be notified. The requirement should be changed to make it
consistent with the measure. The requirement would then read ‘Each RC, TOP And BA shall notify impacted entities as identified…’ Requirements 3 and 5 place the responsibility for establishing
Interpersonal Communication capability on the TOP and BA. It is quite conceivable that a TOP or BA may not know all, or newly, registered DPs and GOPs in its respective area. In Requirements 7 and 8,
the DP and GOP, respectively, are in turn responsible for establishing Interpersonal Communication capability. The TOPs/BAs and the DPs/GOPs should not be responsible for this. The DPs and GOPs
should be held accountable for requesting that capability of their TOP and BA. Therefore, we suggest adding the following phrase at the end of Requirements 3.3, 3.4, 5.3 and 5.4 – ‘that has requested
Interpersonal Communications capability.’ Then R3.3 would read ‘Each Distribution Provider within its Transmission Operator Area that has requested Interpersonal Communications capability.’
Requirement 9: could be construed to mean that the repair or replacement due to an unsuccessful test should be completed within 2 hours. In any case a rewording of the second sentence of Requirement
9 would make it clear and we would suggest the following: “ The responsible entity shall, within 2 hours of the unsuccessful test, provide notification to the proper authority in order to initiate repair or
designate a replacement Alternative Interpersonal Communications capability. “ COM-002-3: Requirement 2/Measure 2: There is an inconsistency between the requirement and the measure. The
requirement allows the recipient to repeat, restate, rephrase or recapitulate the directive. Measure 1 only mentions repeating the directive. Requirement 3: The second bullet in Requirement 3 appears to
require the reissuance of an entire Reliability Directive if only a single point in the directive is not correctly repeated, restated, rephrased or recapitulated. Is this what the SDT intended? Shouldn’t
consideration be given for that portion of the directive that was communicated properly? Then only a new, revised directive containing the portion of the original directive that was misunderstood would
need to be reissued.
Group
Southwest Power Pool Regional Entity
Emily Pennel
Yes
Yes
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Neil Phinney
Georgia System Operations
No
While we agree with removing LSE, PSE, and TSP, we do not agree with the need to include Distribution Provider in all the standards. For example, in IRO-001-3, the Distribution Provider will likely never
receive a Reliability Directive directly from its Reliability Coordinator. More likely, the Reliability Directive will be issued by the Transmission Operator or Balancing Authority depending on if the issue is
security or adequacy related. Accordingly, NERC’s Reliability Functional Model V5 describes and identifies the DP’s relationships with other Functional Entities to the TOP and BA with respect to Real Time.
Real Time 7. Implements voltage reduction and sheds load as directed by the Transmission Operator or Balancing Authority. 8. Implements system restoration plans as coordinated by the Transmission
Operator. 9. Directs Load-Serving Entities to communicate requests for voluntary load curtailment.
Yes
No
: The intent of this requirement is not yet clear. Technically, the air we breathe, as well as other mediums like “any” cell phone, fax lines, and/or email accounts would qualify under this proposed definition
of Interpersonal Communication. The burden for compliance evidence to demonstrate failure of “any of its Interpersonal Communication capability” would seem unobtainable and could prove to be a daily
occurrence (dropped phone calls, etc.). The following is suggested: R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication capability
shall consult with their Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable time to restore the Interpersonal Communication capability.
Yes
Requirement R1 should require the use of Reliability Directives. The requirement compels the Reliability Coordinator “to direct others to act to prevent identified events or mitigate the magnitude or
duration of actual events that result in an Emergency or Adverse Reliability Impact”. Reliability Directives are necessary to address Adverse Reliability Impacts or Emergencies and trigger the use of threepart communications identified in COM-002-3. COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive for Emergencies and Adverse Reliability Impacts with the opening
clause: “When a Reliability Coordinator, Transmission Operator, or Balancing Authority determines actions need to be executed as a Reliability Directive”. What else could be more important for a
Reliability Coordinator to issue a Reliability Directive than for an Emergency or Adverse Reliability Impact? Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts and
Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. It is recommended that the treatment of Reliability Directives shall be consistent with those being developed for TOP-001-2 as proposed
by the Real-Time Operations drafting team (Project 2007-03). As such, consider using the following language for R2: “Each TOP, BA, and GOP shall comply with each identified Reliability Directive issued
and identified as such by its RC, unless such actions would violate safety, equipment, regulatory, or statutory requirements.” Accordingly, please consider using the following language for R3: “Each TOP,
BA, and GOP shall inform its RC of its inability to perform an identified Reliability Directive issued by that RC.” Again, we do not believe the DP would receive an identified Reliability Directive directly from
the RC and the DP applicability should be removed from this standard. The DP is appropriately captured under COM-002 and TOP-001 with respect to Reliability Directives. Accordingly, NERC’s Reliability
Functional Model V5 describes and identifies the DP’s relationships with other functional entities to TOP and BA with respect to Real Time. Real Time 7. Implements voltage reduction and sheds load as
directed by the Transmission Operator or Balancing Authority. 8. Implements system restoration plans as coordinated by the Transmission Operator. 9. Directs Load-Serving Entities to communicate
requests for voluntary load curtailment. The following comments are regarding COM-001-2. The SDT should include an additional qualifier to Interpersonal Communications within the context of these
requirements, for example (operational or dispatch center communications???). Technically, the air we breathe, as well as other mediums like “any” cell phone, fax lines, and/or email accounts would
qualify under this proposed definition of Interpersonal Communication. Assuming at least one employed individual can speak, all entities could demonstrate compliance of this capability at all times,
therefore, it is not clear the intent of these requirements are accurately being presented. It is recommended to include the use of “signed attestation letters” as examples of evidence under M4 and M11
and other measures as appropriate.
Group
FirstEnergy
Sam Ciccone
Yes
Yes
Yes
No
Although we agree with the intent of the requirement, we are concerned with the use of “any of its Interpersonal Communication”. The word “any” is very inclusive and the team should consider narrowing
it down to those capabilities that may adversely impact reliability.
Yes
Definition of Interpersonal Communications ♣ We understand that the team does not want to be prescriptive as far as the specific types of communication mediums since we live in an age of many forms
of communication. But in this case it may be helpful to give examples in the definition. An auditor may interpret Interpersonal Communication to strictly include voice-related and two-way conversations.
Depending on the circumstances, other mediums may be adequate, such as blast calls or instant messaging. This should be clarified in the definition. COM-001-2 ♣ In R9, it should be clear that the 2 hour
timeframe is for initiation of corrective action because mitigation may take much longer. We suggest the last sentence of R9 state: “If the test is unsuccessful, the responsible entity shall, within 2 hours,
initiate action to repair or designate a replacement Alternative Interpersonal Communications capability.” ♣ In R10, the phrase “R1 through R6” should state “R1 through R8”. COM-002-3 ♣ In R2, the use
of the term recapitulate may not be appropriate. This term means “to summarize” the directive. Three-part communication during emergency situations should assure that the essential details of the
directives are understood and a summary may inadvertently leave out important information. ♣ The effective date of COM-002-3 should be consistent with COM-001-2 and IRO-001-3 and state “the 1st
calendar day of the 2nd calendar quarter”. It currently shows the “1st calendar quarter in the standard and implementation plan. IRO-001-3 ♣ The third bullet under Data Retention addresses requirement
R4 and measure M4 neither of which exist in the standard. ♣ In R1, the word “and” is missing between Generator Operator and Distribution Provider. ♣ VSL for R2 – “N/A” should be removed from the
High VSL – Furthermore, the VSL should include language for instances when the entity cannot meet the RC’s directive as afforded by R2.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP believes that the intent of these three standards is to ensure reliable normal and emergency communications between BES operating entities. It should be the rare exception that
BES-critical information must be communicated directly to an LSE, PSE, and TSP and IC. The impact of the Standards would be lessened if diffusely applied to multiple entities who do not normally engage
in operations communications.
No
In the background section of this ballot, the project team indicates that the removal of the phrase is intended to signal that these requirements do NOT apply to the exchange of data. Although Ingleside
Cogeneration LP agrees that the phrase is not a helpful description of the need for inter-entity communications – and should be removed – we do not see how the remaining language achieves the project
team’s purpose. It seems the confusion stems from the multitude of data communication types. Email messages between operating entities may be a valid communications path under COM-001-2, while
telemetry/control is covered under other Standards. We believe that a technical guideline may be an appropriate vehicle to distinguish what types of communications are subject to these requirements,
and which are not.
No
Most of Ingleside Cogeneration’s communications capabilities rely on carriers who will immediately deploy technicians to repair land-based or wireless systems when they break. Although we may contact
the carrier to inform them that the systems are not available – or to determine their progress – we do not want them waiting for our go-ahead before proceeding. If the intent of this requirement is to
validate the operation of the repaired connection, or to establish interim means of communications with other operating entities, then Ingleside Cogeneration believes a re-write is in order. There is no
reliability purpose being served otherwise that we can tell.
Yes
Ingleside Cogeneration agrees that it is important to clearly denote when a directive must be issued. In previous definitions, we believed that imprecise language made it difficult for the BA, RC, or TOP to
determine if a gray area situation required a directive or not. With a more precise definition, it will eliminate second guessing by auditors that a directive was necessary because an outcome turned out
poorly – even if an Emergency was not declared or an Adverse Reliability Impact did not occur.
Ingleside Cogeneration LP is concerned that the entity-to-entity organization of the COM Standards is quickly being outdated by voice and video conferencing or one-to-many broadcasts. In addition, email
may be a preferred mode of most communications to and from small Generator Operators. It is not clear that these technologies are precluded from consideration by COM-001 and COM-002 – which
means that some auditors may believe that they are. This leads to inconsistent application of the compliance criteria, and may discourage the use of some powerful technologies. It appears to us that
some technical guidelines would be appropriate to help entities and auditors decide which are applicable under these Standards.
Group
MISO Standards Collaborators
Marie Knox
Yes
(1) In COM-001, the entities in R4 and R6 (now R5 and R6) should be the same, i.e. the BA needs to have the Interpersonal Communication capability as well as the Alternative Interpersonal
Communication capability with the same entities. Although the need to have Alternative Interpersonal Communication capability should be assessed from the viewpoint that whether or not the absence of
such capability can adversely affect reliability, the proposed standard does not require the capability in all cases. At the same time, this standard does not preclude such capability. Even though
Interpersonal Communication capability is needed between a BA and a DP/GOP to communicate reliability instructions or directives, there are other communications paths which can be used in the case of
the loss of that capability. Since TOPs are also required to have the capability, the BA can call the TOP and ask the TOP to contact the DP/GOP for them until they can implement capability. In addition, it is
difficult to visualize entities which would not have the public telephone system or even cell phones available for use in the event of the loss of the capability.
Yes
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(1) We agree with the addition of “Adjacent” entities in the quoted parts. However, there are some entities which may need the capability even though they are not “synchronously connected within the
same Interconnection”. This standard does not require them to have the capability, but it does not preclude such capability. In these cases, those entities should evaluate whether the need for the
capability is a reliability need or market coordination. If the entities were connected synchronously, actions taken by an entity could have immediate effect upon other entities. However, if not
synchronously connected, changes in flows across the asynchronous ties would have to follow the interchange scheduling process with approval by all involved entities before changes could be enacted.
Some TOPs do communicate with other TOPs even in another Interconnection (e.g. between Quebec and all of its asynchronously interconnected neighbors). (2) Measure M3 does not cover the added R3.5
condition (having Interpersonal Communications capability with each adjacent TOP). M3 needs to be revised.
Yes
We urge the SDT to remove the phrase. If necessary, regional situations can be addressed by a regional variance.
Yes
Yes
The Data Retention Section in IRO-001 does not reflect the revised requirements. For example: the Electric Reliability Organization is no longer a responsible entity; the Reliability Coordinator should
replace the ERO for keeping data for R1; Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider should replace the Reliability Coordinator for keeping data for R2; and
there is no R4/M4. Additional comments associated with COM-002 We are concerned with the use of ‘shall’ in the measurement sections. ‘Shall’ statements should only be used in the Requirements, as
these are the only enforceable items in the standard. The measures should not limit how we show compliance. If there are specific issues that the drafting team is proposing to be a requirement, they
should be added to the requirements section of the standard. Measurement M1 should also allow entities to develop procedures, that are distributed to and trained on, in advance with recipients of
directives that meet the requirements for the communication of what constitutes a Reliability Directive. The last sentence in the measurement should be revised to read: Such evidence could include, but is
not limited to, dated and time -stamped voice recordings, dated and time -stamped transcripts of voice recordings, or dated operator logs to show that it identified the action as a Reliability Directive to
the recipient or approved procedures that identify what constitutes a Reliability Directive and when Reliability Directives are issued. (R1) The Data Retention section states;’ For instances where the
evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for
the full time period since the last audit.’ It is unclear on how an entity would be expected to provide evidence beyond 3 months when requested if the data retention period and established procedures do
not require the evidence to be retained. The SDT should provide examples of what other types of evidence could be expected or the phrase should be removed.
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
In COM-001-2 R5.3, should a BA have communications with a DP or LSE? For the TOP, it is the DP because the load influence is very local; however, for a BA the supply / demand balance is not local and
in markets that allow retail competition, it may be that the LSE is the more appropriate functional entity. For instance, the Functional Model when discussing LSE on page 55 states that one of the LSE’s
real time duties is: “12. Receives requests from the Balancing Authority and Distribution Provider for voluntary load curtailment.” If the LSE is the more appropriate entity, then R7 would need to be
changed and a new requirement specific to LSE's would need to be added. For Florida, which does not have retail competition, it doesn’t matter whether the DP or the LSE is more appropriate; hence, the
“yes” answer.
Yes
Yes
No
By use of the term “any” in the phrase “a failure of any of its Interpersonal Communication” the standard will actually create a disincentive for redundant communications with DPs and GOPs due to
compliance risk. To truly further the goals of reliability, the requirement should align with R3.3 and R3.4 which requires a primary Interpersonal Communications capability and R4 which does not require
DPs or GOPs to have Alternative Interpersonal Communications capability. A possible solution is through use of the terms “Primary” for R3 and “Alternate” for R4 and then make R11 applicable to Primary
only.
Yes
In the definition of Interpersonal Communication, the use of the word “medium” is ambiguous. Suggestions for alternatives: “system”, “channel”. COM-001-2, R1 and R3, the phrase: “have Interpersonal
Communications capabilities”, what if the communication system fails? Is that an immediate non-compliance (especially R3.3 and R3.4 which do not require a redundant system). Suggest using EOP-008
type of language to allow restoration of failed equipment without non-compliance. COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications capability", suggest adding the phrase
"to each entity for which Alternative Interpersonal Communications is required" to add clarity. In addition, the type of testing is unclear and ambiguous. The is also ambiguity in the terms “direct”,
“directive”, “direction” and “Reliability Directive”. The SDT may want to consider using the terms “instruct” and “instruction” in place of “direct”, “directive”, “direction” to more clearly distinguish from a
Reliability Directive.
Individual
Greg Rowland
Duke Energy
Yes
Yes
However, we believe that the phrase “synchronously connected within the same Interconnection” should be struck, because TOPs are controlling DC ties and should be required to have communications
with each other.
Yes
However, the definition of Interpersonal Communication should also be expanded to clearly include the drafting team’s intent that the capability is NOT for the exchange of data. The phrase “for the
exchange of Interconnection and operating information" should also be struck from the Purpose statement.
No
The phrase “consult with... to determine a mutually agreeable time” makes this requirement too open-ended to be auditable and enforceable. We question why R11 does not establish a timeframe for
notification similar to R10, which requires the RC, TOP or BA to make notification within 60 minutes of failure detection. We also question why DPs and GOPs are not required to have Alternative
Interpersonal Communications capability in order to be able to make such notifications.
No
• Since FERC has not yet approved the new definition of Adverse Reliability Impact, we believe the term “Adverse Reliability Impact” should be replaced by the words of the BOT-approved definition: “the
impact of an event that results in Bulk Electric System instability or Cascading”. • Also, add the phrase “and the communication is identified as a reliability directive to the recipient” to the end of the
definition of Reliability Directive. This will eliminate potential confusion regarding when a communication is a Reliability Directive, and when a communication is a routine instruction. Revising the definition
in this manner may also eliminate the need Requirement R1 of COM-002-3. If R1 is retained, we suggest rewording as follows: “Each Reliability Coordinator, Transmission Operator, or Balancing Authority
shall identify a Reliability Directive to the recipient when it issues a Reliability Directive that requires an action or actions to be executed.” • Proposed reworded definition: “Reliability Directive: A
communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by the recipient is necessary to address an Emergency or the impact of an event that
results in Bulk Electric System instability or Cascading, and the communication is identified as a Reliability Directive to the recipient.”
• COM-001-2 does not specify how much time an entity is allowed to restore failed Interpersonal Communications capability or failed Alternative Interpersonal Communications capability. R1 through R6
require that the RC, TOP and BA have both. R7 and R8 require that DPs and GOPs have Interpersonal Communications capability. An auditor could find an entity non-compliant with these requirements
upon failure of either capability. R9, R10 and R11 specify actions to take upon failure, but do not relieve entities of responsibility under R1 through R8. • COM-001-2 R9, M9 and VSLs – M9 and VSLs
should be revised to be consistent with wording of R9 phrase “at least once per calendar month”. • COM-001-2 R10, M10 and VSLs – Clarity is needed regarding when the 60-minute clock starts. For
example, suppose a failure is detected immediately upon occurrence of the failure. Does the 60-minute clock start immediately, or after the failure has lasted 30 minutes? When does the 60-minute clock
start if a failure is detected and the entity is unsure when it occurred? • COM-001-2 R10, M10 and VSLs - If the failure only lasts for 35 minutes, it appears that the RC, TOP or BA is still required to notify
entities identified in R1 through R6. Is this the drafting team’s intent? • COM-001-2 R10, M10 and VSLs – Should be revised since the RC, TOP and BA are only required to have Alternative Interpersonal
Communications capability with other RCs, TOPs and BAs per R2, R4 and R6. Suggested rewording for R10: “Each Reliability Coordinator, Transmission Operator and Balancing Authority shall notify
entities with which it is required to have Alternative Interpersonal Communications capability as identified in R2, R4 and R6 within 60 minutes of the detection of a failure of its Interpersonal
Communications capabilities that lasts 30 minutes or longer.” • COM-001-2 M11 and VSL – Replace the word “their” with the word “its”. • COM-001-2 Data Retention – The way Data Retention is being
enforced, this whole section could just be reduced to a blanket statement that an entity must be able to provide evidence that it has been in compliance since its last audit. • COM-002-3 R2, M2 and VSL –
Replace “and” with “or”. Also, the phrase “repeat, restate, rephrase or recapitulate” seems excessive and may be intended to avoid a violation where an entity fails to repeat the Reliability Directive word
for word. Suggested rewording: “Each Balancing Authority, Transmission Operator, Generator Operator or Distribution Provider that is the recipient of a Reliability Directive shall repeat the Reliability
Directive back to the issuer with sufficient accuracy so that understanding can be confirmed.” • COM-002-3 R3, M3 - Replace “and” with “or”. • IRO-001-3 – We believe that the Purpose and the
Requirements of this standard should be focused solely on situations where the Reliability Coordinator issues Reliability Directives to prevent an Emergency or Adverse Reliability Impact. • IRO-001-3 –
The Purpose should be rewritten as follows: “To establish the authority of Reliability Coordinators to issue Reliability Directives to other entities to prevent an Emergency or the impact of an event that
results in Bulk Electric System instability or Cascading.” • IRO-001-3 – R1 should be rewritten as follows: “Each Reliability Coordinator shall have authority to act or to issue Reliability Directives to others,
including but not limited to the Transmission Operator, Balancing Authority and Generator Operator within its Reliability Coordinator Area to prevent identified events or mitigate the magnitude or duration
of actual events that result in an Emergency or the impact of an event that results in Bulk Electric System instability or Cascading.” • IRO-001-3 – R2 should be rewritten as follows: “Each Transmission
Operator, Balancing Authority, Generator Operator or Distribution Provider shall comply with a Reliability Directive issued by the Reliability Coordinator unless the Reliability Directive cannot be physically
implemented or unless such action would violate safety, equipment, regulatory, or statutory requirements.” • IRO-001-3 – R3 should be rewritten as follows: “Each Transmission Operator, Balancing
Authority, Generator Operator or Distribution Provider shall inform its Reliability Coordinator upon recognition of its inability to comply with a Reliability Directive in accordance with Requirement R2. • IRO001-3 Measures and VSLs – Should be revised to conform with the above suggested revisions to requirements.
Individual
Kathleen Goodman
ISO New England
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and therefore does not support the draft as written. We believe such "requirements" (i.e. capabilities) should be verified
through an entity certification process. Additionally, results-based requirements should be the driver to have the capability to achieve them; on other words, there is no other way to reliably dispatch than
to have communications facilities (electronic or voice).
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and therefore does not support the draft as written. We believe such "requirements" (i.e. capabilities) should be verified
through an entity certification process. Additionally, results-based requirements should be the driver to have the capability to achieve them; on other words, there is no other way to reliably dispatch than
to have communications facilities (electronic or voice).
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and therefore does not support the draft as written. We believe such "requirements" (i.e. capabilities) should be verified
through an entity certification process. Additionally, results-based requirements should be the driver to have the capability to achieve them; on other words, there is no other way to reliably dispatch than
to have communications facilities (electronic or voice).
Yes
none
Individual
H. Steven Myers
ERCOT ISO
No
Some concern for removal of LSE in particular from R2 and R3 from current IRO-001-2 R7 for the ERCOT region. ERCOT Region has QSE’s that manage Load Resources. There may be some QSEs that are
not registered as a GOP that deploy Load Resources. Per the current LSE JRO, QSEs with Load Resources are registered as LSEs. Not requiring them to deploy Load Resource directives could be perceived
as a reliability gap created from previous version to this version. PSEs could be removed as long as they fall under BA authority.
Yes
These changes will clarify intentions regarding the undefined term "adjacent".
Yes
Yes
Yes
The definition of Reliability Directive appropriately clarifies the importance of knowing the level of importance of any instructions being issued. If there is no room for variance from the specific action
required, or if there is no time to further negotiate or discuss the action required, it is important that the instruction be identified as a Reliability Directive and for such instructions to be followed in a timely
fashion. Normal operating instructions typically do not rise to this level of urgency and some variation from the words will not result in unmanageable reliability impacts. Also, there typically may be time
for addressing the instructions in more than one way.
Regarding COM-001-2: We are not clear on the time horizon of requiresments for COM-001-2. Based upon the purpose statement, it appears that establishment would be ahead of real time. Wording in
the requirements could be construed as maintaining at all times vs. establishing communications The timeline for mandatory/effectiveness may not be acceptable to establish communications with DPs if
hardware procurement/projects must take place. Regarding IRO-001-3: We have some concern for the removal of LSE in particular from R2 and R3 from current IRO-001-2 for the ERCOT region. The
ERCOT region has QSEs that manage Load Resources. There may be some QSEs that are not registered as a GOP that deploy Load Resources. Per the current LSE JRO, QSEs with Load Resources are
registered as LSEs. Not requiring LSEs to deploy Load Resource directives could be perceived as a reliability gap created from the previous version to this version. PSEs could be removed as long as they
fall under BA authority. The Data Retention section should be corrected to match the new requirements numbers and elimination of the previous version R1 with ERO. The Version History mentions six
requirements retired, but only details five.
Individual
Anthony Jablonski
ReliabilityFirst
Yes
Yes
ReliabilityFirst agrees with adding the term adjacent but is unclear what the term adjacent is referring to. Does is mean directly connected or is it more than one layer out.
Yes
No
ReliabilityFirst believes Distribution Provider and Generator Operator should be added to Requirement R10 and Requirement R11 should be removed. Finite time frames should be prescribed for each
Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication capabilities. ReliabilityFirst believes that the failure of Interpersonal Communication
between Distribution Providers/Generator Operators and Transmission Operators/Balancing Authorities could have the same negative effects similar to the failure of Interpersonal Communication by the
Reliability Coordinator, Transmission Operator, and Balancing Authority.
No
ReliabilityFirst believes the definition of “Reliability Directive” should be all inclusive and include “all” actions initiated by the Reliability Coordinator, Transmission Operator or Balancing Authority (not just
Emergency or Adverse Reliability Impacts). Even though Emergency or Adverse Reliability Impacts are defined, during operations, it may become a gray area to whether or not it falls under the intent of a
“Reliability Directive.” Furthermore, if the system falls under a condition that results in an Adverse Reliability Impact, it may be too late for a Reliability Coordinator, Transmission Operator or Balancing
Authority to issue a Reliability Directive. ReliabilityFirst recommends the following for revision to the term “Reliability Directive”: Reliability Directive - A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where an action by the recipient is required.
Comments on COM-001-2 1. Applicability Section a. RFC recommends adding the Generator Owner to the applicably section of the standard along with corresponding Requirements R8 and R11.
ReliabilityFirst believes to maintain system reliability and based on certain business practices in effect, Generator Owners need to be required to have associated Interpersonal Communications with its
Balancing Authority and Transmission Operator. 2. Requirement R7 and R8 a. ReliabilityFirst seeks further clarity on why the Distribution Provider and Generator Operator are not required to designate an
Alternative Interpersonal Communications capability? Requirements R7 and R8 require the Distribution Providers and Generator Operators to have Interpersonal Communications capability but there is not
corresponding requirement to have an Alternative Interpersonal Communications capability. ReliabilityFirst recommends adding two new requirements for the Distribution Provider and Generator Operator
to designate an Alternative Interpersonal Communications capability. This will be consistent with how Requirements R1 through R6 are set up. 3. Requirement R9 a. Assuming new requirements for the
Distribution Provider and Generator Operator to designate an Alternative Interpersonal Communications capability (based on previous comment) are added to the standard, the Distribution Provider and
Generator Operator will need to be added to Requirement R9 to test its Alternative Interpersonal Communications capability at least once per calendar month. 4. Requirement R10 a. Based on the
ReliabilityFirst comment submitted for Question 4, ReliabilityFirst believes the Distribution Provider and Generator Operator should be included in Requirement R10. b. Since Interpersonal Communications
capabilities is a very important piece of operating the BES in a reliable manner, ReliabilityFirst believes the timeframe in which an entity is required to notify the entities is too long. ReliabilityFirst
recommends the following language for Requirement R10: i. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Distribution Provider and Generator Operator shall notify entities as
identified in Requirements R1 through R8 of a failure of its Interpersonal Communications capabilities that lasts 15 minutes or longer. The notification shall be made within 30 minutes of the detection of a
failure. 5. VSLS for Requirement R1 through R8 a. ReliabilityFirst suggest gradating the VSLs for R1 through R8. Listed below is an example of how to gradate the VSL for R1. The same type of approach
could be used for R2 through R8 as well. i. High VSL- the Reliability Coordinator failed to have Interpersonal Communications capability with one or more of the entities listed in Parts 1.1 or 1.2. ii. Severe
VSL - The Reliability Coordinator failed to have Interpersonal Communications capability with one or more of the entities listed in Parts 1.1 and 1.2. 6. VSL for Requirement R9 a. For consistency with the
requirement language, ReliabilityFirst recommends adding the words “at least on a monthly basis” to the Lower, Moderate and High VSLs and adding the words “if the test was unsuccessful” to the end of
the Lower, Moderate and High VSLs. Listed below is an example of the Lower VSL. i. The responsible entity tested the Alternative Interpersonal Communications capability at least once per calendar month
but failed to initiate action to repair or designate a replacement Alternative Interpersonal Communications in more than 2 hours and less than or equal to 4 hours if the test was unsuccessful. 7. VSL for
Requirement R10 a. ReliabilityFirst provided alternate language for R10 in the comments listed above. If the alternated language is not incorporated, ReliabilityFirst recommends the following language for
the Lower VSL. Similar language could be used for the Moderate, High and Severe VSLs as well. i. The responsible entity failed to notify entities as identified in Requirements R1 through R6 more than 60
minutes but less than or equal to 70 minutes of the detection of a failure of its Interpersonal Communications capabilities. b. If the alternate language for R10, in the comments listed above, is
incorporated, ReliabilityFirst recommends the following language for the Lower VSL. Similar language could be used for the Moderate, High and Severe VSLs as well. i. The responsible entity failed to notify
entities as identified in Requirements R1 through R6 more than 30 minutes but less than or equal to 740 minutes of the detection of a failure of its Interpersonal Communications capabilities c. For
Moderate VSL (the VSL after the OR statement), ReliabilityFirst recommends using a percentage rather than the “least one, but not all” statement. For example, if there is say 100 impacted entities and
the applicable entity only notify 1, they would only fall under the Moderate. In another scenario there is say 100 impacted entities and the applicable entity only notified 99, they would also fall under the
Moderate as well. The use of percentages will help even this out. 8. VSL for Requirement R11 a. For consistency with the requirement language, ReliabilityFirst recommends the following language: i. The
responsible entity that experiences a failure of any of its Interpersonal Communication capabilities failed to consult with their Transmission Operator or Balancing Authority as applicable to determine a
mutually agreeable time to restore the Interpersonal Communication capability. Comments on COM-002-3 1. Requirement R1 a. Based on ReliabilityFirst suggested change to the definition of “Reliability
Directive” as noted in Question 5, ReliabilityFirst recommends deleting Requirement R1. Based on the suggested definition, any communication initiated, where an action by the recipient is required, is
considered a “Reliability Directive.” Thus, there would no longer be a need for responsible entity to identify the action as a “Reliability Directive” to the recipient. 2. VSL for Requirement R3 a. For
consistency with the requirement language, ReliabilityFirst recommends the following language: i. The responsible entity issued a Reliability Directive, but failed to confirm that the response from the
recipient of the Reliability Directive (in accordance with Requirement R2) was accurate. Comments on IRO-001-3 1. Requirement R1 a. ReliabilityFirst seeks further clarity on why Requirement R1 only
requires the Reliability Coordinator to have the “authority to act” rather than requiring the Reliability Coordinator to actually “take action” to prevent identified events that result in an Emergency or
Adverse Reliability Impacts. Having the “authority to act” does not inherently require the Reliability Coordinator to take action, if appropriate. b. ReliabilityFirst seeks further clarity on the language “to
prevent identified events.” If the event was already identified, how can the Reliability Coordinator act to prevent it? ReliabilityFirst recommends adding the word “potential” in between the words “prevent”
and “identified.” 2. Requirement R3 a. There is no time qualifier specified in Requirement R3 dealing with the timeframe in which the applicable entity has to inform its Reliability Coordinator of its inability
to perform as directed in accordance with Requirement R2. Without a time qualifier, Requirement R3 is open ended and could cause issues if the applicable entitiy does not inform its Reliability Coordinator
upon recognition of its inability to perform as directed in a timely manner. ReliabilityFirst recommends the following language for Requirement R3: i. Each Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider shall inform its Reliability Coordinator within 30 minutes upon recognition of its inability to perform as directed in accordance with Requirement R2. 3. VSL for
Requirement R1 a. Requirement R1 requires the Reliability Coordinator to “…have the authority to act” – and the VSL does not reflect this language. ReliabilityFirst had questioned why Requirement R1,
does not specifically require the RC to take action or direct actions in a comment submitted under Requirement R1. If the SDT does not change the language in Requirement R1, ReliabilityFirst
recommends the following language: i. The Reliability Coordinator failed to have the authority to take action or direct actions, to prevent an identified event that resulted in an Adverse Reliability Impact.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4. VSL for Requirement R2 a. For the High VSL, the words “fully comply” are ambiguous and open to interpretation. ReliabilityFirst recommends only having a Severe VSL. b. The Severe VSL states
“directive” while Requirement R2 states “direction”. To be consistent, ReliabilityFirst recommends the following language: i. “The Responsible Entity failed to comply with its Reliability Coordinator’s
direction”
Individual
Randall McCamish
City of Vero Beach
Yes
In COM-001-2 R5.3, should a BA have communications with a DP or LSE? For the TOP, it is the DP because the load influence is very local; however, for a BA the supply / demand balance is not local and
in markets that allow retail competition, it may be that the LSE is the more appropriate functional entity. For instance, the Functional Model when discussing LSE on page 55 states that one of the LSE’s
real time duties is: “12. Receives requests from the Balancing Authority and Distribution Provider for voluntary load curtailment.” If the LSE is the more appropriate entity, then R7 would need to be
changed and a new requirement specific to LSE's would need to be added. For Florida, which does not have retail competition, it doesn’t matter whether the DP or the LSE is more appropriate; hence, the
“yes” answer.
Yes
Yes
No
By use of the term “any” in the phrase “a failure of any of its Interpersonal Communication” the standard will actually create a disincentive for redundant communications with DPs and GOPs due to
compliance risk. To truly further the goals of reliability, the requirement should align with R3.3 and R3.4 which requires a primary Interpersonal Communications capability and R4 which does not require
DPs or GOPs to have Alternative Interpersonal Communications capability. A possible solution is through use of the terms “Primary” for R3 and “Alternate” for R4 and then make R11 applicable to Primary
only.
Yes
In the definition of Interpersonal Communication, the use of the word “medium” is ambiguous. Suggestions for alternatives: “system”, “channel”. COM-001-2, R1 and R3, the phrase: “have Interpersonal
Communications capabilities”, what if the communication system fails? Is that an immediate non-compliance (especially R3.3 and R3.4 which do not require a redundant system). Suggest using EOP-008
type of language to allow restoration of failed equipment without non-compliance. COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications capability", suggest adding the phrase
"to each entity for which Alternative Interpersonal Communications is required" to add clarity. In addition, the type of testing is unclear and ambiguous. The is also ambiguity in the terms “direct”,
“directive”, “direction” and “Reliability Directive”. The SDT may want to consider using the terms “instruct” and “instruction” in place of “direct”, “directive”, “direction” to more clearly distinguish from a
Reliability Directive.
Individual
Rich Salgo
NV Energy
Yes
Yes
Yes
Yes
Agree, however, the ability for a DP or GOP to have such consultation with its TOP or BA would likely be hampered by the failure of the Interpersonal Communications itself. DP and GOP are only required
to have a single source for this Interpersonal Communications.
Yes
The meaning of R9 is open to some interpretation. It states that if the monthly test is unsuccessful, the entity shale "initiate action to repair or designate a replacement" AIC within 2 hours. The meaning
of this is unclear in several ways: First, does "initiate action" apply to the remainder of the sentence or just to the "repair" option? Second, what constitutes initiation of action? Is it the intent of the SDT
that the alternate interpersonal communications be restored within a 2-hour limit? If so, the words do not clearly state that, and it seems an impossible task to ensure no more than 2-hr outage to an
alternate communications medium. I am voting affirmative under the interpretation that one must only "initiate" the repair or "initiate" the designation of a replacement option within this tight 2-hour
limit.
Individual
Rebecca Moore Darrah
Midwest Independent Transmission System Operator
Yes
Yes
Yes
No
MISO requests clarification regarding (1) when Distribution Providers/Generator Operators have an obligation to collaborate with Transmission Operators versus Balancing Authorities; and (2) the
obligation of Transmission Operators to inform Balancing Authorities (and vice versa) of an agreed upon time for restoration of Interpersonal Communication capability when collaboration occurs only
between Transmission Operators and Distribution Providers/Generator Operators or, conversely, Balancing Authorities and Distribution Providers/Generator Operators.
No
The proposed definition of Reliability Directive is unacceptable because the use of the defined terms “Emergency” and “Adverse Reliability Impact” results in an undefined, broadened scope of responsibility
for Reliability Coordinators when coupled with the definition of the Bulk Electric System. This may lead to confusion/ambiguity for Reliability Coordinators that must be clarified to ensure compliance.
Further, this broadened scope may mis-direct Reliability Coordinator’s attention and mitigation efforts to small-scale, localized issues that represent no true threat to the operation of the Interconnection.
COM-001-2, R2 and R6: MISO requests clarification as to whether the designation of Interpersonal Communications and Alternative Interpersonal Communications methods by Responsible Entities must be
formally documented and/or agreed upon with those entities with which communications capability must be established. COM-001-2, R9: MISO suggests that the designation of Alternative Interpersonal
Communications methods should not require formal documentation and may be agreed upon (when necessary) informally with those entities with which communications capability must be established in
the event of an unsuccessful test of its Alternative Interpersonal Communications capability. COM-001-2, Requirement R10: MISO requests clarification as to whether “impacted entities” refers to those
entities with which the Responsible Entity must have Interpersonal Communications and Alternative Interpersonal Communications capability. Further, MISO requests clarification as to whether the
notification required by R10 must be made using the Alternative Interpersonal Communications method selected by the Responsible Entity. COM-002-3, R1 – R3: MISO respectfully submits that, while it
appreciates the distinction in responsibilities proposed in the new COM-002-3 and acknowledges that such distinction is beneficial, these requirements increase compliance risk and potential penalty liability
without attendant benefit to the reliability of the Bulk Electric System. MISO respectfully suggests that Requirements 2 and 3 be converted into sub-requirements as follows: R1. When a Reliability
Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify
the action as a Reliability Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time] R1.1. When the Reliability Coordinator, Transmission Operator or Balancing Authority identifies a
stated action as a Reliability Directive, the receiving Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider shall repeat, restate, rephrase or recapitulate the Reliability
Directive to the issuing Reliability Coordinator, Transmission Operator or Balancing Authority. [Violation Risk Factor: High][Time Horizon: Real-Time] R1.2. When the Reliability Coordinator, Transmission
Operator, and Balancing Authority that issues a Reliability Directive receives a response from the receiving Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider, it
shall then either [Violation Risk Factor: High][Time Horizon: Real-Time]: • Confirm that the response from the recipient of the Reliability Directive (in accordance with Requirement R2) was accurate, or •
Reissue the Reliability Directive to resolve any misunderstandings.
Individual
Don Jones
Texas Reliability Entity
Yes
No
(1) Requirements R1, R2, R3 and R4 should apply to all adjacent Reliability Coordinators and Transmission Operators, regardless of whether they are in the same Interconnection. The ERCOT
Interconnection is asynchronously connected to adjacent Interconnections, and it is imperative that Functional Entities within Texas RE’s purview be able to exchange operating information with
Transmission Operators and Reliability Coordinators in those adjacent areas, even if they are in a different Interconnection. (2) Requirement parts R5.5 and R6.3 refer to “Adjacent Balancing Authorities.”
Measures M5 and M6 refer to “adjacent Balancing Authority” – note the small “a” on adjacent. “Adjacent Balancing Authority” is a defined term in the NERC Glossary, which has a more specific meaning
than “adjacent Balancing Authority.” Which term is intended in R5.5 and R6.3? If you don’t intend to use the defined term, perhaps use a word like “contiguous” or “neighboring” rather than “adjacent.”
Yes
No
(1) Why does R10 refer to “failure of its Interpersonal Communications capabilities” while R11 refers to “failure of **any of** its Interpersonal Communications capabilities”? What is the distinction that is
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intended by addition of the words “any of”? (2) As a Compliance Enforcement Authority, we have several fundamental questions regarding what is intended in this standard. It appears the drafting team is
using the defined term “Interpersonal Communications” to refer to a designated primary communication medium, and the term “Alternative Interpersonal Communications” to refer to one or more
designated backup communication mediums. Is that correct? This should be clarified in the Standard. (3) There is ambiguity in the current draft because the defined term “Interpersonal Communications”
appears to include primary, back-up and all other mediums that may be available (which may include landline phone, cell phone, satellite phone, instant messaging, email, and data links, all in one
facility), including any “Alternative Interpersonal Communications”. Do R10 and R11 apply to ALL available mediums, or just to the designated primary and back-up mediums? Does R9 apply to ALL
available back-up mediums, or just to a specifically designated back-up medium?
No
We oppose the definition of Reliability Directive as it is currently being proposed in this standard because three-part communication should not be required only after an Emergency or Adverse Reliability
Impact actually occurs. In particular we object to the removal of the word “expected” (or “anticipated”) from the definition, because Reliability Directives may be required before a situation escalates to an
Emergency, in order to prevent the Emergency from occurring. This proposed change potentially undermines efforts required to avoid emergencies and events. We note that there are instances in other
Reliability Standards where “anticipated” conditions require actions to be taken (e.g. TOP-001-1 R5 and EOP-002 R4), when clear, concise, and definitive communication, verbal or electronic, is required to
avoid or mitigate an impending emergency
(1) There are numerous errors in the Mapping Document in referencing the current version of the standard and requirement. Specifically, referencing IRO-001-2 where it appears that the document should
reference standard IRO-001-3. In addition, the notes on page 2 of COM-002-3 are incorrect. (2) In the VRF/VSL Justification document, there are numerous errors in referring to standard versions and
requirements. (3) In IRO-001-3, R1 – What is an “identified event,” and who “identifies” an event that requires compliance with this requirement R1? An RC may choose not to “identify” an event, such as
a limit violation, and run the risk of causing or exacerbating an emergency. If the RC does not “identify” the event, it may become an actual event and then fall within the standard. (4) In the VSL for IRO001-3, R1, there should be language in the VSL to capture the term “Emergency,” which was added in the Requirement. The High VSL for R2 needs to be fixed. (5) In IRO-001-3, R1, remove the “s” in the
phrase “Adverse Reliability Impacts.” (6) Referring to the Implementation Plan for IRO-001 – There is a different list in the Implementation Plan (R2, R4, R5, R6, R7, R9) than the Revision History of the
Standard (R2, R4, R5, R6, R8). Where is the retirement of R1 shown? (7) Referring to COM-001-2: Measure 7, the word “that” is inadvertently repeated in the first sentence. (8) In COM-001-2, Measure 9,
is “at least on a monthly basis” to be interpreted differently than “at least once per calendar month” as stated in the requirement? (9) In COM-001-2, there is a “Measure 12” bullet that should be
removed. (10) Referring to COM-002-3: Electronic directives (which may be issued over many different types of electronic communication channels) are increasingly necessary to manage the modern,
dynamic Bulk Power System (generation and transmission) on a real-time basis. The effective use of electronic directives is undermined by this proposed Standard in its current form. This draft standard,
in conjunction with other standards that refer to directives, appears to require that directives (at least Reliability Directives) be given verbally. The failure of the NERC standards to address electronic
directives may cause significant manpower issues for BAs with large portfolios of generation to manage. (11) In the VSL for COM-001-2 R4, a reference to Part 4.3 should be added. (12) In IRO-001-3,
Part 1.3 Data Retention, the reference in the first bullet to “Electric reliability Organization” is incorrect. We think it should say “Reliability Coordinator” instead. The other references to entities and to
Requirements in this Part 1.3 also appear to be incorrect and need to be updated and corrected. (13) Referring to COM-001-2, the prior version of this standard included Requirement R5: “Each Reliability
Coordinator, Transmission Operator, and Balancing Authority shall have written operating instructions and procedures to enable continued operation of the system during the loss of telecommunications
facilities.” This Requirement has been removed from the present draft of COM-001-2. The mapping document seems to suggest that this Requirement was moved to EOP-008, but it is not there. We are
concerned that removal of this Requirement will result in a reduction in the level of BES reliability and introduce a potential reliability gap.
Individual
David Kiguel
Hydro One Networks Inc.
Yes
No
(1) We agree with the addition of “Adjacent” entities in the quoted parts except the qualifier “synchronously connected within the same Interconnection” need to be removed from Parts 3.5 and 4.3 since
TOPs do communicate with other TOPs even in another Interconnection (e.g. between Quebec and all of its asynchronously interconnected neighbors). Even in the case of ERCOT, TOPs on the two sides of
a DC tie do communicate with each other for daily operations. (2) Measure M3 does not cover the added R3.5 condition (having Interpersonal Communications capability with each adjacent TOP). M3
needs to be revised.
No
(1) In the last posting, there were suggestions of removing the phrase “within the same Interconnection” from R1 (now R2.2) since there are RCs between two Interconnections that need to
communication with each other for reliability coordination (e.g. between Quebec and the RCs the Northeast such as IESO, NYISO, NBSO and ISO-NE, and between the RCs in WECC with the RCs in the
Eastern Interconnection). Such coordination may include but not limited to curtailing interchange transactions crossing Interconnection/RC boundary, as stipulated in IRO-006. The SDT’s response to our
comments citing that the phrase was added to address the ERCOT situation leaves a reliability gap to the other situations. We again urge the SDT to remove the phrase. If necessary, the ERCOT situation
can be addressed by a regional variance.
Yes
Yes
(1) The proposed implementation plan conflicts with Ontario regulatory practice respecting the effective date of the standard. It is suggested that this conflict be removed by appending to the
implementation plan wording, after “applicable regulatory approval” in the Effective Dates Section A5 on P. 4 of the draft standard COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s
Implementation Plan and P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following effect: “, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.” (2) COM-001: Measure M9: - “monthly basis”. Suggest changing “monthly basis” to “at least once per calendar month” to be consistent the wording in R9. (3) IRO-001: Measures M1, M2, M3
– The types of evidence are listed in paragraph form. This is not consistent with presentation style in COM-001-2 Measures, where evidence is listed in bullet format. Suggest using bullet form for
consistency. (4) IRO-001, Data Retention Section: i. The retention requirements do not reflect the revised requirements. For example: the Electric Reliability Organization is no longer a responsible entity;
the Reliability Coordinator should replace the ERO for keeping data for R1; Transmission Operator, Balancing Authority, Generator Operator and Distribution Provider should replace the Reliability
Coordinator for keeping data for R2; and there is no R4/M4. ii. Section 1.3, second paragraph: “The Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, or Distribution
Provider... shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an
investigation:” The word “or” between Generator Operator and Distribution Provider should be changed to “and”.
Individual
Gregory Campoli
New York Independent System Operator
Yes
No
It is not clear the distinction between an Emergency and ARI. We would like to confirm that Since ARI is the impact of an event that results in instability or cascading, that an ARI is a subset of an
emergency? Or said differently is an ARI simply instability or cascading? Utlimately if ARI is a subset of Emergency, then why do we need both in the requirement?
COM-001 The drafting team has complicated the requirements by having different requirements between RC/TOP/BA and other entities such as GOP/LSE/DP. The proposal is for redundancy to be required
only between RC/TOP/BA. The requirement should be simplified to require all identified entities to have plans for loss of primary communication channels. This could include third parties as a
communication channel. COM-002 The drafting team added a requirement to identify a Reliability Directive is being initiated during an emergency to track 3-part communication for compliance purposes.
This will change and complicate the communication protocols between normal and emergency operations simply to simplify compliance assessments. The NYISO is asking for clarification that an entity may
identify Reliability Directives as a category of communications to be communicated through procedures and training; and will not require a different communication protocol between normal and
emergency operations. Affective communications can only be achieve through consistent processes for all conditions. Compliance assessments should be made on when we are in an emergency or not, and
not on how the dialogue was initiated.
Group
ZGlobal Engineering and Energy Solutions
Mary Jo Cooper
Yes
Yes
No
No
We are pleased that the drafting team addition provides addition description on the process for communicating failed Interpersonal Communication. However additional clarity should be made regarding if
there is an expectation that the Interpersonal Communication should be available 24x7. There are many Distribution Providers that do not have a 24x7 managed facility that can view and respond to a
communication received in real time on the Interpersonal Communication device. These DPs rely on on-call personnel for off-hour emergencies such as an outage on the distribution system. The on-call
personnel may use a cell phone, pager, etc. In other cases the Transmission Operator or Balancing Authority may communicate by email and response is provided during business hours. In these cases, if
the Transmission Operator or Balancing Authority had a system emergency they have the ability to isolate the distribution system from the grid and therefore do not require a 24x7 manned distribution. If
the intent of the Standard is for ensuring real-time communication than the applicability should be limited to those Distribution Providers who have been required by the Transmission Operator or
Balancing Authority to have a manned 24x7 manned facility. Many of the DPs referred to here have not received a real-time call in the last 20 years. Requiring them to staff 24x7 for a condition likely not
to occur is cost prohibited and does not improve reliability.
Yes
Group
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ACES Power Marketing Standards Collaborators
Jason Marshall
No
While we agree with removing LSE, PSE, and TSP, we do not agree with the need to include Distribution Provider in all the standards. For example, in IRO-001-3, the Distribution Provider will likely never
receive a Reliability Directive directly from its Reliability Coordinator. More likely, the Reliability Directive will be issued by the Transmission Operator or Balancing Authority depending on if the issue is
security or adequacy related.
Yes
Yes
We thank the drafting team for making this change and for the clear communication that the intent of this standard is not for data exchange in the response to comments. However, we do believe one
additional change is necessary to make the intent absolutely clear. The purpose of statement of COM-001-2 still includes the phrase “to exchange Interconnection and operating information”. Since a
standard must stand on its own, we believe it is necessary to remove that phrase from the purpose statement to avoid misinterpretations in the future. Auditors and enforcement personnel are not
required to understand the development history when enforcing the standard. Furthermore, the purpose is really to enable communications between these functional entities.
No
Requirement R11 does not fully address the issue of what is required by Distribution Providers and Generator Operators and introduces new issues. First, while the standard is intended to clarify that the
Distribution Provider and Generator Operator do not need backup communications capability, it simply does not. Distribution Providers and Generator Operators are required to have an Interpersonal
Communications capability in Requirement R7 and R8 respectively. Unfortunately, the effectiveness of these requirements persists even when the Distribution Provider or Generator Operator experiences a
failure of its Interpersonal Communications capability. When Requirement R11 applies, the Distribution Provider or Generator Operator will still be obligated to comply with Requirements R7 and R8
respectively and will, in fact, be in violation of these requirements because the Distribution Provider or Generator Operator no longer has the capability. Second, capability is used inconsistently between
Requirement R7 and R11 which leads to confusion. In Requirement R7, it is singular while in Requirement R11 is plural. It needs to be clear that only the failure of the capability identified in R7 and R8
needs to be reported by the Distribution Provider and Generator Operator respectively. Third, if the requirements focused on communications devices rather than capabilities, they would come closer to
communicating the intent. Requirement R11 would better complement Requirement R7 and R8 if the focus was on having a communication medium or device. A Generator Operator with an installed
communications device or medium still has that device or medium even when it is not functioning properly and could still meet Requirements R7 and R8. However, they don’t have the Interpersonal
Communications capability if the device is not functioning properly.
Yes
The following comments are regarding IRO-001-3. We disagree with including “authority” in this standard. FERC Order 693a, paragraph 112, made it clear that the authority of a registered entity is
established through the approval of the standards by FERC. Thus, a Reliability Coordinator gets its authority to issue Reliability Directives by having a requirement that states it must issue Reliability
Directives approved by the Commission. Please change “shall have authority to act” in Requirement R1 back to “shall act”. Please also remove all other vestiges of authority from the standards including in
the purpose, measures and VSLs. Requirement R1 should require the use of Reliability Directives. The requirement compels the Reliability Coordinator “to direct others to act to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or Adverse Reliability Impact”. Reliability Directives are necessary to address Adverse Reliability Impacts or Emergencies
and trigger the use of three-part communications identified in COM-002-3. COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive for Emergencies and Adverse Reliability
Impacts with the opening clause: “When a Reliability Coordinator, Transmission Operator, or Balancing Authority determines actions need to be executed as a Reliability Directive”. What else could be
more important for a Reliability Coordinator to issue a Reliability Directive than for an Emergency or Adverse Reliability Impact? Thus, not requiring the use of Reliability Directives for Adverse Reliability
Impacts and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. For clarity and consistency, Requirement R2 and R3 should also be clear that the responsible entities will respond to the
Reliability Coordinator’s Reliability Directives. Furthermore, this would make the standard consistent with how Reliability Directives are handled by the Transmission Operator in the draft TOP-001-2
standard proposed by the Real-Time Operations drafting team (Project 2007-03). The Data Retention section needs to be modified. The first bullet applies to the Electric Reliability Organization and
Requirement R1 and Measure M1. The actual requirement and measure apply to the Reliability Coordinator. Furthermore, five calendar years exceeds the audit period of three years for a Reliability
Coordinator. The second bullet incorrectly applies to the Reliability Coordinator and Requirement R2 and Measure M2. Requirement R2 and Measurement M2 apply to Transmission Operators, Balancing
Authorities, Generator Operators and Distribution Providers. The third bullet mentions Requirement R4 and Measurement M4. There is no Requirement R4 and Measurement M4 in the standard. The VSLs
for Requirement R1 are not consistent with the requirement. The VSL states that it is for failure to act while the requirement compels the Reliability Coordinator to have the authority to act. This modifies
the requirement which is not allowed under FERC VSL guidelines. The VSLs for Requirement R2 need to include the “unless” clause from the requirement. Otherwise, the VSL implies that the responsible
entity violated the requirement for failing to follow the directive even if they could not for one of the reasons listed in the requirement. This again is not consistent with FERC guidelines that state VSLs
cannot modify the requirement. The following comments pertain to COM-001-2. We recommend striking “capability” from all of the requirements. It is not clear to us how this helps when a definition for
Interpersonal Communications is written already and applies to a communication medium. Furthermore, we think it causes confusion and actually contradicts the intent of the standard. Because
Requirements R1, R3, R5, R7 and R8 focus on capability, the responsible entity will be in violation anytime its medium that it uses for the primary capability does not function properly. Whereas if the
requirement stated that the responsible entity was to designate a primary communications medium, the responsible entity is not in violation if that medium is not functioning properly. It would be clear
that Requirement R2, R4 and R6 are intended to be complementary. Furthermore, it is not clear why Requirements R1, R3, R5, R7 and R8 state that the responsible entity shall “have” when the
companion Requirements R2, R4, and R6 state “designate.” Since Requirement R10 deals with a failure of its Interpersonal Communications capabilities and not Alternate Interpersonal Communications
capability, it should only refer to the entities in Requirements R1, R3, and R5. Currently, it includes R1 through R6. We suggest changing “physical assets” to “demonstration of physical assets”. Since
evidence is provided to the auditor and the auditor takes the evidence with them, providing them evidence that is a “physical asset” would be problematic. We believe that the VSLs could be written to
provide more gradations. For example, if a Transmission Operator or Balancing Authority failed to have Interpersonal Communications capability with a Distribution Provider but had Interpersonal
Communications capability with all other required entities, it has met the vast majority of the requirement. Since VSLs are a measure of how much the requirement was missed by the responsible entity,
jumping to a Severe VSL does not seem to adequately capture that the responsible entity met the vast majority of the requirement. Requirements R4 and R6 even seem to recognize this by not including
Distribution Provider in the list of entities to which the Transmission Operator or Balancing Authority are required to designate Alternate Interpersonal Communications capability. The following comments
pertain to COM-002-3. While COM-002-3 is well written to explain the three-part communications requirements and makes it perfectly clear when Reliability Directive has been issued, the opening clause
leaves the responsible entity open to second guessing on whether they should have issued a Reliability Directive. This problem could be solved by changing the opening clause to “When a Reliability
Coordinator, Transmission Operator, or Balancing Authority determines actions need to be executed as a Reliability Directive”. In the second bullet of Requirement R3, we suggest using “Restate” in place
of “Reissue”. The responsible entity is not really reissuing the Reliability Directive. They are still in the act of trying to get the Reliability Directive issued and are simply re-communicating it because it was
not understood.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
Yes
Yes
Group
Kansas City Power & Light
Michael Gammon
Yes
No
Requirements R4.3 and R6.3 require TOP’s and BA’s to establish alternative means of “interpersonal communications” with other TOP’s and BA’s without regard to the reliability impact each TOP or BA has
on the interconnection. Why would it be necessary for a TOP with one 161kv transmission line or a BA with 100 MW of total load, or one GOP with a 30MW unit to realize additional costs when the facilities
they operate have little reliability impact? Rationale criteria should be included here to identify the TOP’s and BA’s where alternative means of “interpersonal communications” should be implemented.
Furthermore, these requirements do not recognize the condition when another party refuses to install alternative communication equipment. TOP’s and BA’s have no authority over other TOP’s and BA’s to
establish alternative means of communication. Requirements that are dependent on the actions of other parties over which you have no control or authority are poor requirements. In addition, most RC’s
have established satellite telephone systems as back-up communication with TOP’s and BA’s. Some RC’s may have to establish additional communication systems with some BA’s as these requirements
impose to avoid Standards of Conduct issues.
Yes
No
How does a DP or GOP experiencing a failure of its “interpersonal communications” consult with its TOP or BA to determine a mutually agreeable time for restoration of “interpersonal communications”?
There are no requirements that require alternative “interpersonal communications” for the DP and GOP. This requirement cannot be fulfilled and should be removed.
Yes
R9 – considering the reliability of communication systems and System Operator attention may be on more important operational concerns, a 2 hour response to a problem with the alternative means of
communication is over sensitive. Allowing for sometime in an operating shift would be more in line, such as 8 hours. Violation Severity Levels for COM-001-2: The VSL’s for requirements R1-R8 and R11 do
not recognize the efforts of Entities to meet the requirements. If an Entity failed to establish communications or alternative communications with 1 Entity out of 20 should that be Severe? Implementation
Plan for COM-001-2: The implementation plan is too aggressive at completing in 6 months after regulatory approvals. Establishing agreements with other RC’s, TOP’s and BA’s for alternative “interpersonal
communications” regarding the various types of communications available that meet these requirements will take more than 6 months. Recommend 12 months to allow Entities sufficient time to reach
agreements and to establish the communications.
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Consideration of Comments
Reliability Coordination − Project 2006-06
The Reliability Coordination Drafting Team thanks all commenters who submitted comments on the
fifth formal posting for Project 2006-06—Reliability Coordination. These standards were posted for a
30-day public comment period from January 9, 2012 through February 8, 2012. Stakeholders were
asked to provide feedback on the standards and associated documents through a special electronic
comment form. There were 62 sets of comments, including comments from approximately 170
different people from approximately 106 companies representing 9 of the 10 Industry Segments, as
shown in the table on the following pages.
Summary Consideration
The RCSDT received comments from stakeholders, where a majority of those comments were focused
on compliance elements of the standards, various errors, and other ambiguities. The RCSDT believes it
has been responsive to the many comments and has either provided adequate explanation, where
applicable, as well as incorporating the needed clarifications or corrections. There were no strong
minority issues revealed in the comments which the RCSDT could not address. Revisions made to the
standards are summarized in the following sections by standard.
COM-001-2
In the last posting and successive ballot, the standard received approval from about half of the ballot
body with numerous comments. The RCSDT made substantive changes to the standard based on
comments. The changes to COM-001-2, R3 and R4 require the standard to undergo a second
successive ballot. The RCSDT believes it has addressed stakeholder comments and concerns in such a
way that the standard is improved and meets the expectation expressed in comments for reliability and
industry approval. Upon achieving industry consensus, this standard will advance to a recirculation
ballot.
Purpose: Removed the text “for the exchange of Interconnection and operating information” based on
comments received and due to the fact that the standard is for capability, which enables information
exchange under other standards.
Effective Date: The language in the effective date was made consistent with current Standard Drafting
Guidelines.
Requirements: Most changes were minor. In places where the capitalized word “Adjacent” began the
requirement Parts, the RCSDT added the word “Each” and made “Adjacent” lowercase to avoid the
perception of a defined glossary term. This change occurred in Parts 1.2, 2.2, 3.5, 4.3, 5.5, and 6.3. A
significant change occurred in requirements R3 and R4. The RCSDT addressed stakeholders concerns
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Reliability Coordination − Project 2006-06
about the use of “synchronously connected within the same Interconnection.” This was addressed by
removing the phrase “within the same Interconnection;” however, other comments were concerned
that synchronously did not address DC ties. The RCSDT addressed this by adding a Part, which reads,
“Each Transmission Operator asynchronously connected” to Requirements R3 and R4. Requirement
R10 was updated to more accurately reflect the reference to other requirements. It should not have
referenced R1 through R6; but, rather, R1, R3, and R5. Requirement R11 was updated to address
stakeholder concerns about reaching a “mutually agreeable time,” so was changed to “mutually
agreeable action.” Other minor changes included making plural terms singular and replacing “per” for
“each” for readability and understanding.
Some commenters had concerns about conditions of non-compliance if the entity’s Interpersonal
Communication capability failed. To address this concern, the RCSDT added conforming language to
Requirements R1, R3, R5, R7 and R8 that bridges the potential gap in non-compliance for a failed
Interpersonal Communication capability.
Measures: Most changes to the measures were non-substantive and provided better formatting for
readability. Measures M3 and M4 were updated to align with the changes to the parts of
Requirements R3 and R4 regarding synchronous and asynchronous. Several measures had inconsistent
example evidence for the performance of the requirement. For example, time (hour/minute) based
elements are introduced in R9 and R10; however, the measures did not note using dated and “timestamped” evidence. Likewise, previous requirements did make use of “time-stamped” where there
was no time based (hour/minute) performance. The RCSDT found this an unnecessary compliance
burden. Other minor changes included making plural terms singular and replacing “per” for “each,” for
readability and understanding.
Compliance, Compliance Enforcement Authority: The language in the CEA section was made
consistent with current Standard Drafting Guidelines.
Compliance, Data Retention: The language in the data retention section was made consistent with
current Standard Drafting Guidelines. The bulleted items were reformatted for consistency and
readability.
Violation Severity Levels: Clarifying changes were made to the VSLs. Terms were made singular, the
word “Requirement” added to appropriately designate the applicable requirement, and added the two
newly-created parts from Requirements R3 and R4. The RCSDT added High VSLs for Requirements R1
through R8 to conform with VSL Guidelines. Requirements R1 through R8 are not binary only.
COM-002-3
The changes to COM-002-3 are considered non-substantive; therefore, the standard will advance to a
recirculation ballot. The RCSDT believes it addressed stakeholder comments and concerns in such a
2
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Reliability Coordination − Project 2006-06
way that the updated sections of the standard is improved and overall meets industry’s expectation for
approval. Following approval, this standard will be submitted for adoption by the NERC Board of
Trustees
Effective Date: The language in the effective date was made consistent with current Standard Drafting
Guidelines.
Requirements: For the named functional entities in Requirements R2 and R4, the conjunction “and”
previously used has been changed to “or,” based on comments received from stakeholders.
Measures: Corresponding changes to Measures M2 and M3 were made in regards to Requirement R2
and R3. Measure M2 received an addition to include the phrasing, “restated, rephrased, or
recapitulated” for consistency with Requirement R2.
Compliance, Compliance Enforcement Authority: The language in the CEA section was made
consistent with current Standard Drafting Guidelines.
Compliance, Data Retention: The language in the data retention section was made consistent with
current Standard Drafting Guidelines. Some bulleted items were corrected to accurately align them
with the respective requirements.
Violation Severity Levels: One clarifying change was made to the R3 VSL. The RCSDT added a High VSL
to accurately capture the condition where the entity failed to confirm the response of the recipient and
removed the first part of the Severe VSL.
IRO-001-3
The changes to IRO-001-3 are considered nonsubstantive; therefore, the standard will advance to a
recirculation ballot. The RCSDT believes it addressed stakeholder comments and concerns in such a
way that the updated sections of the standard are improved and overall meets industry’s expectation
for approval. Following approval, this standard will be submitted for adoption by the NERC Board of
Trustees
Effective Date: The language in the effective date was made consistent with current Standard Drafting
Guidelines.
Requirements: In requirement R1, the last word (glossary term) was made singular for clarity and
consistency with the definition. Requirement R2 was missing a conjunction in the functional entities,
and this has been added.
3
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Reliability Coordination − Project 2006-06
Measures: Measure M1 was updated to use past tense language, consistent with drafting guidelines.
Also, the parenthetical on “Reliability Directive(s)” was removed and the glossary term made singular
for consistency with R1. Measure M2 addressed stakeholder comments by adding the word
“physically,” phrase now reads, “physically implemented” to be consistent with Requirement R2, as
well as making the term “direction” singular.
Compliance, Compliance Enforcement Authority: The language in the CEA section was made
consistent with current Standard Drafting Guidelines.
Compliance, Data Retention: The language in the data retention section was made consistent with
current Standard Drafting Guidelines. Some bulleted items were corrected to accurately align them
with the respective requirements and remove inaccurate bullets from previous postings.
Violation Severity Levels: Clarifying changes were made to the R1 VSL. The phrase, “exercise its
authority” was added, based on stakeholder comment, to more accurately reflect Requirement R1.
The RCSDT removed the High VSL from R2, and more accurately incorporated it into the Sever VSL.
Additional Information
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to
give every comment serious consideration in this process! If you feel there has been an error or
omission, you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-4462560, or at [email protected]. In addition, there is a NERC Reliability Standards Appeals
Process. 1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
4
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Reliability Coordination − Project 2006-06
Index to Questions, Comments, and Responses
1.
The RCSDT has revised the applicability of the standards and implementation plans by aligning
COM-001-2, COM-002-3, and IRO-001-2 to apply to the same entities and by removing LSE, PSE
and TSP as applicable entities from the COM standards. Additionally, the Interchange Coordinator
has been removed as an applicable entity from the standards. Do you agree with this change in
applicability to the three standards? If not, please explain in the comment area below. ... 14
2.
Do you agree with the addition of “Adjacent” entities in COM-001-2, Parts 3.5, 4.3, 5.5 and 6.3 of
COM-001-2? If not, please explain in the comment area below. ......................................... 28
3.
The RCSDT removed the phrase "to exchange Interconnection and operating information" in COM001-2, Requirements R1 through R8 based on stakeholder comments. Do you agree with the
revision? If not, please explain in the comment area below. ............................................... 39
4.
A new requirement was added for clarity regarding what is required of Distribution Providers and
the Generator Operators: R11. Each Distribution Provider and Generator Operator that
experiences a failure of any of its Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority as applicable to determine a mutually agreeable
time to restore the Interpersonal Communication capability. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations] This requirement requires collaboration between entities to
restore a failed communications capability. Do you agree with the new requirement? If not, please
explain in the comment area below...................................................................................... 47
5.
The proposed definition of Reliability Directive shown in COM-002-3 was revised to include
Adverse Reliability Impact as shown to more fully address emergencies or events that might lead
to instability or Cascading: Reliability Directive: A communication initiated by a Reliability
Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an Emergency or Adverse Reliability Impact. Do you agree with the proposed
definition? If not, please explain in the comment area below. ............................................ 76
6. Do you have any other comment, not expressed in questions above, for the RC SDT?........ 96
5
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Gerald Beckerle
SERC OC Standards Review Group
Additional Member Additional Organization Region Segment Selection
1.
Mike Hirst
Cogentrix
SERC
5
2.
Jeff Harrison
AECI
SERC
1, 3, 5, 6
3.
Sam Holeman
Duke Energy
SERC
1, 3, 5, 6
4.
Michael Belle
SCE&G
SERC
1, 3, 5, 6
5.
Bob Dalrymple
TVA
SERC
1, 3, 5, 6
6.
Joel Wise
TVA
SERC
1, 3, 5, 6
7.
Jake Miller
Dynegy
SERC
5
8.
Robert Thomasson BREC
SERC
1
9.
Alvis Lanton
SIPC
SERC
1
10. Tim Hattaway
PowerSouth
SERC
1, 5
11. Shardra Scott
Southern
SERC
1, 5
12. Greg Stone
Duke Energy
SERC
1, 3, 5, 6
13. Tom Burns
PJM
SERC
2
X
2
3
X
4
5
6
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14. Steve Corbin
SERC Reliability Corp.
SERC
10
15. Brad Young
LGE/KU
SERC
3
16. Wayne Van Liere
LGE/KU
SERC
3
17. Gary Hutson
SMEPA
SERC
1, 3, 4, 5
18. Scott Brame
NCEMC
SERC
1, 3, 4, 5
19. Devan Hoke
SERC Reliability Corp.
SERC
10
20. Jim Case
Entergy
SERC
1, 3, 6
21. William Berry
OMU
SERC
3, 5
22. John Troha
SERC Reliability Corp.
SERC
10
2.
Ron Sporseen
Group
Additional Member
Pacific Northwest Generating Cooperative
Additional Organization
Bud Tracy
Blachly-Lane Electric Cooperative WECC 3
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power Company
WECC 3
4.
Roman Gillen
Consumers Power Inc.
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Dave Sabala
Douglas Electric Cooperative
WECC 8
7.
Bryan Case
Fall River Electric Cooperative
WECC 3
8.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
9.
Ray Ellis
Lincoln Electric Cooperative
WECC 8
10. Annie Terracciano
Northern Lights Inc.
WECC 3
11. David Gottula
Okanogan Electric Cooperative
WECC 8
12. Aleka Scott
PNGC Power
WECC 4
13. Heber Carpenter
Raft River Electric Cooperative
WECC 3
14. Steve Eldrige
Umatilla Electric Cooperative
WECC 1, 3
15. Marc Farmer
West Oregon Electric Cooperative WECC 4
16. Margaret Ryan
PNGC Power
3.
Guy Zito
Group
3
X
4
X
5
6
7
8
9
10
X
Region Segment Selection
1.
Additional Member
X
2
WECC 8
Northeast Power Coordinating Council
Additional Organization
X
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
4.
Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
6.
Brian Evans-Mongeon Utility Services
NPCC 8
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
9.
Chantel Haswell
NPCC 5
Hydro One Networks Inc.
NPCC 1
11. Michael R. Lombardi
Northeast Utilities
NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC 1
16. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
Will Smith
4
5
6
7
8
9
10
NPCC 10
FPL Group, Inc.
Group
3
NPCC 1
10. David Kiguel
4.
2
MRO NSRF
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Tom Webb
WPS
MRO
3, 4, 5, 6
4.
Jodi Jenson
WAPA
MRO
1, 6
5.
Ken Goldsmith
ALTW
MRO
4
6.
Alice Ireland
XCEL/NSP
MRO
1, 3, 5, 6
7.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
9.
Joe DePoorter
MGE
MRO
3, 4, 5, 6
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. Scott Nickels
RPU
MRO
4
11. Terry Harbour
MEC
MRO
3, 5, 6, 1
12. Marie Knox
MISO
MRO
2
13. Lee Kittelson
OTP
MRO
1, 3, 4, 5
14. Scott Bos
MPW
MRO
1, 3, 5, 6
15. Tony Eddleman
NPPD
MRO
1, 3, 5
16. Mike Brytowski
GRE
MRO
1, 3, 5, 6
17. Richard Burt
MPC
MRO
1, 3, 5, 6
5.
Group
Claire Lloyd
No additional members listed.
6.
Group
Brenda Powell
Additional Member
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
3
X
4
X
5
X
CCG, CPG, CECD
Additional Organization
6
C. J. Ingersol
Constellation Energy Control & Dispatch
2.
A. Y. Hammad
Constellation Power Source Generation, Inc. RFC
SERC
9
10
X
3
5
ERCOT 5, 6
4.
FRCC
6
5.
MRO
6
6.
NPCC
5, 6
7.
SPP
6
8.
WECC 5, 6
9.
RFC
6
10.
SERC
6
Group
Brent Ingebrigtson
No additional members listed.
LG&E and KU Services Company
X
X
X
X
8.
Bonneville Power Administration
X
X
X
X
X
X
Chris Higgins
8
X
3.
Group
7
Region Segment Selection
1.
7.
X
2
Additional Member Additional Organization Region Segment Selection
1. Huy
Ngo
WECC 1
2. Paul
Blake
WECC 1
3. Ted
Snodgrass
WECC 1
9.
Group
Annette M. Bannon
PPL Electric Utilities and PPL Supply NERC
X
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Registered Organizations
Additional Member
1. Annette Bannon
Additional Organization
Region Segment Selection
PPL Generation, LLC on behalf of NERC Registered Entities RFC
2.
5
WECC 5
3. Mark Heimbach
PPL EnergyPlus, LLC
MRO
6
4.
NPCC 6
5.
RFC
6
6.
SERC
6
7.
SPP
6
8.
WECC 6
9. Brenda Truhe
10.
Group
PPL Electric Utilities Corp.
RFC
Robert Rhodes
1
SPP Standards Review Group
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. John Allen
City Utilities of Springfield SPP
1, 4
2. Michelle Corley
CLECO Power
SPP
1, 3, 5
3. Jonathan Hayes
Southwest Power Pool
SPP
2
4. Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
5. Terri Pyle
Oklahoma Gas & Electric SPP
11.
Group
Additional Member
Mike Garton
1, 3, 5
Dominion
Additional Organization
X
X
Region Segment Selection
1. Michael Gildea
Dominion Resource Services, Inc.
NPCC 5, 6
2. Louis Slade
Dominion Resource Services, Inc.
RFC
5, 6
3. Connie Lowe
Dominion Resource Services, Inc.
MRO
5, 6
4. Michael Crowley
Virginia Electric and Power Company SERC
1
12.
Group
Steve Rueckert
No additional members listed.
Western Electricity Coordinating Council
X
13.
Group
Emily Pennel
No additional members listed.
Southwest Power Pool Regional Entity
X
14.
FirstEnergy
Group
Sam Ciccone
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1. John Reed
FE
RFC
1
2. Mark Pavlick
FE
RFC
1, 3, 4, 5, 6
3. Doug Hohlbaugh
FE
RFC
1, 3, 4, 5, 6
4. Brian Orians
FE
RFC
5
5. Bill Duge
FE
RFC
5
6. Kevin Querry
FE
RFC
5
15.
Group
Marie Knox
MISO Standards Collaborators
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Jim Cyrulewski
JDRJC Associates, LLC
RFC
8
2. Barb Kedrowski
We Energies
RFC
3, 4, 5
3. Joe O'Brien
NIPSCO
RFC
1, 3, 5, 6
16.
Group
Frank Gaffney
Florida Municipal Power Agency
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
17.
Group
FRCC
Mary Jo Cooper
Additional Member
X
Global Engineering and Energy Solutions
Additional Organization Region Segment Selection
1. Colin Murphey
City of Ukiah
WECC 3
2. Elizabeth Kirkley
City of Lodi
WECC 3
3. Salmon River Electric Coop Salmon River Electric Coop WECC 3
18.
Group
Additional Member
Jason Marshall
Additional Organization
ACES Power Marketing Standards
Collaborators
Region Segment Selection
1. Mark Ringhausen
Old Dominion Electric Cooperative SERC
3, 4
2. Susan Sosbe
Wasbash Valley Power Association RFC
3
19.
Group
Michael Gammon
X
Kansas City Power & Light
X
X
X
X
11
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Jessi Tucker
Kansas City Power & Light SPP
1, 3, 5, 6
2. Brett Holland
Kansas City Power & Light SPP
1, 3, 5, 6
20.
X
X
X
X
X
X
X
X
Individual
22.
Individual
Antonio Grayson
Southern Company
X
X
X
23.
Individual
Jennifer Wright
San Diego Gas & Electric
X
X
X
24.
Individual
Steve Alexanderson
Central Lincoln
25.
Individual
Paul Kerr
Shell Energy North America
26.
Individual
Keira Kazmerski
Xcel Energy
X
X
X
X
27.
Individual
Edward J Davis
Entergy Services, Inc
X
X
X
X
28.
Individual
Michael Falvo
Independent Electricity System Operator
29.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
30.
Individual
Daniel Duff
Liberty Electric Power LLC
31.
Individual
Joe O'Brien
NIPSCO
X
32.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
33.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
X
34.
Individual
Anthony Jankowski
J. S. Stonecipher, PE
We Energies
City of Jacksonville Beach dba/ Beaches
Energy Services
Individual
37. Individual
Scott Berry
Jeff Longshore
Indiana Municipal Power Agency
Luminant Energy Company LLC
38.
Individual
Brian J. Murphy
NextEra Energy, Inc.
39.
Individual
David Thorne
40.
Individual
41.
Individual
35.
Individual
36.
Salt River Project
X
Chris Chavez
Janet Smith, Regulatory
Affairs Supervisor
21.
Individual
Arizona Public Service Company
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Pepco Holdings Inc.
X
X
John Bee
Exelon
X
X
X
Joe Petaski
Manitoba Hydro
X
X
X
X
X
12
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
Individual
Michael Brytowski
Great River Energy
X
X
Individual
44. Individual
David Burke
Michael Schiavone
Orange and Rockland Utilities, Inc.
Niagara Mohawk (dba National Grid)
X
X
45.
Individual
Thad Ness
American Electric Power
46.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
47.
Individual
Jason Snodgrass
Georgia Transmission Corporation
X
48.
Individual
Bill Keagle
BGE
X
49.
Individual
Don Schmit
Nebraska Public Power District
X
50.
Individual
Neil Phinney
Georgia System Operations
51.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
52.
Individual
Greg Rowland
Duke Energy
53.
Individual
Kathleen Goodman
ISO New England
X
54.
Individual
H. Steven Myers
ERCOT ISO
X
55.
Individual
Anthony Jablonski
ReliabilityFirst
56.
Individual
Randall McCamish
City of Vero Beach
X
X
57.
Individual
Rich Salgo
X
X
42.
43.
Individual
Rebecca Moore Darrah
NV Energy
Midwest Independent Transmission System
Operator
59.
Individual
Don Jones
Texas Reliability Entity
60.
Individual
David Kiguel
Hydro One Networks Inc.
61.
Individual
Gregory Campoli
New York Independent System Operator
62.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
58.
4
5
6
X
X
X
X
X
X
X
X
X
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
13
1.
The RCSDT has revised the applicability of the standards and implementation plans by aligning COM-001-2, COM-002-3 and
IRO-001-3 to apply to the same entities and by removing LSE, PSE and TSP as applicable entities from the COM standards.
Additionally, the Interchange Coordinator has been removed as an applicable entity from the standards. Do you agree with
this change in applicability to the three standards? If not, please explain in the comment area below.
Summary Consideration: Most commenters agreed with removing the LSE, PSE, and TSP from the three standards. Some did not
agree with keeping the Distribution Provider (DP) within the standards. The RCSDT in being responsive to the FERC directive in Order
No. 693, Paragraph 487, considered the DP entity; however, concluded having the DP is appropriate in responding to the directive to
allow for reliable operations in normal and emergency situations. In reference to the implementation for DPs and GOPs, the RCSDT
believes there is not a significant burden for most DP and GOP entities to implement an Interpersonal Communication capability.
Some comments referenced the NERC Functional Model V5 concerning DP and GOP entities; however, the model is clear on the basic
activities and supports the DP and GOP being applicable to the standards. The model also supports the removal of LSEs, for example.
The RCSDT did not modify the applicability of the standards with regard to functional entities.
Organization
ACES Power Marketing Standards
Collaborators
Yes or No
Question 1 Comment
No
While we agree with removing LSE, PSE, and TSP, we do not agree with the
need to include Distribution Provider in all the standards. For example, in
IRO-001-3, the Distribution Provider will likely never receive a Reliability
Directive directly from its Reliability Coordinator. More likely, the Reliability
Directive will be issued by the Transmission Operator or Balancing Authority
depending on if the issue is security or adequacy related.
Response: The RCSDT is addressing a FERC directive (P487, Order 693) to include the DP in COM-001, and the RCSDT has included
the DP in COM-002 and IRO-001 applicability because these standards are related to reliability communications. The RCSDT agrees
with the point that communication will most likely be from the BA or TOP; however, the communications may come from the RC.
No change made.
Entergy Services, Inc
No
R3 adds additional responsibilities for the TOP to have Interpersonal
Communications capability with EACH DP and GOP in its footprint.
Similarly, R4 gives the TOP responsibility to have alternative
14
Organization
Yes or No
Question 1 Comment
communications capability with each of these entities. This is a significant
additional responsibility for the TOP to document and perhaps arrange for
additional means of communication with these entities.
The RCSDT is addressing a FERC directive (P487, Order 693) to include the
DP and GOP. The intent is to have Interpersonal Communication capability
with the DP and GOP, and not to build additional communication facilities,
but to be able “to interact, consult, or exchange information.” In contrast
to R3, R4 does not include the DP or GOP. No change made.
The short time frame provided for implementation of these requirements is
not consistent with the additional effort and compliance documentation
that is necessary to implement these requirements. Entergy recommends
that the implementation time frame for these new requirements that apply
to new entities, or expand the application of COM-001 for existing entities
have an effective date 12 months beyond the applicable regulatory
approval.
Additionally, the implementation of the requirements that apply to the DP
and GOP will represent an increase in the amount of documentation that
must be retain to demonstrate compliance, and in some cases may also
result in their having to purchase equipment or install new alternate means
of communication.
The RCSDT believes that six months is adequate, considering additional
facilities should not have to be built to establish communications with the
DP and GOP; similarly, compliance documentation should not impose
significant work on the entities part. No change made.
What is the improvement in reliability expected as a result of these new
requirements?
The expected reliability result is addressed in the FERC directive (P487,
Order 693), “…ensure there is no reliability gap during normal and
15
Organization
Yes or No
Question 1 Comment
emergency operations. For example, during a blackstart when normal
communications may be disrupted, it is essential that the Transmission
Operator, Balancing Authority and Reliability Coordinator maintain
communications with their Distribution Providers and Generator
Operators.” No change made.
Response: See response above.
Independent Electricity System
Operator
No
In COM-001, we commented earlier that the entities in R4 and R6 (now R5
and R6) should be the same, i.e. the BA needs to have the Interpersonal
Communication capability as well as the Alternative Interpersonal
Communication capability with the same entities. The SDT’s response
indicates that the suggested change is not needed since additionally
requiring DP and GOP entities to have Alternative Interpersonal
Communication capability would impose more cost on smaller DP and GOP
entities that have little or no risk impact to the bulk electric system.
We disagree with this assessment since the need to have Alternative
Interpersonal Communication capability should be assessed from the
viewpoint that whether or not the absence of such capability can adversely
affect reliability. If Interpersonal Communication capability is needed
between a BA and a DP/GOP to communicate reliability instructions or
directives, then it is deemed necessary that such communication be
provided at all times, which indicates the need for an alternative capability.
We once again urge the SDT to make the list of entities in R5 and R6 to be
the same.
Response: The RCSDT asserts the standard meets FERC Order 693 regarding DP and GOP entities by requiring these entities to
have Interpersonal Communication capability. Additionally, requiring DP and GOP entities to have Alternative Interpersonal
Communication capability only imposes more cost on smaller DP and GOP entities that have little or no risk impact to the Bulk
Electric System. No change made.
16
Organization
Georgia System Operations
Yes or No
Question 1 Comment
No
While we agree with removing LSE, PSE, and TSP, we do not agree with the
need to include Distribution Provider in all the standards. For example, in
IRO-001-3, the Distribution Provider will likely never receive a Reliability
Directive directly from its Reliability Coordinator. More likely, the Reliability
Directive will be issued by the Transmission Operator or Balancing Authority
depending on if the issue is security or adequacy related.
The RCSDT is addressing a FERC directive (P487, Order 693) to include the
DP in COM-001, and the RCSDT has included the DP in COM-002 and IRO001 applicability because these standards are related to reliability
communications. The RCSDT agrees with the point that communication will
most likely be from the BA or TOP; however, the communications may come
from the RC. No change made.
Accordingly, NERC’s Reliability Functional Model V5 2 describes and
identifies the DP’s relationships with other Functional Entities to the TOP
and BA with respect to Real Time.
Real Time 3
7. Implements voltage reduction and sheds load as directed by the
Transmission Operator or Balancing Authority.
8. Implements system restoration plans as coordinated by the Transmission
Operator.
9. Directs Load-Serving Entities to communicate requests for voluntary load
curtailment.
With respect to the Functional Model V5, please see Page 31, “18. Issues
2
NERC Functional Model Version 5, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
3
NERC Functional Model Version 5, “Functional Entity – Distribution Provider,” pg 47, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
17
Organization
Yes or No
Question 1 Comment
corrective actions and emergency procedures directives (e.g., curtailments
or load shedding) to Transmission Operators, Balancing Authorities,
Generator Operators, Distribution Providers, and Interchange
Coordinators.” No change made.
Response: See response above.
ERCOT ISO
No
Some concern for removal of LSE in particular from R2 and R3 from current
IRO-001-2 R7 for the ERCOT region. ERCOT Region has QSE’s 4 that manage
Load Resources. There may be some QSEs that are not registered as a GOP
that deploy Load Resources. Per the current LSE JRO, QSEs with Load
Resources are registered as LSEs. Not requiring them to deploy Load
Resource directives could be perceived as a reliability gap created from
previous version to this version. PSEs could be removed as long as they fall
under BA authority.
Response: The RCSDT believes the DP is the correct entity because the LSE does not own assets. The definition of LSE is, “The
functional entity that secures energy and transmission service (and reliability related services) to serve the electrical demand and
energy requirements of its end use customers.” In contrast, the definition of a DP is, “The functional entity that provides facilities
that interconnect an End-use Customer load and the electric system for the transfer of electrical energy to the End-use Customer.”
Additionally, the Functional Model V5 demonstrates this under the Reliability Coordinator, “18. Issues corrective actions and
emergency procedures directives (e.g., curtailments or load shedding) to Transmission Operators, Balancing Authorities, Generator
Operators, Distribution Providers, and Interchange Coordinators.” No change made.
City of Green Cove Springs
4
Affirmative
COM-001-2: In R5.3, should a BA have communications with a DP or LSE?
For the TOP, it is the DP because the load influence is very local; however,
for a BA the supply / demand balance is not local and in markets that allow
retail competition, I'm thinking LSE is the right functional entity. For Florida,
Qualifying Scheduling Entities, (http://www.ercot.com/services/rq/qse/)
18
Organization
Yes or No
Question 1 Comment
it doesn't really matter. If the LSE is the "correct" entity, then R7 would
need to be changed and a new requirement specific to LSE's would need to
be added.
The RCSDT believes the DP should be included and that the LSE should not
because the Functional Model V5 addresses this case. See Page 47,
“Distribution Provider,” of the Functional Model V5, Item 9. “Directs LoadServing Entities to communicate requests for voluntary load curtailment.”
The DP is the asset owner and would direct the LSE to perform actions. No
change made.
COM-001-2, R9 – "Each ... shall test its Alternative Interpersonal
Communications capability", suggest adding the phrase "to each entity for
which Alternative Interpersonal Communications is required" to add clarity.
The RCSDT believes the additional phrasing has little value to the overall
requirement. The requirement specifically applies to those responsible
entities listed, and it further aligns with R2, R4 and R6. No change made.
Response: See response above.
Beaches Energy Services
Affirmative
COM-001-2: In R5.3, should a BA have communications with a DP or LSE?
For the TOP, it is the DP because the load influence is very local; however,
for a BA the supply/demand balance is not local and in markets that allow
retail competition, I'm thinking LSE is the right functional entity. For Florida,
it doesn't really matter. If the LSE is the "correct" entity, then R7 would
need to be changed and a new requirement specific to LSE's would need to
be added.
Response: The RCSDT believes the DP should be included and not the LSE because the Functional Model V5 addresses this case.
See Page 47, “Distribution Provider,” of the Functional Model V5, Item 9. “Directs Load-Serving Entities to communicate requests
for voluntary load curtailment.” With regard to R7, the DP is the asset owner and would direct the LSE to perform actions. No
19
Organization
Yes or No
Question 1 Comment
Yes
(1) In COM-001, the entities in R4 and R6 (now R5 and R6) should be the
same, i.e. the BA needs to have the Interpersonal Communication capability
as well as the Alternative Interpersonal Communication capability with the
same entities. Although the need to have Alternative Interpersonal
Communication capability should be assessed from the viewpoint that
whether or not the absence of such capability can adversely affect
reliability, the proposed standard does not require the capability in all cases.
At the same time, this standard does not preclude such capability. Even
though Interpersonal Communication capability is needed between a BA
and a DP/GOP to communicate reliability instructions or directives, there
are other communications paths which can be used in the case of the loss of
that capability.
change made.
MISO Standards Collaborators
Since TOPs are also required to have the capability, the BA can call the TOP
and ask the TOP to contact the DP/GOP for them until they can implement
capability. In addition, it is difficult to visualize entities which would not
have the public telephone system or even cell phones available for use in
the event of the loss of the capability.
Response: The RCSDT stresses the standard meets FERC Order 693 regarding DP and GOP entities by requiring these entities to
have Interpersonal Communication capability. Additionally, requiring DP and GOP entities to have Alternative Interpersonal
Communication capability only imposes more cost on smaller DP and GOP entities that have little or no risk impact to the Bulk
Electric System. No change made.
Florida Municipal Power Agency
Yes
In COM-001-2 R5.3, should a BA have communications with a DP or LSE? For
the TOP, it is the DP because the load influence is very local; however, for a
BA the supply / demand balance is not local and in markets that allow retail
competition, it may be that the LSE is the more appropriate functional
entity. For instance, the Functional Model when discussing LSE on page 55
20
Organization
Yes or No
Question 1 Comment
states that one of the LSE’s real time duties is:
“12. Receives requests from the Balancing Authority and Distribution
Provider for voluntary load curtailment.” 5
The RCSDT believes the DP should be included and not the LSE because the
Functional Model V5 addresses this case. See Page 47, “Distribution
Provider,” of the Functional Model V5, Item 9. “Directs Load-Serving
Entities to communicate requests for voluntary load curtailment.” In this
case (COM-001), the load curtailment is voluntary and would generally be
for economics, the exchange of operating information and not reliability
actions. No change made.
If the LSE is the more appropriate entity, then R7 would need to be changed
and a new requirement specific to LSE's would need to be added.
For Florida, which does not have retail competition, it doesn’t matter
whether the DP or the LSE is more appropriate; hence, the “yes” answer.
With regard to R7, the DP is the asset owner and would direct the LSE to
perform actions. No change made.
Response: See response above.
Georgia Transmission Corporation
5
Yes
While we agree with removing LSE, PSE, and TSP, we do not agree with the
need to include Distribution Provider in all the standards. For example, in
IRO-001-3, the Distribution Provider will likely never receive a Reliability
Directive directly from its Reliability Coordinator. Reliability Directives
received by Distribution Providers will be issued by the Transmission
Operator or Balancing Authority depending on if the issue is security or
adequacy related. Accordingly, NERC’s Reliability Functional Model V5
NERC Functional Model Version 5, “Functional Entity – Load Serving Entity,” pg 55, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
21
Organization
Yes or No
Question 1 Comment
describes and identifies the DP’s relationships with other Functional Entities
to the TOP and BA with respect to Real Time.
Real Time 6
7. Implements voltage reduction and sheds load as directed by the
Transmission Operator or Balancing Authority.
8. Implements system restoration plans as coordinated by the Transmission
Operator.
9. Directs Load-Serving Entities to communicate requests for voluntary load
curtailment.
The RCSDT is addressing a FERC directive (P487, Order 693) to include the
DP in COM-001, and the RCSDT has included the DP in COM-002 and IRO001 applicability because these standards are related to reliability
communications. The RCSDT agrees with the point that communication will
most likely be from the BA or TOP; however, the communications may come
from the RC. With respect to the Functional Model V5, please see Page 31,
“18. Issues corrective actions and emergency procedures directives (e.g.,
curtailments or load shedding) to Transmission Operators, Balancing
Authorities, Generator Operators, Distribution Providers, and Interchange
Coordinators.” No change made.
Lastly, we believe that Distribution Providers requirements with respect to
complying with Reliability Directives received by TOPs and BAs are
adequately covered by Reliability Standards TOP-001 and COM-002.
The RCSDT agrees that TOP-001 and COM-002 apply to DP complying with
Reliability Directives; however, IRO-001 applies to having the authority to
act or direct others act and may not necessarily be done by issuing a
6
NERC Functional Model Version 5, “Functional Entity – Distribution Provider,” pg 47, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
22
Organization
Yes or No
Question 1 Comment
Reliability Directive. No change made.
Response: See response above.
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP believes that the intent of these three standards
is to ensure reliable normal and emergency communications between BES
operating entities. It should be the rare exception that BES-critical
information must be communicated directly to an LSE, PSE, and TSP and IC.
The impact of the Standards would be lessened if diffusely applied to
multiple entities who do not normally engage in operations
communications.
Yes
In COM-001-2 R5.3, should a BA have communications with a DP or LSE? For
the TOP, it is the DP because the load influence is very local; however, for a
BA the supply / demand balance is not local and in markets that allow retail
competition, it may be that the LSE is the more appropriate functional
entity. For instance, the Functional Model when discussing LSE on page 55
states that one of the LSE’s real time duties is:
Response: Thank you for your comment.
City of Vero Beach
“12. Receives requests from the Balancing Authority and Distribution
Provider for voluntary load curtailment.” 7
The RCSDT notes that the LSE should not be included because the
Functional Model V5 addresses this case. See Page 47, “Distribution
Provider,” of the Functional Model V5, Item 9. “Directs Load-Serving
Entities to communicate requests for voluntary load curtailment.” No
change made.
7
NERC Functional Model Version 5, “Functional Entity – Load Serving Entity,” pg 55, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
23
Organization
Yes or No
Question 1 Comment
If the LSE is the more appropriate entity, then R7 would need to be changed
and a new requirement specific to LSE's would need to be added.
For Florida, which does not have retail competition, it doesn’t matter
whether the DP or the LSE is more appropriate; hence, the “yes” answer.
With regard to R7, the DP is the asset owner and directs the LSE to perform
actions. No change made.
Response: See response above.
SERC OC Standards Review Group
Yes
Pacific Northwest Generating
Cooperative
Yes
MRO NSRF
Yes
City of Tacoma, Department of
Public Utilities, Light Division, dba
Tacoma Power
Yes
LG&E and KU Services Company
Yes
Bonneville Power Administration
Yes
SPP Standards Review Group
Yes
Dominion
Yes
Western Electricity Coordinating
Council
Yes
24
Organization
Yes or No
Southwest Power Pool Regional
Entity
Yes
FirstEnergy
Yes
Global Engineering and Energy
Solutions
Yes
Kansas City Power & Light
Yes
Salt River Project
Yes
Southern Company
Yes
San Diego Gas & Electric
Yes
Central Lincoln
Yes
Shell Energy North America
Yes
Xcel Energy
Yes
Liberty Electric Power LLC
Yes
NIPSCO
Yes
Oncor Electric Delivery Company LLC
Yes
Consolidated Edison Co. of NY, Inc.
Yes
We Energies
Yes
Question 1 Comment
25
Organization
Yes or No
Luminant Energy Company LLC
Yes
NextEra Energy, Inc.
Yes
Pepco Holdings Inc.
Yes
Exelon
Yes
Manitoba Hydro
Yes
Great River Energy
Yes
Orange and Rockland Utilities, Inc.
Yes
Niagara Mohawk (dba National Grid)
Yes
American Electric Power
Yes
South Carolina Electric and Gas
Yes
BGE
Yes
Nebraska Public Power District
Yes
Duke Energy
Yes
ISO New England
Yes
ReliabilityFirst
Yes
NV Energy
Yes
Question 1 Comment
26
Organization
Yes or No
Midwest Independent Transmission
System Operator
Yes
Texas Reliability Entity
Yes
Hydro One Networks Inc.
Yes
New York Independent System
Operator
Yes
American Transmission Company,
LLC
Yes
City of Jacksonville Beach dba/
Beaches Energy Services
Question 1 Comment
In R5.3, should a BA have communications with a DP or LSE? For the TOP, it
is the DP because the load influence is very local; however, for a BA the
supply/demand balance is not local and in markets that allow retail
competition, I'm thinking LSE is the right functional entity. For Florida, it
doesn't really matter. If the LSE is the "correct" entity, then R7 would need
to be changed and a new requirement specific to LSE's would need to be
added
Response: The RCSDT notes that the LSE not should be included because the Functional Model V5 addresses this case. See Page
47, “Distribution Provider,” of the Functional Model V5, Item 9. “Directs Load-Serving Entities to communicate requests for
voluntary load curtailment.” With regard to R7, the DP is the asset owner and directs the LSE to perform actions. No change
made.
Indiana Municipal Power Agency
No comment.
27
2.
Do you agree with the addition of “Adjacent” entities in COM-001-2, Parts 3.5, 4.3, 5.5 and 6.3 of COM-001-2? If not, please
explain in the comment area below.
Summary Consideration: The majority of comments were regarding COM-001-2, R3 and R4. Concerns included issues with the use of
“Adjacent Transmission Operators” and “synchronously connected within the same Interconnection.” The capitalized word “Adjacent,”
beginning the requirement gives the appearance of an undefined glossary term. Therefore, the RCSDT addressed this by starting the
applicable Parts of those requirements with “Each” to form “Each adjacent Transmission Operator…” and avoiding the need for another
glossary term for something that is widely understood within the industry. The RCSDT made an additional clarifying change to address
the issue that some Transmission Operators may not be adjacent for situations other that synchronously connected within the same
Interconnection in the traditional understanding. For example, some entities have connections beyond the interconnection and some
connections are asynchronous. To address this concern, the RCSDT separated the requirements to identify “synchronously connected”
and “asynchronously connected,” and removed the “within the same Interconnection” criteria. Other minor formatting and reference
errors were noted and corrected.
Organization
SERC OC Standards Review
Group
Yes or No
No
Question 2 Comment
We are concerned regarding communications between Transmission Operators on
opposite ends of DC ties, which may or may not be in the same interconnection.
Similarly, COM-001, R1.2 limits the requirement of adjacent Reliability Coordinators
to the same interconnection and this should not be limited to the same
interconnection whether it is synchronous or non-synchronous.
The measures should also be verified to ensure that they align properly with the final
requirements.
Response: The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address asynchronous connections between
Transmission Operators, and has eliminated the phrase “within the same interconnection.” See change in COM-001-2, R3 and R4.
Requirement R1 addresses a reliability need for adjacent Reliability Coordinators synchronously connected within the same
Interconnection to have Interpersonal Communication capability; however, it does not preclude or limit the Reliability Coordinator
from establishing Interpersonal Communication capability with others. The RCSDT does not see where there is a need to
communicate with other Reliability Coordinator’s from one interconnection to another. No change made.
28
Organization
Northeast Power Coordinating
Council
Yes or No
Question 2 Comment
No
NERC uses the terms “adjacent” and “neighboring” in various standards. It is
generally believed that those terms have the same meanings, but there are those
who believe those terms, as used, are intended to have different meanings. To
ensure a consistent usage and understanding, the definition of the term adjacent
must be made known before its addition to the standard. Consideration should be
given to using only one term in all standards if adjacent and neighboring are intended
to mean the same thing. Both terms are used in NERC Standards, sometimes both in
the same standard. For example, EOP-001-2b uses “neighboring” in R5, and
“adjacent” in R3.3.
Response: The RCSDT thanks you for your comment and recognizes the confusion created by having “Adjacent” start the sentence.
This gave the appearance of a defined NERC glossary term. The RCSDT has made clarify changes to the requirements and measures
to eliminate this problem. See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
MRO NSRF
No
NERC has formally defined “Adjacent Balancing Authority” in the NERC Glossary of
Terms, but not “Adjacent Transmission Operator.” The MRO NSRF recommends that”
Adjacent Transmission Operator” be defined similar to the “Adjacent Balancing
Authority” definition in the NERC Glossary of Terms.
Response: The RCSDT thanks you for your comment and recognizes the confusion created by having “Adjacent” start the sentence.
This gave the appearance of a defined NERC glossary term. The RCSDT has made clarify changes to the requirements and measures
to eliminate this problem. See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
Kansas City Power & Light
No
Requirements R4.3 and R6.3 require TOP’s and BA’s to establish alternative means of
“interpersonal communications” with other TOP’s and BA’s without regard to the
reliability impact each TOP or BA has on the interconnection. Why would it be
necessary for a TOP with one 161kv transmission line or a BA with 100 MW of total
load, or one GOP with a 30MW unit to realize additional costs when the facilities they
operate have little reliability impact?
Rationale criteria should be included here to identify the TOP’s and BA’s where
29
Organization
Yes or No
Question 2 Comment
alternative means of “interpersonal communications” should be implemented.
Furthermore, these requirements do not recognize the condition when another party
refuses to install alternative communication equipment. TOP’s and BA’s have no
authority over other TOP’s and BA’s to establish alternative means of
communication. Requirements that are dependent on the actions of other parties
over which you have no control or authority are poor requirements.
In addition, most RC’s have established satellite telephone systems as back-up
communication with TOP’s and BA’s. Some RC’s may have to establish additional
communication systems with some BA’s as these requirements impose to avoid
Standards of Conduct issues.
Response: The RCSDT has not placed any limiting applicability on entities in being responsive to the FERC directive (P487, Order
693), “…ensure there is no reliability gap during normal and emergency operations. For example, during a blackstart when normal
communications may be disrupted, it is essential that the Transmission Operator, Balancing Authority and Reliability Coordinator
maintain communications with their Distribution Providers and Generator Operators.” The RCSDT does not prescribe the criteria for
alternative means of Interpersonal Communication capability, so each entity may determine its own needs to meet the requirement.
With regard to requiring other BAs or TOPs to install Alternative Interpersonal Communication capability as registered entities, other
BAs or TOPs have the same responsibility to comply with the requirement. Having a satellite backup is an acceptable form of
communication; however, the RCSDT does not understand the comment about the Standards of Conduct issues. No change made.
Southern Company
No
We are concerned regarding communications between Transmission Operators on
opposite ends of DC ties, which may or may not be in the same interconnection.
Similarly, COM-001, R1.2 limits the requirement of adjacent Reliability Coordinators
to the same interconnection and this should not be limited to the same
interconnection whether it is synchronous or non-synchronous.
The measures should also be verified to ensure that they align properly with the final
requirements.
Response: The RCSDT has made clarifying changes by adding Parts to R3 and R4 to address asynchronous connections between
30
Organization
Yes or No
Question 2 Comment
Transmission Operators and have eliminated the phrase “within the same interconnection.” See change in COM-001-2, R3 and R4.
Requirement R1 addresses a reliability need for adjacent Reliability Coordinators synchronously connected within the same
Interconnection to have Interpersonal Communication capability; however, it does not preclude or limit the Reliability Coordinator
from establishing Interpersonal Communication capability with others. The RCSDT does not see where there is a need to
communicate with other Reliability Coordinators from one Interconnection to another. No change made.
Xcel Energy
No
In COM-001-2, R4.3. Adjacent Transmission Operators synchronously connected
within the same Interconnection. This new requirement has a term that is not
defined Adjacent Transmission Operators.
Response: The RCSDT thanks you for your comment and recognizes the confusion created by having “Adjacent” start the sentence.
This gave the appearance of a defined NERC glossary term. The RCSDT has made clarifying changes to the requirements and
measures to eliminate this problem. See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
Independent Electricity
System Operator
No
(1) We agree with the addition of “Adjacent” entities in the quoted parts except the
qualifier “synchronously connected within the same Interconnection” need to be
removed from Parts 3.5 and 4.3 since TOPs do communicate with other TOPs even in
another Interconnection (e.g. between Quebec and all of its asynchronously
interconnected neighbors). Even in the case of ERCOT, TOPs on the two sides of a DC
tie do communicate with each other for daily operations.
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and has eliminated the
phrase “within the same interconnection.” See change in COM-001-2, R3 and R4.
(2) Measure M3 does not cover the added R3.5 condition (having Interpersonal
Communications capability with each adjacent TOP). M3 needs to be revised.
The RCSDT thanks you for catching this oversight. The corresponding TOP entity in
R3.5 has been added to the Measure M3.
Response: See response above.
31
Organization
Exelon
Yes or No
Question 2 Comment
No
May have an unintended effect on registrations as some GOPs use an intermediately
dispatch organization that perform actions on behalf of the generating units.
Response: Having an intermediary dispatching actions for generation units is okay; however, the responsible GOP should have
adequate agreements to perform these activities; for example, a Joint Registration Organization (Type 1) or Coordinated Functional
Registration (Formerly Type 2). No change made.
ISO New England
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and
therefore does not support the draft as written. We believe such "requirements" (i.e.
capabilities) should be verified through an entity certification process.
Additionally, results-based requirements should be the driver to have the capability
to achieve them; on other words, there is no other way to reliably dispatch than to
have communications facilities (electronic or voice).
Response: Although this is not a results-based standard, the RCSDT believes it is a significant improvement over the current COM001 standard. No change made.
Texas Reliability Entity
No
(1) Requirements R1, R2, R3 and R4 should apply to all adjacent Reliability
Coordinators and Transmission Operators, regardless of whether they are in the same
Interconnection.
The ERCOT Interconnection is asynchronously connected to adjacent
Interconnections, and it is imperative that Functional Entities within Texas RE’s
purview be able to exchange operating information with Transmission Operators and
Reliability Coordinators in those adjacent areas, even if they are in a different
Interconnection.
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and has eliminated the
phrase “within the same Interconnection.” See change in COM-001-2, R3 and R4.
(2) Requirement parts R5.5 and R6.3 refer to “Adjacent Balancing Authorities.”
32
Organization
Yes or No
Question 2 Comment
Measures M5 and M6 refer to “adjacent Balancing Authority” - note the small “a” on
adjacent. “Adjacent Balancing Authority” is a defined term in the NERC Glossary,
which has a more specific meaning than “adjacent Balancing Authority.” Which term
is intended in R5.5 and R6.3? If you don’t intend to use the defined term, perhaps
use a word like “contiguous” or “neighboring” rather than “adjacent.”
The RCSDT thanks you for your comment and recognizes the confusion created by
having “Adjacent” start the sentence. This gave the appearance of a defined NERC
glossary term. The RCSDT has made clarifying changes to the requirements and
measures to eliminate this problem. See changes to COM-001-2, R1.2, R2.2, R3.5,
R4.3, R5.5, and R6.3.
Response: See response above.
Hydro One Networks Inc.
No
(1) We agree with the addition of “Adjacent” entities in the quoted parts except the
qualifier “synchronously connected within the same Interconnection” need to be
removed from Parts 3.5 and 4.3 since TOPs do communicate with other TOPs even in
another Interconnection (e.g. between Quebec and all of its asynchronously
interconnected neighbors). Even in the case of ERCOT, TOPs on the two sides of a DC
tie do communicate with each other for daily operations.
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and has eliminated the
phrase “within the same Interconnection.” See change in COM-001-2, R3 and R4.
(2) Measure M3 does not cover the added R3.5 condition (having Interpersonal
Communications capability with each adjacent TOP). M3 needs to be revised.
The RCSDT thanks you for catching this oversight. The corresponding TOP entity in
R3.5 has been added to the Measure M3.
Response: See response above.
33
Organization
SPP Standards Review Group
Yes or No
Question 2 Comment
Yes
We concur with the addition of “Adjacent” but ask that the SDT give some
consideration to allowing an exemption in R6.3 for relatively small loads, less than 20
MW, that are pseudo tied into a Balancing Authority. Loss of these facilities would
not place a burden on the BES and should not require Alternative Interpersonal
Communications capabilities.
Response: The RCSDT has not placed any limiting applicability on entities in being responsive to the FERC directive (P487, Order
693), “…ensure there is no reliability gap during normal and emergency operations. For example, during a blackstart when normal
communications may be disrupted, it is essential that the Transmission Operator, Balancing Authority and Reliability Coordinator
maintain communications with their Distribution Providers and Generator Operators.” The RCSDT does not prescribe the criteria for
alternative means of Interpersonal Communication capability so each entity may determine its own needs to meet the requirement.
With regard to requiring other BAs or TOPs to install Alternative Interpersonal Communication capability as registered entities, other
BAs or TOPs have the same responsibility to comply with the requirement. Having a satellite backup is an acceptable form of
communication. No change made.
MISO Standards Collaborators
Yes
(1) We agree with the addition of “Adjacent” entities in the quoted parts. However,
there are some entities which may need the capability even though they are not
“synchronously connected within the same Interconnection.” This standard does not
require them to have the capability, but it does not preclude such capability. In these
cases, those entities should evaluate whether the need for the capability is a
reliability need or market coordination. If the entities were connected
synchronously, actions taken by an entity could have immediate effect upon other
entities. However, if not synchronously connected, changes in flows across the
asynchronous ties would have to follow the interchange scheduling process with
approval by all involved entities before changes could be enacted. Some TOPs do
communicate with other TOPs even in another Interconnection (e.g. between
Quebec and all of its asynchronously interconnected neighbors).
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and has eliminated the
34
Organization
Yes or No
Question 2 Comment
phrase “within the same Interconnection.” See change in COM-001-2, R3 and R4.
(2) Measure M3 does not cover the added R3.5 condition (having Interpersonal
Communications capability with each adjacent TOP). M3 needs to be revised.
The RCSDT thanks you for catching this oversight. The corresponding TOP entity in
R3.5 has been added to the Measure M3.
Response: See response above.
Entergy Services, Inc
Yes
Entergy agrees with the inclusion of the term “Adjacent” in these requirements to
limit the entities that the BA or TOP must have communications capability with to
those that they border.
Response: Thank you for your comment.
Duke Energy
Yes
However, we believe that the phrase “synchronously connected within the same
Interconnection” should be struck, because TOPs are controlling DC ties and should
be required to have communications with each other.
Response: The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address asynchronous connections between
Transmission Operators and has eliminated the phrase “within the same Interconnection.” See change in COM-001-2, R3 and R4.
ERCOT ISO
Yes
These changes will clarify intentions regarding the undefined term "adjacent.”
Response: The RCSDT thanks you for your comment and recognizes the confusion created by having “Adjacent” start the sentence.
This gave the appearance of a defined NERC glossary term. The RCSDT has made conforming measures to eliminate this problem.
See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
ReliabilityFirst
Yes
ReliabilityFirst agrees with adding the term adjacent but is unclear what the term
adjacent is referring to. Does is mean directly connected or is it more than one layer
out.
35
Organization
Yes or No
Question 2 Comment
Response: The RCSDT thanks you for your comment and recognizes the confusion created by having “Adjacent” start the sentence.
This gave the appearance of a defined NERC glossary term. The RCSDT has made conforming measures to eliminate this problem.
See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
Pacific Northwest Generating
Cooperative
Yes
City of Tacoma, Department
of Public Utilities, Light
Division, dba Tacoma Power
Yes
LG&E and KU Services
Company
Yes
Bonneville Power
Administration
Yes
Dominion
Yes
Western Electricity
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
FirstEnergy
Yes
Florida Municipal Power
Agency
Yes
Global Engineering and
Yes
36
Organization
Yes or No
Question 2 Comment
Energy Solutions
ACES Power Marketing
Standards Collaborators
Yes
Salt River Project
Yes
San Diego Gas & Electric
Yes
Liberty Electric Power LLC
Yes
NIPSCO
Yes
Oncor Electric Delivery
Company LLC
Yes
We Energies
Yes
City of Jacksonville Beach dba/
Beaches Energy Services
Yes
Luminant Energy Company
LLC
Yes
NextEra Energy, Inc.
Yes
Pepco Holdings Inc.
Yes
Manitoba Hydro
Yes
Niagara Mohawk (dba
Yes
37
Organization
Yes or No
Question 2 Comment
National Grid)
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
Georgia Transmission
Corporation
Yes
BGE
Yes
Nebraska Public Power District
Yes
Georgia System Operations
Yes
City of Vero Beach
Yes
NV Energy
Yes
Midwest Independent
Transmission System Operator
Yes
American Transmission
Company, LLC
Yes
Indiana Municipal Power
Agency
No comment.
38
3.
The RCSDT removed the phrase "to exchange Interconnection and operating information" in COM-001-2, Requirements R1
through R8 based on stakeholder comments. Do you agree with the revision? If not, please explain in the comment area
below.
Summary Consideration: Several commenters noted the phrase “to exchange Interconnection and operating information” should also
be removed from the Purpose statement. The RCSDT agrees and removed this phrase from the Purpose statement. Some concerns also
noted COM-001-2 should also add additional language to clarify the standard is not for the exchange of data. Since the standard focuses
on having communication capability, the additional clarity is not needed; therefore, the RCSDT made no change. Some commenters
noted items which have been addressed in the questions above.
Organization
Yes or No
Global Engineering and
Energy Solutions
No
Independent Electricity
System Operator
No
Question 3 Comment
In the last posting, we suggest removing the phrase “within the same
Interconnection” from R1 (now R2.2) since there are RCs between two
Interconnections that need to communication with each other for reliability
coordination (e.g. between Quebec and the RCs the Northeast such as IESO, NYISO,
NBSO and ISO-NE, and between the RCs in WECC with the RCs in the Eastern
Interconnection). Such coordination may include but not limited to curtailing
interchange transactions crossing Interconnection/RC boundary, as stipulated in IRO006. The SDT’s response to our comments citing that the phrase was added to
address the ERCOT situation leaves a reliability gap to the other situations. We again
urge the SDT to remove the phrase. If necessary, the ERCOT situation can be
addressed by a regional variance.
Response: The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address asynchronous connections between
Transmission Operators and has eliminated the phrase “within the same Interconnection.” See change in COM-001-2, R3 and R4.
39
Organization
Great River Energy
Yes or No
No
Question 3 Comment
"to exchange interconnection and operation information" was removed from the
requirements in COM-001-2 but remains in the purpose. For consistency, it needs to
be removed. It could read,
"To establish Interpersonal Communication capabilities for the exchange of
information necessary to maintain reliability."
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001. See revised Purpose statement.
Ingleside Cogeneration LP
No
In the background section of this ballot, the project team indicates that the removal
of the phrase is intended to signal that these requirements do NOT apply to the
exchange of data. Although Ingleside Cogeneration LP agrees that the phrase is not a
helpful description of the need for inter-entity communications - and should be
removed - we do not see how the remaining language achieves the project team’s
purpose.
It seems the confusion stems from the multitude of data communication types. Email
messages between operating entities may be a valid communications path under
COM-001-2, while telemetry/control is covered under other Standards. We believe
that a technical guideline may be an appropriate vehicle to distinguish what types of
communications are subject to these requirements, and which are not.
Response: The RCSDT has drafted performance requirements that are intended to be flexible enough to accommodate different
technologies and innovation by industry. It is not the intent of the drafting team to establish all the possible methods of
communicating. Drafting teams generally do not create guidelines. No change made.
ISO New England
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and
therefore does not support the draft as written. We believe such "requirements" (i.e.
capabilities) should be verified through an entity certification process.
Additionally, results-based requirements should be the driver to have the capability
to achieve them; on other words, there is no other way to reliably dispatch than to
40
Organization
Yes or No
Question 3 Comment
have communications facilities (electronic or voice).
Response: Although this is not a results-based standard, the RCSDT believes it is a significant improvement over the current COM001 standard. No change made.
Hydro One Networks Inc.
No
(1) In the last posting, there were suggestions of removing the phrase “within the
same Interconnection” from R1 (now R2.2) since there are RCs between two
Interconnections that need to communication with each other for reliability
coordination (e.g. between Quebec and the RCs the Northeast such as IESO, NYISO,
NBSO and ISO-NE, and between the RCs in WECC with the RCs in the Eastern
Interconnection). Such coordination may include but not limited to curtailing
interchange transactions crossing Interconnection/RC boundary, as stipulated in IRO006. The SDT’s response to our comments citing that the phrase was added to
address the ERCOT situation leaves a reliability gap to the other situations. We again
urge the SDT to remove the phrase. If necessary, the ERCOT situation can be
addressed by a regional variance.
Response: Requirement R1 addresses a reliability need for adjacent Reliability Coordinators synchronously connected within the
same interconnection to have Interpersonal Communication capability; however, it does not preclude or limit the Reliability
Coordinator from establishing Interpersonal Communication capability with others. The RCSDT does not see where there is a need to
communicate with other Reliability Coordinators from one Interconnection to another. No change made.
SERC OC Standards Review
Group
Yes
We suggest that this phrase should also be removed from the “Purpose” statement.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
MISO Standards Collaborators
Yes
We urge the SDT to remove the phrase. If necessary, regional situations can be
addressed by a regional variance.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
41
Organization
ACES Power Marketing
Standards Collaborators
Yes or No
Yes
Question 3 Comment
We thank the drafting team for making this change and for the clear communication
that the intent of this standard is not for data exchange in the response to
comments. However, we do believe one additional change is necessary to make the
intent absolutely clear.
The purpose of statement of COM-001-2 still includes the phrase “to exchange
Interconnection and operating information.” Since a standard must stand on its own,
we believe it is necessary to remove that phrase from the purpose statement to avoid
misinterpretations in the future. Auditors and enforcement personnel are not
required to understand the development history when enforcing the standard.
Furthermore, the purpose is really to enable communications between these
functional entities.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
Southern Company
Yes
We suggest that this phrase should also be removed from the “Purpose” statement.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
Entergy Services, Inc
Yes
Yes, the requirements of this standard pertain to having communications capability.
The specific content of that communication should not be the subject of the
standard.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
We Energies
Yes
Please add "does not include telemetered or derived data"
Response: The standard COM-001 is for Interpersonal Communication capability, which facilitates the communication (i.e., “… to
interact, consult, or exchange information.”) and not the exchange of data which is addressed in IRO-010. No change made.
Duke Energy
Yes
However, the definition of Interpersonal Communication should also be expanded to
clearly include the drafting team’s intent that the capability is NOT for the exchange
42
Organization
Yes or No
Question 3 Comment
of data.
The phrase “for the exchange of Interconnection and operating information" should
also be struck from the Purpose statement.
Response: The SDT agrees and has made a conforming change to the Purpose of COM-001: See revised Purpose statement.
The standard COM-001 is for Interpersonal Communication capability, which facilitates the communication (i.e., “… to interact,
consult, or exchange information.”) and not the exchange of data which is addressed in IRO-010. No change made.
Pacific Northwest Generating
Cooperative
Yes
MRO NSRF
Yes
City of Tacoma, Department
of Public Utilities, Light
Division, dba Tacoma Power
Yes
LG&E and KU Services
Company
Yes
Bonneville Power
Administration
Yes
SPP Standards Review Group
Yes
Dominion
Yes
Western Electricity
Coordinating Council
Yes
43
Organization
Yes or No
Southwest Power Pool
Regional Entity
Yes
FirstEnergy
Yes
Florida Municipal Power
Agency
Yes
Kansas City Power & Light
Yes
Salt River Project
Yes
San Diego Gas & Electric
Yes
Central Lincoln
Yes
Xcel Energy
Yes
Liberty Electric Power LLC
Yes
NIPSCO
Yes
Oncor Electric Delivery
Company LLC
Yes
Consolidated Edison Co. of
NY, Inc.
Yes
City of Jacksonville Beach dba/
Beaches Energy Services
Yes
Question 3 Comment
44
Organization
Yes or No
Luminant Energy Company
LLC
Yes
NextEra Energy, Inc.
Yes
Pepco Holdings Inc.
Yes
Exelon
Yes
Manitoba Hydro
Yes
Orange and Rockland Utilities,
Inc.
Yes
Niagara Mohawk (dba
National Grid)
Yes
American Electric Power
Yes
South Carolina Electric and
Gas
Yes
BGE
Yes
Nebraska Public Power District
Yes
ERCOT ISO
Yes
ReliabilityFirst
Yes
City of Vero Beach
Yes
Question 3 Comment
45
Organization
Yes or No
NV Energy
Yes
Midwest Independent
Transmission System Operator
Yes
Texas Reliability Entity
Yes
American Transmission
Company, LLC
Yes
Indiana Municipal Power
Agency
Question 3 Comment
No comment.
46
4.
A new requirement was added for clarity regarding what is required of Distribution Providers and the Generator Operators:
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of its Interpersonal Communication
capabilities shall consult with their Transmission Operator or Balancing Authority as applicable to determine a mutually
agreeable time to restore the Interpersonal Communication capability. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations] This requirement requires collaboration between entities to restore a failed communications capability. Do you
agree with the new requirement? If not, please explain in the comment area below.
Summary Consideration: Most of the comments pertain to compliance and clarity concerns; for example, the use of “any of” in the
requirement. The phrase “any of” has been eliminated to resolve this concern. Additionally, the RCSDT made a clarifying change to
indicate the DP and GOP only need to consult with the entity affected by the failure. Other comments recommended using the terms,
such as, “primary,” “secondary,” “device,” “means,” and “medium” with regard to the proposed definitions. The RCSDT emphasizes the
requirements are for “capability” and adding such proposed terms is not needed to achieve the necessary clarity. Some commenters
raised concerns about being able to reach “mutually agreeable time” for restoration. The RCSDT addressed these concerns by revising
the phrase to “mutually agreeable action,” which allows the applicable entities to reach consensus on the effort needed to restore
communications. This change also provides flexibility to the entities in addressing the steps to restore communications rather than
focusing on the time for restoration. The requirement does not limit the sources of information. Allowing the DP and GOP to reach a
mutually agreeable action, eliminates the need for Alternative Interpersonal Communication capability considering the limited impact a
failure might have on DPs and GOPs overall. From a compliance standpoint, the DP or GOP that is working to restore its Interpersonal
Communication capability is not out of compliance as far as the entity is meeting the requirement for taking action to restore its
capability. Other similar concerns pertained to having 24/7 dispatch, which is an operational function. The requirements are
constructed around having communication capability. The RCSDT understands there may be entities that have certain operations where
there is not 24/7 staffing and these cases should be addressed by their operation with other entities through agreements, procedures or
other means as needed for reliable operations. Other minor corrections and formatting issues noted were reviewed and corrected
accordingly.
Some commenters were concerned that large entities would not be capable of meeting the 60-minute notification upon the loss of their
Interpersonal Communication capability. The RCSDT notes this pertains to the BA, RC, and TOP, which are required to have an
Alternative Interpersonal Communication capability, and should have the ability to accomplish the required notification. Also, the loss
of Interpersonal Communication capability may not always impact the entire capability. This time frame does not apply to the DP and
GOP since the Alternative Interpersonal Communication capability is not required for these functional entities. Other minor formatting
and corrections to references were made, such as, focusing on using the singular form of words rather than the plural to avoid
confusion.
47
Organization
Yes or No
Question 4 Comment
Alliant Energy Corp. Services,
Inc.
Negative
COM-001-2: Alliant Energy is opposed to the use of the word "any" as it is too broad.
It should be revised to the primary Interpersonal Communication capabilities with the
Transmission Operator or Balancing Authority.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The RCSDT emphasizes the requirement refers only to Interpersonal Communication capabilities. Adding the phrase “to the primary”
is not needed. Please refer to the definitions of Interpersonal Communication and Alternative Interpersonal Communication for
clarification. No change made.
Wisconsin Electric Power
Marketing; Wisconsin Electric
Power Co.
Negative
R11 is not clear on the purpose of the statement “determine a mutually agreeable
time for restoration” this could be driven by forces outside the control any of the
entities. I think, “provide estimated restoration and actual restoration time and
determine mutually agreeable alternative during outage” would be better.
Response: The RCSDT has made clarifying changes to R11 to use mutually agreeable action rather than time for restoration.
Lakeland Electric
Negative
Use of the term "any" in the new R11 and immediate non-compliance if there is a
failure in a communication system.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
SERC OC Standards Review
Group
No
We suggest Requirement 11 should be deleted as the generic nature of the term
“...any of its Interpersonal Communications capabilities...” could be interpreted to
include communications capabilities used for internal DP/GO purposes. Such DP/GO
internal communications capability would not be critical to BES reliability. Also, no
BES reliability benefit is realized by the parties simply agreeing to a time for the
48
Organization
Yes or No
Question 4 Comment
restoration of the failed Interpersonal Communication capability.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Pacific Northwest Generating
Cooperative
No
As per COM-001-2, R7, “Each Distribution Provider shall have Interpersonal
Communications capability with the following entities...” R11 states that the DP or
GOP that experiences a failure of its Interpersonal Communications ability shall
consult with TOPs and BAs and agree on how to restore Interpersonal
Communications. We believe better language might be, “Restore Interpersonal
Communications with your TOP/BA as soon as operationally feasible."
Response: The RCSDT notes that R11 does not limit the sources of information used by the DP or GOP in establishing a mutually
agreeable restoration time for its Interpersonal Communication capability with its TOP or BA. That is precisely why R11 is written in
this manner. This allows flexibility on the part of the TOP and BA in determining when the Interpersonal Communication capability
must be restored. In situations where there is little or no impact to the reliability of the BES, some flexibility could be allowed
without requiring the acquisition of Alternative Interpersonal Communication capability. The RCSDT has made clarifying changes to
R11 to use mutually agreeable action rather than time for restoration.
MRO NSRF
No
Please note that the use of the word “any” as in “Each Distribution Provider and
Generator Operator that experiences a failure of any of its Interpersonal
Communication capabilities...” will be viewed as meaning every Interpersonal
Communication medium that an Entity has or uses. The NSRF recommends that the
word “any” be removed from this Requirement.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The NSRF recommends that R11 be revised to read:
49
Organization
Yes or No
Question 4 Comment
“Each Distribution Provider and Generator Operator that experiences a failure of any
of its primary (or defined) Interpersonal Communication capabilities with its
Transmission Operator or Balancing Authority...”
In that way it focuses it down to the communications issues with the TOP or BA. In
lieu of “primary” the SDT could state “defined” as long as it is not meant to be “any.”
The RCSDT emphasizes the requirement refers only to Interpersonal Communication
capabilities. Adding the phrase “to the primary” is not needed. Please refer to the
definitions of Interpersonal Communication and Alternative Interpersonal
Communication for clarification. No change made.
The latter part of R11 states; “...shall consult with their Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable time to restore
the Interpersonal Communication capability.” This ambiguous statement does not
support reliability. Consulting with a TOP or BA does not solve the problem of the lack
of Interpersonal Communication capabilities. The NSRF recommends this be
rewritten as:
“...shall consult with inform their Transmission Operator or Balancing Authority as
applicable as to the status of the Interpersonal Communication capability.”
So the new R11 would read:
“Each Distribution Provider and Generator Operator that experiences a failure of its
primary (or designated) Interpersonal Communication with their Transmission
Operator or Balancing Authority shall inform them, as applicable, as to the status of
the Interpersonal Communication capability.”
The RCSDT has made clarifying changes to R11 to use mutually agreeable action
rather than time for restoration.
Response: See response above.
50
Organization
LG&E and KU Services
Company
Yes or No
No
Question 4 Comment
Regarding R11, as written it is unclear when the DP and GOP are required to consult
with their TOP or BA. “[A] failure of any of its Interpersonal Communication
capabilities” could be construed to mean any internal phone line of either the DP or
GOP failing. Internal phone lines do not affect either the DP’s or GOP’s ability to
communicate with the TOP or BA.
If the DP or GOP loses its Interpersonal Communication with an entity it is required to
have the capability with, then the entity must consult with that entity to determine a
mutually agreeable action (was time) to restore. A failure of the entity’s capability
means the entity is no longer able to communicate with its BA or TOP, then it must
consult with the affected entity.
It is also unclear whether a failure of an interpersonal communication capability
would require consultation if there were multiple other interpersonal communication
capabilities that were still fully functional.
Furthermore, what exactly is required in “consultation” and who would be
responsible if the “consulting” entities did not come to a “mutually agreeable time”
are questions that are left unanswered.
LG&E and KU Services Company suggest the following language:
R11. Each Distribution Provider and Generator Operator that experiences a failure of
more than one of its Means for Interpersonal Communications or failure of its
Alternative Means for Interpersonal Communication with their Transmission Operator
or Balancing Authority shall notify their Transmission Operator or Balancing Authority
regarding the time to restore the impacted Means for Interpersonal Communication
or Alternative Means for Interpersonal Communication.
The RCSDT thanks you for your comment; however, great lengths were taken in
communicating mediums regarding IC and AIC and finds that adding “Means” to the
proposed terms being defined diminishes clarity of the definition. No change made.
51
Organization
Yes or No
Question 4 Comment
Response: See response above.
PPL Electric Utilities and PPL
Supply NERC Registered
Organizations
No
PPL has concerns with the use of the word “any” in this requirement. PPL
recommends striking the words “any of” and instead using “its primary” as follows:
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Each Distribution Provider and Generator Operator that experiences a failure of its
primary Interpersonal Communication capabilities with its Transmission Operator or
Balancing Authority...” In the current version, it is unclear when the DP and GOP are
required to consult with their TOP or BA.
The RCSDT notes that the requirement refers only to Interpersonal Communication
capabilities. Adding the phrase “to the primary” is not needed. Please refer to the
definitions of Interpersonal Communication and Alternative Interpersonal
Communication for clarification. No change made.
“[A] failure of any of its Interpersonal Communication capabilities” could be
construed to mean an internal phone line of either the DP or GOP failing. Internal
phone lines do not affect either the DP’s or the GOP’s ability to communicate with
the TOP or BA.
It is also unclear whether a failure of an interpersonal communication capability
would require consultation if there were multiple other interpersonal communication
capabilities that were still fully functional.
The RCSDT believes an entity meets the intent of the requirement when it has
Interpersonal Communication capability, whether through a single capability or
multiple capabilities. A single failure of an entity’s capability would not require any
consultation if the entity continues to have the capability. The drafting team has
removed the phrase “any of” as a clarifying change. Additionally, the RCSDT made a
52
Organization
Yes or No
Question 4 Comment
clarifying change to indicate the DP and GOP only need to consult with the entity
affected by the failure.
Response: See response above.
SPP Standards Review Group
No
We would suggest deleting the phrase ‘any of’ in the Requirement. It would then
read:
‘Each DP and GOP that experiences a failure of its Interpersonal Communication...’
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Also, how does the DP or GOP consult with its TOP or BA when it loses its
Interpersonal Communications capability?
To do this wouldn’t they have to have an Alternative Interpersonal Communications
capability?
The RCSDT believes each entity must determine how to accomplish this (R11) and
having another requirement or change would be overly prescriptive. No change
made.
Response: See response above.
Western Electricity
Coordinating Council
No
We have two concerns with R11 as worded.
First, the term "as applicable" is undefined. Who decides what is applicable. We
suggest that words clarifying which entity, TOP or BA, the DP and GO experiencing a
failure of any of its Interpersonal Communication capabilities must consult with.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “as applicable” in COM-001, R11.
53
Organization
Yes or No
Question 4 Comment
Second, the inclusion of the "mutually agreeable" time to restore the Interpersonal
Communication capability is problematic. Although unlikely, two entities could
"mutually agree" to an exceptionally long time frame for restoration (two years) and
that unreasonable timeframe would meet the requirement as long as they both
agreed. Suggest some finite time limit be included.
The RCSDT has made clarifying changes to R11 to reference “mutually agreeable
action,” rather than “time” for restoration. The use of “action” eliminates the need
for a timeframe. New information regarding the restoration parameters may change
under a mutually agreeable action.
Response: See response above.
FirstEnergy
No
Although we agree with the intent of the requirement, we are concerned with the
use of “any of its Interpersonal Communication.” The word “any” is very inclusive and
the team should consider narrowing it down to those capabilities that may adversely
impact reliability.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Florida Municipal Power
Agency
No
By use of the term “any” in the phrase “a failure of any of its Interpersonal
Communication” the standard will actually create a disincentive for redundant
communications with DPs and GOPs due to compliance risk.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
To truly further the goals of reliability, the requirement should align with R3.3 and
R3.4 which requires a primary Interpersonal Communications capability and R4 which
54
Organization
Yes or No
Question 4 Comment
does not require DPs or GOPs to have Alternative Interpersonal Communications
capability.
A possible solution is through use of the terms “Primary” for R3 and “Alternate” for
R4 and then make R11 applicable to Primary only.
The term “Interpersonal Communication” is a defined term in this standard. As such,
it has a different meaning than “Alternative Interpersonal Communication,” thus
there should be no confusing of the two. In addition, the word “primary” purposely
does not exist in the requirements since the RCSDT did not intend to create a
requirement for redundancy. Redundancy continues to be a good practice, but it is
not required by this standard except that some entities must have both an
Interpersonal Communication capability and a designated Alternative Interpersonal
Communication capability. No change made.
Response: See response above.
Global Engineering and
Energy Solutions
No
We are pleased that the drafting team addition provides addition description on the
process for communicating failed Interpersonal Communication. However additional
clarity should be made regarding if there is an expectation that the Interpersonal
Communication should be available 24x7. There are many Distribution Providers that
do not have a 24x7 managed facility that can view and respond to a communication
received in real time on the Interpersonal Communication device. These DPs rely on
on-call personnel for off-hour emergencies such as an outage on the distribution
system. The on-call personnel may use a cell phone, pager, etc. In other cases, the
Transmission Operator or Balancing Authority may communicate by email and
response is provided during business hours. In these cases, if the Transmission
Operator or Balancing Authority had a system emergency they have the ability to
isolate the distribution system from the grid and therefore do not require a 24x7
manned distribution.
If the intent of the Standard is for ensuring real-time communication than the
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Organization
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Question 4 Comment
applicability should be limited to those Distribution Providers who have been
required by the Transmission Operator or Balancing Authority to have a manned 24x7
manned facility. Many of the DPs referred to here have not received a real-time call
in the last 20 years. Requiring them to staff 24x7 for a condition likely not to occur is
cost prohibited and does not improve reliability.
Response: The RCSDT thanks you for your comment. There is no requirement for 24/7 support. The requirement is to have
communications capability. The type of system (e.g., On-Call) is not prescribed in the standard, and the standard is designed not to
impose needless communications requirements. The Purpose of COM-001-2 is, “To establish Interpersonal Communication
capabilities necessary to maintain reliability. No change made.
ACES Power Marketing
Standards Collaborators
No
Requirement R11 does not fully address the issue of what is required by Distribution
Providers and Generator Operators and introduces new issues.
The RCSDT notes that R11 grants the DP and GOP flexibility in determining, in
conjunction with its TOP or BA, when its Interpersonal Communication capability
requires restoration. This would provide allowances for those entities, which have
little or no impact on the reliability of the BES. No change made.
First, while the standard is intended to clarify that the Distribution Provider and
Generator Operator do not need backup communications capability, it simply does
not. Distribution Providers and Generator Operators are required to have an
Interpersonal Communications capability in Requirement R7 and R8 respectively.
Unfortunately, the effectiveness of these requirements persists even when the
Distribution Provider or Generator Operator experiences a failure of its Interpersonal
Communications capability. When Requirement R11 applies, the Distribution
Provider or Generator Operator will still be obligated to comply with Requirements
R7 and R8 respectively and will, in fact, be in violation of these requirements because
the Distribution Provider or Generator Operator no longer has the capability.
The RCSDT thanks you for your comment. Requirements R7 and R8 have been
revised to account for the failure of Interpersonal Communication capability. The
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Organization
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Question 4 Comment
intent of R11 is to require the responsible entity to take action upon the failure of its
Interpersonal Communication.
Second, capability is used inconsistently between Requirement R7 and R11, which
leads to confusion. In Requirement R7, it is singular while in Requirement R11 is
plural. It needs to be clear that only the failure of the capability identified in R7 and
R8 needs to be reported by the Distribution Provider and Generator Operator
respectively.
The RCSDT thanks you for your observation and has modified COM-001-2 R11 to be
singular and to more clearly address the entities being consulted with upon a failure.
Third, if the requirements focused on communications devices rather than
capabilities, they would come closer to communicating the intent. Requirement R11
would better complement Requirement R7 and R8 if the focus was on having a
communication medium or device.
The RCSDT believes that prescribing a device or medium would limit an entity. In
regards to a device not functioning properly is contrary to R10, notification of
Interpersonal Communication capability failure. Please refer to the definition of
Interpersonal Communication and Alternative Interpersonal Communication. No
change made.
A Generator Operator with an installed communications device or medium still has
that device or medium even when it is not functioning properly and could still meet
Requirements R7 and R8. However, they don’t have the Interpersonal
Communications capability if the device is not functioning properly.
The RCSDT thanks you for your comment. Requirements R7 and R8 have been
revised to account for the failure of Interpersonal Communication capability. The
intent of R11 is to require the responsible entity to take action upon the failure of its
Interpersonal Communication.
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Organization
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Question 4 Comment
No
How does a DP or GOP experiencing a failure of its “interpersonal communications”
consult with its TOP or BA to determine a mutually agreeable time for restoration of
“interpersonal communications”? There are no requirements that require alternative
“interpersonal communications” for the DP and GOP. This requirement cannot be
fulfilled and should be removed.
Response: See response above.
Kansas City Power & Light
Response: The RCSDT notes that R11 does not limit the sources of information used by the DP or GOP in establishing a mutually
agreeable restoration time for its Interpersonal Communication capability with its TOP or BA; that is precisely why R11 is written in
this manner. This allows flexibility on the part of the TOP and BA in determining when the Interpersonal Communication capability
must be restored. In situations where there is little or no impact to the reliability of the BES, some flexibility could be allowed
without requiring the acquisition of Alternative Interpersonal Communication capability. The RCSDT has made clarifying changes to
R11 to use mutually agreeable action, rather than time for restoration.
Southern Company
No
We suggest the following changes:
1. Requirement 10 should include Distribution Providers and Generator Operators,
The RCSDT stresses that R11 grants the DP and GOP flexibility in determining, in
conjunction with its TOP or BA, when its Interpersonal Communication capability
must be restored. This would provide allowances for those entities, which have little
or no impact on the reliability of the BES, while not requiring them to obtain
Alternative Interpersonal Communication capabilities. Making the proposed changes
would eliminate this flexibility. Removing R11 takes away the RCSDT’s effort to
include those provisions in the standard. No change made.
2. Entities to be notified should be “as identified in requirements R1 through R8”,
The RCSDT thanks you for pointing this out. The RCSDT has modified the language of
R10 to refer to R1, R3, and R5, rather than “R1 through R6” since the responsible
entities are limited to the RC, the TOP, and the BA in these requirements.
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Organization
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Question 4 Comment
3. Requirement 11 should be deleted, and,
The RCSDT thanks you for your comment. COM-001-2 R11 requires the entity to
consult with its BA or TOP when it experiences a failure of its Interpersonal
Communication capability. The BA or TOP need to know communication is
compromised between the DP or GOP.
4. Measures (M10) and VSLs should be adjusted accordingly.
The RCSDT did not elect to include the DP and GOP in R10; therefore, Measure, M10
and the corresponding VSLs were not adjusted. No change made.
Response: See response above.
Central Lincoln
No
The new requirement presents us with a paradoxical situation. The communication
has failed, so we must consult; yet consultation requires communication. We note
that the SDT used the word “any”, implying that multiple communication paths are
required. The reality of the situation at Central Lincoln, due to our remote location, is
that a single back hoe incident at the right location can take out all of our of our
communication capability (including the terrestrial portion of the cellular networks)
with our BA/TO; making this requirement impossible to meet for this circumstance
using our present capabilities.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Furthermore, R11 addresses the direction given in Order 693 that DP and GOP
entities do not necessarily need to have Alternative Interpersonal Communication
capability. The requirement allows flexibility in “consult with” by not naming the
method. If all communications are out, then the DP or GOP may have to meet the
requirement by an in-person consultation.
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Organization
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Question 4 Comment
We also note that no time limit was indicated. Most interruptions are brief, and fixed
before consultation could reasonably take place. CEAs will be finding entities noncompliant for quickly fixing problems at their end without first consulting to ensure
the restoration time was agreeable. To avoid non-compliance, entities will be forced
delay repairs while they investigate alternative communication paths for consultation
purposes. We fail to see how such an outcome improves reliability.
The DP and GOP are only required to have Interpersonal Communication capability.
If the DP or GOP restores its Interpersonal Communication capability before it could
reasonably contact the affected entity by another method, there is no failure to
comply. The DP or GOP could then consult with the affected entity to determine a
mutually agreeable action. In this case, the RCSDT believes the "action" would then
be the entities acknowledging the failure and the repair; therefore, no mutually
agreeable action is needed. The RCSDT recognizes there is no way to account for all
the various circumstances in a failure. To comply, the DP and GOP are still required
to consult the entity which the failure affected regardless of whether the
Interpersonal Communication capability was restored or is still failed. No change
made.
The new requirement is one sided, requiring the DP and GOP to consult with no
corresponding requirement for the TO or BA to have personnel available for such a
consultation. Consultation failure or failure to mutually agree due to actions or
inactions on the part of the TO or BA should not result in an enforcement action
against the DP or GOP, yet that is how the requirement is written.
The RCSDT notes that once the failure has been detected, the responsible entity must
make the consultation with the BA or TOP; that relieves the compliance burden.
While the RCSDT understands your concern about single points of failure, the
question becomes should this relieve the DP or GOP of the requirement for having
Interpersonal Communication capabilities. No change made.
The new requirement fails to add any “clarity” to the other requirements, and we
don’t see that the stakeholders thought there was a problem with DP/GOP obligation
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Organization
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Question 4 Comment
clarity. Instead, it adds new obligations with no justification for how they enhance
reliability. We suggest removing the requirement.
Based on the RCSDT’s understanding of the comments received on the previous
posting, the industry desired additional clarity on specifically what communication
capabilities the DP and GOP were required to have. There was confusion that the
standard did not specifically say that the DP and GOP were required to have
Alternative Interpersonal Communication capabilities. R11 clarifies that a DP and
GOP are not required to have Alternative Interpersonal Communication capability if
the DP or GOP consult with their TOP or BA, whichever is applicable in the given
situation, and they mutually agree that the restoration action does not adversely
impact the reliability of the BES. No change made.
Response: See response above.
Entergy Services, Inc
No
The DP or GOP should have to notify the TOP and BA of its communications failure,
similar to the requirement in R10 for TOP and BA. The DP or GOP should restore the
communications capability as soon as possible. Entergy does not agree that the TOP
or BA should have to negotiate the restoration time with the DP or GOP. This is an
unreasonable burden on the BA and TOP.
Response: The RCSDT notes that R11 does not exempt the DP or GOP from notifying its TOP or BA when they experience a
communication failure. There is nothing in R11 that says a DP or GOP does not have to restore its communications capability. What
is in R11 is flexibility. The RCSDT has gone to great lengths to provide some flexibility for those DPs and GOPs with little or no impact
on the reliability of the BES. FERC directed NERC to provide for this consideration. While one could consider this a negotiation, the
notification is required so some sort of communication must be made. All that is being asked of the BA and TOP is to give some
consideration for the entities involved and the overall situation. The SDT modified the requirement so mutual agreement must be
reached on an “action” for restoration rather than a “time” for restoration.
Liberty Electric Power LLC
No
The phrase "mutually agreeable time" needs to be replaced in order to make this
standard acceptable. This phrasing creates a potential violation if equipment
functionality cannot be restored in the time frame preferred by another entity, even
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Organization
Yes or No
Question 4 Comment
if the time of repair is beyond the control of the RE. This phrase should be replaced
with "inform their TO or BA as applicable of the failure, and provide estimates as to
the time the Interpersonal Communication capabilities will be restored.”
Response: The RCSDT has gone to great lengths to provide some flexibility for those DPs and GOPs with little or no impact on the
reliability of the BES. FERC directed NERC to provide for this consideration. Therefore, we use the language as proposed in R11.
Mutually agreeable implies that both parties are willing to accept the outcome. It doesn’t mean that a DP or GOP must comply with
the wishes of its TOP or BA because as you state that could be beyond the control of the DP or GOP. However, what transpires in the
consultation is a realization of what the situation is, what the impacts to reliability are and a determination of what is amicable to
both parties. The RCSDT has made clarifying changes to R11 to use mutually agreeable action rather than time for restoration.
We Energies
No
R11 Implies that R8 and R9 are independent and redundant to R5.3, R5.4 and R3.3
and R3.4.
R11 is not clear on the purpose of the statement “determine a mutually agreeable
time for restoration” this could be driven by forces outside the control any of the
entities. I think” provide estimated restoration and actual restoration time and
determine mutually agreeable alternative during outage” would be better.
Update M9 accordingly.
Response: The RCSDT has made clarifying changes to R11 to use mutually agreeable action, rather than time for restoration.
Indiana Municipal Power
Agency
No
IMPA does not believe that this requirement is necessary in order to ensure
communication lines are restored by Distribution Providers and Generator Operators.
If this requirement is kept, IMPA does not think the use of the words “a failure of any
of its Interpersonal Communication capabilities” is acceptable.
The RCSDT notes the intent of this requirement is not to ensure that DP and GOP
communication lines are restored. The intent of this requirement is to provide some
flexibility for the DP or GOP that does not have an impact on the reliability of the BES.
Depending on the impact of the given entity, the TOP or BA can be flexible in
specifying when the Interpersonal Communication capability must be restored,
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Organization
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Question 4 Comment
rather than requiring the availability and use of an Alternative Interpersonal
Communication capability. No change made.
The wording is too inclusive and should apply to only primary Interpersonal
Communication capabilities. IMPA is also concerned about how entities are
supposed to know when the telephone companies may have equipment repaired in
order to determine a mutually agreeable time to restore Interpersonal
Communication capability. The entity may have no control over the restoration and
hence would not be able to set a time other than whenever the capabilities are
restored by for instance the telephone company.
The RCSDT deliberately avoided the use of primary and secondary mediums and
elected to use communications capabilities. As such, R11 applies to Interpersonal
Communication capabilities of the DP and GOP. The RCSDT has gone to great lengths
to provide some flexibility for those DPs and GOPs with little or no impact on the
reliability of the BES. FERC directed NERC to provide for this consideration.
Therefore, we use the language as proposed in R11. No change made.
It does not mean that a DP or GOP must comply with the wishes of its TOP or BA
because as you state that could be beyond the control of the DP or GOP. However,
what transpires in the consultation is a realization of the situation, what the impacts
to reliability are and a determination of what is amicable to both parties. No change
made. The RCSDT has made clarifying changes to R11 to use mutually agreeable
action rather than time for restoration.
In addition, entities will have to keep evidence to show that a “mutually” agreeable
time was reached by two or more entities. The most workable solution would be to
require notification if primary Interpersonal Communication is lost and a follow-up
notification when that capability is restored.
The RCSDT notes that R11 does not limit the sources of information used by the DP or
GOP in establishing a mutually agreeable restoration action for its Interpersonal
Communication capability with its TOP or BA; that is precisely why R11 is written in
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Organization
Yes or No
Question 4 Comment
this manner. This allows flexibility on the part of the TOP and BA in determining
when the Interpersonal Communication capability must be restored. In situations
where there is little or no impact to the reliability of the BES, some flexibility could be
allowed without requiring the acquisition of Alternative Interpersonal
Communication capability. No change made.
Response: See response above.
NextEra Energy, Inc.
No
NextEra Energy, Inc. (NextEra), which includes Florida Power & Light Company,
believes that Requirement 11 of COM-001-2, as drafted, is too vague to be adopted
as a mandatory Reliability Standard.
For example, it is unclear what is meant by “shall consult.” The North American
Electric Reliability Corporation’s (NERC) Rules of Procedure state that a foundation of
any Reliability Standard is that: “. . . [the] reliability standard shall be stated using
clear and unambiguous language. Responsible entities, using reasonable judgment
and in keeping with good utility practices, are able to arrive at a consistent
interpretation of the required performance.” The term “shall consult” is not a term
generally understood or used in the electric utility industry, and, therefore, does not
enable a consistent interpretation of the performance required. Accordingly, NextEra
requests that Requirement 11 either:
(i) be deleted; or
(ii) be redrafted to read more like Requirement 10.
Response: The RCSDT believes the term, “consult,” is well understood. Basically, entities must have a conversation. No change
made.
Manitoba Hydro
No
COM-001-2 R11 does not specify a timeline in which entities have to come up with a
‘mutually agreeable’ time to restore Interpersonal Communication capability.
Manitoba Hydro believes this omission creates a reliability gap and suggests that
wording be revised as follows:’... shall consult with their Transmission Operator or
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Organization
Yes or No
Question 4 Comment
Balancing Authority as applicable and determine a mutually agreeable time to restore
the Interpersonal Communication capability within 24 hours of experiencing the
failure.’
Response: The RCSDT has made clarifying changes to R11 to use mutually agreeable action rather than time for restoration.
The RCSDT believes R11 grants the DP and GOP flexibility in determining, in conjunction with its TOP or BA, when its Interpersonal
Communication capability must be restored. This would provide allowances for those entities, which have little or no impact on the
reliability of the BES while not requiring them to obtain Alternative Interpersonal Communication capabilities. No change made.
Great River Energy
No
Capability is not used consistently in R7 and R11. It changes from singular to plural.
Response: The RCSDT thanks you for your observation. Generally, the singular implies the plural or vice-versa. The RCSDT has
corrected R10 and R11 to be consistent with the singular application.
American Electric Power
No
Regarding COM-001-02 R10 and R11, some of the entity pairs (for example, BA to a
GO) are not required to have alternative inter-personnel communication. How can
the notification occur with 60 minutes for example, when primary communication is
not available for a role that doesn’t require an alternate means of communication? In
addition, requiring notification within 60 minutes in Requirement 10 would not be
feasible for larger entities that might have hundreds of contacts to make.
Response: The RCSDT thanks you for your comment. The notification within 60 minutes found in R10 pertains to the BA, RC and
TOP; therefore, these entities are required to have designated Alternative Interpersonal Communication capability with other
entities and more specifically other BA, TOP and RC entities. It is understood by virtue of R11 that the DP and GOP may not have
Alternative Interpersonal Communication capability and may not be notified within 60 minutes. No change made.
Georgia Transmission
Corporation
No
The intent of this requirement is not yet clear. Technically, the air we breathe, as
well as other mediums like “any” cell phone, fax lines, and/or email accounts would
qualify under this proposed definition of Interpersonal Communication. The burden
for compliance evidence to demonstrate failure of “any of its Interpersonal
Communication capability” would seem unobtainable and could prove to be a daily
65
Organization
Yes or No
Question 4 Comment
occurrence (dropped phone calls, etc.). The following is suggested to utilize the
singular form of capability rather than plural form of capabilities:
R11. Each Distribution Provider and Generator Operator that experiences a failure of
its Interpersonal Communication capability shall consult with their Transmission
Operator or Balancing Authority as applicable to determine a mutually agreeable
time to restore the Interpersonal Communication capability.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Nebraska Public Power District
No
We would suggest deleting the phrase ‘any of’ in the Requirement. It would then
read:
‘Each DP and GOP that experiences a failure of its Interpersonal Communication...’
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Also, how does the DP or GOP consult with its TOP or BA when it loses its
Interpersonal Communications capability?
To do this wouldn’t they have to have an Alternative Interpersonal Communications
capability?
The RCSDT notes that R11 does not limit the sources of information used by the DP or
GOP in establishing mutually agreeable action for restoration for its Interpersonal
Communication capability with its TOP or BA; that is precisely why R11 is written in
this manner. This allows flexibility on the part of the TOP and BA in determining
when the Interpersonal Communication capability must be restored. In situations
where there is little or no impact to the reliability of the BES, some flexibility could be
66
Organization
Yes or No
Question 4 Comment
allowed without requiring the acquisition of Alternative Interpersonal
Communication capability. No change made.
Response: See response above.
Georgia System Operations
No
The intent of this requirement is not yet clear. Technically, the air we breathe, as
well as other mediums like “any” cell phone, fax lines, and/or email accounts would
qualify under this proposed definition of Interpersonal Communication. The burden
for compliance evidence to demonstrate failure of “any of its Interpersonal
Communication capability” would seem unobtainable and could prove to be a daily
occurrence (dropped phone calls, etc.). The following is suggested:
R11. Each Distribution Provider and Generator Operator that experiences a failure of
any of its Interpersonal Communication capability shall consult with their
Transmission Operator or Balancing Authority as applicable to determine a mutually
agreeable time to restore the Interpersonal Communication capability.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Ingleside Cogeneration LP
No
Most of Ingleside Cogeneration’s communications capabilities rely on carriers who
will immediately deploy technicians to repair land-based or wireless systems when
they break. Although we may contact the carrier to inform them that the systems are
not available – or to determine their progress – we do not want them waiting for our
go-ahead before proceeding. If the intent of this requirement is to validate the
operation of the repaired connection, or to establish interim means of
communications with other operating entities, then Ingleside Cogeneration believes a
re-write is in order. There is no reliability purpose being served otherwise that we
can tell.
Response: The RCSDT believes there is nothing in R11 that says repairs by communication technicians should wait on anyone for a
67
Organization
Yes or No
Question 4 Comment
go-ahead. The RCSDT sees it working this way: When a communication link goes down, a communication technician is dispatched as
soon as the failure is noted and according to the agreements regarding repair between the provider and the user. When the user
contacts the provider, an estimate of the anticipated repair time should be provided. One would expect this type of arrangement in
service agreements. The user, DP or GOP, then takes that time to the consultation with the TOP or BA. Based on this anticipated
restoration time and the impact the DP or GOP has on the reliability of the BES, a mutually agreed to restoration action is
established. No change made.
Duke Energy
No
The phrase “consult with... to determine a mutually agreeable time” makes this
requirement too open-ended to be auditable and enforceable.
The RCSDT has made clarifying changes to R11 to use mutually agreeable action
rather than time for restoration.
We question why R11 does not establish a timeframe for notification similar to R10,
which requires the RC, TOP or BA to make notification within 60 minutes of failure
detection.
The RCSDT thanks you for your comment. The notification within 60 minutes found
in R10 pertains to the BA, RC and TOP; therefore, these entities are required to have
designated Alternative Interpersonal Communication capability with other entities
and more specifically other BA, TOP and RC entities. It is understood by virtue of R11
that the DP and GOP would not have Alternative Interpersonal Communication
capability and would not be notified within 60 minutes. No change made.
We also question why DPs and GOPs are not required to have Alternative
Interpersonal Communications capability in order to be able to make such
notifications.
The RCSDT believes that R11 grants the DP and GOP flexibility in determining, in
conjunction with its TOP or BA, when its Interpersonal Communication capability
must be restored. This would provide allowances for those entities which have little
or no impact on the reliability of the BES while not requiring them to obtain
Alternative Interpersonal Communication capabilities. The requirement allows
flexibility in “consult with” by not naming the method. If all communications are out,
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Organization
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Question 4 Comment
then the DP or GOP may have to meet the requirement by an in-person consultation.
No change made.
Response: See response above.
ISO New England
No
ISO-NE does not believe COM-001, in its entirety, is a results-based standards and
therefore does not support the draft as written. We believe such “requirements” (i.e.
capabilities) should be verified through an entity certification process.
Additionally, results-based requirements should be the driver to have the capability
to achieve them; on other words, there is no other way to reliably dispatch than to
have communications facilities (electronic or voice).
Response: Although this is not a results-based standard, the RCSDT believes it is a significant improvement over the current COM001 standard. No change made.
ReliabilityFirst
No
ReliabilityFirst believes Distribution Provider and Generator Operator should be
added to Requirement R10 and Requirement R11 should be removed. Finite time
frames should be prescribed for each Distribution Provider and Generator Operator
that experiences a failure of any of its Interpersonal Communication capabilities.
ReliabilityFirst believes that the failure of Interpersonal Communication between
Distribution Providers/Generator Operators and Transmission Operators/Balancing
Authorities could have the same negative effects similar to the failure of
Interpersonal Communication by the Reliability Coordinator, Transmission Operator,
and Balancing Authority.
Response: If the RCSDT made the changes proposed, the standards loses the flexibility of the TOP and BA to work with DPs and GOPs
which have little or no adverse reliability impact on the BES. The RCSDT feels we need to maintain this flexibility. In fact, FERC
directed NERC to do so in Order 693. No change made.
City of Vero Beach
No
By use of the term “any” in the phrase “a failure of any of its Interpersonal
69
Organization
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Question 4 Comment
Communication” the standard will actually create a disincentive for redundant
communications with DPs and GOPs due to compliance risk.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
To truly further the goals of reliability, the requirement should align with R3.3 and
R3.4 which requires a primary Interpersonal Communications capability and R4 which
does not require DPs or GOPs to have Alternative Interpersonal Communications
capability. A possible solution is through use of the terms “Primary” for R3 and
“Alternate” for R4 and then make R11 applicable to Primary only.
The RCSDT deliberately stayed away from the use of primary and secondary mediums
and prefers to use communications capabilities. Further, the RCSDT has gone to
great lengths to provide some flexibility for those DPs and GOPs with little or no
impact on the reliability of the BES. FERC directed NERC to provide for this
consideration. Therefore, we use the language as proposed in R11. Mutually
agreeable implies that both parties are willing to accept the outcome. It doesn’t
mean that a DP or GOP must comply with the wishes of its TOP or BA because as you
state that could be beyond the control of the DP or GOP. But what transpires in the
consultation is a realization of what the situation is, what the impacts to reliability are
and a determination of what is amicable to both parties. No change made.
The RCSDT emphasizes the requirement refers only to Interpersonal Communication
capabilities. Adding the phrase “to the primary” is not needed. Please refer to the
definitions of Interpersonal Communication and Alternative Interpersonal
Communication for clarification. No change made.
Response: See response above.
Midwest Independent
No
MISO requests clarification regarding
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Organization
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Transmission System Operator
Question 4 Comment
(1) when Distribution Providers/Generator Operators have an obligation to
collaborate with Transmission Operators versus Balancing Authorities; and
(2) the obligation of Transmission Operators to inform Balancing Authorities (and vice
versa) of an agreed upon time for restoration of Interpersonal Communication
capability when collaboration occurs only between Transmission Operators and
Distribution Providers/Generator Operators or, conversely, Balancing Authorities and
Distribution Providers/Generator Operators.
Response: The RCSDT believes, (1) As specified in R11, the DP and GOP have an obligation to consult with their TOP and/or BA with
who they are experiencing an Interpersonal Communication capability failure. If the DP or GOP experiences a failure with the TOP,
then they consult with the TOP. If that failure is with the BA, they consult with the BA. If the failure is with both the TOP and BA,
they consult with both. (2) There is no such obligation. Both the TOP and BA are required to have Alternative Interpersonal
Communication capability, which would be used as a substitute for the Interpersonal Communication capability. No change made.
Texas Reliability Entity
No
(1) Why does R10 refer to “failure of its Interpersonal Communications capabilities”
while R11 refers to “failure of **any of** its Interpersonal Communications
capabilities”?
What is the distinction that is intended by addition of the words “any of”?
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
(2) As a Compliance Enforcement Authority, we have several fundamental questions
regarding what is intended in this standard. It appears the drafting team is using the
defined term “Interpersonal Communications” to refer to a designated primary
communication medium, and the term “Alternative Interpersonal Communications”
to refer to one or more designated backup communication mediums.
Is that correct?
71
Organization
Yes or No
Question 4 Comment
This should be clarified in the Standard.
(2) The RCSDT deliberately stayed away from the use of primary and secondary
mediums and prefers to use communications capabilities. However, you are correct
in considering the Alternative Interpersonal Communication capability as a substitute
for the Interpersonal Communication capability, as specified in their respective
definitions. No change made.
(3) There is ambiguity in the current draft because the defined term “Interpersonal
Communications” appears to include primary, back-up and all other mediums that
may be available (which may include landline phone, cell phone, satellite phone,
instant messaging, email, and data links, all in one facility), including any “Alternative
Interpersonal Communications.”
(3) Interpersonal Communication capability could use any of the mediums mentioned
in your comment. Likewise, the Alternative Interpersonal Communication capability
could be any of those mediums, as well, provided that it did not use the same
infrastructure as the Interpersonal Communication capability. No change made.
Do R10 and R11 apply to ALL available mediums, or just to the designated primary
and back-up mediums?
Does R9 apply to ALL available back-up mediums, or just to a specifically designated
back-up medium?
The RCSDT deliberately stayed away from the use of primary and secondary mediums
and prefers to use communications capabilities. Further, the RCSDT has gone to
great lengths to provide some flexibility for those DPs and GOPs with little or no
impact on the reliability of the BES. FERC directed NERC to provide for this
consideration. Therefore, we use the language as proposed in R11. Mutually
agreeable implies that both parties are willing to accept the outcome. It doesn’t
mean that a DP or GOP must comply with the wishes of its TOP or BA because as you
state that could be beyond the control of the DP or GOP. But what transpires in the
consultation is a realization of what the situation is, what the impacts to reliability are
72
Organization
Yes or No
Question 4 Comment
and a determination of what is amicable to both parties. No change made.
Response: See response above.
Dominion
Yes
Dominion agrees with the intent of R11; however, suggest language changes for
consistency with R10 as follows:
R11. Each Distribution Provider and Generator Operator that experiences a failure of
any of its Interpersonal Communication capabilities shall consult with their
Transmission Operator or Balancing Authority as applicable to determine a mutually
agreeable time to restore the Interpersonal Communication capability. [Violation Risk
Factor: Medium][Time Horizon: Real-time Operations]
Response: The RCSDT has made clarifying changes to R11 to use mutually agreeable action, rather than time for restoration.
NV Energy
Yes
Agree, however, the ability for a DP or GOP to have such consultation with its TOP or
BA would likely be hampered by the failure of the Interpersonal Communications
itself. DP and GOP are only required to have a single source for this Interpersonal
Communications.
Response: RCSDT did not want to burden the DP and GOP with having Alternative Interpersonal Communication capability based on
Paragraph 508 of Order No. 693. There are multiple avenues of communication technology available to comply with R11. No change
made.
NIPSCO
If the Interpersonal Communication is down, and no backup is required for the DP
and GOP, how are they to consult and collaborate?
Response: RCSDT did not want to burden the DP and GOP with having Alternative Interpersonal Communication capability based on
Paragraph 508 of Order No. 693. There are multiple avenues of communication technology available to comply with R11. No change
made.
City of Tacoma, Department
Yes
73
Organization
Yes or No
Question 4 Comment
of Public Utilities, Light
Division, dba Tacoma Power
Bonneville Power
Administration
Yes
Southwest Power Pool
Regional Entity
Yes
MISO Standards Collaborators
Yes
Salt River Project
Yes
San Diego Gas & Electric
Yes
Xcel Energy
Yes
Independent Electricity
System Operator
Yes
Oncor Electric Delivery
Company LLC
Yes
City of Jacksonville Beach dba/
Beaches Energy Services
Yes
Luminant Energy Company
LLC
Yes
Pepco Holdings Inc.
Yes
74
Organization
Yes or No
Exelon
Yes
Niagara Mohawk (dba
National Grid)
Yes
South Carolina Electric and
Gas
Yes
BGE
Yes
ERCOT ISO
Yes
Hydro One Networks Inc.
Yes
American Transmission
Company, LLC
Yes
Question 4 Comment
75
5. The proposed definition of Reliability Directive shown in COM-002-3 was revised to include Adverse Reliability Impact as shown
to more fully address emergencies or events that might lead to instability or Cascading: Reliability Directive: A communication
initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary to
address an Emergency or Adverse Reliability Impact. Do you agree with the proposed definition? If not, please explain in the
comment area below.
Summary Consideration: There were a significant number of comments about the definition of Reliability Directive with accompanying
suggested language; for example, having the definition to prescribe a level of performance. The practice of writing a level of
performance within a definition is discouraged and generally prevents future use of the term. Several comments pertained to
compliance with the requirements; for example, would an entity be required to use three-part communication for a voltage schedule?
The requirements do not preclude an entity from doing so; however, the requirements focus on the situation of addressing an
Emergency or Adverse Reliability Impact. Other concerns were raised that the terms “Emergency” and “Adverse Reliability Impact” are
the same. The RCSDT believes these terms capture independent conditions. The term “Emergency” implies situations where the event
is anticipated or currently happening. Likewise, Adverse Reliability Impact clearly identifies a potential or actual event in the phrase, “an
event that results in.” The RCSDT notes the definition of Adverse Reliability Impact is the revised term, which is NERC Board of Trustees
adopted and is pending regulatory filing in IRO-014-2. Additionally, using the currently adopted version does not capture the full
spectrum of the proposed definition by the RCSDT.
The development of the term Reliability Directive concept places a heightened awareness on actions that are required to avoid an
Adverse Reliability Impact. Additionally, the use of “direct” is consistent with the uses of “direct” in other standards. A commenter had
a concern about the removal of “issued in a clear, concise, and definitive manner” would lead to repeating the process. The RCSDT
believes it to be in the interest of the issuer to do this without the burden of a requirement. Additionally, this type of requirement
would be difficult to measure and by virtue of the issuer having to confirm the Reliability Directive; it is to the issuer’s advantage to be
clear for efficient communications. Other minor formatting and corrections to references were made to align requirements, measures,
and compliance components. Several other comments were made that are addressed in the questions above.
Organization
Yes or No
Constellation Power Source
Generation, Inc.
Negative
Question 5 Comment
As we commented on Project 2007-03 TOP-001-2, the definition of Reliability
Directive is an improvement but the definition must capture the identification
concept that is reflected in the Requirement (R1). As a result, when Reliability
76
Organization
Yes or No
Question 5 Comment
Directive is used elsewhere, it would be clear that the communication must be
identified as a Reliability Directive.
We suggest the following revision to the definition and it should follow through to
Project 2006-06 IRO-001-3 and Project 2007-03 TOP-001-2, eventually being added
to the Reliability Standards Glossary of Terms.
A communication identified as a Reliability Directive by a Reliability Coordinator,
Transmission Operator, or Balancing Authority to initiate action by the recipient to
address an Emergency or Adverse Reliability Impact.
The RCSDT thanks you for your comment; however, the suggested improvement is
addressed in the requirement COM-002-3, R1 (see below). Definitions should avoid
a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in
the first paragraph: “Definitions shall not contain statements of performance
Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3. To avoid
confusion with a Reliability Directive (both for auditors and entities), we suggest the
following:
To establish the authority of Reliability Coordinators to make requests of other
entities to prevent an Emergency or Adverse Reliability Impacts to the Bulk Electric
System.
R1: Each Reliability Coordinator shall have the authority to act or request others to
act (which could include issuing Reliability Directives) to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or
77
Organization
Yes or No
Question 5 Comment
Adverse Reliability Impacts.
R2: Each Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider shall comply with its Reliability Coordinator’s request unless
compliance with the request cannot be physically implemented, or unless such
actions would violate safety, equipment, regulatory or statutory requirements, or
unless the TOP, BA, GOP or DP convey a business reason not to comply with the
request but express that they will comply if a Reliability Directive is given.
R3: Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as requested in accordance with Requirement R2.
The RCSDT feels the use of direct and directed is consistent with the purpose and
application of those terms in other standards. The RCSDT believes using the word
“request” makes the requirement conditional and is not consistent with the purpose
of the standard. No change made.
Response: See response above.
MidAmerican Energy Co.
Negative
Do not nest definitions.
The use of the word “any” in the COM-002-3 and IRO-001-3 definition of
“Emergency” is too broad and should be deleted. The use of “any” in regulatory
standards almost always causes unintended consequences.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The definition should be shortened to read:
“Abnormal system condition that requires automatic or immediate manual actions to
prevent or limit Bulk Electric System transmission facility or generation failures that
78
Organization
Yes or No
Question 5 Comment
could result in instability, uncontrolled separation, or cascading.”
The RCSDT appreciates the suggested rewording of the definition. The suggestion
creates a disconnect with the already approved NERC glossary term. Additionally,
the proposed definition adds new words which were not included originally. The
RCSDT does not propose a new definition of Emergency. No change made.
Response: See response above.
Tennessee Valley Authority
Negative
We suggest adding the words “and identified as a reliability directive to the
recipient” at the end of the definition of Reliability Directive.
The RCSDT thanks you for your comment; however, the suggested improvement is
addressed in the requirement COM-002-3, R1 (see below). Definitions should avoid
a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in
the first paragraph: “Definitions shall not contain statements of performance
Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
For R2, we question the phrase “physically implemented” and recommend that the
intent be clarified in the language.
The RCSDT believes there may be conditions were an entity may not be able to
physically implement the direction; for example, an entity that does not have the
right to access certain equipment or cannot manually operate a broken apparatus.
We feel the proposed language achieves the intended purpose. No change made.
Response: See response above.
79
Organization
SERC OC Standards Review
Group
Yes or No
No
Question 5 Comment
We suggest adding the words “and identified as a reliability directive to the
recipient” at the end of the definition of Reliability Directive. As written, this
definition could lead to a dispute of what communications are Reliability Directives;
leading to further dispute as to what Requirements are applicable. By adding this
clarity in the definition of this term, clarity will not be needed in the application of
this definition as is proposed in COM-002-3, Req 1.
This would allow the removal of R1 from COM-002-3
Response: The RCSDT thanks you for your comment; however, the suggested improvement is addressed in the requirement COM002-3, R1 (see below). Definitions should avoid a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in the first paragraph: “Definitions shall not
contain statements of performance Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
CCG, CPG, CECD
No
As we commented on Project 2007-03 TOP-001-2, the definition of Reliability
Directive is an improvement but the definition must capture the identification
concept that is reflected in the Requirement (R1). As a result, when Reliability
Directive is used elsewhere, it would be clear that the communication must be
identified as a Reliability Directive.
We suggest the following revision to the definition and it should follow through to
Project 2006-06 IRO-001-3 and Project 2007-03 TOP-001-2, eventually being added
to the Reliability Standards Glossary of Terms.
“A communication identified as a Reliability Directive by a Reliability Coordinator,
Transmission Operator, or Balancing Authority to initiate action by the recipient to
address an Emergency or Adverse Reliability Impact.”
Response: The RCSDT thanks you for your comment; however, the suggested improvement is addressed in the requirement COM80
Organization
Yes or No
Question 5 Comment
002-3, R1 (see below). Definitions should avoid a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in the first paragraph: “Definitions shall not
contain statements of performance Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
Arizona Public Service
Company
No
There is a risk of not properly identifying an abnormal condition (Emergency or
Adverse Reliability Impact) in time to require specific use of the statement ‘this is a
Reliability Directive’ when issuing switching on the system in the event of an
emergency.
The RCSDT believes that it is the responsibility of each entity to identify abnormal
conditions when it requires an action to be executed as a Reliability Directive. If
conditions are not identified as having Emergency or Adverse Reliability Impact, then
the requirement is not applicable. No change made.
This is a deviation from consistently using 3-way communication when an emergency
occurs. It may not be apparent that an emergency exists and breaking from
consistent use of expected 3-way communication could cause confusion.
The RCSDT believes this does not preclude an entity from utilizing 3-part
communications for activities other than Reliability Directives. No change made.
Response: See response above.
Southern Company
No
This definition would encompass more communication than is now included. The
definition now requires that a directive be declared as a part of the three part
communication. For example, sending out the voltage schedule each morning would
be included as a directive using the new definition.
The RCSDT thanks you for your comment; however, we believe the definition of
Reliability Directive is specific in the nature of the communication while providing
81
Organization
Yes or No
Question 5 Comment
adequate flexibility for the responsible entity to define those conditions that would
rise to the level of a Reliability Directive. No change made.
We suggest adding the words “and identified as a reliability directive to the
recipient” at the end of the definition of Reliability Directive. This would allow the
removal of R1 from COM-002-3
The RCSDT thanks you for your comment; however, the suggested improvement is
addressed in the requirement COM-002-3, R1 (see below). Definitions should avoid
a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in
the first paragraph: “Definitions shall not contain statements of performance
Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
Response: See response above.
Entergy Services, Inc
No
An Adverse Reliability Impact is a type of Emergency. Including a new term for
Adverse Reliability Impact and including both terms in the definition for Reliability
Directive doesn’t add clarity. I suggest changing the definition for Reliability
Directive to remove phrase “or Adverse Reliability Impact.”
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition captures two independent
conditions, anticipated and after or post event. The definition of Emergency implies situations where the event is anticipated or
currently happening. Likewise, the definition of Adverse Reliability Impact clearly identifies as a potential or actual event in the
phrase, “an event that results in.” Both conditions are important to the definition. The RCSDT notes that the term, “Adverse
Reliability Impact,” is a currently defined NERC Glossary term; however, the term as it appears in the standard is the revised term,
which is NERC Board of Trustee adopted and pending regulatory filing in IRO-014-2: “The impact of an event that results in Bulk
82
Organization
Yes or No
Question 5 Comment
Electric System instability or Cascading.” No change made.
NextEra Energy, Inc.
No
NextEra objects to the use of “Adverse Reliability Impact” in Reliability Standards
COM-002-3 and IRO-001-3. NextEra requests that the use of Adverse Reliability
Impact be revised as suggested below or it be deleted from the definition of
Reliability Directive. NextEra does not agree with the use of Adverse Reliability
Impact in the definition of “Reliability Directive” for the following reasons:
1. This term Adverse Reliability Impact is ambiguous. In part, the term is ambiguous
because it includes in its definition the term “instability,” which has lead to
considerable misunderstanding and confusion in the industry. There are also
differing views on what is (and is not) Cascading, because the definition is not
sufficiently clear. For example, some believe instability and Cascading occur when an
event affects multiple substations of one Transmission Operator, while others
believe instability or Cascading only occur when the event affects more than one
Transmission Operator’s system. As mentioned in response to item 4, above,
Reliability Standards must be clear and consistently interpreted. It is not appropriate
to issue a Standard that perpetuates the use of terms that lack consistent
interpretation.
2. While not perfect, the term Emergency is better understood in the industry, and it
may include many or all of the instances of instability or Cascading intended to be
captured by Adverse Reliability Impact. Consequently, it is not advisable to
introduce Adverse Reliability Impact as a new term, when it is not clearly
distinguishable from Emergency. NextEra is concerned that an unclear and imprecise
term, such as Adverse Reliability Impact, does not promote reliability, and, such a
term is particularly troublesome in the context of real time system operations.
Therefore, for the reasons stated above, NextEra believes that the term Adverse
Reliability Impact should be deleted from the definition of Reliability Directive. In
the alternative, if Adverse Reliability Impact is not deleted from the definition of
Reliability Directive in Reliability Standards COM-002-3 and IRO-001-3, NextEra
83
Organization
Yes or No
Question 5 Comment
requests that Adverse Reliability Impact be revised to read:
“an event or condition on the Bulk Electric System that may, or is leading to,
Cascading over more than one Bulk Electric System transmission system.”
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition captures two independent
conditions, anticipated and after or post event. The definition of Emergency implies situations where the event is anticipated or
currently happening. Likewise, the definition of Adverse Reliability Impact clearly identifies as a potential or actual event in the
phrase, “an event that results in.” Both conditions are important to the definition. The RCSDT notes that the term, “Adverse
Reliability Impact,” is a currently defined NERC Glossary term; however, the term as it appears in the standard is the revised term,
which is NERC Board of Trustee adopted and pending regulatory filing in IRO-014-2: “The impact of an event that results in Bulk
Electric System instability or Cascading.” No change made.
Niagara Mohawk (dba
National Grid)
No
The "adverse reliability impact" definition is not clear, is this an actual event or
contingency? The words imply it is an actual event, which is already covered in the
"Directive" definition. If the intent is to apply directives to potential stability or
cascading contingencies it should say so.
Response: The RCSDT notes that the term, “Adverse Reliability Impact,” is a currently defined NERC Glossary term; however, the
term as it appears in the standard is the revised term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO014-2: “The impact of an event that results in Bulk Electric System instability or Cascading.” The pending definition covers the
application to potential instability and cascading conditions. The RCSDT included the phrase “to address” in the proposed definition
of “Reliability Directive” to account for (1) potential and (2) actual events leading to an Emergency or Adverse Reliability Impact.” No
change made.
BGE
No
BGE would prefer that the definition of Reliability Directive include the requirement
to identify the fact that a Reliability Directive is being issued. See the following
proposed definition:
Reliability Directive: A communication initiated and identified as a Reliability
Directive, by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse
84
Organization
Yes or No
Question 5 Comment
Reliability Impact.
Response: The RCSDT thanks you for your comment; however, the suggested improvement is addressed in the requirement COM002-3, R1 (see below). Definitions should avoid a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in the first paragraph: “Definitions shall not
contain statements of performance Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
Duke Energy
No
-Since FERC has not yet approved the new definition of Adverse Reliability Impact,
we believe the term “Adverse Reliability Impact” should be replaced by the words of
the BOT-approved definition: “the impact of an event that results in Bulk Electric
System instability or Cascading.”
The RCSDT notes that the term, “Adverse Reliability Impact,” is a currently defined
NERC Glossary term; however, the term as it appears in the standard is the revised
term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO014-2: “The impact of an event that results in Bulk Electric System instability or
Cascading.” The RCSDT thanks you for your comment; however, by inserting the text
of the currently adopted version of the Adverse Reliability Impact definition would
create a loss of continuity in the intent of the pending definition. No change made.
-Also, add the phrase “and the communication is identified as a reliability directive to
the recipient” to the end of the definition of Reliability Directive. This will eliminate
potential confusion regarding when a communication is a Reliability Directive, and
when a communication is a routine instruction. Revising the definition in this
manner may also eliminate the need Requirement R1 of COM-002-3.
If R1 is retained, we suggest rewording as follows:
“Each Reliability Coordinator, Transmission Operator, or Balancing Authority shall
identify a Reliability Directive to the recipient when it issues a Reliability Directive
85
Organization
Yes or No
Question 5 Comment
that requires an action or actions to be executed.”
The RCSDT thanks you for your comment; however, the suggested improvement is
addressed in the requirement COM-002-3, R1 (see below). Definitions should avoid
a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in
the first paragraph: “Definitions shall not contain statements of performance
Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
-Proposed reworded definition:
“Reliability Directive: A communication initiated by a Reliability Coordinator,
Transmission Operator, or Balancing Authority where action by the recipient is
necessary to address an Emergency or the impact of an event that results in Bulk
Electric System instability or Cascading, and the communication is identified as a
Reliability Directive to the recipient.”
The RCSDT thanks you for your comment; however, the suggested improvement is
addressed in the requirement COM-002-3, R1 (see below). Definitions should avoid
a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in
the first paragraph: “Definitions shall not contain statements of performance
Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
86
Organization
Yes or No
Question 5 Comment
No
ReliabilityFirst believes the definition of “Reliability Directive” should be all inclusive
and include “all” actions initiated by the Reliability Coordinator, Transmission
Operator or Balancing Authority (not just Emergency or Adverse Reliability Impacts).
Even though Emergency or Adverse Reliability Impacts are defined, during
operations, it may become a gray area to whether or not it falls under the intent of a
“Reliability Directive.”
Response: See response above.
ReliabilityFirst
The RCSDT appreciates your comment about including all actions initiated by the BA,
RC and TOP; however, the RCSDT has determined that the development of the
Reliability Directive concept improves reliability by placing a heightened awareness
on actions that are required to avoid an Adverse Reliability Impact. Additionally, the
industry does not support the proposed suggestion above based on previous
postings and comments. No change made.
Furthermore, if the system falls under a condition that results in an Adverse
Reliability Impact, it may be too late for a Reliability Coordinator, Transmission
Operator or Balancing Authority to issue a Reliability Directive. ReliabilityFirst
recommends the following for revision to the term “Reliability Directive”:
Reliability Directive - A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where an action by the recipient is
required.
The RCSDT has determined that the development of the Reliability Directive concept
as currently drafted, improves reliability by placing a heightened awareness on
actions that are required to avoid an Adverse Reliability Impact. Additionally, the
industry does not support the proposed suggestion above based on previous
postings and comments. No change made.
Response: See response above.
87
Organization
Midwest Independent
Transmission System
Operator
Yes or No
Question 5 Comment
No
The proposed definition of Reliability Directive is unacceptable because the use of
the defined terms “Emergency” and “Adverse Reliability Impact” results in an
undefined, broadened scope of responsibility for Reliability Coordinators when
coupled with the definition of the Bulk Electric System. This may lead to
confusion/ambiguity for Reliability Coordinators that must be clarified to ensure
compliance. Further, this broadened scope may mis-direct Reliability Coordinator’s
attention and mitigation efforts to small-scale, localized issues that represent no true
threat to the operation of the Interconnection.
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition actually narrows the responsibility
by framing the condition(s) within which it is appropriate for anticipated actions necessary to address an Emergency or Adverse
Reliability Impact. The IRO standards require the Reliability Coordinator to respond to issues regardless of the scale of issues. No
change made.
Texas Reliability Entity
No
We oppose the definition of Reliability Directive as it is currently being proposed in
this standard because three-part communication should not be required only after
an Emergency or Adverse Reliability Impact actually occurs.
In particular, we object to the removal of the word “expected” (or “anticipated”)
from the definition, because Reliability Directives may be required before a situation
escalates to an Emergency, in order to prevent the Emergency from occurring. This
proposed change potentially undermines efforts required to avoid emergencies and
events.
We note that there are instances in other Reliability Standards where “anticipated”
conditions require actions to be taken (e.g. TOP-001-1 R5 and EOP-002 R4), when
clear, concise, and definitive communication, verbal or electronic, is required to
avoid or mitigate an impending emergency.
Response: The RCSDT notes that the term, “Adverse Reliability Impact,” is a currently defined NERC Glossary term; however, the
term as it appears in the standard is the revised term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO014-2: “The impact of an event that results in Bulk Electric System instability or Cascading.” The pending definition covers the
88
Organization
Yes or No
Question 5 Comment
application to potential instability and cascading conditions. The RCSDT included the phrase “to address” in the proposed definition
of “Reliability Directive” to account for (1) potential and (2) actual events leading to an Emergency or Adverse Reliability Impact.” No
change made.
New York Independent
System Operator
No
It is not clear the distinction between an Emergency and ARI. We would like to
confirm that Since ARI is the impact of an event that results in instability or
cascading, that an ARI is a subset of an emergency?
Or said differently is an ARI simply instability or cascading? Ultimately, if ARI is a
subset of Emergency, then why do we need both in the requirement?
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition captures two independent
conditions, anticipated and after or post event. The definition of Emergency implies situations where the event is anticipated or
currently happening. Additionally, the term “Adverse Reliability Impact” is a currently defined NERC Glossary term; however, the
term as it appears in the standard is the revised term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO014-2: “The impact of an event that results in Bulk Electric System instability or Cascading.” The pending definition covers the
application to potential instability and cascading conditions. The RCSDT included the phrase “to address” in the proposed definition
of “Reliability Directive” to account for (1) potential impacts of events and (2) actual events leading to an Emergency or Adverse
Reliability Impact.” No change made.
Oncor Electric Delivery
Affirmative
"Oncor requests clarity about what constitutes a “recipient.”
For example, if a Transmission Grid Operator performing the functions of a
Transmission Operator issues a Reliability Directive to its own field operations
personnel to perform an action on behalf of the same entity, does the field
operations personnel as the recipient become in affect a “Transmission Operator”
subject to R2?"
Response: The term “recipient” in this case is referring to entity-to-entity communication and is inferred by Requirement R2 naming
the entities. No change made.
Constellation Energy
Affirmative
As we commented on Project 2007-03 TOP-001-2, the definition of Reliability
89
Organization
Yes or No
Commodities Group
Question 5 Comment
Directive is an improvement but the definition must capture the identification
concept that is reflected in the Requirement (R1).
As a result, when Reliability Directive is used elsewhere, it would be clear that the
communication must be identified as a Reliability Directive.
We suggest the following revision to the definition and it should follow through to
Project 2006-06 IRO-001-3 and Project 2007-03 TOP-001-2, eventually being added
to the Reliability Standards Glossary of Terms.
“A communication identified as a Reliability Directive by a Reliability Coordinator,
Transmission Operator, or Balancing Authority to initiate action by the recipient to
address an Emergency or Adverse Reliability Impact.”
Response: The RCSDT thanks you for your comment; however, the suggested improvement is addressed in the requirement COM002-3, R1 (see below). The definitions should avoid a structure that identifies an action or performance of an entity. The Standard
Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in the first paragraph: “Definitions shall not
contain statements of performance Requirements.” No change made.
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]”
National Grid
Affirmative
Delete reference to "adverse reliability impact" in R1. The "adverse reliability impact"
definition is not clear, is this an actual event or contingency?
The words imply it is an actual event which is already covered in the "Directive"
definition. If the intent is to apply directives to potential stability or cascading
contingencies it should say so.
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition captures two independent
conditions, anticipated and after or post event. The definition of Emergency implies situations where the event is anticipated or
currently happening. Additionally, the term “Adverse Reliability Impact” is a currently defined NERC Glossary term; however, the
term as it appears in the standard is the revised term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO90
Organization
Yes or No
Question 5 Comment
014-2: “The impact of an event that results in Bulk Electric System instability or Cascading.” The pending definition covers the
application to potential instability and cascading conditions. The RCSDT included the phrase “to address” in the proposed definition
of “Reliability Directive” to account for (1) potential and (2) actual events leading to an Emergency or Adverse Reliability Impact.” No
change made.
Wisconsin Public Service Corp.
Affirmative
The Standards Drafting Team has provided a great deal of clarity regarding Reliability
Directives, however we believe BES reliability would be further enhanced if
Reliability Directives were still required to be issued in a clear, concise, and definitive
manner. Under Emergency conditions, we feel this would enhance communications
effectiveness and expedite parties taking necessary actions quickly.
Response: The RCSDT believes the current form of the requirements accomplish this objective. If the issuer is not clear, concise and
definitive, it would lead to the issuer having to repeat the process. It is incumbent and beneficial to the issuer to meet this
performance without a specific requirement to instruct. Additionally, measuring clear, concise and definitive manner poses
significant issues. No change made.
We Energies
Yes
The definition is acceptable, but as used may imply that all Emergency
communications must be Reliability Directives.
Response: The RCSDT thanks you for your comment; however, definitions should avoid a structure that identifies an action or
performance of an entity. The Standard Processes Manual (SPM), “Process for Developing a Defined Term”, Page 22 states in the
first paragraph: “Definitions shall not contain statements of performance Requirements.” No change made.
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration agrees that it is important to clearly denote when a directive
must be issued. In previous definitions, we believed that imprecise language made it
difficult for the BA, RC, or TOP to determine if a gray area situation required a
directive or not. With a more precise definition, it will eliminate second guessing by
auditors that a directive was necessary because an outcome turned out poorly - even
if an Emergency was not declared or an Adverse Reliability Impact did not occur.
Response: Thank you for your comment.
91
Organization
ERCOT ISO
Yes or No
Question 5 Comment
Yes
The definition of Reliability Directive appropriately clarifies the importance of
knowing the level of importance of any instructions being issued. If there is no room
for variance from the specific action required, or if there is no time to further
negotiate or discuss the action required, it is important that the instruction be
identified as a Reliability Directive and for such instructions to be followed in a timely
fashion. Normal operating instructions typically do not rise to this level of urgency
and some variation from the words will not result in unmanageable reliability
impacts. Also, there typically may be time for addressing the instructions in more
than one way.
Response: Thank you for your comment.
NIPSCO
The question of whether one is in a state of Emergency or Instability, or in an
Abnormal Condition can be still be subjective; it may be difficult to provide evidence
for an audit.
Response: The responsible entity determines “state of Emergency or instability” and acts accordingly. No change made.
Pacific Northwest Generating
Cooperative
Yes
MRO NSRF
Yes
City of Tacoma, Department
of Public Utilities, Light
Division, dba Tacoma Power
Yes
LG&E and KU Services
Company
Yes
Bonneville Power
Yes
92
Organization
Yes or No
Question 5 Comment
Administration
SPP Standards Review Group
Yes
Dominion
Yes
Western Electricity
Coordinating Council
Yes
Southwest Power Pool
Regional Entity
Yes
FirstEnergy
Yes
MISO Standards Collaborators
Yes
Florida Municipal Power
Agency
Yes
Global Engineering and
Energy Solutions
Yes
ACES Power Marketing
Standards Collaborators
Yes
Kansas City Power & Light
Yes
Salt River Project
Yes
San Diego Gas & Electric
Yes
93
Organization
Yes or No
Central Lincoln
Yes
Shell Energy North America
Yes
Xcel Energy
Yes
Independent Electricity
System Operator
Yes
Liberty Electric Power LLC
Yes
Oncor Electric Delivery
Company LLC
Yes
Consolidated Edison Co. of
NY, Inc.
Yes
City of Jacksonville Beach
dba/ Beaches Energy Services
Yes
Luminant Energy Company
LLC
Yes
Pepco Holdings Inc.
Yes
Exelon
Yes
Manitoba Hydro
Yes
Orange and Rockland Utilities,
Inc.
Yes
Question 5 Comment
94
Organization
Yes or No
South Carolina Electric and
Gas
Yes
Georgia Transmission
Corporation
Yes
Nebraska Public Power
District
Yes
Georgia System Operations
Yes
ISO New England
Yes
City of Vero Beach
Yes
NV Energy
Yes
Hydro One Networks Inc.
Yes
American Transmission
Company, LLC
Yes
Indiana Municipal Power
Agency
Question 5 Comment
No comment.
95
6. Do you have any other comment, not expressed in questions above, for the RC SDT?
Summary Consideration: This question yielded the most comments overall and many are duplicative of previous comments. For those
duplicative comments, the RCSDT respectfully directs summary consideration of those comments to the above questions. Several
commenters noted these standards are not “results-based” and this is mainly due to the project’s ongoing work. The standard(s), in a
way, appear more results-based by not being prescriptive; however, the specific standards do not implement the results-based
formatting. There were many comments about aligning the three standards to have the same implementation plan. The RCSDT agrees
and aligned all three with the same implementation. Some comments questioned the need to have an authority requirement for the
Reliability Coordinator in IRO-001-3, R1 because it appears to be granted under the ERO registration criteria. The ERO criteria does not
provide for this authority. Additionally, IRO-001-3 does not limit the Reliability Coordinator’s authority to issuing only Reliability
Directives. The Reliability Coordinator has the authority to direct, which could include Reliability Directives (a subset of direction or
directing) is the theme carried out in each requirement. Some comments asked about direct, direction, and when an Emergency or
Adverse Reliability Impact would be identified. The terms “direct” and “direction” are consistent with the intent of the standard in its
authority and “identify” is upon recognition, which is a condition when the Reliability Coordinator would be acting or directing others to
act. The requirements do not preclude the Reliability Coordinator from taking action for other situations, even if it is aware of situations
beyond its area. A few comments concerned adding a time element to the requirements, such as, preventing events in Real-time;
however, the assigned Time Horizons provide for this under Real-time Operations and Same Day Operations.
Comments noted a difference in “shall have” and “shall designate” within the requirements of COM-001-2. The intent of allowing an
entity to “designate” allows the entity to designate the Alternative Interpersonal Communication capability providing greater flexibility
in meeting the requirement. Additionally, there were comments about testing the Interpersonal Communication capability in addition
to the Alternative Interpersonal Communication capability. The RCSDT intentionally omitted testing the Interpersonal Communication
capability because routine use is sufficient to demonstrate functionality. The standard COM-001-2 measures have been updated to
appropriately reflect the specific requirements and make the evidence examples clearer. There were several concerns about the
designating a replacement Alternative Interpersonal Communication capability within two hours. The RCSDT notes the performance is
to designate a replacement, not to accomplish the repairs. The reliability need is to designate what the Alternative Interpersonal
Communication capability will be, should it be called upon. Commenters raised concerns about most of the VSLs in COM-001-2 being
Severe. These VSLs are Severe because there are essential to reliability. By the construction of the requirement, VSLs are binary, which
requires the VSLs to be Severe according to NERC VSL Guidelines. Some comments questioned the removal of requirement, R4. This
requirement remains enforce until the approval of COM-003-1 under Project 2007-02.
Several commenters noted that COM-002-3 seems to be requiring the “how” to accomplish the communication coordination. The
RCSDT emphasizes the requirements state the “what,” rather than “how.” In a basic sense, the “what” is highlighted by R1 by
96
identifying the communication as a Reliability Directive, next in R2 the recipient responds accordingly, and R3 the issuer confirms the
communication. How the process is accomplished is up to the entity.
Some commenters were concerned about the measures and evidence. The measures are examples, and the entity is not limited to the
examples provided; including letters of attestation, where appropriate. The RCSDT addressed other document errors, formatting issues,
referencing, and mismatch issues raised in the comments. The Effective Date, Compliance, and Data Retention sections have been
updated to the most current language used in standards through the standard review process.
Organization
Alberta Electric System
Operator
Yes or No
Abstain
Question 6 Comment
IRO-001-3: The Alberta version of IRO-001 will outline limitations to the authority of
the RC, that are required by Alberta legislation.
Response: The standard drafting team (SDT) has drafted requirements to address the purpose of the standard, repeated here: To
establish the authority of Reliability Coordinators to direct other entities to prevent an Emergency or Adverse Reliability Impacts to
the Bulk Electric System. The requirements have been drafted within the context established by the NERC Functional Model V5, and
describes interrelationships of the functional entities in accordance with the Functional Model V5. Please address any variations
from this structure, which may be required by Alberta legislation, with NERC as the ERO. No change made.
City Utilities of Springfield,
Missouri
Affirmative
City Utilities of Springfield, Missouri supports comments submitted by SPP.
Response: Thank you for your comment.
United Illuminating Co.
Affirmative
COM-001-2: UI votes Affirmative with the comment that R1 through R9 are
requirements in the Planning Horizon not the Real Time Operations horizon. These
requirements are scoped to the establishment of communication processes with
other entities not with actions taken by operations.
Response: The RCSDT recognizes that, in most instances, the establishment of communications capability and the designation of
Alternative Interpersonal Communications capability will have taken place at some time in the past (which could be the operations
planning horizon for the present Real-time instance). However, the full reason for such action is to be sure that the communications
capability is in place and functional during the Real-time Operations horizon for use in Real-time operating actions. Therefore, the
97
Organization
Yes or No
Question 6 Comment
RCSDT has established the applicable time horizon to be the Real-Time Operations horizon. No change made.
SERC Reliability Corporation
Affirmative
COM-002-3 Comments
R2: We recommend that the following phrase (in quotes) be added to R2: Each
Balancing Authority, Transmission Operator and Distribution Provider that is the
recipient of a Reliability Directive shall repeat, restate, rephrase or recapitulate the
Reliability Directive "immediately upon receiving it."
As written, there is no limit as to when the entity must repeat it (i.e. they could wait
2 hours) The Standard is not clear as to what each entity is to do when more than
one entity receives a Reliability Directive at the same time (e.g. during a RC area
teleconference call).
For example, is a roll call of receiving entities expected to be held so that they
individually can repeat, restate, rephrase or recapitulate the Reliability Directive
followed by individual confirmation required in R3?
Response: The requirement aims at being a performance-based requirement, and states a description of “what” communication
must take place, but does not prescribe “how” the communication is to be made. Adding the suggested phrase “immediately upon
receiving it” introduces the ambiguous term “immediately,” for which there is neither plain meaning nor simple explanation. What
must happen is that the recipient must respond in such a way that the issuer may determine whether the message has been properly
understood. The RCSDT concludes that the proposed language gives plain meaning. No change made.
The question about whether a roll call of receiving entities is expected to be held is asking for prescription of “how” to accomplish
what is required. The RCSDT recognizes that there is more than one way to accomplish the confirmation when more than one entity
received a Reliability Directive at the same time. What is required is for the recipient to respond in such a way that the issuer may
determine whether the message has been properly understood. One way for that to occur would be, as you suggest, for the entities
to individually respond. Another way would be for a pre-established protocol or procedure (e.g., roll-call, all-call, etc.) to be in place
and used in such cases. The RCSDT has determined that prescribing “how” to ensure that “what” is required has been accomplished
is not required and that the individually adopted procedures or protocols could offer many different ways to ensure effectiveness.
No change made. The RCSDT concept is that “All Call” compliance is related to having a document that explains how the entity
responds. No change made.
98
Organization
Alliant Energy Corp. Services,
Inc.
Yes or No
Affirmative
Question 6 Comment
COM-002-3: Alliant Energy recommends that the Effective Date be the first day of
the second calendar quarter after applicable regulatory approval, to be the same as
COM-001-2 and IRO-001-3. In that way all 3 standards would be effective at the
same time, making implementation much smoother.
Response: Thank you for your comment. The RCSDT will adjust the standards to have the same implementation date.
Wisconsin Electric Power Co.
Affirmative
COM-002-3: Since all the Requirements are related to Reliability Directives, is it
implied that all “Emergency Communications” are Reliability Directives even if not
designated as such per R1?
-The M2 measure could be difficult for a recipient such as a Distribution Provider or
Generator Operator. A recipient’s phone may not be recorded but an initiator’s
always should. If a receiver refused to meet the R2 requirement, an initiator should
have an alternative (i.e., repeat the directive and provide potential penalties if
recipient refuses to comply).
Should the initiator have responsibility for providing the entire 3-way evidence as M3
implies?
Response: The RCSDT would like to highlight that communications is not a defined term in the NERC Glossary of Terms used in
Reliability Standards, nor is it defined in this standard. Thus, the plain meaning of communications is intended. The RCSDT has not
implied a defined term in the wording of the purpose statement of the standard, nor in the requirements themselves, that any
communication is a Reliability Directive unless the issuing functional entity identifies the actions to be taken as a Reliability Directive.
Therefore, not all communications during Emergencies will be Reliability Directives. No change made.
COM-002, R2: The RCSDT included some examples of how to provide the evidence needed for Measure M2. The examples are not
intended to be an all-inclusive list. The RCSDT does point out, though, that dated operator logs could provide such evidence. The
RCSDT does not believe that the recipient has the alternative to refuse to perform, as required. However, the RCSDT does bring
attention to standard IRO-001-3, which requires entities to comply with directions unless compliance with the direction cannot be
physically implemented or unless such actions would violate safety, equipment, regulatory, or statutory requirements. No change
made.
99
Organization
Yes or No
Question 6 Comment
COM-002 M3: The Measure is correct as written. The issuer only needs the evidence that it confirmed the response was accurate or
reissued according to the requirement. Evidence does not necessarily mean the entity must have the entire three-way conversation
captured (i.e., recording), but evidence the entity confirmed or reissued according to requirement. No change made.
Wisconsin Electric Power
Marketing
Affirmative
COM-002-3: Since all the Requirements are related to Reliability Directives, is it
implied that all “Emergency Communications” are Reliability Directives even if not
designated as such per R1.
The M2 measure could be difficult for a recipient such as a Distribution Provider or
Generator Operator. A recipient’s phone may not be recorded but an initiator’s
always should. If a receiver refused to meet the R2 requirement, an initiator should
have an alternative. i.e., repeat the directive and provide potential penalties if
recipient refuses to comply. Should the initiator have responsibility for providing the
entire 3-way evidence as M3 implies?
Response: The RCSDT would like to highlight that communications is not a defined term in the Glossary of Terms used in NERC
Reliability Standards, nor is it defined in this standard. Thus, the plain meaning of communications is intended. The RCSDT has not
implied in the wording of the purpose statement of the standard, nor in the Requirements statements themselves, that any
communication is a Reliability Directive unless the issuing functional entity identifies the actions to be taken as a Reliability Directive.
No change made.
COM-002, R2: The RCSDT included some examples of how to provide the evidence needed for measure M2. The examples are not
intended to be an all-inclusive list. The RCSDT does point out, though, that dated operator logs could provide the evidence. The
RCSDT does not believe that the recipient has the alternative to refuse to perform as required. No change made.
COM-002 M3: The Measure is correct as written. The issuer only needs the evidence that it confirmed the response was accurate or
reissued according to the requirement. Evidence does not necessarily mean the entity must have the entire three-way conversation
captured (i.e., recording), but evidence the entity confirmed or reissued according to requirement. No change made.
Southwest Transmission
Cooperative, Inc.
Affirmative
COM-002-3: While COM-002-3 is well written to explain the three-part
communications requirements and makes it perfectly clear when a Reliability
Directive has been issued, the opening clause leaves the responsible entity open to
second guessing on whether they should have issued a Reliability Directive. This
100
Organization
Yes or No
Question 6 Comment
problem could be solved by changing the opening clause to “When a Reliability
Coordinator, Transmission Operator, or Balancing Authority determines actions need
to be executed as a Reliability Directive.”
In the second bullet of Requirement R3, we suggest using “Restate” in place of
“Reissue.” The responsible entity is not really reissuing the Reliability Directive. They
are still in the act of trying to get the Reliability Directive issued and are simply recommunicating it because it was not understood.
Response: The RCSDT believes the offered suggestion does not improve COM-002-3, R1. No change made.
COM-002-3, R3: The communications described are not intended to be a once-through process. Effective communications,
sometimes referred to as three-part or three-way, often may be effective only after numerous iterations. The RCSDT believes the
likely first effort to clarify would be to re-issue the instructions just to determine whether the recipient simply “heard wrong.” Using
the word re-state seems to imply that the wording is incorrect in some way or for some other reason needs to be said a different
way. The RCSDT believes it is more likely that the issuer is attempting to bet the recipient to understand and therefore believes that
reissue is more appropriate. No change made.
Public Utility District No. 1 of
Okanogan County
Affirmative
IRO-001-3: Need to correct language in Data Retention section 1.3. references R3 R4
and M3 and M4. There is no R4 and M4.
Response: The RCSDT agrees and thanks you for your comment. The language has been changed to eliminate R4 and M4
references.
Sierra Pacific Power Co.
Affirmative
IRO-001-3: R1 appears to be unnecessary due to the authority that is already
inherent through the functional model. 8
Further, the measure for R1 does not properly cover the requirement that the RC
"have authority"; rather, it measures whether the RC exercised that authority.
8
NERC Functional Model Version 5, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
101
Organization
Yes or No
Question 6 Comment
Response: The RCSDT agrees that the standard requirements language is consistent with the authority that is inherent in the
Functional Model V5. However, the Functional Model V5 does not constitute enforceable requirements for entities to follow. Such
requirements are established within the Reliability Standards. The Functional Model V5 provides good guidance for a consistent
structure throughout the Reliability Standards. In addition, the Reliability Coordinator’s reliability certification is established through
Regional Entities and the authority to act is measured. No change made.
Platte River Power Authority;
Portland General Electric Co.;
U.S. Army Corps of Engineers
Affirmative
IRO-001-3: Requirement R1 of IRO-001-3, requiring the Reliability Coordinator to
have the authority to act or direct actions, appears to be unnecessary because it
seems that this authority is granted when the entity is certified as the Reliability
Coordinator.
Additionally, the associated Measure M1, as worded, does not provide evidence that
the Reliability Coordinator has the authority to act or direct other to act, but rather
provides evidence that the Reliability Coordinator acted or took action to direct
others.
Response: IRO-001-3, R1: The RCSDT agrees that the requirement is consistent with intended functions of a Reliability Coordinator
when the entity is recognized as a Reliability Coordinator. The RCSDT has been informed by the ERO that registration criteria do not
provide for certification of this authority In addition, the Reliability Coordinator’s reliability certification is established through
Regional Entities and the authority to act is measured. No change made.
National Grid
Negative
- Requiring RCs, TOPs and BAs to state an action as a "reliability directive"
complicates communications during a time when response time and clarity are
important. If those issuing a directive don't get a repeat back they just need to ask
for one. The requirement just needs to define "what" is required not "how.” This can
be handled by procedures and training.
COM-002-3, R1: The requirement states “what” must be done: the action(s) are to
be identified as a Reliability Directive. The requirement does not establish “how” the
action is to be done. The RCSDT agrees that, under conditions such as you describe,
time may be of the essence. Much as in military operations, discussion time is over
and action is required when the recipient understands an order has been given.
102
Organization
Yes or No
Question 6 Comment
Discussion of disagreement or alternatives may occur later, if and as needed, but no
more time can be consumed discussing the directions given. The RCSDT has not
prescribed “how” these things must be done, and the RCSDT recognizes there is
more than one way. The RCSDT has determined it is appropriate to place the
responsibility on the recipient to give a response. The RCSDT agrees that the issuer
may ask for a response if one has not been given, but the responsible entity to
perform the action is the recipient. The RCSDT agrees that procedures and training
are good practices appropriate for this process, but the standard requirements
establish what must be done, not how personnel are prepared to do it. No change
made.
- Delete reference to "adverse reliability impact" from the "Directive" definition. The
"adverse reliability impact" definition is not clear, is this an actual event or
contingency?
The words imply it is an actual event which is already covered in the "Directive"
definition. If the intent is to apply directives to potential stability or cascading
contingencies it should say so.
The RCSDT notes that the term, “Adverse Reliability Impact” is a currently defined
NERC Glossary term; however, the term as it appears in the standard is the revised
term, which is NERC Board of Trustee adopted and pending regulatory filing in IRO014-2: “The impact of an event that results in Bulk Electric System instability or
Cascading.” The pending definition covers the application to potential instability and
cascading conditions. The RCSDT included the phrase “to address” in the proposed
definition of “Reliability Directive” to account for (1) potential and (2) actual events
leading to an Emergency or Adverse Reliability Impact.” No change made.
Response: See response above.
SERC Reliability Corporation
Negative
COM-001-2 Comments Definition of Alternative Interpersonal Communication: The
proposed definition uses the term "medium.”
103
Organization
Yes or No
Question 6 Comment
What is the scope of that? Telephony is a "medium", but there is wired, wireless,
satellite, etc.
Was "medium", intended to differentiate voice, paper, text, email, teletype, or
something else? Does the qualifying term "same", when modifying infrastructure
mean something like voice versus written?
What about situations where the primary telephone system is Voice Over Internet
Protocol (VOIP) and it is using the same computer network infrastructure as an email
or messaging system. That is the “same infrastructure” but a different “medium.”
The RCSDT believes that prescribing a device or medium would limit an entity.
Please refer to the definition of Interpersonal Communication and Alternative
Interpersonal Communication. Medium: the plain meaning of the word medium in
noun form is a vehicle for ideas, a means of conveying ideas or information. The
RCSDT recognizes there are many differing technologies for accomplishing
communications and it is not necessary to prescribe which to use. A common
medium is telephony, and the commenter is correct that there are different
technological forms of telephony. What is required is that there be a medium in
place so that Interpersonal Communication capability exists. No change made.
R1 and R2 - We suggest the drafting team look at Standard EOP-008, Requirements
R3 and R8 and add appropriate language in Standard COM-001-2, to avoid
instantaneous non-compliance for loss of Interpersonal Communications and/or
Alternate Interpersonal Communications.
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard. This was not intended by the drafting team. The intent is
to give the entity the flexibility in meeting the requirement. A loss of Interpersonal
Communication capability is covered by R10, notification of Interpersonal
Communication capability failure. No change made.
R1 - In later requirements it is proposed that the entity "shall designate an.” It is
104
Organization
Yes or No
Question 6 Comment
suggested that for consistently and audit ability, this concept be used for R1, R3, R5,
R7 and R8.
The RCSDT believes the requirements achieve the desired intent of the standard.
Each entity listed must “have” an Interpersonal Communication capability and for
Alternative Interpersonal Communication capability able to “designate” the
alternate. The team established these requirements to provide flexibility to the
industry. No change made.
In addition, the qualifier of "primary” should be used such that the requirements
read:
"shall have designated, primary Interpersonal Communications capability with the
following entities:"
Although it is appropriate that "Alternative" be capitalized since it is used in a
defined term (i.e. Alternative Interpersonal Communication) that bounds acceptable
alternative methods , we do not see the need to capital "primary.”
The term “Interpersonal Communication” is a defined term in this standard. As such,
it has a different meaning than “Alternative Interpersonal Communication,” thus
there should be no confusing of the two. In addition, the word “primary” purposely
does not exist in the requirements since the RCSDT did not intend to create a
requirement for redundancy. Redundancy continues to be a good practice, but it is
not required by this standard. Only that some entities must have both an
Interpersonal Communication capability and a designated Alternative Interpersonal
Communication capability. No change made.
R9 - The requirement is unclear if the required monthly test is a general functionality
test or if there is the expectation of testing the designated Alternative Interpersonal
Communications with all of the entities defined in the sub-requirements of R2, R4,
and R6. There is no expectation of testing the primary Interpersonal Communications
- is this intentional or an oversight?
Although functional testing of this should be done as a normal course of business,
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Organization
Yes or No
Question 6 Comment
should an explicit test be required with each entity in the sub-requirements of R1,
R3, R5, R7 and R8 to insure, for example, that all the phone numbers are correct?
The RCSDT intends each Alternative Interpersonal Communication capability to be
verified functional by testing. If an entity has only one such capability, then only one
test would be required. You further ask whether the absence of required testing of
the “primary” (word is not in the requirement) Interpersonal Communication
capability is intentional. The RCSDT intentionally left it out because the
communications capability is used routinely and the use is sufficient to demonstrate
functionality. With respect to phone numbers, these are procedural matters to be
addressed by each individual entity and by including phone numbers it would make
the requirement prescriptive. The requirement is to test capability. No change
made.
R10 - The following scenario seems plausible: The Interpersonal Communications
fails and is detected at 14:00 and gets fixed at 14:35. It lasted more than 30 minutes
but is fixed. As written the requirement would require the responsible entity to
notify entities identified in R1 through R6 by 15:00 (i.e. 60 minutes from detection)
even though the problem no longer exists. Is that the expectation?
Does COM-001 apply only to primary control centers or back-ups, per EOP-008, as
well?
Yes, the entity experiencing the failure is required by R10 to notify the entities as
identified within the 60-minute time frame. The RCSDT believes these situations
would be few in numbers and not overly burdensome to perform. No change made.
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard. No change made.
M9 reads “at least on a monthly basis.” We suggest that this be changed to “at least
once per calendar month” as written in R9. This change should also be corrected in
the VSLs.
106
Organization
Yes or No
Question 6 Comment
The RCSDT agrees and has changed the language in COM-001-2, M9 to agree with
the language in R9.
M8 - We suggest removing the second “that” in the first sentence of the measure.
COM-001-2, M8: The RCSDT agrees and the language in M8 has been changed to
delete the additional “that”.
M10 - We suggest this be revised to coincide with changes made in R10 (deleting
impacted and adding as identified in Requirements R1 through R6), therefore M10
should read:
“Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1 through R6 within 60 minutes of the detection of a failure of its
Interpersonal Communications capabilities that lasted 30 minutes or longer. Evidence
could include, but is not limited to dated operator logs, dated voice recordings or
dated transcripts of voice recordings, electronic communications, or equivalent
evidence. (R10.)“
The RCSDT agrees and has changed the language in COM-001-2, M10 to include
language consistent with the language in R10.
M12 needs to be removed.
COM-001-2, M12: The RCSDT agrees that the heading “M12” has no corresponding
requirement and was overlooked in format clean-up. The “M12” heading has been
removed.
We question why the first paragraph of Section 1.3” Data Retention has been
included in each of these three standards. We suggest that it should be removed
from each standard.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
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Organization
Yes or No
Question 6 Comment
Response: See response above.
Independent Electricity
System Operator
Negative
COM-001-2:
1. R1.2 and R2.2: The phrase “within the same Interconnection” is improper; it needs
to be removed. RCs between two Interconnections still need to communicate with
each other for reliability coordination (e.g. between Quebec and the other RCs in the
NPCC region to curtail interchange transactions crossing Interconnection boundary).
The SDT’s response that the phrase was added to address the ERCOT situation and
citing that ERCOT does not need to communicate with other RCs leaves a reliability
gap.
Requirement R1 addresses a reliability need for adjacent Reliability Coordinators
synchronously connected within the same Interconnection to have Interpersonal
Communication capability; however, it does not preclude or limit the Reliability
Coordinator from establishing Interpersonal Communication capability with others.
The RCSDT does not see where there is a need to communicate with other Reliability
Coordinator’s from one interconnection to another. No change made.
2. R3.5 and R4.3: The phrase “synchronously connected within the same
Interconnection” is also improper; it needs to be removed. TOPs do communicate
with other TOPs including those asynchronously connected and in another
Interconnection (e.g. between Quebec and all of its asynchronously interconnected
neighbors).
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and have eliminated the
phrase “within the same interconnection.”
3. R4 and R6: not requiring an Alternative Interpersonal Communication capability
between the BAs and the DP and GOP can result in a reliability gap. If Interpersonal
Communication capability between the BAs and these entities is required to begin
with to enable BAs to communicate with these entities (such as operating
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Organization
Yes or No
Question 6 Comment
instructions or Reliability Directives) to ensure reliable operations, then an
alternative capability is also needed to ensure this objective is achieved when the
primary capability fails.
The RCSDT refers the Order No. 693 in Paragraph 508 to clarify the reason the DP
and GOP are not required to have Alternative Interpersonal Communication and is as
follows: “(1) expands the applicability to include Generator Operators and
Distribution Providers and includes Requirements for their telecommunications
facilities; (2) identifies specific requirements for telecommunications facilities for use
in normal and emergency conditions that reflect the roles of the applicable entities
and their impact on Reliable Operation and (3) includes adequate flexibility for
compliance with the Reliability Standard, adoption of new technologies and costeffective solutions.” In addition, R11 requires the DP and GOP to consult with its BA
and TOP to determine a mutually agreeable action for restoration. No change made.
4. Measure M3 does not cover the added R3.5 condition (having Interpersonal
Communications capability with each adjacent TOP). M3 needs to be revised.
The RCSDT thanks you for your comment and has made conforming changes to make
to COM-001-2, M3.
Response: See response above.
Wisconsin Electric Power
Marketing; Wisconsin Electric
Power Co.
Negative
COM-001-2: Although a great improvement over existing COM-001, and eliminates
the data component see comments:
-For R5.1 Can the solutions included to meet R1 be included, same R3.2 and R5.2,
same R5.3 and R7.2, same R5.4 and R8.1.
-For R5.2 Can the solutions included to meet R2 be included, same R4.2 and R6.2.
COM-001-2, R5: In a word: Yes. The requirement is to have capability, and that
capability does not have to be different from what the entity on the other end has.
No change made.
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Organization
Yes or No
Question 6 Comment
-R9 a 2 hour response for a once a month test seems extreme, as would require a
secondary Alternate Interpersonal Communications capability.
-M9 is reasonable, but should include something about communication actual repair
and or time estimates.
COM-001-2, R9: The requirement is to “initiate action to repair or designate a
replacement Alternative Interpersonal Communication capability…” within two
hours. The RCSDT recognizes that many different contracts or other arrangements
may exist to address repair. However, the RCSDT finds that entities should know
what they have and how to initiate repair and those two hours to do so is
reasonable. No change made.
COM-001-2, M9: The requirement is to have evidence that either repair was
initiated or an Alternative Interpersonal Communication capability was designated
within two hours. The RCSDT understands that, in extreme cases, the entity may
need to make its initial Alternative Interpersonal Communication capability its
Interpersonal Communication capability and then designate another Alternative
Interpersonal Communication capability, if the repair times are so long that to
continue in that mode for that long would present a reliability risk. Such
arrangements, if they exist at all, are very rare. No change made.
-R10 The use of R1 through R6 implies notification of both Interpersonal
Communications and Alternate Interpersonal Communications failures. Do you notify
if you become aware after the link is back up if it was down for GT 30 minutes, and
doesn’t address notifying when restored?
COM-001-2, R10: The RCSDT thanks you for pointing this out. The RCSDT has
modified the language of R10 to refer to R1, R3, and R5, rather than “R1 through R6”
since the responsible entities are limited to the RC, the TOP, and the BA in these
requirements.
Yes, there is no requirement to notify identified entities the Interpersonal
Communication have been restored. No change made.
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Organization
Yes or No
Question 6 Comment
-R11 Implies that R8 and R9 are independent and redundant to R5.3, R5.4 and R3.3
and R3.4.
Update M9 accordingly.
COM-001-2, R11: The RCSDT believes you intended to refer to R7 and R8, rather
than R8 and R9. The RCSDT does not believe that the language implies that the
communications capability required by R7 and R8 are independent, but they may be.
If the entity which is registered as a DP is also registered as a GOP, although unlikely,
then the capability could be met by the same medium. Neither does the RCSDT
believe that R11 implies that R7 and R8 are redundant to R3.3 and R3.4 or to R5.3
and R5.4. No change made.
Response: See response above.
Tampa Electric Co.
Negative
COM-001-2:
By use of the term “any” in the phrase “a failure of any of its Interpersonal
Communication” the standard will actually create a disincentive for redundant
communications with DPs and GOPs due to compliance risk. It needs to be limited to
primary Interpersonal Communications with its TOP and/or BA.
Response: The RCSDT appreciates your comment and has made clarifying changes by removing the phrase “any of” in COM-001,
R11. Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The term “Interpersonal Communication” is a defined term in this standard. As such, it has a different meaning than “Alternative
Interpersonal Communication,” thus there should be no confusing of the two. In addition, the word “primary” purposely does not
exist in the requirements since the RCSDT did not intend to create a requirement for redundancy. Redundancy continues to be a
good practice, but it is not required by this standard. Only that some entities must have both an Interpersonal Communication
capability and a designated Alternative Interpersonal Communication capability. No change made.
Cogentrix Energy, Inc.
Negative
COM-001-2:
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Organization
Yes or No
Question 6 Comment
Definition of Alternative Interpersonal Communication: The proposed definition uses
the term “medium.”
What is the scope of that? Telephony is a “medium” but there is wired, wireless,
satellite, etc. Was “medium” intended to differentiate voice, paper, text, email,
teletype, or something else?
Does the qualifying term “same” when modifying infrastructure mean something like
voice versus written?
What about situations where the primary telephone system is Voice Over Internet
Protocol (VOIP) and it is using the same computer network infrastructure as an email
or messaging system.
That is the “same infrastructure” but a different “medium” R8 Revision:
GOP cannot dictate to the BA or TOP what types of Interpersonal Communication
will be used, but they can work with them to establish a common tool.
COM-001-2, “Medium”: the plain meaning of the word medium in noun form is a
vehicle for ideas, a means of conveying ideas or information. The RCSDT recognizes
there are many differing technologies for accomplishing communications, and it is
not necessary to prescribe which to use. A common medium is telephony, and the
commenter is correct that there are different technological forms of telephony.
What is required is that there be a medium in place so that Interpersonal
Communication capability exists. Your comment poses compliance questions but
does not suggest changes. No change made.
COM-001-2, Definition of Alternative Interpersonal Communication: You ask
whether the use of the word “same” as a modifier of infrastructure mean something
like voice versus written? It could, but is not required to. The RCSDT intends the
language to indicate that whatever causes the loss of the Interpersonal
Communication capability should not be a common cause of failure of the
Alternative Interpersonal Communication capability. Thus, one telephone number
could serve as the Interpersonal Communication capability and another telephone
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Organization
Yes or No
Question 6 Comment
number could serve as the Alternative Interpersonal Communication capability, as
long as whatever causes the failure of the Interpersonal Communication capability
does not automatically cause the failure of the Alternative Interpersonal
Communication capability. No change made.
R8 Balloting:
R8. Each Generator Operator shall have Interpersonal Communications capability
with the following entities:
R8.1 Balancing Authority
R8.2 Transmission Operator
R8 Suggestion:
R8. Each Generator Operator shall coordinate with the BA and TOP to establish
Interpersonal Communications capability as requested by the BA and TOP.
The standard establishes requirement for communication capability appropriate to
ensure reliability. There is no requirement for it to be different from the
Interpersonal Communication capability that its Balancing Authority has with it, nor
the Interpersonal Communication capability that its Transmission Operator has with
it. Cooperation and coordination is always encouraged and is an excellent practice,
but is not required by this standard. Thank you for your suggestion. No change
made.
Response: See response above.
Oncor Electric Delivery
Negative
COM-001-2:
Oncor takes the position that contacting all impacted entities within 60 minutes of
the detection of a failure of its Interpersonal Communications capabilities that lasts
30 minutes or longer as prescribed in R1 through R6 is not doable within the ERCOT
interconnect for a Transmission Operator.
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Organization
Yes or No
Question 6 Comment
The standard establishes requirement for Interpersonal Communication capability
between entities for reliability purposes. The RCSDT recognizes that there are many
different organizational arrangements and structures within the North American
continent. The standard establishes “what” is required, but does not prescribe
“how” it must be done. No change made.
Oncor takes the position that notification to the RC and BA only is sufficient and that
those two entities have the operational functionality to contact within the prescribed
time all affected Distribution Providers, Generator Operators, and other
Transmission Operators.
Oncor also takes the position adding the word “impacted” to R10 will clarify that
notification needs to be made only to the entities that are affected by the failure of a
communication path.
This will also more align with the language in M10."
Thank you for your suggestion. The word “impacted” was removed in previous
postings. For further clarification, the RCSDT has modified M10 to remove the word
“impacted” to be consistent with R10. For additional clarity, the RCSDT also changed
the phrase in R10 and M10, “R1 through R6” to “R1, R3, and R5,” to clarify that it
applies to the capabilities with the RC, the TOP, and the BA.
Response: See response above.
National Grid
Negative
COM-001-2:
Overly prescriptive, not results-based. R7 & R8 are not necessary. Every entity at a
minimum has a contact with a phone as their "Interpersonal Communications
capability." Just need to require that every entity has a plan if they lose their primary
communication channel ("Interpersonal Communications capability").
Response: The standard establishes requirement for communication capability appropriate to ensure reliability. In addition, R7 and
R8 are responsive to FERC Order No. 693. Entities may use the telephone cited in the example as their Interpersonal Communication
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Organization
Yes or No
Question 6 Comment
capability. Requirement R11 as modified addresses the loss of Interpersonal Communication capability. No change made.
Lincoln Electric System
Negative
COM-001-2: Please clarify whether R10 is intended to address both Interpersonal
and Alternative Interpersonal Communications or only Interpersonal
Communication.
Although R10 identifies only Interpersonal Communication within the requirement,
the reference to Requirements R1-R6 appears to include Alternative Interpersonal
Communication as well. LES is concerned that if an entity’s Interpersonal
Communication is fully functional but discovers a failure in its Alternative
Interpersonal Communication, the entity would still be required to notify entities per
R10.
Response: The RCSDT thanks you for pointing this out. The RCSDT has modified the language of R10 to refer to R1, R3, and R5,
rather than “R1 through R6,” since the responsible entities are limited to the RC, the TOP, and the BA in these requirements.
ISO New England, Inc.
Negative
COM-001-2: Please see comments submitted with the project... ISO-NE does not
believe COM-001, in its entirety, is a results-based standards and therefore does not
support the draft as written. We believe such "requirements" (i.e. capabilities)
should be verified through an entity certification process.
Additionally, results-based requirements should be the driver to have the capability
to achieve them; on other words, there is no other way to reliably dispatch than to
have communications facilities (electronic or voice).
Response: Although this is not a results-based standard, the RCSDT believes it is a significant improvement over the current COM001 standard. The RCSDT will forward your comment to NERC staff for consideration.
Commonwealth of
Massachusetts Department of
Public Utilities
Negative
COM-001-2: Primary concern here is with the phrase "within the same
interconnection" which appears in R1.2 and R2.2. This removes any standard
requirement for adjacent RCs that may not be in the same interconnection from
communicating with each other. This constitutes a "gap" in reliability and is a
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Organization
Yes or No
Question 6 Comment
concern.
Response: Requirement R1 addresses a reliability need for adjacent Reliability Coordinators synchronously connected within the
same Interconnection to have Interpersonal Communication capability; however, it does not preclude or limit the Reliability
Coordinator from establishing Interpersonal Communication capability with others. The RCSDT does not see where there is a need to
communicate with other Reliability Coordinator’s from one interconnection to another. No change made.
Detroit Edison Company
Negative
COM-001-2:
R9. I believe 2 hours is too short, suggest "within 24 hours."
COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is NOT
to have the repair completed within two hours. The requirement recognizes that the
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability, and then, if it decides to do so, designate
another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
R11. "mutually agreeable time" creates issues. What if TO and BA have differing time
frames?
Which entity bears the violation if agreement cannot be reached?
Alexander Eizans
COM-001-2, R11, For, “mutually agreeable time,” the “what” is required is to consult
and determine a mutually agreeable time and the “How” that is to be done is too
prescriptive to be included within a standard because of the great number of
possible scenarios, organizational arrangement, and sizes of entities involved. No
change made.
I am concerned with the evidence listed under the measures (see M6, M7 and M8).
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Organization
Yes or No
Question 6 Comment
Dated equipment specifications and installation documentation is to much. I know
this is listed as "could include" but at one point could become "must include.”
Jeffrey DePriest
COM-001-2, M6, M7, and M8, “could include” may some day become “must
include”: “What” is required is to provide evidence. A list, which could include but is
not limited to various forms of evidence is presented for consideration, but the
entity may, and is encouraged to do so when it is appropriate, provide other forms of
equally appropriate evidence. No change made.
R9 define "unsuccessful test.”
Is it a mechanical failure of equipment or failure of one or more entities to respond
to the test?
If mechanical failure, does the 2 hour window to initiate repairs mean notification to
proper business unit or do repairs have to actually begin (crew investigating). If
crews need to be on site 2 hours is too limiting.
COM-001-2, R9, define “unsuccessful test”: The RCSDT notes that your words are a
paraphrase of the actual standard requirement language. In its simple form, a test is
unsuccessful when the capability fails to perform as expected. The entity may have
an elaborate contract in place with very specific technical specifications within which
the capability is to perform. The test may be unsuccessful if it does not meet those
technical specifications, although the intent of the standard is for the entities to be
able to communicate, usually verbally, with one another so as to operate reliably.
The standard does not prescribe the performance expectations for the capability
apart from the expectation that communication capability is to exist. The RCSDT
recognizes that there may be many variations of service, maintenance, and repair
agreement implemented for these communication capabilities. Whatever the
agreement provides for initiation of the response and repair is what is required. This
standard cannot prescribe all the possible combinations or scenarios. No change
made.
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Organization
Yes or No
Question 6 Comment
- R11. Mutual Agreeable time is vague.
Barbara Holland
COM-001-2, R11, “mutual agreeable time” is too vague: “What” is required is to
consult and determine a mutually agreeable time. “How” that is to be done is too
prescriptive to be included within a standard because of the great number of
possible scenarios, organizational arrangement, and sizes of entities involved. No
change made.
Response: See response above.
Madison Gas and Electric Co.
Negative
COM-001-2:
The definition of Interpersonal Communication is: “Any medium that allows two or
more individuals to interact, consult, or exchange information.” Recommend that
the word "any" be removed from Interpersonal Communication and recommend the
new definition be "The primary (or designated) medium that allows two or more
individuals to interact, consult, or exchange information."
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The term “Interpersonal Communication” is a defined term in this standard. As such,
it has a different meaning than “Alternative Interpersonal Communication,” thus
there should be no confusing of the two. In addition, the word “primary” purposely
does not exist in the requirements since the RCSDT did not intend to create a
requirement for redundancy. Redundancy continues to be a good practice, but it is
not required by this standard. Only that some entities must have both an
Interpersonal Communication capability and a designated Alternative Interpersonal
Communication capability. No change made.
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Organization
Yes or No
Question 6 Comment
R11, Please note that the use of the word “any” as in “Each Distribution Provider and
Generator Operator that experiences a failure of any of its Interpersonal
Communication capabilities...” will be viewed as meaning every Interpersonal
Communication medium that an Entity has or uses.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
Recommend R11 be updated to read:
“Each Distribution Provider and Generator Operator that experiences a failure of any
of its primary (or defined) Interpersonal Communication capabilities with its
Transmission Operator or Balancing Authority...”
In that way it focuses it down to the communications issues with the TOP or BA.
In lieu of “primary” the SDT could state “defined” as long as it is not meant to be
“any.” The latter part of R11 states; “...shall consult with their Transmission Operator
or Balancing Authority as applicable to determine a mutually agreeable time to
restore the Interpersonal Communication capability.” This ambiguous statement
does not support reliability. Consulting with a TOP or BA does not solve the problem
of the lack of Interpersonal Communication capabilities. Recommend this to be
“...shall consult with inform their Transmission Operator or Balancing Authority as
applicable as to determine a mutually agreeable time to restore the status of the
Interpersonal Communication capability.”
Thus R11 is recommended to read as:
“Each Distribution Provider and Generator Operator that experiences a failure of its
primary (or designated) Interpersonal Communication with their Transmission
Operator or Balancing Authority shall inform them, as applicable, as to the status of
the Interpersonal Communication capability.”
119
Organization
Yes or No
Question 6 Comment
This allows for situational awareness and supports the reliability of each system.
Additionally, the RCSDT notes that the requirement refers only to Interpersonal
Communication capabilities. Adding the phrase “to the primary” is not needed.
Please refer to the definitions of Interpersonal Communication and Alternative
Interpersonal Communication for clarification. No change made.
Response: See response above.
New York Independent
System Operator
Negative
COM-001-2:
The drafting team has complicated the requirements by having different
requirements between RC/TOP/BA and other entities such as GOP/LSE/DP. The
proposal is for redundancy to be required only between RC/TOP/BA. The
requirement should be simplified to require all entities to have plans for loss of
primary communication channels. This can include third parties as a communication
channel.
Response: The term “Interpersonal Communication” is a defined term in this standard. As such, it has a different meaning than
“Alternative Interpersonal Communication,” thus there should be no confusing of the two. In addition, the word “primary” purposely
does not exist in the requirements since the RCSDT did not intend to create a requirement for redundancy. Redundancy continues to
be a good practice, but it is not required by this standard. Only that some entities must have both an Interpersonal Communication
capability and a designated Alternative Interpersonal Communication capability. The DP and GOP are not required to have
Alternative Interpersonal Communication; however, R11 addresses the loss of communication capability (plan). No change made.
Public Utility District No. 1 of
Lewis County
Negative
COM-001-2: This standard should be combined with COM-002.
Response: The standard COM-001-2 is capability based (equipment) and COM-002-3 is communication and coordination based.
Each fulfills independent concepts. No change made.
Southwest Transmission
Negative
COM-001-2:
120
Organization
Yes or No
Cooperative, Inc.
Question 6 Comment
We believe that the VSLs could be written to provide more gradations. For example,
if a Transmission Operator or Balancing Authority failed to have Interpersonal
Communications capability with a Distribution Provider but had Interpersonal
Communications capability with all other required entities, it has met the vast
majority of the requirement. Since VSLs are a measure of how much the requirement
was missed by the responsible entity, jumping to a Severe VSL does not seem to
adequately capture that the responsible entity met the vast majority of the
requirement. Requirements R4 and R6 even seem to recognize this by not including
Distribution Provider in the list of entities to which the Transmission Operator or
Balancing Authority are required to designate Alternate Interpersonal
Communications capability.
Response: The RCSDT has applied the VSL to the Severe column because not having Interpersonal Communication capability with any
entity is detrimental to reliability. No change made.
Tennessee Valley Authority
Negative
COM-001-2:
We suggest the drafting team look at Standard EOP-008, Requirements R3 and R8
and add appropriate language in Standard COM-001-2, to avoid instantaneous noncompliance for loss of Interpersonal Communications and/or Alternate Interpersonal
Communications (R1 and R2).
Response: The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future enforcement. In either version, the team
believes there is no need to add additional language to the standard. No change made.
This was not intended by the drafting team. The intent is to give the entity the flexibility in meeting the requirement. A loss of
Interpersonal Communication capability is covered by R10, notification of Interpersonal Communication capability failure. No change
made.
Southwest Transmission
Cooperative, Inc.
Negative
COM-001-2:
We thank the drafting team for its efforts but believe there are still issues that need
to be addressed. We thank the drafting team for clarifying that the intent of this
121
Organization
Yes or No
Question 6 Comment
standard is not for data exchange in the response to comments.
However, we do believe one additional change is necessary to make the intent
absolutely clear. The purpose of statement of COM-001-2 still includes the phrase
“to exchange Interconnection and operating information.” Since a standard must
stand on its own, we believe it is necessary to remove that phrase from the purpose
statement to avoid misinterpretations in the future. Auditors and enforcement
personnel are not required to understand the development history when enforcing
the standard. Furthermore, the purpose is really to enable communications between
these functional entities.
The SDT agrees and has made a conforming change to the purpose of COM-001.
Requirement R11 does not fully address the issue of what is required by Distribution
Providers and Generator Operators and introduces new issues.
For, “mutually agreeable,” the “what” is required is to consult and determine a
mutually agreeable time and the “how” that is to be done is too prescriptive to be
included within a standard because of the great number of possible scenarios,
organizational arrangement, and sizes of entities involved. No change made.
First, while the standard is intended to clarify that the Distribution Provider and
Generator Operator do not need backup communications capability, it simply does
not. Distribution Providers and Generator Operators are required to have an
Interpersonal Communications capability in Requirement R7 and R8 respectively.
Unfortunately, the effectiveness of these requirements persists even when the
Distribution Provider or Generator Operator experiences a failure of its Interpersonal
Communications capability. When Requirement R11 applies, the Distribution
Provider or Generator Operator will still be obligated to comply with Requirements
R7 and R8 respectively and will, in fact, be in violation of these requirements because
the Distribution Provider or Generator Operator no longer has the capability.
The RCSDT thanks you for your comment. Requirements R7 and R8 have been
revised to account for the failure of Interpersonal Communication capability. The
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Organization
Yes or No
Question 6 Comment
intent of R11 is to require the responsible entity to take action upon the failure of its
Interpersonal Communication.
Second, capability is used inconsistently between Requirement R7 and R11 which
leads to confusion. In Requirement R7, it is singular while in Requirement R11 is
plural. It needs to be clear that only the failure of the capability identified in R7 and
R8 needs to be reported by the Distribution Provider and Generator Operator
respectively.
The RCSDT thanks you for your observation. Generally, the singular implies the
plural or vice-versa. The RCSDT has corrected R10 and R11 to be consistent with the
singular application.
Third, if the requirements focused on communications devices rather than
capabilities, they would come closer to communicating the intent. Requirement R11
would better complement Requirement R7 and R8 if the focus was on having a
communication medium or device. A Generator Operator with an installed
communications device or medium still has that device or medium even when it is
not functioning properly and could still meet Requirements R7 and R8. However,
they don’t have the Interpersonal Communications capability if the device is not
functioning properly.
The RCSDT thanks you for your comment. Requirements R7 and R8 have been
revised to account for the failure of Interpersonal Communication capability. The
intent of R11 is to require the responsible entity to take action upon the failure of its
Interpersonal Communication.
We recommend striking “capability” from all of the requirements. It is not clear to us
how this helps when a definition for Interpersonal Communications is written
already and applies to a communication medium. Furthermore, we think it causes
confusion and actually contradicts the intent of the standard. Because Requirements
R1, R3, R5, R7 and R8 focus on capability, the responsible entity will be in violation
anytime its medium that it uses for the primary capability does not function
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properly. Whereas if the requirement stated that the responsible entity was to
designate a primary communications medium, the responsible entity is not in
violation if that medium is not functioning properly. It would be clear that
Requirement R2, R4 and R6 are intended to be complementary.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
Furthermore, it is not clear why Requirements R1, R3, R5, R7 and R8 state that the
responsible entity shall “have” when the companion Requirements R2, R4, and R6
state “designate.”
Each entity listed must “have” an Interpersonal Communication capability and for
Alternative Interpersonal Communication capability able to “designate” the
alternate. The team established these requirements to provide flexibility to the
industry. No change made.
Since Requirement R10 deals with a failure of its Interpersonal Communications
capabilities and not Alternate Interpersonal Communications capability, it should
only refer to the entities in Requirements R1, R3, and R5. Currently, it includes R1
through R6.
The RCSDT thanks you for pointing this out. The RCSDT has modified the language of
R10 to refer to R1, R3, and R5, rather than “R1 through R6,” since the responsible
entities are limited to the RC, the TOP, and the BA in these requirements.
Response: See response above.
New York Independent
Negative
COM-002-3: The drafting team added a requirement to identify a Reliability Directive
is being initiated during an emergency to track 3-part communication for compliance
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Question 6 Comment
purposes. This will change and complicate the communication protocols between
normal and emergency operations simply to simplify compliance assessments. The
NYISO is asking for clarification that an entity may identify Reliability Directives as a
category of communications to be communicated through procedures and training;
and will not require a different communication protocol between normal and
emergency operations. Affective communications can only be achieve through
consistent processes for all conditions. Compliance assessments should be made on
when we are in an emergency or not, and not on how the dialogue was initiated.
Response: The RCSDT believes the standard allows for this condition, and the method of implementation is up to the entity. No
change made.
Illinois Municipal Electric
Agency
Negative
Illinois Municipal Electric Agency supports and encourages SDT consideration of
comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comment. See response to SERC comments.
Wisconsin Public Service Corp.
Negative
In COM-002-3, the Standards Drafting Team provided great clarity to the industry
and also reduced risk to the BES, by clearly defining Reliability Directives and how the
RC, TOP, and BA must utilize them. Unfortunately, they failed to maintain this level
of clarity in IRO-001-3, where they state:
R2. Each Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider shall comply with its Reliability Coordinator’s direction unless
compliance with the direction cannot be physically implemented or unless such
actions would violate safety, equipment, regulatory or statutory requirements.
[Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same Day
Operations and Operations Planning]
R3. Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as directed in accordance with Requirement R2. [Violation Risk
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Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and
Operations Planning]
The use of “direction” and “directed” essentially makes any request equivalent to a
Reliability Directive. In addition, IRO-001-3 as written is largely redundant of COM002-3. Given this, we recommend that the Standards Drafting Team consider
granting the RC authority to issue Reliability Directives by adding this requirement to
COM-002-3 and then eliminate IRO-001-3.
The RCSDT feels the use of direct and directed is consistent with the purpose and
application of those terms in other standards. No change made.
Response: See response above.
Wisconsin Electric Power
Marketing; Wisconsin Electric
Power Co.
Negative
IRO-001-03: Although a great improvement over existing IRO-001, see comments:
-R2 needs to be clear that it is the Reliability Coordinator’s Reliability Directive that
must be complied with not just any Reliability Coordinator’s direction as stated.
The RCSDT notes that the intent of the standard is not intended to limit the RC
authority to Reliability Directives. The Reliability Coordinator issuing the Reliability
Directive is the one, which the recipient must comply. It is assumed that a BA or TOP
has a relationship with one, and only one, RC for a given Balancing Area or
Transmission Operator Area (some may have multiple, disconnected areas, that are
subject to different RCs). No change made.
-The M2 measure could be difficult, as the operator would have to have access to
documents proving the safety, equipment, regulatory or statutory requirements,
which may be the assessment of an individual applying the safety rule. Is the
measure requiring a deposition of the individual to be performed for each instance?
In the RCSDT’s opinion, the Measure M2 does not contemplate depositions. If an
entity cannot comply with a Reliability Directive for one of the stated reasons, it
should have documentation, such as an attestation, to support that stated reason
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available during an audit. No change made.
With an assumed data retention of 90 day (voice) or 12 month document retention,
the deposition would be unlikely to be acquired prior to the retention period ending.
Data retention is a significant issue when the data being recorded is voluminous,
supporting a 90-day retention period. No change made.
-R3 needs to be clear that it is the inability to perform the Reliability Coordinator’s
Reliability Directive that must be communicated not just any “Reliability
Coordinator’s as directed.”
The RCSDT believes R3 contains the full communication set of “action or direction”
and the subset, Reliability Directive, is included; therefore, the respective entity is
still required to inform the RC. The RCSDT believes the requirement is clear in
regards to Reliability Directives. No change made.
-The Data Retention section does not align with the standard: The Reliability
Coordinator shall retain its evidence for the most recent 90 calendar days for voice
recordings or 12 months for documentation for Requirement R2, Measure M2.
R2 and M2 apply to the Transmission Operator, Balancing Authority, Generator
Operator, or Distribution Provider.
There is no R4 and M4.
Data retention related to IRO-001-2, R2/M2 was changed to agree with your
suggestion. The changes were more involved – several sections were changed,
including removing the reference to R4/M4.
Response: See response above.
SERC Reliability Corporation
Negative
IRO-001-3 Comments
We recommend that where the verb "direct/directed" or noun "direction" is used in
Purpose, R1, R2 and R3, that it be replaced with the verb "instruct/instructed" or
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noun "instruction", as appropriate. This would help the industry avoid confusion
often referred to as "big D" or "little d" directives. It is noted that the term
"Reliability Directive" does that to a great degree but avoiding the verb/noun
"direct/direction" would augment the difference.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. No change made.
R1 - At what point in time is "identified" referring to in "to prevent identified events
or"? Is it referring to current or future events?
The context of “identified” is when a set of system conditions is recognized that
could lead to an Emergency or Adverse Reliability Impact, which may require action.
See Standards IRO-008 and IRO-009. No change made.
One might assume both since the "Time Horizon" is defined as Real-time Operations,
Same Day Operations and Operations Planning, but the requirement may be
enhanced if explicitly stated ("to prevent events identified in real-time or in the
future or to mitigate the magnitude"). For clarity, the scope of the authority should
be limited to the Reliability Coordinator Area (that result in an Emergency or Adverse
Reliability Impacts within its Reliability Coordinator Area). As written, it implies the
authority should extend outside its RC Area.
R2 - We question the phrase‚-“physically implemented‚” and recommend that the
intent be clarified in the language.
The RCSDT believes there may be conditions were an entity might not be able to
physically implement the direction. For example, entities that do not have the right
to access certain equipment or cannot manually operate a broken apparatus. We
feel the proposed language achieves the intended purpose. No change made.
We note the following comment and response posted under Consideration of
Comments on Initial Ballot ‚ ” Reliability Coordination (Project 2006-06) Date of Initial
Ballot: February 25, ” March 7, 2011:
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“IRO-001 R2, R3, and R4 have replaced “Directives with the word direction in lower
case (while it appears that “Directives is a subset of “directions). We believe that this
muddies the waters and could bring numerous conversations and dialog into scope
unnecessarily. The end result is that the RC has the right to issue and use “Directives
and anything short of this could just be communications. For example, a number of
entities that are Reliability Coordinators also facilitate energy markets. There are
many communications related to markets that probably should be out of scope with
respect to the standards. Furthermore, it might not be clear what role (e.g. Reliability
Coordinator, market operator, etc) the staff at these entities is fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios and also
emergency scenarios. The required performance encompasses issuing and responding
to Reliability Directives as well as other directions. The requirement language
specifically ties back to Requirement R2 which states that the RC “shall take actions
or direct actions, which could include issuing Reliability Directives.” This is the
“direction in accordance with Requirement R2 stated in R3 and the “direction in
accordance with Requirement R3 stated in R4. We believe the entity comments
remain valid and the response provided by the SDT does not address all aspects of the
concern.
We suggest that the language be changed to “Reliability Directive consistent with
COM-002.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
R3 - The requirement states the responsible entities shall “inform its RC when unable
to perform as directed but it is unclear when the notification needs to take place.
Although the term “as soon as practical may seem be un-measureable, as written
now there is no time deadline to perform the notification” i.e. it could be 4 hours
later after recognition.
M2‚” need to add the following words “compliance with, physically, unless which
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were included in R2, therefore M2 should read‚
“Each Transmission Operator, Balancing Authority, Generator Operator, Interchange
Coordinator and Distribution Provider shall have and provide evidence which may
include, but is not limited to dated operator logs, dated records, dated and timestamped voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent documentation, that will be used to determine that it
complied with its Reliability Coordinator's direction(s) per Requirement R1 unless
compliance with the direction per Requirement R1 could not be physically
implemented or unless such actions would have violated safety, equipment,
regulatory or statutory requirements. In such cases, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution
Provider shall have and provide copies of the safety, equipment, regulatory or
statutory requirements as evidence for not complying with the Reliability Coordinator
direction. (R2)“
The RCSDT thanks you for your comment and has added the word “physically” to the
IRO-001-2 Measure M2.
Section 1.3, the second bullet; need to add calendar to 12 calendar months
The RCSDT appreciates your comments and conforming changes have been made to
the Data Retention section.
Response: See response above.
Dominion Virginia Power;
Dominion Resources, Inc.
Negative
IRO-001-3: Dominion does not support the use of “Reliability Coordinator’s
direction” in IRO-001-3 and would prefer that the language be changed to “Reliability
Directive” consistent with the use in COM-002-3.
Response: The word “direction” connects with the language in the R1 (act or direct). Reliability Directives is a subset of “direction.”
The RCSDT feels the use of direct and directed is consistent with the purpose and application of those terms in other standards. No
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change made.
Constellation Energy
Commodities Group
Negative
IRO-001-3:
IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3. To avoid
confusion with a Reliability Directive (both for auditors and entities), we suggest the
following: To establish the authority of Reliability Coordinators to make requests of
other entities to prevent an Emergency or Adverse Reliability Impacts to the Bulk
Electric System.
R1: Each Reliability Coordinator shall have the authority to act or request others to
act (which could include issuing Reliability Directives) to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or
Adverse Reliability Impacts.
R2: Each Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider shall comply with its Reliability Coordinator’s request unless
compliance with the request cannot be physically implemented, or unless such
actions would violate safety, equipment, regulatory or statutory requirements, or
unless the TOP, BA, GOP or DP convey a business reason not to comply with the
request but express that they will comply if a Reliability Directive is given.
R3: Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as requested in accordance with Requirement R2.
Response: This standard provides for the authority of the RC to act or direct actions, and not request. The RCSDT believes by using
the word “request” make the requirement conditional and is not consistent with the purpose of the standard. No change made.
Tampa Electric Co.
Negative
IRO-001-3:
R1 VSL should have the phrase "exercise their authority" inserted between "to" and
"take" in the first sentence. Otherwise it could be read that the RC would be in
violation of the standard requirement for any event that resulted in an Adverse
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Reliability Impact whether he issued a Reliability Directive or not.
Response: Thank you for your comment. The RCSDT has added the additional clarifying language.
Independent Electricity
System Operator
Negative
IRO-001-3:
The IESO is unable to support this standard as written since Data Retention Section
does not reflect the revised requirements. For examples: the Electric Reliability
Organization is no longer a responsible entity; the Reliability Coordinator should
replace the ERO for keeping data for R1; Transmission Operator, Balancing Authority,
Generator Operator and Distribution Provider should replace the Reliability
Coordinator for keeping data for R2;
and there is no R4/M4.
Response: The RCSDT agrees and has made conforming changes in Data Retention.
Southwest Transmission
Cooperative, Inc.
Negative
IRO-001-3:
We thank the drafting team for their efforts but believe this standard needs
additional work. We disagree with including “authority” in this standard. FERC Order
693a, paragraph 112, made it clear that the authority of a registered entity is
established through the approval of the standards by FERC. Thus, a Reliability
Coordinator gets its authority to issue Reliability Directives by having a requirement
that states it must issue Reliability Directives approved by the Commission. Please
change “shall have authority to act” in Requirement R1 back to “shall act.” Please
also remove all other vestiges of authority from the standards including in the
purpose, measures and VSLs. Requirement R1 should require the use of Reliability
Directives. The requirement compels the Reliability Coordinator “to direct others to
act to prevent identified events or mitigate the magnitude or duration of actual
events that result in an Emergency or Adverse Reliability Impact.” Reliability
Directives are necessary to address Adverse Reliability Impacts or Emergencies and
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trigger the use of three-part communications identified in COM-002-3.
The RCSDT believes that other standards (i.e., IRO-009 - R3 & R4, EOP-002 - R1 and
R8) address the action of others; and if the term “authority” is omitted, creates a
generic requirement. Such as what has been suggested puts the RC in a double
jeopardy situation. No change made.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive
for Emergencies and Adverse Reliability Impacts with the opening clause: “When a
Reliability Coordinator, Transmission Operator, or Balancing Authority determines
actions need to be executed as a Reliability Directive.” What else could be more
important for a Reliability Coordinator to issue a Reliability Directive than for an
Emergency or Adverse Reliability Impact?
Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts
and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. For clarity
and consistency, Requirement R2 and R3 should also be clear that the responsible
entities will respond to the Reliability Coordinator’s Reliability Directives.
The RCSDT notes that IRO-001-3 addresses direction, which may include a Reliability
Directive. The responsible entity receiving the direction, at a minimum, must comply
with the RC’s direction, unless the receiver cannot physically implement or unless
such actions would violate safety, equipment, regulatory, or statutory requirements.
The standard IRO-001-3 is not limited to only actions that are Reliability Directives.
On the other hand, the standard COM-002-3 requires the BA, RC, and TOP to identify
the communication as a Reliability Directive and to use three-part communication
when actions are required to be executed as a Reliability Directive. No change made.
Furthermore, this would make the standard consistent with how Reliability Directives
are handled by the Transmission Operator in the draft TOP-001-2 standard proposed
by the Real-Time Operations drafting team (Project 2007-03). We do not agree with
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the need to include Distribution Provider in IRO-001-3. The Distribution Provider will
likely never receive a Reliability Directive directly from its Reliability Coordinator.
More likely, the Reliability Directive will be issued by the Transmission Operator or
Balancing Authority depending on if the issue is security or adequacy related.
The RCSDT notes that IRO-001-3 is an authority standard, the DP may not likely
receive a Reliability Directive from the RC; however, in the case they do, they are
required to comply with the requirement. No change made.
Response: See response above.
Northeast Utilities
Negative
NU contributed in and joins on the comments submitted by NPCC.
Response: Thank you for your comment.
MidAmerican Energy Co.
Negative
COM-001-2:
The definition of Interpersonal Communication is too broad and should be revised to
read,
"the primary defined communication system used to communicate between NERC
defined reliability entities when operating the Bulk Electric System."
Examples may include a telephone system as a primary system and an email system
as an alternative system.
R11 is too broad and should either be deleted or revised to read:
“Each Distribution Provider and Generator Operator that experiences a failure of its
defined primary Interpersonal Communication capabilities with its Transmission
Operator or Balancing Authority...“
The RCSDT deliberately avoided the use of primary and secondary mediums and
elected to use communications capabilities. As such, R11 applies to Interpersonal
Communication capabilities of the DP and GOP. The RCSDT has gone to great lengths
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to provide some flexibility for those DPs and GOPs with little or no impact on the
reliability of the BES. FERC directed NERC to provide for this consideration.
Therefore, we use the language as proposed in R11. Mutually agreeable implies that
both parties are willing to accept the outcome. It doesn’t mean that a DP or GOP
must comply with the wishes of its TOP or BA because as you state that could be
beyond the control of the DP or GOP. No change made.
The use of the word “any” could end up applying to an intercom and not to a primary
mode of communication such as telephone system or email system.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The latter part of R11 states; “...shall consult with their Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable time to restore
the Interpersonal Communication capability.” This ambiguous statement does not
support reliability. Consulting with a TOP or BA does not solve the problem of the
lack of Interpersonal Communication capabilities. This statement should be deleted
or revised to read:
“Each Distribution Provider and Generator Operator that experiences a failure of its
defined primary Interpersonal Communication with their Transmission Operator or
Balancing Authority shall notify the applicable TOP or BA as to the status of the
Interpersonal Communication capability.”
The RCSDT believes non-compliance is not due solely to the failure of any
Interpersonal Communication capability, but must be accompanied by a failure to
consult with the applicable Transmission Operator or Balancing Authority to
establish mutually agreeable action for restoration. No change made.
Response: See response above.
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SERC OC Standards Review
Group
Yes or No
Question 6 Comment
COM-001-2 Comments
Definition of Alternative Interpersonal Communication:
The proposed definition uses the term “medium.”
What is the scope of that?
Telephony is a “medium” but there is wired, wireless, satellite, etc. Was “medium”
intended to differentiate voice, paper, text, email, teletype, or something else?
Does the qualifying term “same” when modifying infrastructure mean something like
voice versus written?
What about situations where the primary telephone system is Voice Over Internet
Protocol (VOIP) and it is using the same computer network infrastructure as an email
or messaging system. That is the “same infrastructure” but a different “medium” R1
and R2 –
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
We suggest the drafting team look at Standard EOP-008, Requirements R3 and R8
and add appropriate language in Standard COM-001-2, to avoid instantaneous noncompliance for loss of Interpersonal Communications and/or alternate Interpersonal
communications.
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard.
The RCSDT believes that prescribing a device or medium would limit an entity;
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therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
R1 - In later requirements it is proposed that the entity “...shall designate an...” It is
suggested that for consistently and audit ability, this concept be used for R1, R3, R5,
R7 and R8.
In addition, the qualifier of “primary” should be used such that the requirements
read:
“... shall have designated, primary Interpersonal Communications capability with the
following entities:”
Although it is appropriate that “Alternative” be capitalized since it is used in a
defined term (i.e. Alternative Interpersonal Communication”) that bounds
acceptable alternative methods , we do not see the need to capital “primary.”
Each entity listed must “have” an Interpersonal Communication capability and for
Alternative Interpersonal Communication capability able to “designate” the
alternate. The team established these requirements to provide flexibility to the
industry. No change made.
R9 - The requirement is unclear if the required monthly test is a general functionality
test or if there is the expectation of testing the designated Alternative Interpersonal
Communications with all of the entities defined in the sub-requirements of R2, R4,
and R6.
There is no expectation of testing the primary Interpersonal Communications - is this
intentional or an oversight?
Although functional testing of this should be done as a normal course of business,
should an explicit test be required with each entity in the sub-requirements of R1,
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R3, R5, R7 and R8 to insure, for example, that all the phone numbers are correct?
COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is not to
have the repair completed within two hours. The requirement recognizes that the
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability, and then, if it decides to do so, designate
another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
R10 - The following scenario seems plausible:
The Interpersonal Communications fails and is detected at 14:00 and gets fixed at
14:35. It lasted more than 30 minutes but is fixed. As written the requirement
would require the responsible entity to notify entities identified in R1 through R6 by
15:00 (i.e. 60 minutes from detection) even though the problem no longer exists. Is
that the expectation?
The RCSDT proposes that upon detection of failure that continues at least 30
minutes, starts the 60-minute clock. The 30 minutes allows an entity time to restore
or determine if they can restore its Interpersonal Communication capability before
the clock starts. No change made.
Does COM-001 apply only to primary control centers or back-ups, per EOP-008, as
well?
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard. No change made.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
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flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
M9 reads “at least on a monthly basis.” We suggest that this be changed to “at least
once per calendar month” as written in R9. This change should also be corrected in
the VSLs.
The RCSDT agrees and the language in M9 has been changed to agree with the
language in R9 and the VSL.
M8 - We suggest removing the second “that” in the first sentence of the measure.
COM-001-2, M8: The RCSDT agrees and the language in M8 has been changed to
delete the additional “that.”
M10 - We suggest this be revised to coincide with changes made in R10 (deleting
impacted and adding as identified in Requirements R1 through R6), therefore M10
should read:
“Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1 through R6 within 60 minutes of the detection of a failure of its
Interpersonal Communications capabilities that lasted 30 minutes or longer. Evidence
could include, but is not limited to dated operator logs, dated voice recordings or
dated transcripts of voice recordings, electronic communications, or equivalent
evidence. (R10.)”
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP and the BA.
M12 needs to be removed.
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The RCSDT appreciates your comment and has deleted Measure M12 that was left in
error.
We question why the first paragraph of Section 1.3 - Data Retention has been
included in each of these three standards. We suggest that it should be removed
from each standard.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
COM-002-3 Comments
R2 - We recommend that the following phrase (in quotes) be added to R2:
Each Balancing Authority, Transmission Operator and Distribution Provider that is
the recipient of a Reliability Directive shall repeat, restate, rephrase or recapitulate
the Reliability Directive “immediately upon receiving it.” As written, there is no limit
as to when the entity must repeat it (i.e. they could wait 2 hours)The Standard is not
clear as to what each entity is to do when more than one entity receives a Reliability
Directive at the same time (e.g. during a RC area teleconference call). For example,
is a roll call of receiving entities expected to be held so that they individually can
repeat, restate, rephrase or recapitulate the Reliability Directive followed by
individual confirmation required in R3?
The requirement is aimed at being a performance-based requirement and states a
description of “what” communication must take place, but does not prescribe “how”
the communication is to be made. Adding the suggested phrase “immediately upon
receiving it” introduces the ambiguous term “immediately,” for which there is
neither plain meaning nor simple explanation. What must happen is that the
recipient must respond in such a way that the issuer may determine whether the
message has been properly understood. The RCSDT concludes that the proposed
language gives plain meaning. No change made.
IRO-001-3 Comments
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We recommend that where the verb “direct/directed” or noun “direction” is used in
Purpose, R1, R2 and R3, that it be replaced with the verb “instruct/instructed” or
noun “instruction”, as appropriate. This would help the industry avoid confusion
often referred to as “big D” or “little d” directives. It is noted that the term
“Reliability Directive” does that to a great degree but avoiding the verb/noun
“direct/direction” would augment the difference.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. No change made.
R1 - At what point in time is “identified” referring to in “...to prevent identified
events or...?” Is it referring to current or future events? One might assume both
since the “Time Horizon” is defined as Real-time Operations, Same Day Operations
and Operations Planning, but the requirement may be enhanced if explicitly stated
(“...to prevent events identified in real-time or in the future or to mitigate the
magnitude...”).
The context of “identified” is when a set of system conditions is recognized that
could lead to an Emergency or Adverse Reliability Impact, which may require action.
See standards IRO-008 and IRO-009. No change made.
For clarity, the scope of the authority should be limited to the Reliability Coordinator
Area (“...that result in an Emergency or Adverse Reliability Impacts within its
Reliability Coordinator Area”). As written, it implies the authority should extend
outside its RC Area.
The RCSDT believes that limiting the scope to the RC’s area would be too limiting and
not account for potential conditions where an adjacent RC may have lost its widearea view and requests the assistance of another RC or vice-versa. No change made.
R2 - We question the phrase “physically implemented” and recommend that the
intent be clarified in the language.
The RCSDT believes there may be conditions where an entity may not be able to
physically implement the direction. For example, an entity that does not have the
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right to access certain equipment or cannot manually operate a broken apparatus.
We feel the proposed language achieves the intended purpose. No change made.
We note the following comment and response posted under Consideration of
Comments on Initial Ballot - Reliability Coordination (Project 2006-06) Date of Initial
Ballot: February 25 - March 7, 2011:
“IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower
case (while it appears that “Directives” is a subset of “directions”). We believe that
this muddies the waters and could bring numerous conversations and dialog into
scope unnecessarily. The end result is that the RC has the right to issue and use
“Directives” and anything short of this could just be communications. For example, a
number of entities that are Reliability Coordinators also facilitate energy markets.
There are many communications related to markets that probably should be out of
scope with respect to the standards. Furthermore, it might not be clear what role
(e.g., Reliability Coordinator, market operator, etc) the staff at these entities is
fulfilling. Response: IRO-001 is written to cover both typical daily operating scenarios
and also emergency scenarios. The required performance encompasses issuing and
responding to Reliability Directives as well as other directions. The requirement
language specifically ties back to Requirement R2 which states that the RC “shall
take actions or direct actions, which could include issuing Reliability Directives.” This
is the “direction in accordance with Requirement R2” stated in R3 and the “direction
in accordance with Requirement R3” stated in R4.”We believe the entity’s comments
remain valid and the response provided by the SDT does not address all aspects of the
concern.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
We suggest that the language be changed to “Reliability Directive” consistent with
COM-002.
R3 - The requirement states the responsible entities shall “inform” its RC when
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unable to perform as directed but it is unclear when the notification needs to take
place. Although the term “as soon as practical” may seem be un-measureable, as
written now there is no time deadline to perform the notification - i.e. it could be 4
hours later after recognition.
The proposed requirement uses the term “upon recognition.” No change made.
M2 - need to add the following words “compliance with, physically, unless” which
were included in R2, therefore M2 should read:
The RCSDT thanks you for your comment and has added the word “physically” to the
IRO-001-2, Measure M2.
“Each Transmission Operator, Balancing Authority, Generator Operator, Interchange
Coordinator and Distribution Provider shall have and provide evidence which may
include, but is not limited to dated operator logs, dated records, dated and timestamped voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent documentation, that will be used to determine that it
complied with its Reliability Coordinator's direction(s) per Requirement R1 unless
compliance with the direction per Requirement R1 could not be physically
implemented or unless such actions would have violated safety, equipment,
regulatory or statutory requirements. In such cases, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution
Provider shall have and provide copies of the safety, equipment, regulatory or
statutory requirements as evidence for not complying with the Reliability
Coordinator’s direction”
(R2) “Section 1.3, the second bullet; need to add calendar to 12 calendar months.”
The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review group only and should not be
construed as the position of SERC Reliability Corporation, its board or its officers.”
The RCSDT appreciates your comments and conforming changes have been made to
the Data Retention section.
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Response: See response above.
Pacific Northwest Generating
Cooperative
The PNGC Comment Group believes COM-002-3, R2, lacks justification for
applicability to a Distribution Provider (DP). RCs in the WECC region do not
communicate reliability directives to DP only entities. Having this requirement apply
to DPs seems to indicate that we will need 24/7 communications capability to record
and respond to calls that will never come in order to satisfy the requirement with no
improvement to reliability. The SDT’s response from the last round of comments:
“It is the expectation that an issuer of a Reliability Directive would request a return
call by the Distribution Provider operating personnel, then issue the Reliability
Directive.” Nowhere is this expectation provided for in the written standard. If the
issuer of a reliability directive has already called the DP, are they going to then reissue the reliability directive after the DP calls them back?
Response: In COM-002-3, the DP may or may not receive a Reliability Directive from the RC; however, in the case they do, they are
required to comply with the requirement. The measures do not require recordings. Evidence may include things like dated operator
logs. No change made.
Northeast Power Coordinating
Council
For COM-001:
1. R1.2 and R2.2: The phrase “within the same Interconnection” is improper; it
needs to be removed. RCs between two Interconnections still need to communicate
with each other for reliability coordination (e.g. between Quebec and the other RCs
in the NPCC region to coordinate reliability issues including curtailing interchange
transactions crossing an Interconnection boundary). The SDT’s response to industry
comments on the previous posting that the phrase was added to address the ERCOT
situation (that ERCOT does not need to communicate with other RCs and that such
coordination takes place between TOPs) leaves a reliability gap.
Requirement R1 addresses a reliability need for adjacent Reliability Coordinators
synchronously connected within the same Interconnection to have Interpersonal
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Communication capability; however, it does not preclude or limit the Reliability
Coordinator from establishing Interpersonal Communication capability with others.
The RCSDT does not see where there is a need to communicate with other Reliability
Coordinator’s from one interconnection to another. No change made.
2. R3.5 and R4.3: The phrase “synchronously connected within the same
Interconnection” is also improper; it needs to be removed. TOPs do communicate
with other TOPs including those asynchronously connected and in another
Interconnection (e.g. between Quebec and all of its asynchronously interconnected
neighbors). The reason that was used in response to the above comments
(coordination among TOPs for DC tie operation) contradicts with the inclusion of this
phrase in R3.5 and R4.3.
The RCSDT has made clarifying changes by adding Parts to R3 and R4 to address
asynchronous connections between Transmission Operators and have eliminated the
phrase “within the same interconnection.”
COM-001-2, R3.5 and R4.3: Use of the phrase “within the same interconnection.”
The RCSDT recognizes that operating activities occurring inside an interconnection
that is not synchronously interconnected with another interconnection cannot cause
immediate effects upon that interconnection. Any changes in flow across any
asynchronous tie between those interconnections must take place through a
coordinated interchange energy scheduling process, except for contingency loss the
asynchronous ties. In the case of the latter, there is no other path which can be used
to address the loss of the asynchronous tie, nor is any synchronous tie immediately
affected. The standard does not require such involved RCs to have Interpersonal
Communication capability, but does not preclude it. Any rearrangement of
scheduled flows on other asynchronous ties must be done through a pre-existing
interchange energy scheduling process. No change made.
3. R4 and R6: Not requiring an Alternative Interpersonal Communication capability
between the BAs and the DP and GOP can result in a reliability gap. If Interpersonal
Communication capability between the BAs and these entities is required to begin
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with to enable BAs to communicate with these entities (such as operating
instructions or Reliability Directives) to ensure reliable operations, then an
alternative capability is also needed to ensure this objective is achieved when the
primary capability fails.
The RCSDT refers the Order No. 693 in Paragraph 508 to clarify the reason the DP
and GOP are not required to have Alternative Interpersonal Communication and is as
follows: “(1) expands the applicability to include Generator Operators and
Distribution Providers and includes Requirements for their telecommunications
facilities; (2) identifies specific requirements for telecommunications facilities for use
in normal and Emergency conditions that reflect the roles of the applicable entities
and their impact on Reliable Operation and (3) includes adequate flexibility for
compliance with the Reliability Standard, adoption of new technologies and costeffective solutions.” In addition, R11 requires the DP and GOP to consult with its BA
and TOP to determine a mutually agreeable action for restoration. No change made.
4. To preclude the possibility of problems arising from having different languages
spoken between entities, COM-001-1.1 R4 should remain as it was or those ideas
kept in the revised requirement. R4 read:
“R4. Unless agreed to otherwise, each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use English as the language for all
communications between and among operating personnel responsible for the realtime generation control and operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use an alternate language for
internal operations.”
According to the proposed implementation plan for COM-001-2, R4 pertaining to the
use of English will remain in effect upon the effective date of COM-001-3. This
requirement is being revised and will be included in Standard COM-003-1, Operating
Personnel Communications Protocols. COM-001-1.1, R4 will be retired at midnight
the day before COM-003-1 becomes effective. No change made.
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5. Measure M3 does not cover the added R3.5 condition (having Interpersonal
Communications capability with each adjacent TOP). M3 needs to be revised.
The RCSDT thanks you for your comment and has made conforming changes to make
to Measure, M3.
For IRO-001:
The Data Retention Section does not reflect the revised requirements. As examples:
the Electric Reliability Organization is no longer a responsible entity; the Reliability
Coordinator should replace the ERO for keeping data for R1.
Transmission Operator, Balancing Authority, Generator Operator and Distribution
Provider should replace the Reliability Coordinator for keeping data for R2.
And, in the Data Retention Section, R4 and M4 are mentioned. However, there are
only three requirements with their corresponding measures in the standard.
Response: The RCSDT thanks you for your comment and has made conforming changes to IRO-001-3.
MRO NSRF
Has the SDT looked at combining COM-002-3 and IRO-001-3 into a single Standard?
It would allow Entities a one stop shopping place to refer to issuing and receiving a
Reliability Directive.
The RCSDT understands some of the benefits with combining the standards;
however, at this juncture, it would further delay the progress of the standards. No
change made.
The definition of Interpersonal Communication is:
“Any medium that allows two or more individuals to interact, consult, or exchange
information.” As stated in Question 4, the use of the word “any” will bring in
mediums that are outside the scope of this Standard.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
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change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The NSRF recommends the following:
Interpersonal Communication: The primary (or designated) medium that allows two
or more individuals to interact, consult, or exchange information.
The RCSDT emphasizes the requirement refers only to Interpersonal Communication
capabilities. Adding the phrase “to the primary” is not needed. Please refer to the
definitions of Interpersonal Communication and Alternative Interpersonal
Communication for clarification. No change made.
In Standard COM-002-3 the MRO NSRF recommends that the Effective Date be the
first day of the second calendar quarter after applicable regulatory approval, to be
the same as COM-001-2 and IRO-001-3. In that way all 3 standards would be
effective at the same time, making implementation much smoother.
The RCSDT thanks you for your comment and has made conforming changes to
adjust IRO-001 to be the same as COM-001 and COM-002.
The below section will lead to entities hold evidence past the 12 month retention
period. This ambiguous wording will force entities to hold data past the 12 month
period as stated in the following paragraph, after the below sighting. Recommend
that the first paragraph within 1.3 be deleted in its entirety.
1.3. Data Retention The following evidence retention periods identify the period of
time an entity is required to retain specific evidence to demonstrate compliance. For
instances where the evidence retention period specified below is shorter than the
time since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
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Response: See response above.
CCG, CPG, CECD
Comments: IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3.
To avoid confusion with a Reliability Directive (both for auditors and entities), we
suggest the following: To establish the authority of Reliability Coordinators to make
requests of other entities to prevent an Emergency or Adverse Reliability Impacts to
the Bulk Electric System.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. No change made.
R1: Each Reliability Coordinator shall have the authority to act or request others to
act (which could include issuing Reliability Directives) to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or
Adverse Reliability Impacts.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. The RCSDT believes by using the word
“request” make the requirement conditional and is not consistent with the purpose
of the standard. No change made.
R2: Each Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider shall comply with its Reliability Coordinator’s request unless
compliance with the request cannot be physically implemented, or unless such
actions would violate safety, equipment, regulatory or statutory requirements, or
unless the TOP, BA, GOP or DP convey a business reason not to comply with the
request but express that they will comply if a Reliability Directive is given.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. The RCSDT believes by using the word
“request” make the requirement conditional and is not consistent with the purpose
of the standard. No change made.
R3: Each Transmission Operator, Balancing Authority, Generator Operator, and
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Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as requested in accordance with Requirement R2.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. The RCSDT believes by using the word
“request” make the requirement conditional and is not consistent with the purpose
of the standard. No change made.
Response: See response above.
LG&E and KU Services
Company
COM-001-2
Regarding COM-001-2 and proposed definitions, LG&E and KU Services recommends
changing the terms being defined from “Interpersonal Communications” and
“Alternative Interpersonal Communication” to “Means for Interpersonal
Communication” and “Alternative Means for Interpersonal Communication.” A
communication is an exchange of information, not a medium. The medium is simply
the means. LG&E and KU Services Company further recommend that each
requirement be rewritten with these new defined terms as appropriate and that the
word “capabilities” currently following the defined terms be removed from each of
the requirements.
We suggest the definition for “Means for Interpersonal Communication” be: “A
medium utilizing electromagnetic energy that allows two or more individuals to
interact, consult or exchange information.”
We suggest the definition for “Alternative Means for Interpersonal Communication”
be: “Any Means for Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Means for
Interpersonal Communications used for day-to-day operation.”
The RCSDT thanks you for your comment; however, great lengths were taken in
communicating mediums regarding IC and AIC and finds that adding “Means” to the
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proposed terms being defined diminishes clarity of the definition. No change made.
Finally, LG&E and KU Services Company request clarification that the requirements
to have in place Interpersonal Communications and Alternative Interpersonal
Communications do not establish non-compliance for the unavailability of either
medium provided the reporting requirements set forth in the standard are otherwise
met.
The RCSDT believes a condition of non-compliance will not be created if the entity
meets all of the requirements for Interpersonal Communication and Alternative
Interpersonal Communication capability. For example, the applicable entity has a
failure of the IC and notifies the identified entities and begins using its AIC. No
change made.
All Proposed Standards LG&E and KU Services Company suggest that the first
paragraph in section 1.3 Data Retention be removed from all proposed standards. It
states: ...For instances where the evidence retention period specified below is
shorter than the time since the last audit, the Compliance Enforcement Authority
may ask an entity to provide other evidence to show that it was compliant for the full
time period since the last audit. While LG&E and KU Services Company is confident
that the SDT intended to clarify entities’ data retention responsibilities, this
paragraph could be clarified to indicate that it does not require that any additional
evidence be retained and provided beyond that written in the standard’s
requirements.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
Response: See response above.
Bonneville Power
Administration
BPA supports COM-001-2, COM-002-3 and IRO-001-3 as written and has no
comments or concerns at this time.
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Response: Thank you for your comment.
SPP Standards Review Group
COM-001-2:
Requirement 10 is too open ended as written.
The measure, M10, indicates that only impacted entities need to be notified. The
requirement should be changed to make it consistent with the measure. The
requirement would then read:
“Each RC, TOP And BA shall notify impacted entities as identified...”
Requirements 3 and 5 places the responsibility for establishing Interpersonal
Communication capability on the TOP and BA. It is quite conceivable that a TOP or
BA may not know all, or newly, registered DPs and GOPs in its respective area.
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
In Requirements 7 and 8, the DP and GOP, respectively, are in turn responsible for
establishing Interpersonal Communication capability. The TOPs/BAs and the
DPs/GOPs should not be responsible for this. The DPs and GOPs should be held
accountable for requesting that capability of their TOP and BA.
The standard establishes requirement for communication capability appropriate to
ensure reliability. There is no requirement for it to be different from the
Interpersonal Communication capability that its Balancing Authority has with it, nor
the Interpersonal Communication capability that its Transmission Operator has with
it. Cooperation and coordination is always encouraged and is an excellent practice,
but is not required by this standard. Thank you for your suggestion. No change
made.
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Therefore, we suggest adding the following phrase at the end of Requirements 3.3,
3.4, 5.3 and 5.4 - ‘that has requested Interpersonal Communications capability.’ Then
R3.3 would read:
“Each Distribution Provider within its Transmission Operator Area that has requested
Interpersonal Communications capability.”
The SDT does not agree that these changes to R3.3, R3.4, R5.3 and R5.4 are
necessary. The current R7 and R8 require the DP and the GOP to have this capability.
It is not a request. No change made.
COM-002-3:
Requirement 2/Measure 2: There is an inconsistency between the requirement and
the measure. The requirement allows the recipient to repeat, restate, rephrase or
recapitulate the directive. Measure 1 only mentions repeating the directive.
The RCSDT agrees that M2 needs to match the phrasing used in R2 and has made
clarifying changes.
Response: See response above.
Dominion
COM-001-2; M9 reads “at least on a monthly basis”, Dominion suggests that this be
changed to “at least once per calendar month” as written in R2.
The RCSDT agrees and the language in M9 has been changed to agree with the
language in COM-001-2, R9.
M8 Dominion suggests removing the second “that” in the first sentence of the
measure.
COM-001-2, M8: The RCSDT agrees and the language in M8 has been changed to
delete the additional “that.”
M10 Dominion suggests this be revised to coincide with changes made in R10
(deleting impacted and adding as identified in Requirements R1 through R6),
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therefore M10 should read:
“Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1 through R6 within 60 minutes of the detection of a failure of its
Interpersonal Communications capabilities that lasted 30 minutes or longer. Evidence
could include, but is not limited to dated operator logs, dated voice recordings or
dated transcripts of voice recordings, electronic communications, or equivalent
evidence. (R10.)”
The RCSDT thanks you for your comment and has made conforming changes to make
change “impacted” to “identified” entities.
M12 needs to be removed.
The RCSDT appreciates your comment and has deleted Measure M12 that was left in
error.
IRO-001-3;
R2 - Dominion questions the phrase “physically implemented” and recommends that
the intent be clarified in the language.
The RCSDT believes there may be conditions were an entity may not be able to
physically implement the direction. For example, an entity that does not have the
right to access certain equipment or cannot manually operate a broken apparatus.
We feel the proposed language achieves the intended purpose. No change made.
Dominion notes the following comment and response posted under Consideration of
Comments on Initial Ballot - Reliability Coordination (Project 2006-06) Date of Initial
Ballot: February 25 - March 7, 2011:”
IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower
case (while it appears that “Directives” is a subset of “directions”). We believe that
this muddies the waters and could bring numerous conversations and dialog into
scope unnecessarily. The end result is that the RC has the right to issue and use
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“Directives” and anything short of this could just be communications. For example, a
number of entities that are Reliability Coordinators also facilitate energy markets.
There are many communications related to markets that probably should be out of
scope with respect to the standards. Furthermore, it might not be clear what role
(e.g., Reliability Coordinator, market operator, etc) the staff at these entities are
fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios and also
emergency scenarios. The required performance encompasses issuing and responding
to Reliability Directives as well as other directions. The requirement language
specifically ties back to Requirement R2 which states that the RC “shall take actions
or direct actions, which could include issuing Reliability Directives.” This is the
“direction in accordance with Requirement R2” stated in R3 and the “direction in
accordance with Requirement R3” stated in R4.”Dominion believes the entity’s
comments remain valid and the response provided by the SDT does not address all
aspects of the concern.
Dominion suggests that the language be changed to “Reliability Directive” consistent
with COM-002.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
M2 - need to add the following words “compliance with, physically, unless” which
were included in R2, therefore M2 should read:
“Each Transmission Operator, Balancing Authority, Generator Operator, Interchange
Coordinator and Distribution Provider shall have and provide evidence which may
include, but is not limited to dated operator logs, dated records, dated and timestamped voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent documentation, that will be used to determine that it
complied with its Reliability Coordinator's direction(s) per Requirement R1 unless
compliance with the direction per Requirement R1 could not be physically
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implemented or unless such actions would have violated safety, equipment,
regulatory or statutory requirements. In such cases, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution
Provider shall have and provide copies of the safety, equipment, regulatory or
statutory requirements as evidence for not complying with the Reliability
Coordinator’s direction. (R2)“
The RCSDT thanks you for your comment and has added the word “physically” to the
IRO-001-2 Measure M2.
Section 1.3, the second bullet; need to add calendar to 12 calendar months
The RCSDT appreciates your comments and conforming changes have been made to
the Data Retention section.
Response: See response above.
FirstEnergy
Definition of Interpersonal Communications.
We understand that the team does not want to be prescriptive as far as the specific
types of communication mediums since we live in an age of many forms of
communication. But in this case it may be helpful to give examples in the definition.
An auditor may interpret Interpersonal Communication to strictly include voicerelated and two-way conversations. Depending on the circumstances, other
mediums may be adequate, such as blast calls or instant messaging. This should be
clarified in the definition.
COM-001-2.
In R9, it should be clear that the 2-hour timeframe is for initiation of corrective
action because mitigation may take much longer. We suggest the last sentence of R9
state: “If the test is unsuccessful, the responsible entity shall, within 2 hours, initiate
action to repair or designate a replacement Alternative Interpersonal
Communications capability.
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COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is NOT
to have the repair completed within two hours. The requirement recognizes that the
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability, and then, if it decides to do so, designate
another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
In R10, the phrase “R1 through R6” should state “R1 through R8.”
The RCSDT thanks you for your comment; alternatively, the RCSDT has modified the
language of R10 to refer to R1, R3, and R5, rather than “R1 through R6,” since the
responsible entities are limited to the RC, the TOP, and the BA in these requirements.
COM-002-3
In R2, the use of the term recapitulate may not be appropriate. This term means “to
summarize” the directive. Three-part communication during emergency situations
should assure that the essential details of the directives are understood and a
summary may inadvertently leave out important information.
The RCSDT carefully considered the use of the term “recapitulate,” and believes it
correctly captures the intent. No change made.
The effective date of COM-002-3 should be consistent with COM-001-2 and IRO-0013 and state “the 1st calendar day of the 2nd calendar quarter.” It currently shows the
“1st calendar quarter in the standard and implementation plan.
The RCSDT thanks you for your comment and has made conforming changes to
adjust IRO-001 to be the same as COM-001 and COM-002.
IRO-001-3
The third bullet under Data Retention addresses requirement R4 and measure M4
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neither of which exist in the standard.
The RCSDT thanks you for your comment and has made conforming changes.
In R1, the word “and” is missing between Generator Operator and Distribution
Provider.
The RCSDT thanks you for your comment and has made conforming changes to IRO001, R2.
VSL for R2 - “N/A” should be removed from the High VSL - Furthermore, the VSL
should include language for instances when the entity cannot meet the RC’s directive
as afforded by R2.
The RCSDT thanks you for your comment and has made conforming changes to IRO001, R2 VSL.
Response: See response above.
MISO Standards Collaborators
The Data Retention Section in IRO-001 does not reflect the revised requirements. For
example: the Electric Reliability Organization is no longer a responsible entity; the
Reliability Coordinator should replace the ERO for keeping data for R1; Transmission
Operator, Balancing Authority, Generator Operator and Distribution Provider should
replace the Reliability Coordinator for keeping data for R2; and there is no R4/M4.
The RCSDT thanks you for your comment and has made conforming changes.
Additional comments associated with COM-002
We are concerned with the use of ‘shall’ in the measurement sections. ‘Shall’
statements should only be used in the Requirements, as these are the only
enforceable items in the standard. The measures should not limit how we show
compliance. If there are specific issues that the drafting team is proposing to be a
requirement, they should be added to the requirements section of the standard.
The RCSDT has checked the usage of “shall” in other standards and has found it to be
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consistent with writing measures. The RCSDT notes the measures are examples and
the entity is not limited to those examples. No change made.
Measurement M1 should also allow entities to develop procedures that are
distributed to and trained on in advance with recipients of directives that meet the
requirements for the communication of what constitutes a Reliability Directive. The
last sentence in the measurement should be revised to read:
“Such evidence could include, but is not limited to, dated and time-stamped voice
recordings, dated and time-stamped transcripts of voice recordings, or dated
operator logs to show that it identified the action as a Reliability Directive to the
recipient or approved procedures that identify what constitutes a Reliability Directive
and when Reliability Directives are issued.”
The RCSDT believes that M1 does not preclude an entity from developing, having or
utilizing procedures as evidence to address Reliability Directives. No change made.
(R1) The Data Retention section states; ’For instances where the evidence retention
period specified below is shorter than the time since the last audit, the Compliance
Enforcement Authority may ask an entity to provide other evidence to show that it
was compliant for the full time period since the last audit.’
It is unclear on how an entity would be expected to provide evidence beyond 3
months when requested if the data retention period and established procedures do
not require the evidence to be retained.
The SDT should provide examples of what other types of evidence could be expected
or the phrase should be removed.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
Response: See response above.
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Florida Municipal Power
Agency
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In the definition of Interpersonal Communication, the use of the word “medium” is
ambiguous. Suggestions for alternatives: “system”, “channel.”
The RCSDT deliberately stayed away from the use of primary and secondary
mediums, and prefers to use communications capabilities. Further, the RCSDT has
gone to great lengths to provide some flexibility for those DPs and GOPs with little or
no impact on the reliability of the BES. FERC directed NERC to provide for this
consideration. Therefore, we use the language as proposed in R11. Mutually
agreeable implies that both parties are willing to accept the outcome. It doesn’t
mean that a DP or GOP must comply with the wishes of its TOP or BA because as you
state that could be beyond the control of the DP or GOP. But what transpires in the
consultation is a realization of what the situation is, what the impacts to reliability
are and a determination of what is amicable to both parties. No change made.
COM-001-2, R1 and R3, the phrase:
“have Interpersonal Communications capabilities”, what if the communication
system fails? Is that an immediate non-compliance (especially R3.3 and R3.4 which
do not require a redundant system).
Suggest using EOP-008 type of language to allow restoration of failed equipment
without non-compliance.
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
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COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications
capability", suggest adding the phrase "to each entity for which Alternative
Interpersonal Communications is required" to add clarity. In addition, the type of
testing is unclear and ambiguous.
The RCSDT proposes that R9 correctly identifies and provides clarity for the entities
required to have Alternative Interpersonal Communication capability. No change
made
The is also ambiguity in the terms “direct”, “directive”, “direction” and “Reliability
Directive.” The SDT may want to consider using the terms “instruct” and
“instruction” in place of “direct”, “directive”, “direction” to more clearly distinguish
from a Reliability Directive.
The RCSDT feels the use of “direct” and “directed” is consistent with the purpose and
application of those terms in other standards. No change made.
Response: See response above.
ACES Power Marketing
Standards Collaborators
The following comments are regarding IRO-001-3.
We disagree with including “authority” in this standard. FERC Order 693a, paragraph
112, made it clear that the authority of a registered entity is established through the
approval of the standards by FERC. Thus, a Reliability Coordinator gets its authority
to issue Reliability Directives by having a requirement that states it must issue
Reliability Directives approved by the Commission. Please change “shall have
authority to act” in Requirement R1 back to “shall act.”
Please also remove all other vestiges of authority from the standards including in the
purpose, measures and VSLs.
The RCSDT believes that other standards (i.e., IRO-009 - R3 & R4, EOP-002 - R1 &R8)
address the action of others and if the term “authority” is omitted, creates a generic
requirement such as what has been suggested puts the RC in a double jeopardy
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situation. No change made.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
Requirement R1 should require the use of Reliability Directives. The requirement
compels the Reliability Coordinator “to direct others to act to prevent identified
events or mitigate the magnitude or duration of actual events that result in an
Emergency or Adverse Reliability Impact.” Reliability Directives are necessary to
address Adverse Reliability Impacts or Emergencies and trigger the use of three-part
communications identified in COM-002-3.
The RCSDT views R1 as an authority requirement to direct others, which could
include a subset of direction called, Reliability Directive. Requirement R2 is the
response requirement for the recipient. The judgment the recipient is under is that
the recipient must comply with the direction, unless the direction cannot be
physically implemented or unless such actions would violate safety, equipment,
regulatory or statutory requirements. Requirement R3 is simply requires the
recipient to inform the issuer of its inability to perform the direction. No change
made.
COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive
for Emergencies and Adverse Reliability Impacts with the opening clause:
“When a Reliability Coordinator, Transmission Operator, or Balancing Authority
determines actions need to be executed as a Reliability Directive.”
What else could be more important for a Reliability Coordinator to issue a Reliability
Directive than for an Emergency or Adverse Reliability Impact?
Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts
and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. For clarity
and consistency, Requirement R2 and R3 should also be clear that the responsible
entities will respond to the Reliability Coordinator’s Reliability Directives.
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Furthermore, this would make the standard consistent with how Reliability Directives
are handled by the Transmission Operator in the draft TOP-001-2 standard proposed
by the Real-Time Operations drafting team (Project 2007-03).
The RCSDT development of IRO-001-3 R1 states “…which could include issuing
Reliability Directives…” and therefore does not preclude its use if it is determined by
the RC to use it. There may be instances where the RC discusses operational issues
in normal dialogue with entities that do not require the use of Reliability Directive.
No change made.
The Data Retention section needs to be modified. The first bullet applies to the
Electric Reliability Organization and Requirement R1 and Measure M1. The actual
requirement and measure apply to the Reliability Coordinator. Furthermore, five
calendar years exceeds the audit period of three years for a Reliability Coordinator.
The RCSDT thanks you for your comment and has removed this bullet.
The second bullet incorrectly applies to the Reliability Coordinator and Requirement
R2 and Measure M2. Requirement R2 and Measurement M2 apply to Transmission
Operators, Balancing Authorities, Generator Operators and Distribution Providers.
The third bullet mentions Requirement R4 and Measurement M4.
The RCSDT thanks you for your comment and has made conforming changes.
There is no Requirement R4 and Measurement M4 in the standard.
The RCSDT thanks you for your comment and has made conforming changes.
The VSLs for Requirement R1 are not consistent with the requirement. The VSL
states that it is for failure to act while the requirement compels the Reliability
Coordinator to have the authority to act. This modifies the requirement which is not
allowed under FERC VSL guidelines.
The RCSDT thanks you for your comment and will correct the R1 VSL to have the
phrase "exercise their authority" inserted between "to" and "take" in the first
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sentence.
The VSLs for Requirement R2 need to include the “unless” clause from the
requirement. Otherwise, the VSL implies that the responsible entity violated the
requirement for failing to follow the directive even if they could not for one of the
reasons listed in the requirement. This again is not consistent with FERC guidelines
that state VSLs cannot modify the requirement.
The RCSDT did not include the “unless such actions would violate safety, equipment,
regulatory or statutory requirements” portion of the requirement in the VSL because
if an entity could not perform the directed action, there is no violation. No change
made.
The following comments pertain to COM-001-2.
We recommend striking “capability” from all of the requirements. It is not clear to
us how this helps when a definition for Interpersonal Communications is written
already and applies to a communication medium. Furthermore, we think it causes
confusion and actually contradicts the intent of the standard. Because Requirements
R1, R3, R5, R7 and R8 focus on capability, the responsible entity will be in violation
anytime its medium that it uses for the primary capability does not function
properly. Whereas if the requirement stated that the responsible entity was to
designate a primary communications medium, the responsible entity is not in
violation if that medium is not functioning properly. It would be clear that
Requirement R2, R4 and R6 are intended to be complementary.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
Furthermore, it is not clear why Requirements R1, R3, R5, R7 and R8 state that the
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responsible entity shall “have” when the companion Requirements R2, R4, and R6
state “designate.”
The RCSDT believes the requirements achieve the desired intent of the standard.
Each entity listed must “have” an Interpersonal Communication capability and for
Alternative Interpersonal Communication capability able to “designate” the
alternate. The team established these requirements to provide flexibility to the
industry. No change made.
Since Requirement R10 deals with a failure of its Interpersonal Communications
capabilities and not Alternate Interpersonal Communications capability, it should
only refer to the entities in Requirements R1, R3, and R5. Currently, it includes R1
through R6.
COM-001-2, R10: The RCSDT thanks you for pointing this out. The RCSDT has
modified the language of R10 to refer to R1, R3, and R5, rather than “R1 through R6,”
since the responsible entities are limited to the RC, the TOP, and the BA in these
requirements.
(COM-001 M1)
We suggest changing “physical assets” to “demonstration of physical assets.” Since
evidence is provided to the auditor and the auditor takes the evidence with them,
providing them evidence that is a “physical asset” would be problematic. We believe
that the VSLs could be written to provide more gradations. For example, if a
Transmission Operator or Balancing Authority failed to have Interpersonal
Communications capability with a Distribution Provider but had Interpersonal
Communications capability with all other required entities, it has met the vast
majority of the requirement. Since VSLs are a measure of how much the
requirement was missed by the responsible entity, jumping to a Severe VSL does not
seem to adequately capture that the responsible entity met the vast majority of the
requirement. Requirements R4 and R6 even seem to recognize this by not including
Distribution Provider in the list of entities to which the Transmission Operator or
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Balancing Authority are required to designate Alternate Interpersonal
Communications capability.
The following comments pertain to COM-002-3.
The RCSDT believes the Measures address the needed examples of evidence. No
change made.
While COM-002-3 is well written to explain the three-part communications
requirements and makes it perfectly clear when Reliability Directive has been issued,
the opening clause leaves the responsible entity open to second guessing on
whether they should have issued a Reliability Directive. This problem could be
solved by changing the opening clause to:
“When a Reliability Coordinator, Transmission Operator, or Balancing Authority
determines actions need to be executed as a Reliability Directive.” In the second
bullet of Requirement R3, we suggest using “Restate” in place of “Reissue.”
The responsible entity is not really reissuing the Reliability Directive. They are still in
the act of trying to get the Reliability Directive issued and are simply recommunicating it because it was not understood.
Response: The RCSDT believe the offered suggestion does not improve COM-002-3, R1. No change made.
Kansas City Power & Light
R9 - considering the reliability of communication systems and System Operator
attention may be on more important operational concerns, a 2-hour response to a
problem with the alternative means of communication is over sensitive. Allowing for
sometime in an operating shift would be more in line, such as 8 hours.
COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is NOT
to have the repair completed within two hours. The requirement recognizes that the
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability, and then, if it decides to do so, designate
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another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
Violation Severity Levels for COM-001-2: The VSL’s for requirements R1-R8 and R11
do not recognize the efforts of Entities to meet the requirements. If an Entity failed
to establish communications or alternative communications with 1 Entity out of 20
should that be Severe?
The RCSDT believes the requirements are essential to reliable operations; however,
the requirement is Severe more so because it is a pass-fail requirement, and by
definition makes it Severe (binary requirement). No change made.
Implementation Plan for COM-001-2: The implementation plan is too aggressive at
completing in 6 months after regulatory approvals. Establishing agreements with
other RC’s, TOP’s and BA’s for alternative “interpersonal communications” regarding
the various types of communications available that meet these requirements will
take more than 6 months. Recommend 12 months to allow Entities sufficient time to
reach agreements and to establish the communications.
The RCSDT believes that six months is adequate considering additional facilities
should not have to be built to establish communications with the DP and GOP;
similarly, compliance documentation should not impose significant work on the
entities’ part. No change made.
Response: See response above.
Southern Company
We question why the first paragraph of Section 1.3 - Data Retention has been
included in each of these three standards. We suggest that it should be removed
from each standard.
The RCSDT thanks you for your comments. The Data Retention language has been
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updated to be consistent with the Standards Drafting Guidelines.
We suggest the drafting team look at Standard EOP-008, Requirements R3 and R8
and add appropriate language in Standard COM-001-2, to avoid instantaneous noncompliance for loss of Interpersonal Communications and/or alternate Interpersonal
communications (R1 and R2).
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
COM-001-2 Dominion VP:
COM-001-2; M9 reads “at least on a monthly basis”, Dominion suggests that this be
changed to “at least once per calendar month” as written in R9. This change should
also be corrected in the VSLs.
The RCSDT agrees and the language in M9 has been changed to agree with the
language in R9 and the R9 VSL.
M8 - We suggest removing the second “that” in the first sentence of the measure.
COM-001-2, M8: The RCSDT agrees and the language in M8 has been changed to
delete the additional “that.”
M10 - Dominion suggests this be revised to coincide with changes made in R10
(deleting impacted and adding as identified in Requirements R1 through R6),
therefore M10 should read:
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“Each Reliability Coordinator, Transmission Operator, and Balancing Authority, shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1 through R6 within 60 minutes of the detection of a failure of its
Interpersonal Communications capabilities that lasted 30 minutes or longer.
Evidence could include, but is not limited to dated operator logs, dated voice
recordings or dated transcripts of voice recordings, electronic communications, or
equivalent evidence. (R10.)”
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
M12 needs to be removed.
The RCSDT thanks you for your comment and has made the deletion.
Southern: Definition of Alternative Interpersonal Communication: Any Interpersonal
Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communications used for day-to-day
operation.
Comments:
-The proposed definition uses the term “medium.”
What is the scope of that?
Telephony is a “medium” but there is wired, wireless, satellite, etc. Was “medium”
intended to differentiate voice, paper, text, email, teletype, or something else?
-Similar to that last question - does the qualifying term “same” when modifying
infrastructure mean something like voice versus written?
What about situations where the primary telephone system is Voice Over Internet
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Protocol (VOIP) and it is using the same computer network infrastructure as an email
or messaging system. That is the “same infrastructure” but a different “medium”
R1 Each Reliability Coordinator shall have Interpersonal Communications capability
with the following entities: ...”
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
Comments
-In later requirements it is proposed that the entity “...shall designate an...” It is
suggested that for consistently and auditability, this concept be used for R1, R3, R5,
R7 and R8.
Each entity listed must “have” an Interpersonal Communication capability and for
Alternative Interpersonal Communication capability able to “designate” the
alternate. The team established these requirements to provide flexibility to the
industry. No change made.
In addition, the qualifier of “primary” should be used such that the requirements
read “... shall have designated, primary Interpersonal Communications capability
with the following entities:” Although it is appropriate that “Alternative” be
capitalized since it is used in a defined term (i.e. Alternative Interpersonal
Communication”) that bounds acceptable alternative methods , we do not see the
need to capital “primary.”
The RCSDT emphasizes the requirement refers only to Interpersonal Communication
capabilities. Adding the phrase “to the primary” is not needed. Please refer to the
definitions of Interpersonal Communication and Alternative Interpersonal
Communication for clarification. No change made.
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R9 Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communications capability at least once per
calendar month.
Comments
-The requirement is unclear if the required monthly test is a general functionality
test or if there is the expectation of testing the designated Alternative Interpersonal
Communications with all of the entities defined in the subrequirements of R2, R4,
and R6.
-There is no expectation of testing the primary Interpersonal Communications is this
intentional or an oversight?
Although functional testing of this should be done as a normal course of business,
should an explicit test be required with each entity in the subrequirements of R1, R3,
R5, R7 and R8 to insure, for example, that all the phone numbers are correct?
The RCSDT intends each Alternative Interpersonal Communication capability to be
verified functional by testing. If an entity has only one such capability, then only one
test would be required. You further ask whether the absence of required testing of
the “primary” (word is not in the requirement) Interpersonal Communication
capability is intentional. The RCSDT intentionally left it out because the
Communication capability is used routinely and the use is sufficient to demonstrate
functionality. With respect to phone numbers, these are procedural matters to be
addressed by each individual entity and by including phone numbers it would make
the requirement prescriptive. The requirement is to test capability. No change
made.
R10 Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall notify entities as identified in Requirements R1 through R6 within 60 minutes of
the detection of a failure of its Interpersonal Communications capabilities that lasts
30 minutes or longer.
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Comments
-The following scenario seems plausible: The Interpersonal Communications fails and
is detected at 14:00 and gets fixed at 14:35. It lasted more than 30 minutes but is
fixed. As written the requirement would require the responsible entity to notify
entities identified din R1 through R6 by 15:00 (i.e. 60 minutes from detection) even
though the problem no longer exists. Is that the expectation?
The RCSDT proposes that upon detection of failure that continues at least 30
minutes, starts the 60-minute clock. The 30 minutes allows an entity time to restore
or determine if it can restore its Interpersonal Communication capability before the
clock starts. No change made.
General Question
-Does COM-001 apply only to primary control centers or back-ups, per EOP-008, as
well?
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard. No change made.
COM-002-3 Southern
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient.
Comment
It is recommended that the requirement be clarified that the Reliability Directive be
identified as such during its delivery. (e.g., “...shall identify the action as a Reliability
Directive to the recipient during its delivery.”)
The RCSDT believes the suggestion is overly prescriptive and limits the ability for an
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entity to meet the requirement. No change made.
R2 Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of a Reliability Directive shall repeat,
restate, rephrase or recapitulate the Reliability Directive.
Comment
-It is recommended that the requirement be clarified that an entity receiving a
Reliability Directive repeat, restate, rephrase or recapitulate it immediately upon
receiving it. (e.g., “...shall repeat, restate, rephrase or recapitulate the Reliability
Directive immediately upon receiving it.”). As written, there is not limit as to when
the entity must repeat it (i.e. they could wait 2 hours).
The proposed requirement uses the term “upon recognition.” No change made.
General Question
-The Standard is not clear as to what each entity is to do when more than one entity
receives a Reliability Directive at the same time (e.g. during a RC area teleconference
call) . Is, for example, a roll call of receiving entities expected to be held so that they
individually can repeat, restate, rephrase or recapitulate the Reliability Directive
followed by individual confirmation required in R3?
The question about whether a roll call of receiving entities is expected to be held is
asking for prescription of “how” to accomplish what is required. The RCSDT
recognizes that there is more than one way to accomplish the confirmation when
more than one entity received a Reliability Directive at the same time. What is
required is for the recipient to respond in such a way that the issuer may determine
whether the message has been properly understood. One way for that to occur
would be, as you suggest, for the entities to individually respond. Another way
would be for a pre-established protocol or procedure (e.g. roll-call, all-call, etc.) to be
in place and used in such cases. The RCSDT has determined that prescribing “how”
to ensure that “what” is required has been accomplished is not required and that the
individually adopted procedures or protocols could offer many different ways to
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ensure effectiveness. No change made. The RCSDT concept is that “All Call”
compliance is related to having a document that explains how the entity responds.
No change made.
IRO-001-3 Dominion VP:
R2 - Dominion questions the phrase “physically implemented” and recommends that
the intent be clarified in the language.
The RCSDT believes there may be conditions were an entity may not be able to
physically implement the direction; for example, an entity that does not have the
right to access certain equipment or cannot manually operate a broken apparatus.
We feel the proposed language achieves the intended purpose. No change made.
Dominion notes the following comment and response posted under Consideration of
Comments on Initial Ballot - Reliability Coordination (Project 2006-06) Date of Initial
Ballot: February 25 - March 7, 2011:
”IRO-001 R2, R3, and R4 have replaced “Directives” with the word direction in lower
case (while it appears that “Directives” is a subset of “directions”). We believe that
this muddies the waters and could bring numerous conversations and dialog into
scope unnecessarily. The end result is that the RC has the right to issue and use
“Directives” and anything short of this could just be communications. For example, a
number of entities that are Reliability Coordinators also facilitate energy markets.
There are many communications related to markets that probably should be out of
scope with respect to the standards. Furthermore, it might not be clear what role
(e.g., Reliability Coordinator, market operator, etc) the staff at these entities are
fulfilling.
Response: IRO-001 is written to cover both typical daily operating scenarios and also
emergency scenarios. The required performance encompasses issuing and responding
to Reliability Directives as well as other directions. The requirement language
specifically ties back to Requirement R2 which states that the RC “shall take actions
or direct actions, which could include issuing Reliability Directives.” This is the
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“direction in accordance with Requirement R2” stated in R3 and the “direction in
accordance with Requirement R3” stated in R4.”Dominion believes the entity’s
comments remain valid and the response provided by the RCSDT does not address all
aspects of the concern. Dominion suggests that the language be changed to
“Reliability Directive” consistent with COM-002.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
M2 - need to add the following words “compliance with, physically, unless” which
were included in R2, therefore M2 should read:
“Each Transmission Operator, Balancing Authority, Generator Operator, Interchange
Coordinator and Distribution Provider shall have and provide evidence which may
include, but is not limited to dated operator logs, dated records, dated and timestamped voice recordings or dated transcripts of voice recordings, electronic
communications, or equivalent documentation, that will be used to determine that it
complied with its Reliability Coordinator's direction(s) per Requirement R1 unless
compliance with the direction per Requirement R1 could not be physically
implemented or unless such actions would have violated safety, equipment,
regulatory or statutory requirements. In such cases, the Transmission Operator,
Balancing Authority, Generator Operator, Interchange Coordinator or Distribution
Provider shall have and provide copies of the safety, equipment, regulatory or
statutory requirements as evidence for not complying with the Reliability
Coordinator’s direction.”
The RCSDT thanks you for your comment and has added the word “physically” to the
IRO-001-2 Measure, M2.
(R2) “Section 1.3, the second bullet; need to add calendar to 12 calendar months
Southern General recommendation
The RCSDT appreciates your comments and conforming changes have been made to
the Data Retention section.
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-It is recommended that where the verb “direct/directed” or noun “direction” is used
in Purpose, R1, R2 and R3, that it be replaced with the verb “instruct/instructed” or
noun “instruction”, as appropriate. This would help the industry avoid confusion
often referred to as “big D” or “little d” directives. It is noted that the term
“Reliability Directive” does that to a great degree but avoiding the verb/noun
“direct/direction” would augment the difference.
The RCSDT feels the use of direct and directed is consistent with the purpose and
application of those terms in other standards. No change made.
R1 Each Reliability Coordinator shall have the authority to act or direct others to act
(which could include issuing Reliability Directives) to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or
Adverse Reliability Impacts.
Comment
-At what point in time is “identified” referring to in “...to prevent identified events
or...” Is it referring to current or future events? One might assume both since the
“Time Horizon” is defined as Real-time Operations, Same Day Operations and
Operations Planning but the requirement may be enhanced if explicitly stated (“...to
prevent events identified in real-time or in the future or to mitigate the
magnitude...”).
The context of “identified” is when a set of system conditions is recognized that
could lead to an Emergency or Adverse Reliability Impact, which may require action.
See standards IRO-008 and IRO-009. No change made.
-For clarity, the scope of the authority should be limited to the Reliability
Coordinator Area (“...that result in an Emergency or Adverse Reliability Impacts
within its Reliability Coordinator Area”). As written, it implies the authority should
extend outside its RC Area.
The RCSDT believes that limiting the scope to the RC’s area would be too limiting and
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area view and requests the assistance of another RC or vice-versa. No change made.
R2 Editorial comment - The words “compliance with” are in a different font in the
posted version.
The RCSDT thanks you for your comment and has corrected the font in IRO-001, R2.
R3 Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as directed in accordance with Requirement R2.
Comment
The requirement states the responsible entities shall “inform” its RC when unable to
perform as directed but it is unclear when the notification needs to take place.
Although the term “as soon as practical” may seem be un-measureable, as written
now there is no time deadline to perform the notification - i.e. it could be 4 hours
later after recognition.
The proposed requirement uses the term “upon recognition.” No change made.
Response: See response above.
Central Lincoln
As stated in our prior comments, we continue to have problems with COM-002, R2
and R3 as written. The SDT’s answer (“It is the expectation that an issuer of a
Reliability Directive would request a return call by the Distribution Provider
operating personnel, then issue the Reliability Directive”) addresses our concern
perfectly, and we would agree with such an expectation. Unfortunately, the
expressed expectation is not in the proposed standard or even in a proposed
guideline for the standard.
Response: The RCSDT believes this is a process or procedure question that should be determined by the entity in how it handles
communication with the RC. The standard, as written does, not preclude the entity from having a procedure. No change made.
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Entergy Services, Inc
Yes or No
Question 6 Comment
Entergy does not agree with including the DP and GOP in this standard. However, if
they are to be included and are required to have the communications capability
indicated, they should be included in R10. Why would it be important for the TOP to
notify the DP that their communications method has failed, but it is not important
for the DP to notify the TOP when their communications method has failed? The
distinction doesn’t seem reasonable or meaningful.
The RCSDT stresses that R11 grants the DP and GOP flexibility in determining, in
conjunction with its TOP or BA, when its Interpersonal Communication capability
must be restored. This would provide allowances for those entities, which have little
or no impact on the reliability of the BES while not requiring them to obtain
Alternative Interpersonal Communication capabilities. Making the proposed changes
would eliminate this flexibility. Removing R11, takes away the RCSDT’s effort to
include those provisions in the standard. No change made.
Additionally, in the draft of COM-002-3 requirement 2 contains the language that the
recipient of the directive shall “repeat, restate, rephrase or recapitulate” the
directive. Why are so many synonyms of repeat necessary? Repeat or restate
should be sufficient to get the point across.
The RCSDT used the additional words to facilitate complete understanding. No
change.
Response: See response above.
Independent Electricity
System Operator
(1) The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 on P. 4 of the draft standard
COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s Implementation Plan
and P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following effect:”,
or as otherwise made effective pursuant to the laws applicable to such ERO
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Question 6 Comment
governmental authorities.”
The RCSDT is uncertain where the conflict exists. The standard IRO-001 uses the term
“after applicable” and the others “following applicable.” The RCSDT has updated the
standards to use the most current effective date language.
(2) COM-001: Measure M9: - “monthly basis.” Suggest changing “monthly basis” to
“at least once per calendar month” to be consistent the wording in R9.
The RCSDT thanks you for your comment and has made the conforming change in
the COM-001, Measure M9.
(3) IRO-001: Measures M1, M2, M3 - The types of evidence are listed in paragraph
form. This is not consistent with presentation style in COM-001-2 Measures, where
evidence is listed in bullet format. Suggest using bullet form for consistency.
The RCSDT agrees and has made all the Measures bullet form in COM-001-2, but not
in COM-002-3 and IRO-001-3.
(4) IRO-001, Data Retention Section:
i. The retention requirements do not reflect the revised requirements. For example:
the Electric Reliability Organization is no longer a responsible entity; the Reliability
Coordinator should replace the ERO for keeping data for R1; Transmission Operator,
Balancing Authority, Generator Operator and Distribution Provider should replace
the Reliability Coordinator for keeping data for R2; and there is no R4/M4.
Data retention related to IRO-001-2, R2/M2 was changed to agree with your
suggestion. The changes were more involved – several sections were changed,
including removing the reference to R4/M4.
ii. Section 1.3, second paragraph: “The Reliability Coordinator, Transmission
Operator, Balancing Authority, Generator Operator, or Distribution Provider... shall
keep data or evidence to show compliance as identified below unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer period of
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Question 6 Comment
time as part of an investigation:
”The word “or” between Generator Operator and Distribution Provider should be
changed to “and.”
The RCSDT thanks you for your comment and has made conforming changes.
Response: See response above.
Hydro-Quebec TransEnergie
For COM-001:
R1.2 and R2.2: The phrase “within the same Interconnection” is improper; it needs to
be removed. RCs between two Interconnections still need to communicate with each
other for reliability coordination (e.g. between Quebec and the other RCs in the
NPCC region to coordinate reliability issues including curtailing interchange
transactions crossing an Interconnection boundary). The SDT’s response to industry
comments on the previous posting that the phrase was added to address the ERCOT
situation (that ERCOT does not need to communicate with other RCs and that such
coordination takes place between TOPs) leaves a reliability gap.
Requirement R1 addresses a reliability need for adjacent Reliability Coordinators
synchronously connected within the same Interconnection to have Interpersonal
Communication capability; however, it does not preclude or limit the Reliability
Coordinator from establishing Interpersonal Communication capability with others.
The RCSDT does not see where there is a need to communicate with other Reliability
Coordinator’s from one interconnection to another. No change made.
2. R3.5 and R4.3: The phrase “synchronously connected within the same
Interconnection” is also improper; it needs to be removed. TOPs do communicate
with other TOPs including those asynchronously connected and in another
Interconnection (e.g. between Quebec and all of its asynchronously interconnected
neighbors). The reason that was used in response to the above comments
(coordination among TOPs for DC tie operation) contradicts with the inclusion of this
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Question 6 Comment
phrase in R3.5 and R4.3.
The RCSDT has made clarifying changes by adding a Part to R3 and R4 to address
asynchronous connections between Transmission Operators and have eliminated the
phrase “within the same interconnection.”
3. R4 and R6: Not requiring an Alternative Interpersonal Communication capability
between the BAs and the DP and GOP can result in a reliability gap. If Interpersonal
Communication capability between the BAs and these entities is required to begin
with to enable BAs to communicate with these entities (such as operating
instructions or Reliability Directives) to ensure reliable operations, then an
alternative capability is also needed to ensure this objective is achieved when the
primary capability fails.
The RCSDT refers the Order No. 693 in Paragraph 508 to clarify the reason the DP
and GOP are not required to have Alternative Interpersonal Communication and is as
follows: “(1) expands the applicability to include Generator Operators and
Distribution Providers and includes Requirements for their telecommunications
facilities; (2) identifies specific requirements for telecommunications facilities for use
in normal and emergency conditions that reflect the roles of the applicable entities
and their impact on Reliable Operation and (3) includes adequate flexibility for
compliance with the Reliability Standard, adoption of new technologies and costeffective solutions.” In addition, R11 requires the DP and GOP to consult with its BA
and TOP to determine a mutually agreeable action for restoration. No change made.
4. To preclude the possibility of problems arising from having different languages
spoken between entities, COM-001-1.1 R4 should remain as it was or those ideas
kept in the revised requirement. R4 read: ”R4. Unless agreed to otherwise, each
Reliability Coordinator, Transmission Operator, and Balancing Authority shall use
English as the language for all communications between and among operating
personnel responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal operations.” 5. Measure M3
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Question 6 Comment
does not cover the added R3.5 condition (having Interpersonal Communications
capability with each adjacent TOP). M3 needs to be revised.
According to the proposed implementation plan for COM-001-2, R4 pertaining to the
use of English will remain in effect upon the effective date of COM-001-3. This
requirement is being revised and will be included in Standard COM-003-1, Operating
Personnel Communications Protocols. COM-001-1.1, R4 will be retired at midnight
the day before COM-003-1 becomes effective. No change made.
For IRO-001:
The Data Retention Section does not reflect the revised requirements. As examples:
the Electric Reliability Organization is no longer a responsible entity; the Reliability
Coordinator should replace the ERO for keeping data for R1.
The RCSDT thanks you for your comment and has made conforming changes to the
Data Retention section.
Transmission Operator, Balancing Authority, Generator Operator and Distribution
Provider should replace the Reliability Coordinator for keeping data for R2.
The RCSDT has made conforming changes by correcting an error in the data
retention section
And, in the Data Retention Section, R4 and M4 are mentioned. However, there are
only three requirements with their corresponding measures in the standard.
The RCSDT has made conforming changes by correcting an error in the data
retention section
Response: See response above.
NIPSCO
In IRO-001 R2 an "and" is missing after Generator Operator, and the comma should
be removed.
Why are there 3 different Effective Dates for this project, each standard being
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different? To simplify, can't they all be made identical?
Response: The RCSDT thanks you for your comment and has made conforming changes to IRO-001 R2 and the effective dates to the
second quarter after regulatory approval.
Oncor Electric Delivery
Company LLC
For COM-001-2
Oncor takes the position that contacting all impacted entities within 60 minutes of
the detection of a failure of its Interpersonal Communications capabilities that lasts
30 minutes or longer as prescribed in R1 through R6 is not doable within the ERCOT
interconnect for a Transmission Operator.
Oncor takes the position that notification only to the RC and BA is sufficient and that
those two entities have the operational functionality to contact within the prescribed
time all affected Distribution Providers, Generator Operators, and other
Transmission Operators.
The RCSDT proposes that upon detection of failure that continues at least 30
minutes, starts the 60-minute clock. The 30 minutes allows an entity time to restore
or determine if they can restore Interpersonal Communication capability before the
clock starts. No change made.
R10 - Oncor takes the position that the word “impacted” added to R10 will clarify
that notification only needs to be made to the entities that are effected by the
failure of a communication path. This will also more align with the language in M10.
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
For COM-002-3
Oncor request clarity about what constitutes a “recipient.” For example, if a
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Question 6 Comment
Transmission Grid Operator performing the functions of a Transmission Operator
issues a Reliability Directive to its own field operations personnel to perform an
action on behalf of the same entity, does the field operations personnel as the
recipient become in affect a “Transmission Operator” subject to R2?
The term “recipient” in this case is referring to Functional entity to Functional entity
communication. No change made.
Response: See response above.
Consolidated Edison Co. of
NY, Inc.
Regarding COM-002 Requirement R1, we recommend that this requirement be
reworded as follows: “When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability Directive, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall require
that the Reliability Directive be communicated using three-part communications as
described in Requirements R2 and R3 of this standard.”
The reason for this recommended rewording are threefold:
1. Good operating practice calls for use of three-part communications at all times.
The recommended re-write encourages the use of the good operating practice of
three-part communications at all times, but does not require it.
2. It is not good operating practice to require that an additional (unnecessary) phrase
be used during emergency situations. During emergency situations, it is best to use
standard operating protocols so as to limit unnecessary burdens on operating
personnel during critical and stressful times.
3. By implementing the proposed new R1 requirement, it would effectively weaken
the need for rigorous compliance with any and all directives issued by the RC’s, TO’s
or BA’s.
The RCSDT respectfully disagrees, the recipient needs clarity when a Reliability
Directive is communicated. No change made.
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Regarding IRO-001 Requirement R1, we recommend that the current requirement R3
be reinstated as the new requirement R1. That is, the new requirement R1 should
read as follows: R1. The Reliability Coordinator shall have clear decision-making
authority to act and to direct actions to be taken by Transmission Operators,
Balancing Authorities, Generator Operators, Transmission Service Providers, LoadServing Entities, and Purchasing-Selling Entities within its Reliability Coordinator Area
to preserve the integrity and reliability of the Bulk Electric System. These actions
shall be taken without delay, but no longer than 30 minutes.
We do not support any further dilution of Reliability Coordinator authority to enforce
Reliability Directives through deletion of the 30-minute maximum response time
period. The timely actions in response to any Reliability Coordinator issued Reliability
Directives is an essential part of the process.
The RCSDT believe these concerns are addressed in other performance-based
standards (IRO-008 and IRO-009) that require action and contain timing requirement
when addressing IROLs. The omission of TSP, LSE, and PSE does not diminish
reliability and brings the standard into conformity with COM-001 and COM-002. No
change made.
Response: See response above.
We Energies
COM-001, Although a great improvement over existing COM-001, and eliminates the
data component see comments:
-For R5.1 Can the solutions included to meet R1 be included, same R3.2 and R5.2,
same R5.3 and R7.2, same R5.4 and R8.1
-For R5.2 Can the solutions included to meet R2 be included, same R4.2 and R6.2
COM-001-2, R5: In a word: Yes. The requirement is to have capability and that
capability does not have to be different than the entity on the other end has. No
change made.
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Question 6 Comment
-R9 a 2 hour response for a once a month test seems extreme, as would require a
secondary Alternate Interpersonal Communications capability
-M9 is reasonable, but should include something about communication actual repair
and or time estimates
COM-001-2, R9: The requirement is to “initiate action to repair or designate a
replacement Alternative Interpersonal Communication capability…” within two
hours. The RCSDT recognizes that many different contracts or other arrangements
may exist to address repair. However, the RCSDT finds that entities should know
what they have and how to initiate repair and those two hours to do so is
reasonable. No change made.
COM-001-2, M9: The requirement is to have evidence that either repair was
initiated or an Alternative Interpersonal Communication capability was designated
within two hours. The RCSDT understands that, in extreme cases, the entity may
need to make its initial Alternative Interpersonal Communication capability its
Interpersonal Communication capability and then designate another Alternative
Interpersonal Communication capability if the repair times are so long that to
continue in that mode for that long would present a reliability risk. Such
arrangements, if they exist at all, are very rare. No change made.
-R10 The use of R1 through R6 implies notification of both Interpersonal
Communications and Alternate Interpersonal Communications failures. Do you notify
if you become aware after the link is back up if it was down for GT 30 minutes, and
Doesn’t address notifying when restored?
COM-001-2, R10: The RCSDT thanks you for pointing this out. The RCSDT has
modified the language of R10 to refer to R1, R3, and R5, rather than “R1 through R6,”
since the responsible entities are limited to the RC, the TOP, and the BA in these
requirements.
Yes, there is no requirement to notify identified entities the Interpersonal
Communication have been restored.
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Question 6 Comment
-R11 Implies that R8 and R9 are independent and redundant to R5.3, R5.4 and R3.3
and R3.4.
COM-001-2, R11: The RCSDT believes you intended to refer to R7 and R8, rather
than R8 and R9. The RCSDT does not believe that the language implies that the
communications capability required by R7 and R8 are independent, but they may be.
If the entity which is registered as a DP is also registered as a GOP (probably
unlikely), then the capability could be met by the same medium. Neither does the
RCSDT believe that R11 implies that R7 and R8 are redundant to R3.3 and R3.4 or to
R5.3 and R5.4. No change made.
R11 is not clear on the purpose of the statement “determine a mutually agreeable
time for restoration” this could be driven by forces outside the control any of the
entities. I think” provide estimated restoration and actual restoration time and
determine mutually agreeable alternative during outage” would be better.
The RCSDT notes that R11 does not limit the sources of information used by the DP
or GOP in establishing a mutually agreeable action for restoration of its Interpersonal
Communication capability with its TOP or BA. That is precisely why R11 is written in
this manner. This allows flexibility on the part of the TOP and BA in determining
when the Interpersonal Communication capability must be restored. In situations
where there is little or no impact to the reliability of the BES, some flexibility could
be allowed without requiring the acquisition of Alternative Interpersonal
Communication capability. No change made.
Update M9 accordingly
See comment above concerning R9.
COM-002
-Since all the Requirements are related to Reliability Directives, is it implied that all
“Emergency Communications” are Reliability Directives even if not designated as
such per R1.
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Question 6 Comment
The RCSDT would like to highlight that communications is not a defined term in the
NERC Glossary of Terms used in Reliability Standards ,nor is it defined in this
standard. Thus, the plain meaning of communications is intended. The RCSDT has
not implied a defined term in the wording of the purpose statement of the standard,
nor in the Requirements themselves, that any communication is a Reliability
Directive unless the issuing functional entity identifies the actions to be taken as a
Reliability Directive. Therefore, not all communications during Emergencies will be
Reliability Directives. No change made.
COM-002, R2: The RCSDT included some examples of how to provide the evidence
needed for Measure M2. The examples are not intended to be an all-inclusive list.
The RCSDT does point out, though, that dated operator logs could provide such
evidence. The RCSDT does not believe that the recipient has the alternative to
refuse to perform as required. However, the RCSDT does bring attention to standard
IRO-001-3, which requires entities to comply with directions unless compliance with
the direction cannot be physically implemented or unless such actions would violate
safety, equipment, regulatory, or statutory requirements. No change made.
-The M2 measure could be difficult for a recipient such as a Distribution Provider or
Generator Operator. A recipient’s phone may not be recorded but an initiator’s
always should. If a receiver refused to meet the R2 requirement, an initiator should
have an alternative. i.e., repeat the directive and provide potential penalties if
recipient refuses to comply. Should the initiator have responsibility for providing the
entire 3-way evidence as M3 implies?
The RCSDT would like to highlight that communications is not a defined term in the
NERC Glossary of Terms used in Reliability Standards nor is it defined in this
standard. Thus, the plain meaning of communications is intended. The RCSDT has
not implied a defined term in the wording of the purpose statement of the standard,
nor in the Requirements themselves, that any communication is a Reliability
Directive unless the issuing functional entity identifies the actions to be taken as a
Reliability Directive. Therefore, not all communications during Emergencies will be
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Question 6 Comment
Reliability Directives. No change made.
COM-002 M3: The Measure is correct as written. The issuer only needs the
evidence that it confirmed the response was accurate or reissued according to the
requirement. Evidence does not necessarily mean the entity must have the entire
three-way conversation captured (i.e., recording), but evidence the entity confirmed
or reissued according to requirement. No change made.
IRO-001
Although a great improvement over existing IRO-001, see comments:
-R2 needs to be clear that it is the Reliability Coordinator’s Reliability Directive that
must be complied with not just any Reliability Coordinator’s direction as stated.
-The M2 measure could be difficult, as the operator would have to have access to
documents proving the safety, equipment, regulatory or statutory requirements,
which may be the assessment of an individual applying the safety rule.
Is the measure requiring a deposition of the individual to be performed for each
instance?
The RCSDT notes that the intent of the standard is not intended to limit the RC
authority to issue Reliability Directives. The Reliability Coordinator issuing the
Reliability Directive is the one, which the recipient must comply. It is assumed that a
BA or TOP has a relationship with one and only one RC for a given Balancing Area or
Transmission Operator Area (some may have multiple, disconnected areas, that are
subject to different RCs). Still need a way to communicate to mutually agree. No
change made.
With an assumed data retention of 90 day (voice) or 12 month document retention
the deposition would be unlikely to be acquired prior to the retention period ending.
Data retention is a significant issue when the data being recorded is voluminous,
supporting a 90-day retention period. No change made.
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Question 6 Comment
-R3 needs to be clear that it is the inability to perform the Reliability Coordinator’s
Reliability Directive that must be communicated not just any “Reliability
Coordinator’s as directed.”
The RCSDT believes there is a misunderstanding about IRO-001, R3. The
requirement specifically says “direction” and is in alignment with Requirement R1.
Please note a Reliability Directive is a subset of “direction” that the RC may perform
in accordance with R1. No change made.
-The Data Retention section does not align with the standard:
The Reliability Coordinator shall retain its evidence for the most recent 90 calendar
days for voice recordings or 12 months for documentation for Requirement R2,
Measure M2.
The RCSDT thanks you for your comment. The RC has been removed from the
measure and replaced with the corresponding R2 responsible entities (BA, DP, GOP,
and TOP).
R2 and M2 apply to the Transmission Operator, Balancing Authority, Generator
Operator, or Distribution Provider.
There is no R4 and M4.
The RCSDT thanks you for your comment and has made conforming changes.
Response: See response above.
City of Jacksonville Beach
dba/ Beaches Energy Services
COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications
capability.” I would suggest adding the phrase "...to each entity for which
Alternative Interpersonal Communications is required." to add clarity.
Response: The RCSDT proposes that R9 correctly identifies and provides clarity for the entities required to have Alternative
Interpersonal Communication capability. No change made.
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Indiana Municipal Power
Agency
Yes or No
Question 6 Comment
For R2 in IRO-001-3, the requirement needs to have the entities comply with their
Reliability Coordinator’s direction received in R1. Currently, requirement 2 directions
are not linked back to R1 which means entities would have to comply with all
Reliability Coordinator’s directions regardless if they are associated with R1.
The RCSDT agrees with your comment and believes the requirements does not need
a linkage. No change made.
For R7 in COM-001-2, IMPA does not believe that every Distribution Provider needs
to be included in requirement 7. IMPA recommends stating that requirement 7 only
applies to Distribution Providers who own an UFLS or UFLS system.
The expectation is that a Distribution Provider that is registered with NERC is
obligated to comply. No change made.
Response: See response above.
Luminant Energy Company
LLC
IRO-001-3 R1 is not consistent with the direction taken in COM-002-3 which requires
the Reliability Coordinator to identify Reliability Directive as such. The same
approach should be taken with IRO-001-3 R1 so that the Reliability Coordinator is
required to identify directions that are made to prevent identified events or mitigate
the magnitude or duration of actual events that result in an Emergency or Adverse
Reliability Impacts as such prior to or when issuing the directions. This extra
specification is needed to eliminate any possible confusion in areas where the
market operator and Reliability Coordinator are the same entity. In these areas, the
Reliability Coordinator/market operator routinely gives directions to other entities
that are not to prevent identified events or mitigate the magnitude or duration of
actual events that result in an Emergency or Adverse Reliability Impacts. Without
the added clarification the receiving entity may not know the urgency of the
situation and may not know to inform the Reliability Coordinator if they are unable
to perform as required by R3.
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Question 6 Comment
Response: The RCSDT views R1 as an authority requirement to direct others, which could include a subset of direction called
Reliability Directive. Requirement R2 is the response requirement for the recipient. The judgment the recipient is under is that the
recipient must comply with the direction, unless the direction cannot be physically implemented or unless such actions would violate
safety, equipment, regulatory or statutory requirements. Requirement R3 simply requires the recipient to inform the issuer of its
inability to perform the direction. No change made.
NextEra Energy, Inc.
NextEra has the following additional comments.
COM-002-3
The purpose of COM-002-3 is:
“To ensure Emergency communications between operating personnel are effective.”
This stated purpose is not the same as the specific requirement that three-way
communication is used for a Reliability Directive. Thus, NextEra requests that the
purpose be revised to read as follows:
“To ensure that when a Reliability Directive is given that the Reliability Directive is
explicitly stated and three-way communication is used.”
The majority of stakeholders did not raise any issues with the purposed statement,
and the RCSDT believes the current purpose statement is adequate. No change
made.
Consolidation of COM-002-3 and IRO-001-3
NextEra notes a continuing area of concern with the somewhat unsynchronized
approach taken in the drafting process. Reliability Standards COM-002 and IRO-001
are now on version three, and still there is a somewhat unsynchronized approach
being proposed. A clear and consolidated approach seems easily achievable with
minimal effort. Thus, as proposed below, NextEra requests that COM-002-3 and IRO001-3 be combined, which also would appear to allow for the retirement of certain
requirements, such as TOP-001-1 R1-4.
The standard TOP-001-1, R1 through R4 is under the purview of another team. No
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Question 6 Comment
change made.
NextEra also is concerned that the current approach may have contributed to several
significant misstatements in IRO-001-3, R1-3, which use the terms “direct,”
“direction” and “directed,” instead of the term Reliability Directive as used in COM002-3. COM-002-3 and IRO-001-3 indicate that three-way communication only is
required when a Reliability Directive is issued.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction,” No change made.
This begs the question of what are the potentially other, lower classes of directives in
IRO-001-3 R1-3?
And why do they need to be followed with or without three-way communication?
Reliability Directives are identified as such at the time they are issued so the
recipient understands the magnitude of the action being directed. No change made.
Thus, at a minimum, NextEra requests that the terms direct, direction and directed
be deleted from IRO-001-3 R1-3, respectively, and that Reliability Directive be
inserted. This change, and other proposed changes, are reflected in NextEra’s
overall proposal to combine COM-002-3 and IRO-001-3 into one COM-002-3
standard: {Note: If the term Adverse Reliability Impact is revised as proposed by
NextEra, then the term would not need to be stricken.
The RCSDT understands some of the benefits with combining the standards;
however, at this point, it would further delay the progress of the standards.
The word “direction” connects with the language in the R1 (act or direct). Reliability
Directives is a subset of “direction.” No change made.
R1. Each Reliability Coordinator shall have the authority to act and to issue a
Reliability Directive to a Transmission Operator, Balancing Authority, Generator
Operator and Distribution Provider within its operating region to prevent identified
events that may lead to, or to mitigate the magnitude or duration of, an Emergency.
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[Violation Risk Factor: High][Time Horizon: Real-time Operations, Same Day
Operations and Operations Planning]
R1.1 Each Transmission Operator shall have the authority to act or issue a Reliability
Directive to a Balancing Authority, Generator Operator and Distribution Provider
within its operating region to prevent identified events that may lead to, or to
mitigate the magnitude or duration of, an Emergency. [Violation Risk Factor:
High][Time Horizon: Real-time Operations, Same Day Operations and Operations
Planning]
R1.2 Each Balancing Authority shall have the authority to act or issue a Reliability
Directive to a Generator Operator and Distribution Provider within its balancing
region to prevent identified events that may lead to, or to mitigate the magnitude or
duration of, an Emergency. [Violation Risk Factor: High][Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning]
R2. When a Reliability Coordinator, Transmission Operator or Balancing Authority
issues a Reliability Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability Directive to the recipient.
[Violation Risk Factor: High][Time Horizon: Real-Time]
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of a Reliability Directive shall repeat,
restate, rephrase or recapitulate the Reliability Directive. [Violation Risk Factor:
High][Time Horizon: Real-Time]
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues a Reliability Directive shall either [Violation Risk Factor: High][Time Horizon:
Real-Time]:
-Confirm that the response from the recipient of the Reliability Directive (in
accordance with Requirement R2) was accurate, or
-Reissue the Reliability Directive to resolve any misunderstandings.
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Question 6 Comment
R4. Each Transmission Operator, Balancing Authority, Generator Operator,
Distribution Provider shall comply with its Reliability Coordinator’s Reliability
Directive, unless compliance with the Reliability Directive cannot be physically
implemented or unless such actions would violate safety, equipment, regulatory or
statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-time
Operations, Same Day Operations and Operations Planning]
R4.1 Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform a Reliability Directive in accordance with Requirement R4.
[Violation Risk Factor: High] [Time Horizon: Real-time Operations, Same Day
Operations and Operations Planning]
R5. Each Balancing Authority, Generator Operator, and Distribution Provider shall
comply with its Transmission Operator’s Reliability Directive, unless compliance with
the Reliability Directive cannot be physically implemented or unless such actions
would violate safety, equipment, regulatory or statutory requirements. [Violation Risk
Factor: High] [Time Horizon: Real-time Operations, Same Day Operations and
Operations Planning]
R5.1. Each Balancing Authority, Generator Operator, and Distribution Provider shall
inform its Transmission Operator upon recognition of its inability to perform a
Reliability Directive in accordance with Requirement R5. [Violation Risk Factor: High]
[Time Horizon: Real-time Operations, Same Day Operations and Operations Planning]
R6. Each Generator Operator or Distribution Provider shall comply with its Balancing
Authority’s Reliability Directive, unless compliance with the Reliability Directive
cannot be physically implemented or unless such actions would violate safety,
equipment, regulatory or statutory requirements. [Violation Risk Factor: High] [Time
Horizon: Real-time Operations, Same Day Operations and Operations Planning]
R6.1. Each Generator Operator or Distribution Provider shall inform its Balancing
Authority upon recognition of its inability to perform a Reliability Directive in
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Question 6 Comment
accordance with Requirement R6. [Violation Risk Factor: High] [Time Horizon: Realtime Operations, Same Day Operations and Operations Planning]
Conclusion
Given the importance of having clear and concise Reliability Standards on the issue
of directives and three-way communication, until the above concerns raised by
NextEra in items 4 through 6 are addressed, NextEra intends to continue to vote
“no” on COM-001-2, COM-002-3 and IRO-001-3.
The RCSDT thanks you for your comment and believes the revisions made to this set
of standards is valuable to the industry and within the scope of the project. No
change made.
Response: See response above.
Manitoba Hydro
COM-001-2-Definition ‘Interpersonal Communication’ - for clarity, the definition
should explicitly state that data exchange is not included.
The standard COM-001 is for Interpersonal Communication capability, which
facilitates the communication (i.e., “… to interact, consult, or exchange
information.”) and not the exchange of data which is addressed in IRO-010. No
change made.
-R9 - for clarity, the wording ‘... within 2 hours’ should be replaced with ‘... within 2
hours of the unsuccessful test’. Conforming change required to M9 as well.
The RCSDT proposes that R9 correctly identifies and provides clarity for the entities
required to have Alternative Interpersonal Communication capability. No change
made.
-R10 - for clarity, the wording ‘... as identified in R1 through R6... ‘ should be
replaced with ‘... with which it is required to have Interpersonal Communications
capability or Alternative Interpersonal Communication capability...’.
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Question 6 Comment
The RCSDT has modified the language of R10 to refer to R1, R3, and R5, rather than
“R1 through R6,” since the responsible entities are limited to the RC, the TOP, and
the BA in these requirements.
-M6 - the term ‘Adjacent’ needs to be capitalized in the last sentence of the
paragraph as ‘Adjacent Balancing Authority’ is a NERC defined term.
The RCSDT thanks you for your comment and recognizes the confusion created by
having “Adjacent” start the sentence. This gave the appearance of a defined NERC
glossary term. The RCSDT has made conforming measures to eliminate this problem.
See changes to COM-001-2, R1.2, R2.2, R3.5, R4.3, R5.5, and R6.3.
-M7 - ‘that’ in the first line is repeated
The RCSDT thanks you for your comment and has made conforming changes to
remove the additional word “that.”
-M9 - the wording ‘on a monthly basis’ should be replaced with ‘once per calendar
month’ to be consistent with the wording of the R9.
The RCSDT agrees and the language in M9 has been changed to agree with the
language in R9 and the R9 VSL.
-M11 - the words ‘that experiences a failure of any of its Interpersonal
Communications capabilities’ should be added after Operator to be consistent with
the wording of the Requirement
The RCSDT thanks you for your comment and has made the conforming changes to
Measure M11.
-Compliance
- 1.3 bulleted sentences - the term ‘historical data’ should be removed. The term
'evidence' is sufficiently descriptive and is consistently used in other requirements
The RCSDT thanks you for your comment and has made conforming changes to the
Data Retention section.
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Question 6 Comment
-Data Retention
(1.3) - The data retention requirements are too uncertain for two reasons. First, the
requirement to “provide other evidence” if the evidence retention period specified is
shorter than the time since the last audit introduces uncertainty because a
responsible entity has no means of knowing if or when an audit may occur of the
relevant standard.
Secondly, it is unclear what ‘other evidence’, besides the specified logs, recordings
and emails, an entity may be asked to provide to demonstrate it was compliant for
the full time period since their last audit.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
This comment also applies to COM-002-3 and IRO-001-3.
-Data Retention (1.3) - COM-002-3 requires that voice recordings are kept for the
most recent 3 calendar months but COM-001-2 requires that they be kept for the
most recent 12 calendar months. Manitoba Hydro does not see the reliability benefit
of storing voice recordings for longer than 3 months and suggests that voice
recordings be removed as evidence for COM-001-2.
The RCSDT thanks you for your comment and has provided a retention period of 90
days for voice recordings, if chosen by the entity, as a matter of media storage, and
12 months for all other evidence.
Evidence of the availability of Interpersonal Communications and Alternative
Interpersonal Communications can be demonstrated using the other forms of
evidence listed.
The RCSDT thanks you for your comment. The measures provide a significant listing
of potential evidence, which allows for compliance flexibility. The measures are
examples and the entity is not limited to those examples. No change made.
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-VSLs (general comment)
- for clarity, use for example R1.1 and R1.2 to refer to requirements instead of Part
1.1 and Part 1.2.
The RCSDT thanks you for your comment and has made conforming changes to the
Data Retention section.
-VSLs R4 - a reference to R4.3 is missing
The RCSDT thanks you for your comment and has made conforming changes to the
VSL section.
COM-002-3-Title
- to capture the purpose and intent of the standard, the title should be changed to
‘Emergency Communications’.
The RCSDT believes the title adequately captures the standard’s scope. No change
made.
-R2 - for clarity, the words ‘back to the sender’ should be added to the end of the
sentence
The RCSDT believes the current wording clearly identifies the issuer. No change
made.
-R3 - for clarity, the words ‘to the recipient’ should be added to both of the bulleted
sentences after ‘confirm’ and ‘reissue’. The words ‘evident from the response’
should be added to the end of the second bullet.
The RCSDT believes the current wording is clear as to who is the recipient. No
change made.
-A question for the drafting team: has it been discussed whether there should be an
additional requirement which indicates that the Reliability Coordinator, Transmission
Operator and Balancing Authority shouldn’t take any action in a Reliability Directive
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Question 6 Comment
until such time as it has been confirmed accurate by the sender?
If so, does the team feel that it’s a worthwhile requirement to consider?
RCSDT believes having an additional requirement is unnecessary and would be overly
prescriptive. No change made.
-M2 - the words ‘restated, rephrased or recapitulated' should be added after
‘repeated’ to be consistent with wording of the requirement.
The RCSDT thanks you for your comment and has made conforming changes to the
Measure, M2 in COM-002.
-M3 - the words ‘to show’ should be deleted from the end of this paragraph.
The RCSDT thanks you for your comment and has made conforming changes to the
Measure, M3 in COM-002.
IRO 001-3-Purpose
- the words ‘to the Bulk Electric System’ already appear in the definitions of
Emergency and Adverse Reliability Impact and do not need to be repeated here.
The RCSDT thanks you for your comment and has made conforming changes to the
Purpose in IRO-001.
-Effective Date
- the effective date should be changed to the 2nd calendar quarter following BOT
approval in jurisdictions not requiring regulatory approval to be consistent with
jurisdictions requiring regulatory approval.
The RCSDT thanks you for your comment and has made conforming changes to make
IRO-001 the same as COM-001 and COM-002.
-General comment
- There are repeated references to ‘identified events’
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- it is not clear what this is referring to.
The context of “identified” is when a set of system conditions is recognized that
could lead to an Emergency or Adverse Reliability Impact, which may require action.
See standards IRO-008 and IRO-009. No change made.
M1 - M1 refers to Adverse Reliability Impacts “within its Reliability Coordinator
Area.” The requirement does not refer to ‘within its Reliability Coordinator Area’ the wording in the measure and in the requirement should be consistent.
The RCSDT thanks you for your comment and has made conforming changes to IRO001, M1 to remove the phrase “within its Reliability Coordinator Area.”
M2 - missing the word ‘physically’ when describing that a direction could not be
implemented, should be consistent with the wording in the requirement.
The RCSDT thanks you for your comment and has made conforming changes to make
IRO-001 measure M2.
Compliance
- the entire section needs to be updated as it refers to requirements and measures
that don’t exist.
The RCSDT thanks you for your comment and has made conforming changes to make
IRO-001 Compliance section 1.3 to remove the invalid references.
-VSLs R2 - the reference to ‘fully comply’ is very vague. It is only a violation if the
entity does not fall within the exception.
The RCSDT thanks you for your comment and has made conforming changes to make
IRO-001, R2, High VSL to be more consistent with the R2.
- R2 VSL - For clarity, change “RC’s directive” to “Reliability Coordinator’s Reliability
Directive.”
The RCSDT thanks you for your comment and has made conforming changes to make
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IRO-001, VSL R2, High VSL.
Response: See response above.
Great River Energy
In IRO-001-3 "authority" should be removed and the verbiage returned to "shall act."
The RCSDT believes that other standards (i.e., IRO-009, R3 & R4 and EOP-002, R1 &
R8) address the action of others and if the term “authority” is omitted, creates a
generic requirement such as what has been suggested puts the RC in a double
jeopardy situation. No change made.
In COM-002-3 R2 and in Applicability we suggest removing the Distribution Provider
as the RC would not likely give a Reliability Directive to a Distribution Provider. The
Reliability Directive would more likely come from the Transmission Operator to the
Distribution Provider.
The RCSDT believes that other standards (i.e., IRO-009 - R3 & R4, EOP-002 - R1 &R8)
address the action of others and if the term “authority” is omitted, creates a generic
requirement such as what has been suggested puts the RC in a double jeopardy
situation. No change made.
In COM-002-3 R3 we "replacing "Reissue" with "Restate." You are not technically
reissuing the Reliability Directive.
COM-002-3, R3: The communications described are not intended to be a oncethrough process. Effective communications, sometimes referred to as three-part or
three-way, often may be effective only after numerous iterations. The RCSDT
believes the likely first effort to clarify would be to re-issue the instructions just to
determine whether the recipient simply “heard wrong.” Using the word re-state
seems to imply that the wording is incorrect in some way or for some other reason
needs to be said a different way. The RCSDT believes it is more likely that the issuer
is attempting to bet the recipient to understand and therefore believes that reissue
is more appropriate. No change made.
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Response: See response above.
Orange and Rockland Utilities,
Inc.
Regarding COM-002 Requirement R1, we recommend that this requirement be
reworded as follows:
“When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall require that the Reliability
Directive be communicated using three-part communications as described in
Requirements R2 and R3 of this standard.”
The reason for this recommended rewording are threefold:
1. Good operating practice calls for use of three-part communications at all times.
The recommended re-write encourages the use of the good operating practice of
three-part communications at all times, but does not require it.
2. It is not good operating practice to require that an additional (unnecessary) phrase
be used during emergency situations. During emergency situations, it is best to use
standard operating protocols so as to limit unnecessary burdens on operating
personnel during critical and stressful times.
3. By implementing the proposed new R1 requirement, it would effectively weaken
the need for rigorous compliance with any and all directives issued by the RC’s, TO’s
or BA’s. Regarding IRO-001 Requirement R1, we recommend that the current
requirement R3 be reinstated as the new requirement R1.
That is, the new requirement R1 should read as follows:
“R1. The Reliability Coordinator shall have clear decision-making authority to act and
to direct actions to be taken by Transmission Operators, Balancing Authorities,
Generator Operators, Transmission Service Providers, Load-Serving Entities, and
Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the
integrity and reliability of the Bulk Electric System. These actions shall be taken
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without delay, but no longer than 30 minutes.”
We do not support any further dilution of Reliability Coordinator authority to enforce
Reliability Directives through deletion of the 30 minute maximum response time
period. The timely actions in response to any Reliability Coordinator issued Reliability
Directives is an essential part of the process.
Response: The RCSDT development of IRO-001-3 R1 states “…which could include issuing Reliability Directives…” and, therefore,
does not preclude its use if it is determined by the RC to use it. There may be instances where the RC discusses operational issues in
normal dialogue with entities that do not require the use of Reliability Directive. No change made.
Niagara Mohawk (dba
National Grid)
COM-001-3
- Some requirements are overly prescriptive and not results based.
R7 & R8 are not necessary. Every entity at a minimum has a contact with a phone as
their "Interpersonal Communications capability.” Just need to require that every
entity has a plan if they lose their primary communication channel ("Interpersonal
Communications capability").
The standard establishes requirement for communication capability appropriate to
ensure reliability. There is no requirement for it to be different from the
Interpersonal Communication capability that its Balancing Authority has with it nor
the Interpersonal Communication capability that its Transmission Operator has with
it. Cooperation and coordination is always encouraged and is an excellent practice,
but is not required by this standard. Thank you for your suggestion. No change
made.
COM-002-3
- Requiring RCs, TOPs and BAs to state an action as a "reliability directive"
complicates communications during a time when response time and clarity are
important. If those issuing a directive don't get a repeat back they just need to ask
for one. The requirement just needs to define "what" is required not "how.” This
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can be handled by procedures and training.
The requirement is aimed at being a performance-based requirement and states a
description of “what” communication must take place, but does not prescribe “how”
the communication is to be made. Adding the suggested phrase “immediately upon
receiving it” introduces the ambiguous term “immediately” for which there is neither
plain meaning nor simple explanation. What must happen is that the recipient must
respond in such a way that the issuer may determine whether the message has been
properly understood. The RCSDT concludes that the proposed language gives plain
meaning. No change made.
- Delete reference to "adverse reliability impact" from the "Directive" definition. The
"adverse reliability impact" definition is not clear, is this an actual event or
contingency?
The words imply it is an actual event which is already covered in the "Directive"
definition. If the intent is to apply directives to potential stability or cascading
contingencies it should say so.
Response: The RCSDT thanks you for your comment; however, the RCSDT believes the definition captures two independent
conditions, anticipated and after or post event. The definition of Emergency implies situations where the event is anticipated or
currently happening. Likewise, the definition of Adverse Reliability Impact clearly identifies as a potential or actual event in the
phrase, “an event that results in.” Both conditions are important to the definition. The RCSDT notes that the term, “Adverse
Reliability Impact,” is a currently defined NERC Glossary term. The term as it appears in the standard is the revised term is the NERC
Board of Trustee adopted term: The impact of an event that results in Bulk Electric System instability or Cascading. No change made.
American Electric Power
COM-001-02
R9: A two hour limit to repair or designate a replacement Alternative Interpersonal
Communications capability is overly aggressive.
COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is NOT
to have the repair completed within two hours. The requirement recognizes that the
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Question 6 Comment
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability, and then, if it decides to do so, designate
another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
COM-002-03
R1: Should this requirement also include references to a manual action?
The RCSDT believes adding the word “manual” is unnecessary and overly
prescriptive. No change made.
COM-002-03
R3:The text “to resolve any misunderstandings” is unnecessary and should be
removed.
The RCSDT believes this phrase is essential to the process of communications. No
change made.
COM-002-3 VSL’s:
As we have stated on previous projects, all severity levels need to be commensurate
with both:
a) the degree by which the requirement was violated, and
The RCSDT has followed the VSL Guidelines in properly assigning the VSL as binary.
No change made.
b) by the impact of the violation to the BES. In this case, a single VSL of “Severe”
violates both principles.
The RCSDT notes the Violation Risk Factors define the potential impact to the BES;
whereas, the VSL is how badly an entity violated the requirement. No change made.
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There needs to be more gradients across the severity levels, and the single VSL of
“Severe” incorrectly makes the assumption that the impact to the BES was severe.
The RCSDT has followed the VSL Guidelines in properly assigning the VSL as binary.
No change made.
IRO-001-3
R1, R2, R3: Having this requirement apply to actions and/or directions (which may be
different than Reliability Directives) may put the recipient in a position that they are
judged on whether or not they acted on communication that was not a Reliability
Directive.
The RCSDT views R1 as an authority requirement to direct others, which could
include a subset of direction called, Reliability Directive. Requirement R2 is the
response requirement for the recipient. The judgment the recipient is under is that
the recipient must comply with the direction, unless the direction cannot be
physically implemented or unless such actions would violate safety, equipment,
regulatory or statutory requirements. Requirement R3 is simply requires the
recipient to inform the issuer of its inability to perform the direction. No change
made.
The draft states that the purpose of this standard is “To establish the capability and
authority of Reliability Coordinators to direct other entities to prevent an Emergency
or Adverse Reliability Impacts to the Bulk Electric System.” The key word used is
“direct”, so communications that need to be acted upon should be Reliability
Directives only. The addition of any non-defined term is in conflict with the definition
and intent of the term Reliability Directive. This could potentially cause confusion,
especially at critical times when communication is key.
Response: See response above.
Georgia Transmission
The following comments are regarding IRO-001-3.
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Question 6 Comment
Requirement R1 should require the use of Reliability Directives. The requirement
compels the Reliability Coordinator “to direct others to act to prevent identified
events or mitigate the magnitude or duration of actual events that result in an
Emergency or Adverse Reliability Impact.” Reliability Directives are necessary to
address Adverse Reliability Impacts or Emergencies and trigger the use of three-part
communications identified in COM-002-3.
The RCSDT views R1 as an authority requirement to direct others, which could
include a subset of direction called, Reliability Directive. Requirement R2 is the
response requirement for the recipient. The judgment the recipient is under is that
the recipient must comply with the direction, unless the direction cannot be
physically implemented or unless such actions would violate safety, equipment,
regulatory or statutory requirements. Requirement R3 is simply requires the
recipient to inform the issuer of its inability to perform the direction. No change
made.
COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive
for Emergencies and Adverse Reliability Impacts with the opening clause:
“When a Reliability Coordinator, Transmission Operator, or Balancing Authority
determines actions need to be executed as a Reliability Directive.” What else could
be more important for a Reliability Coordinator to issue a Reliability Directive than
for an Emergency or Adverse Reliability Impact?
Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts
and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent.
The RCSDT development of IRO-001-3 R1 states “…which could include issuing
Reliability Directives…” and, therefore, does not preclude its use if it is determined
by the RC to use it. There may be instances where the RC discusses operational
issues in normal dialogue with entities that do not require the use of Reliability
Directive. No change made.
It is recommended that the treatment of Reliability Directives shall be consistent
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Question 6 Comment
with those being developed for TOP-001-2 as proposed by the Real-Time Operations
drafting team (Project 2007-03).
The RCSDT is using the term in the same context in this standard as it is in TOP-001-2.
No change made.
As such, consider using the following language for R2: “Each TOP, BA, and GOP shall
comply with each identified Reliability Directive issued and identified as such by its
RC, unless such actions would violate safety, equipment, regulatory, or statutory
requirements.”
The RCSDT is addressing a directive (P487, Order 693) to include the DP in COM-001
and the RCSDT has included the DP in COM-002 and IRO-001 applicability because
these standards are related to reliability communications. The RCSDT agrees with
the point that communication will most likely be from the BA or TOP; however, the
communications may come from the RC. No change made.
Accordingly, please consider using the following language for R3:
“Each TOP, BA, and GOP shall inform its RC of its inability to perform an identified
Reliability Directive issued by that RC.” Again, we do not believe the DP would
receive an identified Reliability Directive directly from the RC and the DP applicability
should be removed from this standard. The DP is appropriately captured under
COM-002 and TOP-001 with respect to Reliability Directives.
Accordingly, NERC’s Reliability Functional Model V5 describes and identifies the DP’s
relationships with other functional entities to TOP and BA with respect to Real Time.
Real Time 9
7. Implements voltage reduction and sheds load as directed by the Transmission
Operator or Balancing Authority.
9
NERC Functional Model Version 5, “Functional Entity – Distribution Provider,” pg 47, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
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Organization
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Question 6 Comment
8. Implements system restoration plans as coordinated by the Transmission
Operator.
9. Directs Load-Serving Entities to communicate requests for voluntary load
curtailment.
The following comments are regarding COM-001-2.
With respect to the Functional Model V5, please see Page 31, “18. Issues corrective
actions and emergency procedures directives (e.g., curtailments or load shedding) to
Transmission Operators, Balancing Authorities, Generator Operators, Distribution
Providers, and Interchange Coordinators.” No change made.
The SDT should include an additional qualifier to Interpersonal Communications
within the context of these requirements, for example (operational or dispatch
center communications???). Technically, the air we breathe, as well as other
mediums like “any” cell phone, fax lines, and/or email accounts would qualify under
this proposed definition of Interpersonal Communication. Assuming at least one
employed individual can speak, all entities could demonstrate compliance of this
capability at all times, therefore, it is not clear the intent of these requirements are
accurately being presented.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
It is recommended to include the use of “signed attestation letters” as examples of
evidence under M4 and M11 and other measures as appropriate.
The RCSDT proposes that R4 and R11 allow for compliance flexibility. A “signed
attestation letter” is one form of evidence. The measures are examples and the
entity is not limited to those examples. No change made.
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Yes or No
Question 6 Comment
Response: See response above.
BGE
No comment.
Response: No comment provided.
Nebraska Public Power
District
Comments: COM-001-2:
Requirement 10 is too open ended as written. The measure, M10, indicates that only
impacted entities need to be notified. The requirement should be changed to make it
consistent with the measure. The requirement would then read ‘Each RC, TOP And
BA shall notify impacted entities as identified...’Requirements 3 and 5 place the
responsibility for establishing Interpersonal Communication capability on the TOP
and BA. It is quite conceivable that a TOP or BA may not know all, or newly,
registered DPs and GOPs in its respective area.
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
In Requirements 7 and 8, the DP and GOP, respectively, are in turn responsible for
establishing Interpersonal Communication capability. The TOPs/BAs and the
DPs/GOPs should not be responsible for this. The DPs and GOPs should be held
accountable for requesting that capability of their TOP and BA. Therefore, we
suggest adding the following phrase at the end of Requirements 3.3, 3.4, 5.3 and 5.4
- ‘that has requested Interpersonal Communications capability.’
Then R3.3 would read ‘Each Distribution Provider within its Transmission Operator
Area that has requested Interpersonal Communications capability.’
The standard establishes requirement for communication capability appropriate to
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ensure reliability. There is no requirement for it to be different from the
Interpersonal Communication capability that its Balancing Authority has with it nor
the Interpersonal Communication capability that its Transmission Operator has with
it. Cooperation and coordination is always encouraged and is an excellent practice,
but is not required by this standard. Thank you for your suggestion. No change
made.
Requirement 9: could be construed to mean that the repair or replacement due to
an unsuccessful test should be completed within 2 hours. In any case a rewording of
the second sentence of Requirement 9 would make it clear and we would suggest
the following:
“ The responsible entity shall, within 2 hours of the unsuccessful test, provide
notification to the proper authority in order to initiate repair or designate a
replacement Alternative Interpersonal Communications capability. “
COM-001-2, R9: The requirement is to initiate repair or designate an Alternative
Interpersonal Communication capability within two hours. The requirement is NOT
to have the repair completed within two hours. The requirement recognizes that the
entity may use its Alternative Interpersonal Communication capability now as its
Interpersonal Communication capability; and then, if it decides to do so, designate
another, if you may, “new” Alternative Interpersonal Communication capability. This
is not required, but is an option that the entity can consider. The entity may already
have a maintenance and repair agreement in place that will respond and repair the
failed capability. No change made.
COM-002-3:
Requirement 2/Measure 2: There is an inconsistency between the requirement and
the measure. The requirement allows the recipient to repeat, restate, rephrase or
recapitulate the directive. Measure 1 [See M2] only mentions repeating the
directive.
The RCSDT appreciates your observation. The phrases “restate, rephrase or
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recapitulate,” have been added to Measure, M2.
Requirement 3: The second bullet in Requirement 3 appears to require the
reissuance of an entire Reliability Directive if only a single point in the directive is not
correctly repeated, restated, rephrased or recapitulated. Is this what the SDT
intended?
Shouldn’t consideration be given for that portion of the directive that was
communicated properly? Then only a new, revised directive containing the portion
of the original directive that was misunderstood would need to be reissued.
The RCSDT’s intention of the requirement is to confirm the communication is
confirmed accurate and, if not, any misunderstanding is corrected. The requirement
does not limit the entity to reissuing the entire Reliability Directive. So an entity is
not precluded from only correcting the portion of the misunderstanding. No change
made.
Response: See response above.
Georgia System Operations
Requirement R1 should require the use of Reliability Directives. The requirement
compels the Reliability Coordinator “to direct others to act to prevent identified
events or mitigate the magnitude or duration of actual events that result in an
Emergency or Adverse Reliability Impact.” Reliability Directives are necessary to
address Adverse Reliability Impacts or Emergencies and trigger the use of three-part
communications identified in COM-002-3.
COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability Directive
for Emergencies and Adverse Reliability Impacts with the opening clause: “When a
Reliability Coordinator, Transmission Operator, or Balancing Authority determines
actions need to be executed as a Reliability Directive.” What else could be more
important for a Reliability Coordinator to issue a Reliability Directive than for an
Emergency or Adverse Reliability Impact? Thus, not requiring the use of Reliability
Directives for Adverse Reliability Impacts and Emergencies makes IRO-001-3 R1 and
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COM-002-3 R1 inconsistent.
The RCSDT development of IRO-001-3 R1 states “…which could include issuing
Reliability Directives…” and, therefore, does not preclude its use if it is determined
by the RC to use it. There may be instances where the RC discusses operational
issues in normal dialogue with entities that do not require the use of Reliability
Directive. No change made.
It is recommended that the treatment of Reliability Directives shall be consistent
with those being developed for TOP-001-2 as proposed by the Real-Time Operations
drafting team (Project 2007-03).
The RCSDT is using the term in the same context in this standard as it is in TOP-001-2.
No change made.
As such, consider using the following language for R2: “Each TOP, BA, and GOP shall
comply with each identified Reliability Directive issued and identified as such by its
RC, unless such actions would violate safety, equipment, regulatory, or statutory
requirements.”
Accordingly, please consider using the following language for R3:
“Each TOP, BA, and GOP shall inform its RC of its inability to perform an identified
Reliability Directive issued by that RC.” Again, we do not believe the DP would
receive an identified Reliability Directive directly from the RC and the DP applicability
should be removed from this standard. The DP is appropriately captured under
COM-002 and TOP-001 with respect to Reliability Directives.
The RCSDT believes the latitude afforded in R2 and R3 allows for normal operational
dialogue that may not require the use of Reliability Directive. The RC determines
when Reliability Directive is applicable. No change made.
With respect to the Functional Model V5, please see Page 31, “18. Issues corrective
actions and emergency procedures directives (e.g., curtailments or load shedding) to
Transmission Operators, Balancing Authorities, Generator Operators, Distribution
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Providers, and Interchange Coordinators.” No change made.
The RCSDT is addressing a directive (P487, Order 693) to include the DP in COM-001
and the RCSDT has included the DP in COM-002 and IRO-001 applicability because
these standards are related to reliability communications. The RCSDT agrees with
the point that communication will most likely be from the BA or TOP; however, the
communications may come from the RC. No change made.
Accordingly, NERC’s Reliability Functional Model V5 describes and identifies the DP’s
relationships with other functional entities to TOP and BA with respect to Real Time.
Real Time 10
7. Implements voltage reduction and sheds load as directed by the Transmission
Operator or Balancing Authority.
8. Implements system restoration plans as coordinated by the Transmission
Operator.
9. Directs Load-Serving Entities to communicate requests for voluntary load
curtailment.
The following comments are regarding COM-001-2.
With respect to the Functional Model V5, please see Page 31, “18. Issues corrective
actions and emergency procedures directives (e.g., curtailments or load shedding) to
Transmission Operators, Balancing Authorities, Generator Operators, Distribution
Providers, and Interchange Coordinators.” No change made.
The SDT should include an additional qualifier to Interpersonal Communications
within the context of these requirements, for example (operational or dispatch
center communications???). Technically, the air we breathe, as well as other
mediums like “any” cell phone, fax lines, and/or email accounts would qualify under
10
NERC Functional Model Version 5, “Functional Entity – Distribution Provider,” pg 47, (http://www.nerc.com/files/Functional_Model_V5_Final_2009Dec1.pdf)
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this proposed definition of Interpersonal Communication. Assuming at least one
employed individual can speak, all entities could demonstrate compliance of this
capability at all times, therefore, it is not clear the intent of these requirements are
accurately being presented.
The RCSDT appreciates your comment and has made clarifying changes by removing
the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a clarifying
change to indicate the DP and GOP only need to consult with the entity affected by
the failure.
The RCSDT agrees with your assessment of “medium” and included the term to allow
flexibility for an entity to communicate as they determine and demonstrate
compliance. Two or more individuals are required for communication to occur
where they interact, consult or exchange information. No change made.
The RCSDT proposes that R4 allows for compliance flexibility. “Signed attestation
letters” could qualify as “equivalent evidence” as stated in M4 and M11. No change
made. It is recommended to include the use of “signed attestation letters” as
examples of evidence under M4 and M11 and other measures as appropriate.
The RCSDT proposes that R4 and R11 allow for compliance flexibility. A “signed
attestation letter” is one form of evidence. The measures are examples and the
entity is not limited to those examples. No change made.
Response: See response above.
Ingleside Cogeneration LP
Ingleside Cogeneration LP is concerned that the entity-to-entity organization of the
COM Standards is quickly being outdated by voice and video conferencing or one-tomany broadcasts. In addition, email may be a preferred mode of most
communications to and from small Generator Operators.
It is not clear that these technologies are precluded from consideration by COM-001
and COM-002 - which means that some auditors may believe that they are. This
leads to inconsistent application of the compliance criteria, and may discourage the
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use of some powerful technologies. It appears to us that some technical guidelines
would be appropriate to help entities and auditors decide which are applicable under
these Standards.
Response: The RCSDT proposes that COM-001-2 and COM-002-3, as written, allows flexibility for an entity to communicate where
two or more individuals are required for communication to occur and they interact, consult or exchange information. Compliance is
contained in the measures and an entity must determine if their communication method can demonstrate compliance with the
requirements. No change made.
Duke Energy
- COM-001-2 does not specify how much time an entity is allowed to restore failed
Interpersonal Communications capability or failed Alternative Interpersonal
Communications capability.
R1 through R6 require that the RC, TOP and BA have both. R7 and R8 require that
DPs and GOPs have Interpersonal Communications capability. An auditor could find
an entity non-compliant with these requirements upon failure of either capability.
The RCSDT thanks you for your comment. Requirements R7 and R8 have been
revised to account for the failure of Interpersonal Communication capability. The
intent of R11 is to require the responsible entity to take action upon the failure of its
Interpersonal Communication.
R9, R10 and R11 specify actions to take upon failure, but do not relieve entities of
responsibility under R1 through R8.
The RCSDT believes non-compliance is not due solely to the failure of any
Interpersonal Communication capability, but must be accompanied by a failure to
consult with the applicable Transmission Operator or Balancing Authority to
establish mutually agreeable action for restoration. No change made.
-COM-001-2 R9, M9 and VSLs - M9 and VSLs should be revised to be consistent with
wording of R9 phrase “at least once per calendar month.”
The RCSDT agrees with your comments and has aligned M9 and the R9 VSL to the R9
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to use “once each calendar month.”
-COM-001-2 R10, M10 and VSLs - Clarity is needed regarding when the 60-minute
clock starts. For example, suppose a failure is detected immediately upon
occurrence of the failure. Does the 60-minute clock start immediately, or after the
failure has lasted 30 minutes? When does the 60-minute clock start if a failure is
detected and the entity is unsure when it occurred?
The RCSDT proposes that upon detection of failure that continues at least 30
minutes, starts the 60-minute clock. The 30 minutes allows an entity time to restore
or determine if it can restore its Interpersonal Communication capability before the
clock starts. No change made.
-COM-001-2 R10, M10 and VSLs - If the failure only lasts for 35 minutes, it appears
that the RC, TOP or BA is still required to notify entities identified in R1 through R6.
Is this the drafting team’s intent?
Yes. The clock starts upon detection of failure of at least 30 minutes. No change
made.
-COM-001-2 R10, M10 and VSLs - Should be revised since the RC, TOP and BA are
only required to have Alternative Interpersonal Communications capability with
other RCs, TOPs and BAs per R2, R4 and R6.
For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
Suggested rewording for R10:
“Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
notify entities with which it is required to have Alternative Interpersonal
Communications capability as identified in R2, R4 and R6 within 60 minutes of the
detection of a failure of its Interpersonal Communications capabilities that lasts 30
minutes or longer.”
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Question 6 Comment
-COM-001-2 M11 and VSL - Replace the word “their” with the word “its.”
The RCSDT agrees and has modified M11 and VSL, as you suggested.
-COM-001-2 Data Retention - The way Data Retention is being enforced, this whole
section could just be reduced to a blanket statement that an entity must be able to
provide evidence that it has been in compliance since its last audit.
The RCSDT has provided the Data Retention section consistent with the approved
Standard Drafting Team Guidelines. No change made.
-COM-002-3 R2, M2 and VSL - Replace “and” with “or.”
The RCSDT agrees with your comment and modifies R2, M2, and VSL accordingly.
Also, the phrase “repeat, restate, rephrase or recapitulate” seems excessive and may
be intended to avoid a violation where an entity fails to repeat the Reliability
Directive word for word. Suggested rewording:
“Each Balancing Authority, Transmission Operator, Generator Operator or
Distribution Provider that is the recipient of a Reliability Directive shall repeat the
Reliability Directive back to the issuer with sufficient accuracy so that understanding
can be confirmed.”
The RCSDT believes the term suggested “sufficient accuracy” is subject to
interpretation. The RCSDT proposes the terms to allow a recipient to convey the
message back to the issuer without a word-for-word requirement as long as the
issuer confirms the accuracy of the response or reissues it to resolve any
misunderstanding. No change made.
-COM-002-3 R3, M3 - Replace “and” with “or.”
The RCSDT agrees with your comment and modifies R3, M3, and VSL accordingly.
-IRO-001-3 - We believe that the Purpose and the Requirements of this standard
should be focused solely on situations where the Reliability Coordinator issues
Reliability Directives to prevent an Emergency or Adverse Reliability Impact.
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The RCSDT development of IRO-001-3 R1 states “…which could include issuing
Reliability Directives…” and, therefore, does not preclude its use if it is determined
by the RC to use it. There may be instances where the RC discusses operational
issues in normal dialogue with entities that do not require the use of Reliability
Directive. No change made.
IRO-001-3 - The Purpose should be rewritten as follows: “To establish the authority
of Reliability Coordinators to issue Reliability Directives to other entities to prevent
an Emergency or the impact of an event that results in Bulk Electric System instability
or Cascading.”
The RCSDT appreciates the suggested rewording; however, the RCSDT development
of the IRO-001-3 Purpose Statement allows for instances where the RC discusses
operational issues in normal dialogue with entities that do not require the use of
Reliability Directive. The requirements of IRO-001-3 allow the RC to issue a
Reliability Directive if they determine one should be issued. No change made.
-IRO-001-3 - R1 should be rewritten as follows: “Each Reliability Coordinator shall
have authority to act or to issue Reliability Directives to others, including but not
limited to the Transmission Operator, Balancing Authority and Generator Operator
within its Reliability Coordinator Area to prevent identified events or mitigate the
magnitude or duration of actual events that result in an Emergency or the impact of
an event that results in Bulk Electric System instability or Cascading.”
The RCSDT appreciates the suggested rewording; however, the Functional Model V5
addresses the scope of the RC function. No change made.
-IRO-001-3 - R2 should be rewritten as follows:
“Each Transmission Operator, Balancing Authority, Generator Operator or
Distribution Provider shall comply with a Reliability Directive issued by the Reliability
Coordinator unless the Reliability Directive cannot be physically implemented or
unless such action would violate safety, equipment, regulatory, or statutory
requirements.”
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The RCSDT appreciates the suggested rewording; however, as written R2 allows for
normal operational dialogue without having to invoke a Reliability Directive by the
RC. No change made.
-IRO-001-3 - R3 should be rewritten as follows: “Each Transmission Operator,
Balancing Authority, Generator Operator or Distribution Provider shall inform its
Reliability Coordinator upon recognition of its inability to comply with a Reliability
Directive in accordance with Requirement R2.
The RCSDT appreciates the suggested rewording; however, as written R2 allows for
normal operational dialogue without having to invoke a Reliability Directive by the
RC. No change made.
-IRO-001-3 Measures and VSLs - Should be revised to conform with the above
suggested revisions to requirements.
Response: See response above.
ISO New England
none
ERCOT ISO
Regarding COM-001-2:
We are not clear on the time horizon of requirements for COM-001-2. Based upon
the purpose statement, it appears that establishment would be ahead of real time.
Wording in the requirements could be construed as maintaining at all times vs.
establishing communications.
The RCSDT proposes that compliance with requirements of the standard must be
demonstrated. The Purpose Statement is not measured. No change made.
The timeline for mandatory/effectiveness may not be acceptable to establish
communications with DPs if hardware procurement/projects must take place.
The RCSDT considered concerns about the implementation of the requirements by
DP and GOPs and concluded the requirements are achievable within the
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implementation period. No change made.
Regarding IRO-001-3:
We have some concern for the removal of LSE in particular from R2 and R3 from
current IRO-001-2 for the ERCOT region. The ERCOT region has QSEs that manage
Load Resources. There may be some QSEs that are not registered as a GOP that
deploy Load Resources. Per the current LSE JRO, QSEs with Load Resources are
registered as LSEs. Not requiring LSEs to deploy Load Resource directives could be
perceived as a reliability gap created from the previous version to this version. PSEs
could be removed as long as they fall under BA authority.
The RCSDT believes the DP is the correct entity because the LSE does not own assets.
The definition of LSE is, “The functional entity that secures energy and transmission
service (and reliability related services) to serve the electrical demand and energy
requirements of its end use customers.” In contrast, the definition of a DP is, “The
functional entity that provides facilities that interconnect an End-use Customer load
and the electric system for the transfer of electrical energy to the End-use Customer.
Additionally, the Functional Model V5 demonstrates this under the Reliability
Coordinator, “18. Issues corrective actions and emergency procedures directives
(e.g., curtailments or load shedding) to Transmission Operators, Balancing
Authorities, Generator Operators, Distribution Providers, and Interchange
Coordinators.” No change made.
The Data Retention section should be corrected to match the new requirements
numbers and elimination of the previous version R1 with ERO.
The Version History mentions six requirements retired, but only details five.
The RCSDT thanks you for your comments. The Data Retention language has been
updated to be consistent with the Standards Drafting Guidelines.
Response: See response above.
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ReliabilityFirst
Yes or No
Question 6 Comment
Comments on COM-001-2
1. Applicability Section
a. RFC recommends adding the Generator Owner to the applicably section of the
standard along with corresponding Requirements R8 and R11. ReliabilityFirst
believes to maintain system reliability and based on certain business practices in
effect, Generator Owners need to be required to have associated Interpersonal
Communications with its Balancing Authority and Transmission Operator.
The RCSDT considered this situation and have concluded Generator Owners do not
operate facilities of the BES. Under the Functional Model V5 Generator Owners have
these Relationships with Other Functional Entities. The following is an excerpt from
the Functional Model V5 concerning the Generator Owner. No change made.
1. Provides generator information to the Transmission Operator, Reliability
Coordinator, Balancing Authority, Transmission Planner, and Resource Planner.
2. Provides unit maintenance schedules and unit retirement plans to the
Transmission Operator, Balancing Authority, Transmission Planner, and Resource
Planner.
3. Develops an interconnection agreement with Transmission Owner on a facility
basis.
4. Receives approval or denial of transmission service request from Transmission
Service Provider.
5. Provides reliability related services to Purchasing-Selling Entity pursuant to
agreement.
6. Reports the annual maintenance plan to the Reliability Coordinator, Balancing
Authority and Transmission Operator.
7. Revises the generation maintenance plans as requested by the Reliability
Coordinator.
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2. Requirement R7 and R8
a. ReliabilityFirst seeks further clarity on why the Distribution Provider and Generator
Operator are not required to designate an Alternative Interpersonal Communications
capability?
Requirements R7 and R8 require the Distribution Providers and Generator Operators
to have Interpersonal Communications capability but there is not corresponding
requirement to have an Alternative Interpersonal Communications capability.
ReliabilityFirst recommends adding two new requirements for the Distribution
Provider and Generator Operator to designate an Alternative Interpersonal
Communications capability. This will be consistent with how Requirements R1
through R6 are set up.
The standard establishes requirement for communication capability appropriate to
ensure reliability. In addition, R7 and R8 are responsive to FERC Order No. 693.
Entities may use the telephone cited in the example as their Interpersonal
Communication capability. Requirement R11, as modified, addresses the loss of
Interpersonal Communication capability. No change made.
3. Requirement R9
a. Assuming new requirements for the Distribution Provider and Generator Operator
to designate an Alternative Interpersonal Communications capability (based on
previous comment) are added to the standard, the Distribution Provider and
Generator Operator will need to be added to Requirement R9 to test its Alternative
Interpersonal Communications capability at least once per calendar month.
The RCSDT thanks you for your comment and believes the DP and GOP only need
Interpersonal Communication capability and it meets the respective FERC directive.
No change made.
4. Requirement R10
a. Based on the ReliabilityFirst comment submitted for Question 4, ReliabilityFirst
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believes the Distribution Provider and Generator Operator should be included in
Requirement R10.
The RCSDT proposes that DP and GOP are included in the requirement. “… shall
notify entities…” as identified in R1 through R6. No change made.
b. Since Interpersonal Communications capabilities is a very important piece of
operating the BES in a reliable manner, ReliabilityFirst believes the timeframe in
which an entity is required to notify the entities is too long. ReliabilityFirst
recommends the following language for Requirement R10:
i. Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider and Generator Operator shall notify entities as identified in
Requirements R1 through R8 of a failure of its Interpersonal Communications
capabilities that lasts 15 minutes or longer. The notification shall be made within 30
minutes of the detection of a failure.
The RCSDT proposed the time frame to allow sufficient time for an entity to
determine if IC could be restored. No change made.
5. VSLS for Requirement R1 through R8
a. ReliabilityFirst suggest gradating the VSLs for R1 through R8. Listed below is an
example of how to gradate the VSL for R1. The same type of approach could be used
for R2 through R8 as well.
i. High VSL- the Reliability Coordinator failed to have Interpersonal Communications
capability with one or more of the entities listed in Parts 1.1 or 1.2.
ii. Severe VSL - The Reliability Coordinator failed to have Interpersonal
Communications capability with one or more of the entities listed in Parts 1.1 and
1.2.
The RCSDT has applied the VSL to the Severe column because not having
Interpersonal Communication capability with any entity is detrimental to reliability.
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Question 6 Comment
No change made.
6. VSL for Requirement R9
a. For consistency with the requirement language, ReliabilityFirst recommends
adding the words “at least on a monthly basis” to the Lower, Moderate and High
VSLs and adding the words “if the test was unsuccessful” to the end of the Lower,
Moderate and High VSLs.
Listed below is an example of the Lower VSL.
i. The responsible entity tested the Alternative Interpersonal Communications
capability at least once per calendar month but failed to initiate action to repair or
designate a replacement Alternative Interpersonal Communications in more than 2
hours and less than or equal to 4 hours if the test was unsuccessful.
The RCSDT notes the requirement requires the entity to perform the test each
month. If the test is not performed during each month, there is no other option for
gradating the severity of the violation. No change made.
7. VSL for Requirement R10
a. ReliabilityFirst provided alternate language for R10 in the comments listed above.
If the alternated language is not incorporated, ReliabilityFirst recommends the
following language for the Lower VSL. Similar language could be used for the
Moderate, High and Severe VSLs as well.
i. The responsible entity failed to notify entities as identified in Requirements R1
through R6 more than 60 minutes but less than or equal to 70 minutes of the
detection of a failure of its Interpersonal Communications capabilities.
b. If the alternate language for R10, in the comments listed above, is incorporated,
ReliabilityFirst recommends the following language for the Lower VSL. Similar
language could be used for the Moderate, High and Severe VSLs as well.
i. The responsible entity failed to notify entities as identified in Requirements R1
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through R6 more than 30 minutes but less than or equal to 740 minutes of the
detection of a failure of its Interpersonal Communications capabilities
c. For Moderate VSL (the VSL after the OR statement), ReliabilityFirst recommends
using a percentage rather than the “least one, but not all” statement. For example,
if there is say 100 impacted entities and the applicable entity only notify 1, they
would only fall under the Moderate. In another scenario there is say 100 impacted
entities and the applicable entity only notified 99, they would also fall under the
Moderate as well. The use of percentages will help even this out.
The RCSDT made conforming changes to the VSLs to address a number of comments
and changes to the requirements.
8. VSL for Requirement R11
a. For consistency with the requirement language, ReliabilityFirst recommends the
following language:
i. The responsible entity that experiences a failure of any of its Interpersonal
Communication capabilities failed to consult with their Transmission Operator or
Balancing Authority as applicable to determine a mutually agreeable time to restore
the Interpersonal Communication capability.
Comments on COM-002-3
The RCSDT has made conforming changes to the VSLs due to comments received
about the R11.
1. Requirement R1
a. Based on ReliabilityFirst suggested change to the definition of “Reliability
Directive” as noted in Question 5, ReliabilityFirst recommends deleting Requirement
R1. Based on the suggested definition, any communication initiated, where an
action by the recipient is required, is considered a “Reliability Directive.” Thus, there
would no longer be a need for responsible entity to identify the action as a
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“Reliability Directive” to the recipient.
In coordination with the RTOSDT work on the TOP family of standards, the RCSDT
does not propose that the Reliability Directive definition contain a requirement for
action to be taken. Therefore, R1 is retained as a requirement for the “action” to be
taken. No change made.
2. VSL for Requirement R3
a. For consistency with the requirement language, ReliabilityFirst recommends the
following language:
The RCSDT has followed the VSL Guidelines in properly assigning the VSL as binary.
No change made.
i. The responsible entity issued a Reliability Directive, but failed to confirm that the
response from the recipient of the Reliability Directive (in accordance with
Requirement R2) was accurate.
Comments on IRO-001-3
1. Requirement R1
a. ReliabilityFirst seeks further clarity on why Requirement R1 only requires the
Reliability Coordinator to have the “authority to act” rather than requiring the
Reliability Coordinator to actually “take action” to prevent identified events that
result in an Emergency or Adverse Reliability Impacts. Having the “authority to act”
does not inherently require the Reliability Coordinator to take action, if appropriate.
The RCSDT proposes that R1 reflects the Purpose of IRO-001-3. No change made.
b. ReliabilityFirst seeks further clarity on the language “to prevent identified events.”
If the event was already identified, how can the Reliability Coordinator act to prevent
it? ReliabilityFirst recommends adding the word “potential” in between the words
“prevent” and “identified.”
The context of “identified” is when a set of system conditions is recognized that
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could lead to an Emergency or Adverse Reliability Impact, which may require action.
See standards IRO-008 and IRO-009. No change made.
2. Requirement R3
a. There is no time qualifier specified in Requirement R3 dealing with the timeframe
in which the applicable entity has to inform its Reliability Coordinator of its inability
to perform as directed in accordance with Requirement R2. Without a time qualifier,
Requirement R3 is open ended and could cause issues if the applicable entity does
not inform its Reliability Coordinator upon recognition of its inability to perform as
directed in a timely manner. ReliabilityFirst recommends the following language for
Requirement R3:
i. Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator within 30 minutes upon
recognition of its inability to perform as directed in accordance with Requirement R2.
The RCSDT proposes the term “upon recognition of its inability to perform” does not
require a time limit. No change made.
The Measure M3, has been updated to include the phrase “upon recognition of its
inability” to be consistent with R3.
3. VSL for Requirement R1
a. Requirement R1 requires the Reliability Coordinator to “...have the authority to
act” - and the VSL does not reflect this language. ReliabilityFirst had questioned why
Requirement R1, does not specifically require the RC to take action or direct actions
in a comment submitted under Requirement R1. If the SDT does not change the
language in Requirement R1, ReliabilityFirst recommends the following language:
i. The Reliability Coordinator failed to have the authority to take action or direct
actions, to prevent an identified event that resulted in an Adverse Reliability Impact.
The RCSDT made conforming changes to the VSL.
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4. VSL for Requirement R2
a. For the High VSL, the words “fully comply” are ambiguous and open to
interpretation. ReliabilityFirst recommends only having a Severe VSL.
b. The Severe VSL states “directive” while Requirement R2 states “direction.” To be
consistent, ReliabilityFirst recommends the following language:
i. “The Responsible Entity failed to comply with its Reliability Coordinator’s direction”
The RCSDT thanks you for your comment and has made conforming changes to the
VSL.
Response: See response above.
City of Vero Beach
In the definition of Interpersonal Communication, the use of the word “medium” is
ambiguous. Suggestions for alternatives: “system”, “channel.”
The RCSDT proposes the term “medium” to allow entities flexibility on how they
communicate and meet compliance with the requirements. No change made.
COM-001-2, R1 and R3, the phrase: “have Interpersonal Communications
capabilities”, what if the communication system fails?
The RCSDT proposes that AIC is in force at that time. No change made.
Is that an immediate non-compliance (especially R3.3 and R3.4 which do not require
a redundant system). Suggest using EOP-008 type of language to allow restoration of
failed equipment without non-compliance.
The RCSDT reviewed both EOP-008-0 and EOP-008-1, which is subject to future
enforcement. In either version, the team believes there is no need to add additional
language to the standard. No change made.
The RCSDT believes that prescribing a device or medium would limit an entity;
therefore, “capability” is used to avoid being prescriptive and to provide flexibility.
This was not intended by the drafting team. The intent is to give the entity the
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flexibility in meeting the requirement. A loss of Interpersonal Communication
capability is covered by R10, notification of Interpersonal Communication capability
failure. No change made.
COM-001-2, R9 - "Each ... shall test its Alternative Interpersonal Communications
capability", suggest adding the phrase "to each entity for which Alternative
Interpersonal Communications is required" to add clarity. In addition, the type of
testing is unclear and ambiguous.
The RCSDT proposes that R9 correctly identifies and provides clarity for the entities
required to have Alternative Interpersonal Communication capability. No change
made.
The is also ambiguity in the terms “direct”, “directive”, “direction” and “Reliability
Directive.” The SDT may want to consider using the terms “instruct” and
“instruction” in place of “direct,” “directive,” or “direction” to more clearly
distinguish from a Reliability Directive.
The RCSDT feels the use of direct and directed is consistent with the purpose and
application of those terms in other standards and is consistent with previous
postings. No change made.
Response: See response above.
NV Energy
The meaning of R9 is open to some interpretation. It states that if the monthly test
is unsuccessful, the entity shall "initiate action to repair or designate a replacement"
AIC within 2 hours. The meaning of this is unclear in several ways:
First, does "initiate action" apply to the remainder of the sentence or just to the
"repair" option?
Second, what constitutes initiation of action?
Is it the intent of the SDT that the alternate interpersonal communications be
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restored within a 2-hour limit?
If so, the words do not clearly state that, and it seems an impossible task to ensure
no more than 2-hr outage to an alternate communications medium. I am voting
affirmative under the interpretation that one must only "initiate" the repair or
"initiate" the designation of a replacement option within this tight 2-hour limit.
Response: The requirement is to initiate repair or designate an Alternative Interpersonal Communication capability within two
hours. The requirement is NOT to have the repair completed within two hours. The requirement recognizes that the entity may use
its Alternative Interpersonal Communication capability now as its Interpersonal Communication capability; and then, if it decides to
do so, designate another, if you may, “new” Alternative Interpersonal Communication capability. This is not required, but is an
option that the entity can consider. The entity may already have a maintenance and repair agreement in place that will respond and
repair the failed capability. No change made.
Midwest Independent
Transmission System
Operator
COM-001-2, R2 and R6:
MISO requests clarification as to whether the designation of Interpersonal
Communications and Alternative Interpersonal Communications methods by
Responsible Entities must be formally documented and/or agreed upon with those
entities with which communications capability must be established.
The RCSDT has provided flexibility to the responsible entity with regard to
implementation and compliance. Please note that Interpersonal Communication is a
“shall have” and Alternative Interpersonal Communication capability is “designate.”
Please refer to the Measures for suitable evidence, which may be used to support
compliance with the requirement. No change made.
COM-001-2, R9:
MISO suggests that the designation of Alternative Interpersonal Communications
methods should not require formal documentation and may be agreed upon (when
necessary) informally with those entities with which communications capability must
be established in the event of an unsuccessful test of its Alternative Interpersonal
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Communications capability.
The RCSDT has provided flexibility to the responsible entity with regard to
implementation and compliance. Please note that Interpersonal Communication is a
“shall have” and Alternative Interpersonal Communication capability is “designate.”
Please refer to the Measures for suitable evidence, which may be used to support
compliance with the requirement. No change made.
COM-001-2, Requirement R10:
MISO requests clarification as to whether “impacted entities” refers to those entities
with which the Responsible Entity must have Interpersonal Communications and
Alternative Interpersonal Communications capability.
Further, MISO requests clarification as to whether the notification required by R10
must be made using the Alternative Interpersonal Communications method selected
by the Responsible Entity.
The word “impacted” was removed in previous postings. For further clarification,
the RCSDT has modified M10 to remove the word “impacted” to be consistent with
R10. For additional clarity, the RCSDT also changed the phrase in R10 and M10, “R1
through R6” to “R1, R3, and R5,” to clarify that it applies to the capabilities with the
RC, the TOP, and the BA.
With respect to the method used by the Responsible Entity, the standard does not
provide the “how” or any prescriptive method for accomplishing the requirement.
No change made.
COM-002-3, R1 - R3:
MISO respectfully submits that, while it appreciates the distinction in responsibilities
proposed in the new COM-002-3 and acknowledges that such distinction is
beneficial, these requirements increase compliance risk and potential penalty liability
without attendant benefit to the reliability of the Bulk Electric System. MISO
respectfully suggests that Requirements 2 and 3 be converted into sub-requirements
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as follows:
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]
R1.1. When the Reliability Coordinator, Transmission Operator or Balancing Authority
identifies a stated action as a Reliability Directive, the receiving Balancing Authority,
Transmission Operator, Generator Operator, and Distribution Provider shall repeat,
restate, rephrase or recapitulate the Reliability Directive to the issuing Reliability
Coordinator, Transmission Operator or Balancing Authority. [Violation Risk Factor:
High][Time Horizon: Real-Time]
R1.2. When the Reliability Coordinator, Transmission Operator, and Balancing
Authority that issues a Reliability Directive receives a response from the receiving
Balancing Authority, Transmission Operator, Generator Operator, and Distribution
Provider, it shall then either [Violation Risk Factor: High][Time Horizon: Real-Time]:
-Confirm that the response from the recipient of the Reliability Directive (in
accordance with Requirement R2) was accurate, or
-Reissue the Reliability Directive to resolve any misunderstandings.
The RCSDT contends the requirements in the proposed standard have been
constructed in accordance with standard development guidelines to have only one
performance per requirement. The suggested change places three independent
actions within one requirement. No change made.
Response: See response above.
Texas Reliability Entity
(1) There are numerous errors in the Mapping Document in referencing the current
version of the standard and requirement. Specifically, referencing IRO-001-2 where it
appears that the document should reference standard IRO-001-3. In addition, the
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notes on page 2 of COM-002-3 are incorrect.
The RCSDT thanks you for your comments and has made conforming corrections.
(2) In the VRF/VSL Justification document, there are numerous errors in referring to
standard versions and requirements.
The RCSDT thanks you for your comments and has made conforming corrections.
(3) In IRO-001-3, R1 - What is an “identified event,” and who “identifies” an event
that requires compliance with this requirement R1? An RC may choose not to
“identify” an event, such as a limit violation, and run the risk of causing or
exacerbating an emergency. If the RC does not “identify” the event, it may become
an actual event and then fall within the standard.
The context of “identified” is when a set of system conditions are recognized that
could lead to an Emergency or Adverse Reliability Impact, which may require action.
See standards IRO-008 and IRO-009. The RC named in R1 is the entity that identifies
the even that requires compliance. No change made.
(4) In the VSL for IRO-001-3, R1, there should be language in the VSL to capture the
term “Emergency,” which was added in the Requirement. The High VSL for R2 needs
to be fixed.
The RCSDT thanks you for your comments and has made conforming corrections.
The “N/A” in R2 of COM-002-3 was removed.
(5) In IRO-001-3, R1, remove the “s” in the phrase “Adverse Reliability Impacts.”
The RCSDT thanks you for your comments and has made conforming corrections.
(6) Referring to the Implementation Plan for IRO-001 - There is a different list in the
Implementation Plan (R2, R4, R5, R6, R7, R9) than the Revision History of the
Standard (R2, R4, R5, R6, R8). Where is the retirement of R1 shown?
The RCSDT thanks you for your comments and has made conforming corrections.
(7) Referring to COM-001-2: Measure 7, the word “that” is inadvertently repeated in
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the first sentence.
COM-001-2, M8: The RCSDT agrees and the language in Measure M8 has been
changed to delete the additional “that.”
(8) In COM-001-2, Measure 9, is “at least on a monthly basis” to be interpreted
differently than “at least once per calendar month” as stated in the requirement?
The RCSDT thanks you for your comments and has made conforming corrections to
Measure M9 and the R9 VSL.
(9) In COM-001-2, there is a “Measure 12” bullet that should be removed.
The RCSDT thanks you for your comments and has made conforming corrections.
(10) Referring to COM-002-3: Electronic directives (which may be issued over many
different types of electronic communication channels) are increasingly necessary to
manage the modern, dynamic Bulk Power System (generation and transmission) on a
real-time basis. The effective use of electronic directives is undermined by this
proposed Standard in its current form. This draft standard, in conjunction with other
standards that refer to directives, appears to require that directives (at least
Reliability Directives) be given verbally. The failure of the NERC standards to address
electronic directives may cause significant manpower issues for BAs with large
portfolios of generation to manage.
The RCSDT proposes that COM-001-2 and COM-002-3, as written, allows flexibility
for an entity to communicate where two or more individuals are required for
communication to occur and they interact, consult or exchange information.
Compliance is contained in the Measures and an entity must determine if its
communication method can demonstrate compliance with the requirements. No
change made.
(11) In the VSL for COM-001-2 R4, a reference to Part 4.3 should be added.
The RCSDT thanks you for your comments and has made conforming corrections.
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(12) In IRO-001-3, Part 1.3 Data Retention, the reference in the first bullet to “Electric
reliability Organization” is incorrect. We think it should say “Reliability Coordinator”
instead.
The other references to entities and to Requirements in this Part 1.3 also appear to
be incorrect and need to be updated and corrected.
The RCSDT thanks you for your comment and has made conforming changes.
(13) Referring to COM-001-2, the prior version of this standard included
Requirement R5: “Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions and procedures to
enable continued operation of the system during the loss of telecommunications
facilities.” This Requirement has been removed from the present draft of COM-0012.
The RCSDT removed this requirement because it did not have a reliability benefit.
No change made.
The mapping document seems to suggest that this Requirement was moved to EOP008, but it is not there. We are concerned that removal of this Requirement will
result in a reduction in the level of BES reliability and introduce a potential reliability
gap.
As stated in the Implementation Plan, the RCSDT proposes retiring COM-001-1, R5 as
it is redundant with EOP-008-0, R1 as well as replacement EOP-008-1, R1. No change
made.
Response: See response above.
Hydro One Networks Inc.
(1) The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 on P. 4 of the draft standard
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COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s Implementation Plan
and P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following effect:”,
or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.”
The RCSDT is uncertain where the conflict exists. The standard IRO-001 uses the
term “after applicable” and the others “following applicable.” The RCSDT has
updated the standards to use the most current effective date language.
(2) COM-001: Measure M9: - “monthly basis.” Suggest changing “monthly basis” to
“at least once per calendar month” to be consistent the wording in R9.
The RCSDT thanks you for your comment and has made conforming changes the
Measure M9 and the R9 VSL.
(3) IRO-001: Measures M1, M2, M3 - The types of evidence are listed in paragraph
form. This is not consistent with presentation style in COM-001-2 Measures, where
evidence is listed in bullet format. Suggest using bullet form for consistency.
The RCSDT appreciates your comments and has made all the Measures bullet form in
COM-001-2, but not in COM-002-3 and IRO-001-3.
(4) IRO-001, Data Retention Section:
i. The retention requirements do not reflect the revised requirements. For example:
the Electric Reliability Organization is no longer a responsible entity; the Reliability
Coordinator should replace the ERO for keeping data for R1; Transmission Operator,
Balancing Authority, Generator Operator and Distribution Provider should replace
the Reliability Coordinator for keeping data for R2; and there is no R4/M4.
ii. Section 1.3, second paragraph:
“The Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, or Distribution Provider... shall keep data or evidence to show compliance
as identified below unless directed by its Compliance Enforcement Authority to
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retain specific evidence for a longer period of time as part of an investigation:”
The word “or” between Generator Operator and Distribution Provider should be
changed to “and.”
The RCSDT thanks you for your comment and has made conforming changes to the
Data Retention section.
Response: See response above.
New York Independent
System Operator
COM-001
The drafting team has complicated the requirements by having different
requirements between RC/TOP/BA and other entities such as GOP/LSE/DP. The
proposal is for redundancy to be required only between RC/TOP/BA. The
requirement should be simplified to require all identified entities to have plans for
loss of primary communication channels. This could include third parties as a
communication channel.
The RCSDT refers the Order No. 693 in Paragraph 508 to clarify the reason the DP
and GOP are not required to have Alternative Interpersonal Communication and is as
follows: “(1) expands the applicability to include Generator Operators and
Distribution Providers and includes Requirements for their telecommunications
facilities; (2) identifies specific requirements for telecommunications facilities for use
in normal and emergency conditions that reflect the roles of the applicable entities
and their impact on Reliable Operation and (3) includes adequate flexibility for
compliance with the Reliability Standard, adoption of new technologies and costeffective solutions.” In addition, R11 requires the DP and GOP to consult with its BA
and TOP to determine a mutually agreeable action for restoration. No change made.
COM-002
The drafting team added a requirement to identify a Reliability Directive is being
initiated during an emergency to track 3-part communication for compliance
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purposes. This will change and complicate the communication protocols between
normal and emergency operations simply to simplify compliance assessments. The
NYISO is asking for clarification that an entity may identify Reliability Directives as a
category of communications to be communicated through procedures and training;
and will not require a different communication protocol between normal and
emergency operations. Affective communications can only be achieved through
consistent processes for all conditions. Compliance assessments should be made on
when we are in an emergency or not, and not on how the dialogue was initiated.
The RCSDT believes the standard allows for this condition, and the method of
implementation is up to the entity. No change made.
Response: See response above.
END OF REPORT
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007.
2. Draft SAR Version 1 Comment Period ended February 14, 2007.
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007.
4. Draft Version 2 SAR comment period ended April 17, 2007.
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2 of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 18, 2010.
11. Fourth posting of revised standards on January 25, 2011 with comment period closed on
March 7, 2011.
12. Initial ballot conducted February 25 through March 7, 2011.
13. Draft version 5 of the standard and response to comments March 7, 2011 – January 9,
2012.
14. Fifth posting of revised standards on January 9, 2012 with comment period closed on
February 9, 2012.
15. Successive ballot conducted January 30 through February 9, 2011.
16. Draft version 6 of the standard and response to comments February 9, 2011 – June 5,
2012.
17. Sixth posting of revised standard on June 7, 2012 with comment period closed on July 6,
2012.
18. Successive ballot conducted June 27 through July 6, 2012.
Draft 6: April 6, 2012
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Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contain revisions based on stakeholder comments on the initial ballot. The team is posting for a
successive ballot.
Future Development Plan:
Anticipated Actions
1. Post standards for a successive ballot.
2. Respond to comments on successive ballot.
3. Standard posted for second successive ballot.
Anticipated Date
January-February 2012
March - April 2012
June 2012
4. Standard posted for recirculation ballot.
September 2012
5. Standard to be sent to BOT for approval.
November 2012
6. Standard filed with regulatory authorities.
January 2013
Draft 6: April 6, 2012
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to
interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communication used for day-to-day operation.
Draft 6: April 6, 2012
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A.
Introduction
1. Title: Communications
2. Number:
COM-001-2
3. Purpose:
To establish Interpersonal Communication capabilities necessary to
maintain reliability.
4. Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5. Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1.Each Reliability Coordinator shall have Interpersonal Communication capability with the
following entities (unless the Reliability Coordinator experiences a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1. All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
1.2. Each adjacent Reliability Coordinator within the same Interconnection.
R2.Each Reliability Coordinator shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3.Each Transmission Operator shall have Interpersonal Communication capability with the
following entities (unless the Transmission Operator experiences a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
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3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4.Each Transmission Operator shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5.Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority experiences a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
5.1. Its Reliability Coordinator.
5.2. Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.3. Each Distribution Provider within its Balancing Authority Area.
5.4. Each Generator Operator that operates Facilities within its Balancing Authority
Area.
5.5. Each adjacent Balancing Authority.
R6.Each Balancing Authority shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
6.1. Its Reliability Coordinator.
6.2. Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
6.3. Each adjacent Balancing Authority.
R7.Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider experiences a failure of its
Interpersonal Communication capability in which case Requirement R11 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
7.1.
Its Balancing Authority.
7.2.
Its Transmission Operator.
R8.Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator experiences a failure of its
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Interpersonal Communication capability in which case Requirement R11 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9.Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall test
its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5 within 60 minutes of the
detection of a failure of its Interpersonal Communication capability that lasts 30
minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]
R11. Each Distribution Provider and Generator Operator that experiences a failure of its
Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communication capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with each adjacent
Reliability Coordinator within the same Interconnection, which could include, but is
not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with each adjacent Reliability Coordinator within the same Interconnection,
which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R2.)
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M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
and synchronously connected, which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that that it
has Interpersonal Communication capability with its Transmission Operator and its
Balancing Authority, which could include, but is not limited to:
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•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to dated and time-stamped: test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5 within 60 minutes of the detection of a failure of its
Interpersonal Communication capability that lasted 30 minutes or longer. Evidence
could include, but is not limited to dated and time-stamped: test records, operator logs,
voice recordings, transcripts of voice recordings, or electronic communications. (R10.)
M11. Each Distribution Provider and Generator Operator that experienced a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generator Operator, to
determine mutually agreeable action to restore the Interpersonal Communication
capability. Evidence could include, but is not limited to dated: operator logs, voice
recordings, transcripts of voice recordings, or electronic communications. (R11.)
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
1.2. Compliance Monitoring and Enforcement Processes
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Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•
The Reliability Coordinator shall retain evidence of Requirements R1, R2,
R9, and R10, Measures M1, M2, M9, and M10 for the most recent twelve
calendar months.
•
The Transmission Operator shall retain evidence of Requirements R3, R4,
R9, and R10, Measures M3, M4, M9, and M10 for the most recent twelve
calendar months.
•
The Balancing Authority shall retain evidence of Requirements R5, R6, R9,
and R10, Measures M5, M6, M9, and M10 for the most recent twelve
calendar months.
•
The Distribution Provider shall retain evidence of Requirements R7 and
R11, Measures M7 and M11 for the most recent twelve calendar months.
•
The Generator Operator shall retain evidence of Requirements R8 and R11,
Measures M8 and M11 for the most recent twelve calendar months.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, or Generator Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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2.
R#
R1
R2
R3
R4
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
N/A
Draft 6: April 6, 2012
Moderate VSL
High VSL
Severe VSL
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
N/A
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Reliability
Coordinator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
N/A
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R#
R5
R6
R7
Lower VSL
N/A
N/A
N/A
Draft 6: April 6, 2012
Moderate VSL
N/A
N/A
N/A
High VSL
Severe VSL
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Reliability Coordinator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
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R#
R8
R9
Lower VSL
Moderate VSL
High VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 2 hours and less than or
equal to 4 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 4 hours and less than or
equal to 6 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 6 hours and less than or
equal to 8 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority failed to test the
Alternative Interpersonal
Communication capability once each
calendar month.
Draft 6: April 6, 2012
Severe VSL
OR
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in more
than 8 hours upon an unsuccessful
test.
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R#
Lower VSL
Moderate VSL
High VSL
R10
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5 upon the detection of
a failure of its Interpersonal
Communication capability in more
than 60 minutes but less than or
equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5 upon the detection of
a failure of its Interpersonal
Communication capability in more
than 70 minutes but less than or
equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5 upon the detection of
a failure of its Interpersonal
Communication capability in more
than 80 minutes but less than or
equal to 90 minutes.
R11
N/A
Draft 6: April 6, 2012
N/A
N/A
Severe VSL
The Reliability Coordinator,
Transmission Operator, and
Balancing Authority failed to notify
the identified entities identified in
Requirements R1, R3, and R5 upon
the detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
The Distribution Provider or
Generator Operator that experienced
a failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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E.
Regional Differences
None identified.
F.
Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised in accordance with SAR for
Project 2006-06, Reliability
Coordination (RC SDT). Replaced R1
with R1-R8; R2 replaced by R9; R3
included within new R1; R4 remains
enforce pending Project 2007-02; R5
redundant with EOP-008-0, retiring R5
as redundant with EOP-008-0, R1;
retiring R6, relates to ERO procedures;
R10 & R11, new.
Revised
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007.
2. Draft SAR Version 1 Comment Period ended February 14, 2007.
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007.
4. Draft Version 2 SAR comment period ended April 17, 2007.
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2 of2of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 183, 2010.
11. Fourth posting of revised standards on January 25, 2011 with comment period closed on
March 7, 2011.
11.12.
Initial ballotBallot conducted February 25 through March 7, 2011.
13. Draft version 5 of the standard and response to comments March 7, 2011 – January 9,
2012.
14. Fifth posting of revised standards on January 9, 2012 with comment period closed on
February 9, 2012.
15. Successive ballot conducted January 30 through February 9, 2011.
16. Draft version 6 of the standard and response to comments February 9, 2011 – June 5,
2012.
17. Sixth posting of revised standard on June 7, 2012 with comment period closed on July 6,
2012.
18. Successive ballot conducted June 27 through July 6, 2012.
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Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
containcontains revisions based on stakeholder comments on the initial ballot. The team is
posting for a successive ballot.
Future Development Plan:
Anticipated Actions
1. Post standardsStandards for a successive ballot.
2. Respond to comments on successiveSuccessive ballot.
3. Standard posted for second successive ballot.
Anticipated Date
January-February 2012
March - April 2012
June 2012
3.4.
StandardStandards posted for recirculation ballot.
SeptemberMay 2012
4.5.
StandardStandards to be sent to BOT for approval.
NovemberJune 2012
5.6.
StandardStandards filed with regulatory authorities.
January 2013August 2012
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal
CommunicationCommunications used for day-to-day operation.
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A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To establish Interpersonal Communication capabilities for the exchange of
Interconnection and operating information necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved byfollowing applicable regulatory authorities,approval – or in
those jurisdictions where no regulatory approval is not required, the standard becomes
effective on the first day of the first calendar quarter beyond the date this standard is
approved by the NERCfollowing Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. adoption.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal CommunicationCommunications
capability with the following entities (unless the : [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
R1.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator experiences a failure of its Area.
R1.2.
Adjacent Reliability Coordinators within the same Interconnection.
R2.R1.
Each Reliability Coordinator shall designate an Alternative
Interpersonal CommunicationCommunications capability in which case Requirement
R10 shall apply): with the following entities: [Violation Risk Factor: High] [][Time
Horizon: Real-time Operations]
R2.1.R1.1.
All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area.
R2.2.R1.2.
Each adjacentAdjacent Reliability CoordinatorCoordinators within
the same Interconnection.
R3.R2.
Each Reliability CoordinatorTransmission Operator shall designate an
Alternativehave Interpersonal CommunicationCommunications capability with the
following entities: [Violation Risk Factor: High] [][Time Horizon: Real-time
Operations]
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2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3.Each Transmission Operator shall have Interpersonal Communication capability with the
following entities (unless the Transmission Operator experiences a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
R3.1.
3.1.
Its Reliability Coordinator.
R3.2.
3.2.
Each Balancing Authority within its Transmission Operator Area.
R3.3.
3.3.
Each Distribution Provider within its Transmission Operator Area.
R3.4.
3.4.
Each Generator Operator within its Transmission Operator Area.
R3.5.
3.5.
Each adjacentAdjacent Transmission OperatorOperators
synchronously connected within the same Interconnection.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
CommunicationCommunications capability with the following entities: [Violation
Risk Factor: High] [][Time Horizon: Real-time Operations]
R4.1.
4.1.
Its Reliability Coordinator.
R4.2.
4.2.
Each Balancing Authority within its Transmission Operator Area.
R4.3.
4.3.
Each adjacentAdjacent Transmission OperatorOperators
synchronously connected within the same Interconnection.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal CommunicationCommunications
capability with the following entities (unless the Balancing Authority experiences a
failure of its Interpersonal Communication capability in which case Requirement R10
shall apply): : [Violation Risk Factor: High] [][Time Horizon: Real-time Operations]
R5.1.
Its Reliability Coordinator.
R5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
R5.3.
Each Distribution Provider within its Balancing Authority Area.
R5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
R5.5.
Each adjacentAdjacent Balancing AuthorityAuthorities.
R6. Each Balancing Authority shall designate an Alternative Interpersonal
CommunicationCommunications capability with the following entities: [Violation
Risk Factor: High] [][Time Horizon: Real-time Operations]
R6.1.
Its Reliability Coordinator.
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R6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.).
R6.3.
Each adjacentAdjacent Balancing AuthorityAuthorities.
R7. Each Distribution Provider shall have Interpersonal CommunicationCommunications
capability with the following entities (unless the Distribution Provider experiences a
failure of its Interpersonal Communication capability in which case Requirement R11
shall apply): : [Violation Risk Factor: High] [][Time Horizon: Real-time Operations]
7.1.
Its Balancing Authority.
R7.1.
7.2.
R7.2.
Its Balancing Authority.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal CommunicationCommunications
capability with the following entities (unless the Generator Operator experiences a
failure of its Interpersonal Communication capability in which case Requirement R11
shall apply): : [Violation Risk Factor: High] [][Time Horizon: Real-time Operations]
R8.1.
8.1.
Its Balancing Authority.
R8.2.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal CommunicationCommunications capability at least
once eachper calendar month. If the test is unsuccessful, the responsible entity shall
initiate action to repair or designate a replacement Alternative Interpersonal
CommunicationCommunications capability within 2 hours. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations, Same-day Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5 through R6 within 60
minutes of the detection of a failure of its Interpersonal Communication
capabilityCommunications capabilities that lasts 30 minutes or longer. [Violation Risk
Factor: Medium] [][Time Horizon: Real-time Operations]
R11. Each Distribution Provider and Generator Operator that experiences a failure of any of
its Interpersonal Communication capabilitycapabilities shall consult each entity
affected by the failure, as identified in Requirement R7 for a Distribution Provider or
Requirement R8 for a Generatorwith their Transmission Operator, or Balancing
Authority as applicable to determine a mutually agreeable actiontime for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[][Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal CommunicationCommunications capability with all Transmission
Operators and Balancing Authorities within its Reliability Coordinator Area and with
each adjacent Reliability CoordinatorCoordinators within the same Interconnection,
which. Evidence could include, but is not limited to:
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•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal CommunicationCommunications capability
with all Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area and with each adjacent Reliability CoordinatorCoordinators within
the same Interconnection, which. Evidence could include, but is not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal CommunicationCommunications capability with its Reliability
Coordinator, and within its Transmission Operator Area each Balancing Authority,
Distribution Provider, and Generator Operator within its Transmission Operator Area,
and each adjacent Transmission Operator asynchronously and synchronously
connected, which. Evidence could include, but is not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
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•
electronic communicationcommunications
•
or equivalent evidence. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal CommunicationCommunications capability
with its Reliability Coordinator, and with each Balancing Authority within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
and Operators synchronously connected, which within the same Interconnection.
Evidence could include, but is not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal CommunicationCommunications capability with its Reliability
Coordinator, each Transmission Operator and Generator Operator that operates
Facilities within its Balancing Authority Area, each Distribution Provider within its
Balancing Authority Area, each Generator Operator that operates Facilities within its
Balancing Authority Area, and each adjacent Balancing Authority, which. Evidence
could include, but is not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence . (R5.))
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal CommunicationCommunications capability
with its Reliability Coordinator, each Transmission Operator that operates Facilities
within its Balancing Authority Area, and each adjacent Balancing Authority,
whichAuthorities. Evidence could include, but is not limited to:
Draft 6: April 6, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence (R6.))
M7. Each Distribution Provider shall have and provide upon request evidence that that it
has Interpersonal CommunicationCommunications capability with its Transmission
Operator and its Balancing Authority, which. Evidence could include, but is not limited
to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence (R7.))
M8. Each Generator Operator shall have and provide upon request evidence that that it has
Interpersonal CommunicationCommunications capability with its Balancing Authority
and its Transmission Operator, which. Evidence could include, but is not limited to:
•
•
physical assets, or
dated evidence, such as, equipment specifications and installation
documentation,
•
dated test records,
•
dated operator logs,
•
dated and time-stamped voice recordings, or dated and time-stamped
transcripts of voice recordings, or
•
electronic communications.
•
or equivalent evidence (R8.))
Draft 6: April 6, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least once each calendar
monthon a monthly basis, its Alternative Interpersonal Communication
capabilityCommunications capabilities designated in Requirements R2, R4, or R6. If
the test was unsuccessful, the entity shall have and provide upon request evidence that
it initiated action to repair or designated a replacement Alternative Interpersonal
CommunicationCommunications capability within 2 hours. Evidence could include,
but is not limited to dated and time-stamped: test records, dated operator logs, dated
voice recordings, or dated transcripts of voice recordings, or electronic
communications. , or equivalent evidence. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified impacted entities as identified
in Requirements R1, R3, and R5 within 60 minutes of the detection of a failure of its
Interpersonal Communication capabilityCommunications capabilities that lasted 30
minutes or longer. Evidence could include, but is not limited to dated and timestamped: test records, operator logs, dated voice recordings, or dated transcripts of
voice recordings, or electronic communications. , or equivalent evidence. (R10.)
M11. Each Distribution Provider and Generator Operator that experienced a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generatortheir Transmission
Operator, or Balancing Authority as applicable to determine a mutually agreeable
actiontime to restore the Interpersonal Communication capability. Evidence could
include, but is not limited to dated: operator logs, dated voice recordings, or dated
transcripts of voice recordings, or electronic communications. , or equivalent evidence.
(R11.)
M12.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The For entities that do not work for the Regional Entity, the Regional Entity
shall serve as the Compliance Enforcement Authority (CEA) unless the applicable
entity is owned, operated, or controlled by the.
For Reliability Coordinators that work for their Regional Entity. In such cases,
the ERO or a Regional Entity approved by the ERO and FERC or other applicable
governmental authorityauthorities shall serve as the CEA.Compliance
Enforcement Authority.
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audit
Self-Certification
Draft 6: April 6, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Spot Checking
Compliance Violation Investigation
Self-Reporting
Complaint
1.3. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
o TheEach Reliability Coordinator shall retain keep the most recent twelve
months of historical data (evidence of) for Requirements R1, R2, R9, and
R10, Measures M1, M2, M9, and M10 for the most recent twelve calendar
months.
o TheEach Transmission Operator shall retain keep the most recent twelve
months of historical data (evidence of) for Requirements R3, R4, R9, and
R10, Measures M3, M4, M9, and M10 for the most recent twelve calendar
months.
o TheEach Balancing Authority shall retain keep the most recent twelve
months of historical data (evidence of) for Requirements R5, R6, R9, and
R10, Measures M5, M6, M9, and M10 for the most recent twelve calendar
months.
o TheEach Distribution Provider shall retain keep the most recent twelve
months of historical data (evidence of) for Requirements R7 and R11,
Measures M7 and M11 for the most recent twelve calendar months.
o TheEach Generator Operator shall retain keep the most recent twelve
months of historical data (evidence of) for Requirements R8 and R11,
Measures M8 and M11 for the most recent twelve calendar months.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, or Generator Operator is found non-compliant with a
requirement, it shall keep information related to the noncompliancenoncompliance until mitigation is complete and approvedthe
Compliance Enforcement Authority finds it compliant or for the time period
specified above, whichever is longer.
Draft 6: April 6, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Draft 5:
December 29, 2011
Page 13 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
2.
R#
R1
R2
R3
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
Draft 6: April 6, 2012
Moderate VSL
N/A
N/A
N/A
High VSL
Severe VSL
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.N/A
The Reliability Coordinator failed to
have Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.N/A
The Transmission Operator failed to
have Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Reliability
Coordinator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R105.
Page 14 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R4
R5
R6
Lower VSL
N/A
N/A
N/A
Draft 6: April 6, 2012
Moderate VSL
N/A
N/A
N/A
High VSL
Severe VSL
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.N/A
The Transmission Operator failed to
designate Alternative Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.42.
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Reliability Coordinator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R10.N/A
The Balancing Authority failed to
have Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.N/A
The Balancing Authority failed to
designate Alternative Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
Page 15 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R7
R8
Lower VSL
N/A
N/A
Draft 6: April 6, 2012
Moderate VSL
N/A
N/A
High VSL
Severe VSL
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.N/A
The Distribution Provider failed to
have Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.N/A
The Generator Operator failed to
have Interpersonal
CommunicationCommunications
capability with twoone or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
Page 16 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R9
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
tested the Alternative Interpersonal
CommunicationCommunications
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
CommunicationCommunications in
more than 2 hours and less than or
equal to 4 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
tested the Alternative Interpersonal
CommunicationCommunications
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
CommunicationCommunications in
more than 4 hours and less than or
equal to 6 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
tested the Alternative Interpersonal
CommunicationCommunications
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
CommunicationCommunications in
more than 6 hours and less than or
equal to 8 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
failed to test the Alternative
Interpersonal
CommunicationCommunications
capability once each calendar
monthon at least a monthly basis.
Draft 6: April 6, 2012
OR
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
tested the Alternative Interpersonal
CommunicationCommunications
capability and identified a problem
but failed todidn’t initiate action to
repair or designate a replacement
Alternative Interpersonal
CommunicationCommunications in
more than 8 hours upon an
unsuccessful test.
Page 17 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
failed to notify the impacted entities
identified in Requirements R1, R3,
and R5 upon the detection of a failure
of its Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
failed to notify the impacted entities
identified in Requirements R1, R3,
and R5 upon the detection of a failure
of its Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
failed to notify the impacted entities
identified in Requirements R1, R3,
and R5 upon the detection of a failure
of its Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, and
Balancing Authorityresponsible entity
failed to notify the identifiedimpacted
entities identified in Requirements
R1, R3, and R5 upon the detectionin
more than 90 minutes.
OR
The responsible entity notified at
least one, but not all, impacted
entities of the failure of its
Interpersonal Communications
capabilities within 60 minutes.
Draft 6: April 6, 2012
OR
The responsible entity failed to notify
any impacted entities of athe failure
of its Interpersonal Communication
capability in more than 90
minutes.Communications
capabilities.
Page 18 of 21
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Distribution Provider or
Generator Operator that experienced
a failure of its Interpersonal
Communication capability
R11
N/A
N/A
N/A
responsible entity failed to consult
with each entity affected by the
failure,their Transmission Operator
or Balancing Authority as
identified in Requirement R7 for a
Distribution Provider or Requirement
R8 for a Generator
Operator,applicable to determine a
mutually agreeable action for the
restoration oftime to restore the
Interpersonal Communication
capability.
Draft 6: April 6, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Draft 5: December 29, 2011
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised in accordance with SAR for
Project 2006-06, Reliability
Coordination (RC SDT). Replaced R1
with R1-R8; R2 replaced by R9; R3
included within new R1; R4 remains
enforce pending Project 2007-02; R5
redundant with EOP-008-0, retiring R5
as redundant with EOP-008-0, R1;
retiring R6, relates to ERO procedures;
R10 & R11, new.Revised per SAR for
Project 2006-06, RC SDT
Revised
Draft 5: December 29, 2011
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Implementation Plan and Mapping Document
COM-001-2 Communications
Requested Approval
The RC SDT requests the approval of COM-001-2 – Communications and two new NERC Glossary terms.
Requested Retirement
The RC SDT request the retirement of standard COM-001-1.1, Requirements R1, R2, R3, R5, R6 and the
associated sub-requirements, except Requirement R4. This Requirement R4 is being revised for
inclusion in Standard COM-003-1, Operating Personnel Communications Protocols and will be retired
when COM-003-1 becomes effective.
Prerequisite Approvals
None.
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication
used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
The RC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0,
Requirement R1 as well as EOP-008-1, Requirement R1.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1 standard and is proposing retiring four Requirements (R1, R4, R5,
and R6). The COM-001-1 standard, Requirement R1 is proposed to be replaced with COM-001-2,
Requirements R1, R2, R3, R4, R5, R6, R7, and R8 to achieve clarity to which entities were required to
have to reliable communications. Requirement R2 in COM-001-1 will become Requirement R9 in COM001-2. Requirement R3 in COM-001-1 has been included within Requirement R1 of COM-001-2.
Requirement R4 will remain enforceable until its revision is included in COM-003-1 that is being
developed under Project 2007-02 – Operating Personnel Communication Protocols. Requirement R5 in
COM-001-1 is redundant with EOP-008-0, Requirement R1 and EOP-008-1, Requirement R1 and will be
retired upon the effective date of COM-001-2. The COM-001-1 standard, Requirement R6 will be
retired as it is an ERO procedural requirement and does not impact reliability. Changes were made to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
eliminate redundancies between standards (existing and proposed), to align with the ERO Rules of
Procedure and to address known issues and certain directives in FERC Order 693.
Applicable Entities
•
Reliability Coordinator
•
Balancing Authority
•
Transmission Operator
•
Generator Operator
•
Distribution Provider
Effective Date
The first day of the second calendar quarter beyond the date that this standard is approved by
applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, the
standard becomes effective on the first day of the first calendar quarter beyond the date this standard
is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to the laws
applicable to such ERO governmental authorities.
New or Revised Standards
COM-001-2
In those jurisdictions where regulatory approval is required, this standard shall
become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is
required, this standard shall become effective on the first day of the first
calendar quarter after Board of Trustees adoption.
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard COM-003-1
currently under development.
Implementation Plan for Definitions
Interpersonal Communication – Entities shall use this definition when implementing the standard
COM-001-2, which uses this defined term.
Alternative Interpersonal Communication – Entities shall use this definition when implementing the
standard COM-001-2, which uses this defined term.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
2
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard becomes
effective. If the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R1.
COM-001-2
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing Authorities.
[Violation Risk Factor: High]
R1.3.
R1.4.
With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary
to maintain reliability. [Violation Risk Factor: High]
R1.
R2.
Where applicable, these facilities shall be
redundant and diversely routed. [Violation Risk
Factor: High]
R3.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities (unless the
Reliability Coordinator experiences a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High] [Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area.
R1.2.
Each adjacent Reliability Coordinator within the same
Interconnection.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R2.1.
All Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area.
R2.2.
Each adjacent Reliability Coordinator within the same
Interconnection.
Each Transmission Operator shall have Interpersonal
Communication capability with the following entities (unless the
Transmission Operator experiences a failure of its Interpersonal
3
Already Approved Standard
Proposed Replacement Requirement(s)
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission
Operator Area.
R3.3.
Each Distribution Provider within its Transmission
Operator Area.
R3.4.
Each Generator Operator within its Transmission
Operator Area.
R3.5.
Each adjacent Transmission Operator synchronously
connected.
R3.6.
Each adjacent Transmission Operator asynchronously
connected.
Each Transmission Operator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission
Operator Area.
R4.3.
Each adjacent Transmission Operator synchronously
connected.
R4.4.
Each adjacent Transmission Operator asynchronously
4
Already Approved Standard
Proposed Replacement Requirement(s)
connected.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable communications.
Already Approved Standard
COM-001-1.1
R1.
Proposed Replacement Requirement(s)
COM-001-2
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R5.
Each Balancing Authority shall have Interpersonal
Communication capability with the following entities (unless the
Balancing Authority experiences a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
Internally. [Violation Risk Factor: High]
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing Authorities.
[Violation Risk Factor: High]
R5.1.
Its Reliability Coordinator.
R5.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area.
R1.3.
With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary
to maintain reliability. [Violation Risk Factor: High]
R5.3.
Each Distribution Provider within its Balancing Authority
Area.
R5.4.
R1.4.
Where applicable, these facilities shall be
redundant and diversely routed. [Violation Risk
Factor: High]
Each Generator Operator that operates Facilities within
its Balancing Authority Area.
R5.5.
Each adjacent Balancing Authority.
R6.
Each Balancing Authority shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R6.1.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Its Reliability Coordinator.
5
Already Approved Standard
Proposed Replacement Requirement(s)
R6.2. Each Transmission Operator that operates Facilities
within its Balancing Authority Area.
R6.3.
Each adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal
Communication capability with the following entities (unless the
Distribution Provider experiences a failure of its Interpersonal
Communication capability in which case Requirement R11 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
Each Generator Operator shall have Interpersonal
Communication capability with the following entities (unless the
Generator Operator experiences a failure of its Interpersonal
Communication capability in which case Requirement R11 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable interpersonal
communications. Requirements R7 and R8 were created to address the FERC directive (Order No. 693, P508) to “(1) expand the applicability to
include generator operators and distribution providers and includes Requirements for their telecommunications facilities;”
COM-001-1.1
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
COM-001-2
6
Already Approved Standard
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
R2.
R9.
Proposed Replacement Requirement(s)
Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall test its Alternative Interpersonal Communication
capability at least once each calendar month. If the test is
unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication
capability within 2 hours. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
Notes:
COM-001-1.1
R3.
COM-001-2
Each Reliability Coordinator, Transmission Operator and
R1.
Balancing Authority shall provide a means to coordinate
telecommunications among their respective areas. This
coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas. [Violation Risk Factor: Lower]
Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities (unless the
Reliability Coordinator experiences a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area.
R1.2.
Each adjacent Reliability Coordinator within the same
Interconnection.
Notes:
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
None - retire
7
Already Approved Standard
English as the language for all communications between and
among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
This requirement is being vetted by the OPCPSDT in Project 200702 – Operating Personnel Communication Protocols (COM-003-1).
This requirement and measure will be removed from COM-001-1.1
upon the effective date of COM-003-1.
Notes:
COM-001-1.1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall have a plan to continue reliability operations in the
event its control center becomes inoperable. The contingency plan
must meet the following requirements:
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions
and procedures to enable continued operation of the system
during the loss of telecommunications facilities. [Violation Risk
Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that
there is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control of
critical transmission facilities, generation control, voltage
control, time and frequency control, control of critical
substation devices, and logging of significant power system
events. The plan shall list the critical facilities.
R1.4. The plan shall include procedures and responsibilities for
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
8
Already Approved Standard
Proposed Replacement Requirement(s)
maintaining basic voice communication capabilities with other
areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure viability
of the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating personnel
are able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take
more than one hour to implement the contingency plan for
loss of primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and Transmission
Operator shall have a current Operating Plan describing the manner
in which it continues to meet its functional obligations with regard
to the reliable operations of the BES in the event that its primary
control center functionality is lost. This Operating Plan for backup
functionality shall include the following, at a minimum: [Violation
Risk Factor = Medium] [Time Horizon = Operations Planning]
1.1. The location and method of implementation for providing
backup functionality for the time it takes to restore the primary
control center functionality.
1.2. A summary description of the elements required to support the
backup functionality. These elements shall include, at a
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
9
Already Approved Standard
Proposed Replacement Requirement(s)
minimum:
1.2.1. Tools and applications to ensure that System Operators
have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
1.3. An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4. Operating Procedures, including decision authority, for use in
determining when to implement the Operating Plan for backup
functionality.
1.5. A transition period between the loss of primary control center
functionality and the time to fully implement the backup
functionality that is less than or equal to two hours.
1.6. An Operating Process describing the actions to be taken during
the transition period between the loss of primary control center
functionality and the time to fully implement backup
functionality elements identified in Requirement R1, Part 1.2.
The Operating Process shall include at a minimum:
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the
transition from primary to backup functionality as well as
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
10
Already Approved Standard
Proposed Replacement Requirement(s)
during outages of the primary or backup functionality.
1.6.3. Identification of the roles for personnel involved during
the initiation and implementation of the Operating Plan
for backup functionality.
Notes: The RC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0, Requirement R1 as well as EOP-008-1
Requirement R1.
COM-001-1
R6.
Each NERCNet User Organization shall adhere to the
requirements in Attachment 1-COM-001, “NERCNet Security
Policy.” [Violation Risk Factor: Lower]
None – retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should be
included in the ERO Rules of Procedure.
None
New Requirement
R11. Each Distribution Provider and Generator Operator that experiences
a failure of its Interpersonal Communication capability shall consult
each entity affected by the failure, as identified in Requirement R7
for a Distribution Provider or Requirement R8 for a Generator
Operator, to determine a mutually agreeable action for the
restoration of its Interpersonal Communication capability. [Violation
Risk Factor: Medium][Time Horizon: Real-time Operations]
Notes:
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
11
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Communications
Reliability
Coordinator
Balancing
Authority
X
X
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
e
Implementation Plan and Mapping Document
for COM-001-2 – Communications
Approvals Requested Approval
The RC SDT requests the approval of COM-001-2 – Communications and two new NERC Glossary
terms.
Requested Retirement
The RC SDT request the retirement of standard COM-001-1.1, Requirements R1, R2, R3, R5, R6 and the
associated sub-requirements, except Requirement R4. This Requirement R4 is being revised for
inclusion in Standard COM-003-1, Operating Personnel Communications Protocols and will be retired
when COM-003-1 becomes effective.
Prerequisite Approvals
•
None.
Defined Terms in the NERC Glossary
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact,
consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal
CommunicationCommunications used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
The RC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0,
Requirement R1 as well as EOP-008-1, Requirement R1.
•
None.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1 standard and is proposing retiring four Requirementsrequirements
(R1, R4, R5, and R6). The COM-001-1 standard, Requirementrequirement R1 is proposed to be
replaced with COM-001-2, Requirements requirements R1, R2, R3, R4, R5, R6, R7, and R8 to achieve
clarity to which entities were required to have to reliable communications. Requirement R2 in COM001-1 will become Requirementrequirement R9 in COM-001-2. Requirement R3 in COM-001-1 has
been included within Requirement R1 of COM-001-2. Requirement R4 will remain enforceable until its
revision is included ininclusion into COM-003-1 that is being developedrevised under Project 2007-02 –
Operating Personnel Communication Protocols. and becomes mandatory and enforceable. Requirement
R5 in COM-001-1 is redundant with EOP-008-0, Requirement R1 and EOP-008-1, Requirement R1
and will be retired upon the effective date of COM-001-2. The COM-001-1 standard, Requirement,
requirement R6 will be retired as it is an ERO procedural requirement and does not impact reliability.
Changes were made to eliminate redundancies between standards (existing and proposed), to align with
the ERO Rules of Procedure and to address known issues and certain directives in FERC Order 693.
Applicable Entities
•
Reliability Coordinator
•
Balancing Authority
•
Transmission Operator
•
Generator Operator
•
Distribution Provider
Effective DateDates
The first day of the second calendar quarter beyond the date that this standard is approved byfollowing
applicable regulatory authorities,approval – or in those jurisdictions where no regulatory approval is not
required, the standard becomes effective on the first day of the first calendar quarter beyond the date
this standard is approved by the NERCfollowing Board of Trustees, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. adoption.
New or Revised Standards
COM-001-2
In those jurisdictions where regulatory approval is required, this standard shall
become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is
required, this standard shall become effective on the first day of the first
calendar quarter after Board of Trustees adoption.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard COM-003-1
currently under development.
Implementation Plan for Definitions
Interpersonal Communication – Entities shall use this definition when implementing the standard
COM-001-2, which uses this defined term.
Alternative Interpersonal Communication – Entities shall use this definition when implementing the
standard COM-001-2, which uses this defined term.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Retirements
COM-001-1.1 will be retired at midnight the day before COM-001-2 becomes effective with the
exception of Requirement R4. This requirement is being revised and will be included in Standard
COM-003-1, Operating Personnel Communications Protocols. COM-001-1.1, Requirement R4 will
be retired at midnight the day before COM-003-1 becomes effective.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard becomes
effective.is implemented. If the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R1.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall
provide adequate and reliable
telecommunications facilities for the exchange
of Interconnection and operating information:
[Violation Risk Factor: High]
R1.1.
Internally. [Violation Risk Factor:
High]
R1.2.
Between the Reliability Coordinator
and its Transmission Operators and
Balancing Authorities. [Violation Risk
Factor: High]
R1.3.
R1.4.
COM-001-2
R1.
R2.
With other Reliability Coordinators,
Transmission Operators, and
Balancing Authorities as necessary to
maintain reliability. [Violation Risk
Factor: High]
Where applicable, these facilities shall
be redundant and diversely routed.
[Violation Risk Factor: High]
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
R3.
Each Reliability Coordinator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R1.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Reliability Coordinator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R2.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator Area.
R2.2.
Adjacent Reliability Coordinators within the same
Interconnection.
Each Transmission Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
Implementation Plan and Mapping Document for COM-001-2 Communications
R4.
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its Transmission
Operator Area.
R3.3.
Each Distribution Provider within its Transmission
Operator Area.
R3.4.
Each Generator Operator within its Transmission
Operator Area.
R3.5.
Adjacent Transmission Operators synchronously
connected within the same Interconnection.
Each Transmission Operator shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its Transmission
Operator Area.
R4.3.
Adjacent Balancing Authorities.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable
communications.
Proposed Replacement Requirement(s)
Already Approved Standard
COM-001-1.1
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R1.
Each Reliability Coordinator,
Transmission Operator and Balancing
Authority shall provide adequate and
reliable telecommunications facilities
for the exchange of Interconnection and
operating information: [Violation Risk
Factor: High]
COM-001-2
R5.
Each Balancing Authority shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R5.1.
Its Reliability Coordinator.
R1.1.
Internally. [Violation Risk
Factor: High]
R5.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area
R1.2.
Between the Reliability
Coordinator and its
Transmission Operators and
Balancing Authorities.
[Violation Risk Factor:
High]
R5.3.
Each Distribution Provider within its Balancing
Authority Area
R5.4.
Each Generator Operator that operates Facilities within
its Balancing Authority Area
R5.5.
Adjacent Balancing Authorities.
R1.3.
R1.4.
With other Reliability
Coordinators, Transmission
Operators, and Balancing
Authorities as necessary to
maintain reliability.
[Violation Risk Factor:
High]
Where applicable, these
facilities shall be redundant
and diversely routed.
[Violation Risk Factor:
High]
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
R6.
R7.
Each Balancing Authority shall designate an Alternative
Interpersonal Communications capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area).
R6.3.
Adjacent Balancing Authorities.
Each Distribution Provider shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R8.
Each Generator Operator shall have Interpersonal
Communications capability with the following entities:
[Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R8.1.
Its Balancing Authority.
R8.2.
Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable
interpersonal communications. R7 and R8 were created to address the FERC directive to “expands the applicability to
include generator operators and distribution providers and includes Requirements for their telecommunications facilities”
Already Approved Standard
COM-001-1.1
R1.
COM-001-2
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall
provide adequatemanage, alarm, test and
reliable/or actively monitor vital
telecommunications facilities. Special
attention shall be given to emergency
telecommunications facilities and equipment
not used for the exchange of Interconnection
and operating information: routine
communications. [Violation Risk Factor:
High]
R1.1.
R1.2.
Proposed Replacement Requirement(s)
Internally. [Violation Risk Factor:
High]
Between the Reliability Coordinator
and its Transmission Operators and
Balancing Authorities. [Violation Risk
Factor: High]
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
R9.
Each Reliability Coordinator , Transmission Operator,
and Balancing Authority shall have, on at least a
monthly basis, test its Alternative Interpersonal
CommunicationCommunications capability with. If the
following entities (unlesstest is unsuccessful, the
Reliability Coordinator experiencesentity shall initiate
action to repair or designate a failure of itsreplacement
Alternative Interpersonal
CommunicationCommunications capability in which
case Requirement R10 shall apply):within 2 hours.
[Violation Risk Factor: High] [Medium][Time Horizon:
Real-time Operations]
R1.4.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator
Area.
R1.5.
Each adjacent Reliability Coordinator within
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R1.3.
With other Reliability Coordinators,
Transmission Operators, and
Balancing Authorities as necessary to
maintain reliability. [Violation Risk
Factor: High]
the same Interconnection.
R2.
Where applicable, these
facilities shall be redundant and diversely
routed. [Violation Risk Factor: HighMedium]
R2.R1.
R3.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Each Reliability Coordinator shall designate an
Alternative Interpersonal Communication capability
with the following entities: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R2.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator
Area.
R2.2.
Each adjacent Reliability Coordinator within
the same Interconnection.
Each Transmission Operator shall have
Interpersonal Communication capability with the
following entities (unless the Transmission Operator
experiences a failure of its Interpersonal
Communication capability in which case
Requirement R10 shall apply): [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
R3.1.
Its Reliability Coordinator.
R3.2.
Each Balancing Authority within its
Transmission Operator Area.
R3.3.
Each Distribution Provider within its
Transmission Operator Area.
R3.4.
Each Generator Operator within its
Transmission Operator Area.
R3.5.
Each adjacent Transmission Operator
synchronously connected.
R3.6.
Each adjacent Transmission Operator
asynchronously connected.
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R4.
Each Transmission Operator shall designate an
Alternative Interpersonal Communication capability
with the following entities: [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R4.1.
Its Reliability Coordinator.
R4.2.
Each Balancing Authority within its
Transmission Operator Area.
R4.3.
Each adjacent Transmission Operator
synchronously connected.
Each adjacent Transmission Operator asynchronously
connected.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable
communications.
Already Approved Standard
COM-001-1.1
R2.
COM-001-2
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide
adequate and reliable telecommunications
facilities for the exchange of Interconnection and
operating information: [Violation Risk Factor:
High]
R2.1.
R2.2.
Proposed Replacement Requirement(s)
Internally. [Violation Risk Factor:
High]
Between the Reliability Coordinator
and its Transmission Operators and
Balancing Authorities. [Violation Risk
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
R5.
Each Balancing Authority shall have Interpersonal
Communication capability with the following entities (unless
the Balancing Authority experiences a failure of its
Interpersonal Communication capability in which case
Requirement R10 shall apply): [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R5.1.
Its Reliability Coordinator.
R5.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area.
R5.3.
Each Distribution Provider within its Balancing
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
Factor: High]
R2.3.
R2.4.
With other Reliability Coordinators,
Transmission Operators, and
Balancing Authorities as necessary to
maintain reliability. [Violation Risk
Factor: High]
Authority Area.
R6.
Where applicable, these facilities shall
be redundant and diversely routed.
[Violation Risk Factor: High]
R7.
R8.
R5.4.
Each Generator Operator that operates Facilities
within its Balancing Authority Area.
R5.5.
Each adjacent Balancing Authority.
Each Balancing Authority shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R6.1.
Its Reliability Coordinator.
R6.2.
Each Transmission Operator that operates Facilities
within its Balancing Authority Area.
R6.3.
Each adjacent Balancing Authority.
Each Distribution Provider shall have Interpersonal
Communication capability with the following entities
(unless the Distribution Provider experiences a failure of its
Interpersonal Communication capability in which case
Requirement R11 shall apply): [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R7.1.
Its Transmission Operator.
R7.2.
Its Balancing Authority.
Each Generator Operator shall have Interpersonal
Communication capability with the following entities (unless
the Generator Operator experiences a failure of its
Interpersonal Communication capability in which case
Requirement R11 shall apply): [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R8.1.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Its Balancing Authority.
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R8.2.
Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable
interpersonal communications. Requirements R7 and R8 were created to address the FERC directive (Order No. 693, P508) to
“(1) expand the applicability to include generator operators and distribution providers and includes Requirements for their
telecommunications facilities;”
COM-001-1.1
Each Reliability Coordinator, Transmission
Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital
telecommunications facilities. Special attention
shall be given to emergency telecommunications
facilities and equipment not used for routine
communications. [Violation Risk Factor:
Medium]
R3.
COM-001-2
R10. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall test its Alternative Interpersonal
Communication capability at least once each calendar month.
If the test is unsuccessful, the responsible entity shall initiate
action to repair or designate a replacement Alternative
Interpersonal Communication capability within 2 hours.
[Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
Notes:
Already Approved Standard
COM-001-1.1
R3.
Each Reliability Coordinator, Transmission
Operator and Balancing Authority shall provide a
means to coordinate telecommunications among
their respective areas. This coordination shall
include the ability to investigate and recommend
solutions to telecommunications problems within
the area and with other areas. [Violation Risk
Factor: Lower]
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Proposed Replacement Requirement(s)
COM-001-2
R1.
Each Reliability Coordinator, Transmission Operator,
Balancing Authority, Distribution Provider, and
Generator Operator shall have Interpersonal
Communication capability with the followingnotify
impacted entities (unless the Reliability Coordinator
experienceswithin 60 minutes of the detection of a
failure of its Interpersonal Communication capability in
which case Requirement R10 shall apply):
Communications capabilities that lasts 30 minutes or
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
longer. [Violation Risk Factor: HighMedium][Time
Horizon: Real-time Operations]
R1.1.
All Transmission Operators and Balancing
Authorities within its Reliability Coordinator
Area.
Each adjacent Reliability Coordinator within the same
Interconnection.
Notes:
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and
Balancing Authority shall use English as the
language for all communications between and
among operating personnel responsible for the
real-time generation control and operation of the
interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities
may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
None - retire
This requirement is being vetted by the OPCPSDT in
Project 2007-02 – Operating Personnel
Communication Protocols (COM-003-1).. This
requirement and measure will be removed from COM001-1.1 upon the effective date of COM-003-1.
Notes:
Already Approved Standard
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Proposed Replacement Requirement(s)
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
COM-001-1.1
Each Reliability Coordinator,
Transmission Operator, and Balancing Authority
shall have written operating instructions and
procedures to enable continued operation of the
system during the loss of telecommunications
facilities. [Violation Risk Factor: Lower]
R5.R4.
EOP-008-0
R1.
Each Reliability Coordinator, Transmission Operator
and Balancing Authority shall have a plan to continue
reliability operations in the event its control center
becomes inoperable. The contingency plan must meet the
following requirements:
R1.1. The contingency plan shall not rely on data or
voice communication from the primary control
facility to be viable.
R1.2. The plan shall include procedures and
responsibilities for providing basic tie line control
and procedures and for maintaining the status of all
inter-area schedules, such that there is an hourly
accounting of all schedules.
R1.3. The contingency plan must address monitoring and
control of critical transmission facilities, generation
control, voltage control, time and frequency control,
control of critical substation devices, and logging of
significant power system events. The plan shall list
the critical facilities.
R1.4. The plan shall include procedures and
responsibilities for maintaining basic voice
communication capabilities with other areas.
R1.5. The plan shall include procedures and
responsibilities for conducting periodic tests, at
least annually, to ensure viability of the plan.
R1.6. The plan shall include procedures and
responsibilities for providing annual training to
ensure that operating personnel are able to
implement the contingency plans.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is
expected to take more than one hour to implement
the contingency plan for loss of primary control
facility.
EOP-008-1
R1.
Each Reliability Coordinator, Balancing Authority,
and Transmission Operator shall have a current Operating Plan
describing the manner in which it continues to meet its
functional obligations with regard to the reliable operations of
the BES in the event that its primary control center
functionality is lost. This Operating Plan for backup
functionality shall include the following, at a minimum:
[Violation Risk Factor = Medium] [Time Horizon =
Operations Planning]
1.1.
The location and method of implementation for
providing backup functionality for the time it takes to
restore the primary control center functionality.
1.2.
A summary description of the elements
required to support the backup functionality. These
elements shall include, at a minimum:
1.2.1. Tools and applications to ensure that System
Operators have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
1.3.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
An Operating Process for keeping the backup
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
functionality consistent with the primary control center.
1.4.
Operating Procedures, including decision
authority, for use in determining when to implement the
Operating Plan for backup functionality.
1.5.
A transition period between the loss of primary
control center functionality and the time to fully
implement the backup functionality that is less than or
equal to two hours.
1.6.
An Operating Process describing the actions to
be taken during the transition period between the loss of
primary control center functionality and the time to fully
implement backup functionality elements identified in
Requirement R1, Part 1.2. The Operating Process shall
include at a minimum:
1.6.1. A list of all entities to notify when there is a
change in operating locations.
1.6.2. Actions to manage the risk to the BES during
the transition from primary to backup functionality as
well as during outages of the primary or backup
functionality.
1.6.3. Identification of the roles for personnel
involved during the initiation and implementation of
the Operating Plan for backup functionality.
Notes: The RC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0, Requirement
R1 as well as EOP-008-1 Requirement R1R1 which replaces it.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
R6.
Each NERCNet User Organization shall adhere to
the requirements in Attachment 1-COM-001,
“NERCNet Security Policy.” [Violation Risk
Factor: Lower]
None –- retire
Notes: The RC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a
reliability standard. It should be included in the ERO Rules of Procedure.
Already Approved Standard
None
Proposed Replacement Requirement(s)
New Requirement
R11.
Each Distribution
Provider and Generator Operator that experiences a failure
of any of its Interpersonal Communication
capabilitycapabilities shall consult each entity affected by
the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a
Generatorwith their Transmission Operator, or Balancing
Authority as applicable to determine a mutually agreeable
action fortime to restore the restoration of its Interpersonal
Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
June 8 2
Implementation Plan and Mapping Document for COM-001-2 Communications
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
Reliability
Coordinator
Balancing
Authority
Purchasing
SellingPurc
Transmission
Operator
Transmission
Service
Provider
X
X
hasingSelli
ng Entity
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
COM-001-2
Communications
X
X
Communi-cations
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
June 8 2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Unofficial Comment Form
Reliability Coordination (Project 2006-06)
Please DO NOT use this form to submit comments. Please use the electronic comment form to
submit comments on the first formal posting for Project 2006-06—Reliability Coordination. The
electronic comment form must be completed by July 6, 2012.
2006-06 Project Page
If you have questions please contact Scott Barfield-McGinnis at [email protected] or by
telephone at 404-446-9689.
Background
The RCSDT has revised the COM-001-2 standard based on stakeholder comments received during
the successive ballot, formal comment period and quality review of the standard.
The two proposed definitions remain the same, except letter “s” on “Communications” the
definition of Alternative Interpersonal Communication to make it singular. The RCSDT has
addressed comments on the Purpose statement to align it with the intent of requiring entities to
have communication capability. The effective date language was updated to reflect the current
guidelines for standards.
Purpose: To establish Interpersonal Communication capabilities necessary to maintain
reliability.
Several commenters had suggestions for improvements to the language in the requirements. The
RCSDT addressed the use of “Adjacent…” starting requirements and giving the appearance of a
defined glossary term by rephrasing the occurrence with “Each adjacent…” Other corrections
include using the singular rather than plural for clarity.
Several commenters raised concerns about the use of “…synchronously connected within the same
interconnection.” To address this, the RCSDT shortened the two requirements using this phrase to
“…synchronously connected” and added an a corresponding additional requirement to each to
address DC connections. See the following Requirement Parts below:
3.5. Each adjacent Transmission Operator synchronously connected. (Revised)
3.6. Each adjacent Transmission Operator asynchronously connected. (New)
4.3. Each adjacent Transmission Operator synchronously connected. (Revised)
4.4. Each adjacent Transmission Operator asynchronously connected. (New)
Some commenters had concerns about conditions of non-compliance if the entity’s Interpersonal
Communication capability failed. To address this concern, the RCSDT added conforming language
to Requirements R1, R3, R5, R7 and R8 that bridges the potential gap in non-compliance for a
failed Interpersonal Communication capability. The VSLs were updated to reflect this change.
Requirement R10 was revised to remove R1-R6 and more accurately use R1, R3, and R5.
Requirement R11 was revised the phrase “mutually agreeable time” to remove the word “time” and
replace it with “action.” The Measures M10 and M11 were also corrected. Additionally, the bullets
in Measures M1-M8 were cleaned up for clarity. All of the examples of evidence in the Measures
were reformatted and cleaned up to more accurately reflect the scope of each requirement.
Unofficial Comment Form
Project 2006-06 Reliability Coordination
1
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Based on comments received, the Compliance Section 1.1, Compliance Enforcement Authority, was
updated to reflect the current guidelines for standards. Additionally, Section 1.3, Data Retention,
was updated to reflect the current guidelines for standards and the bulleted items reformatted for
clarity.
The VSLs were updated to make singular, note the applicable Requirement number, and to add the
Parts 3.6 and 4.4 due to being added to the requirements, R3 and R4. Additionally, the RCSDT
added High VSLs for Requirements R1 through R8 to conform with VSL Guidelines. Requirements
R1 through R8 are not binary only.
Unofficial Comment Form
Project 2006-06 Reliability Coordination
2
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You do not have to answer all questions. Enter all comments in Simple
Text Format.
1. The RCSDT has revised the parts of Requirements R1, R2, R3, R4, R5, and R6 of COM-001-2
that began only with “Adjacent…” to begin with “Each adjacent…” to avoid the appearance of
creating a defined glossary phrase. Do you agree with the changes? If not, please explain in
the comment area below.
Yes
No
Comments:
2. The RCSDT has revised parts of two requirements (Parts 3.5 and 4.3) in COM-001-2 and added
two additional parts (Parts 3.6 and 3.4) to address concerns about the phrase “synchronously
connected within the same Interconnection.” Do you agree these changes address concerns
where entities might only be adjacent across an Interconnection for where connected by a
Direct Current (DC) tie? If not, please explain in the comment area below.
Yes
No
Comments:
3. The RCSDT made minor changes and reformatted the evidence examples in the Measures of
COM-001-2 for greater clarity. Do you agree with these revisions? If not, please explain in the
comment area below.
Yes
No
Comments:
4. Do you have any other comments on COM-001-2, not expressed in questions above, for the
RCSDT?
Comments:
Unofficial Comment Form
Project 2006-06 Reliability Coordination
3
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Standard COM-001-1.1 — Telecommunications
A. Introduction
1.
Title:
Telecommunications
2.
Number:
COM-001-1.1
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
Effective Date:
May 13, 2009
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.
Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall use English as the language for all communications between and
among operating personnel responsible for the real-time generation control and operation of the
interconnected Bulk Electric System. Transmission Operators and Balancing Authorities may
use an alternate language for internal operations.
R5.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
written operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilities.
R6.
Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM001, “NERCNet Security Policy.”
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 1 of 6
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Standard COM-001-1.1 — Telecommunications
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. The Reliability Coordinator, Transmission Operator or Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to operator logs, voice
recordings or transcripts of voice recordings, electronic communications, or equivalent, that
will be used to determine compliance to Requirement 4.
M3. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy that will be used to confirm that it meets Requirement 5.
M4. The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to documented procedures, operator logs, voice recordings or
transcripts of voice recordings, electronic communications, etc that will be used to determine if
it adhered to the (User Accountability and Compliance) requirements in Attachment 1-COM001. (Requirement 6)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2 each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall keep 90 days of historical data (evidence).
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 2 of 6
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Standard COM-001-1.1 — Telecommunications
For Measure 3, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 5.
For Measure 4, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.2
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities as
specified in R5.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 3 of 6
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Standard COM-001-1.1 — Telecommunications
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 4 of 6
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Standard COM-001-1.1 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 5 of 6
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Standard COM-001-1.1 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
Adopted by Board of Trustees: October 29, 2008
Effective Date: May 13, 2009
Page 6 of 6
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Violation Risk Factor and Violation
Severity Level Justifications
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 – Communications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and
FERC Guidelines when proposing VRFs and VSL for the requirements under this project.
NERC Criteria – Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Low er R isk Requirem ent
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs: 1
Guideline 1 – Consistency w ith the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
Id. at footnote 15.
2
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
2
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•
Appropriate use of transmission loading relief
Guideline 2 – Consistency w ithin a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Guideline 3 – Consistency am ong Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline 4 – Consistency w ith NER C’s Definition of the Violation R isk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline 5 – Treatm ent of Requirem ents that Co-m ingle M ore Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
There are eleven requirements in the standard. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 are assigned a “High” VRF while the other three requirements
are assigned a “Medium” VRF.
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs
for each requirement, some requirements do not have multiple “degrees” of noncompliant
performance, and may have only one, two, or three VSLs.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance
or is missing a single
vital component.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.
The performance or
product has limited
value in meeting the
intent of the
requirement.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed
for each requirement in the standard meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2 – Violation Severity Level Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3 – Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Guideline 4 – Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Guideline 5- Treatment of Requirements that Co-mingle More than One
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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VRF Justifications – COM-001-2, R1-R6
Proposed VRF
Discussion
High
Obligation:
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Proposed VSLs for COM-001-2, R1-R6
R#
R1
R2
R3
Lower
N/A
N/A
N/A
Moderate
High
Severe
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1
or 1.2, except when the Reliability
Coordinator experienced a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator experienced
a failure of its Interpersonal
Communication capability in
accordance with Requirement
R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one
of the entities listed in Requirement
R2, Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two
or more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
N/A
The Transmission Operator failed
to have Interpersonal
Communication capability with one
of the entities listed in Requirement
R3, Parts 3.1, 3.2, 3.3, 3.4, 3.5, or
3.6, except when the Reliability
Coordinator experienced a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed
to have Interpersonal
Communication capability with two
or more of the entities listed in
Requirement R3, Parts 3.1, 3.2,
3.3, 3.4, 3.5, or 3.6, except when
the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed
to designate Alternative
Interpersonal Communication
capability with two or more of the
entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Balancing Authority failed to
have Interpersonal Communication
R4
N/A
N/A
The Transmission Operator failed
to designate Alternative
Interpersonal Communication
capability with one of the entities
listed in Requirement R4, Parts
4.1, 4.2, 4.3, or 4.4.
R5
N/A
N/A
The Balancing Authority failed to
have Interpersonal Communication
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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R6
N/A
N/A
capability with one of the entities
listed in Requirement R5, Parts
5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Reliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5,
except when the Reliability
Coordinator experienced a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one
of the entities listed in Requirement
R6, Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two
or more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe: The
performance or product measured does not
substantively meet the intent of the
requirement.
FERC VSL G1
The proposed requirement is a revision of COM001-1.1, R1 and its sub-requirements. Each subViolation Severity Level Assignments
requirement
was separated out into a new standShould Not Have the Unintended
Consequence of Lowering the Current Level alone requirement. The VSLs for the approved
sub-requirements are binary and this is reflected
of Compliance
in the proposed VSLs.
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments
Should Ensure Uniformity and Consistency
in the Determination of Penalties
N/A
Guideline 2a: The Single Violation Severity
Level Assignment Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R7
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
The requirement has no sub-requirements; only one VRF is assigned, so there
is no conflict.
COM-001-2, Requirement R7 is an analog to Parts 3.3 and 5.3 and they have
the same VRF (High).
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
N/A
The Distribution Provider failed
to have Interpersonal
Communication capability with
one of the entities listed in
Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R11.
Severe
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe: The performance or
product measured does not substantively meet the intent
of the requirement.
FERC VSL G1
The proposed requirement is a revision of COM-001-1.1,
R1 and its sub-requirements. Each sub-requirement was
separated out into a new stand-alone requirement. The
VSLs for the approved sub-requirements are binary and
this is reflected in the proposed VSLs.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
The proposed VSL uses the same terminology as used in
the associated requirement, and is, therefore, consistent
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative
violations.
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High).
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
Project 2006-06 Reliability Coordination
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VRF Justifications – COM-001-2, R8
Proposed VRF
High
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R8
R#
R8
Lower
N/A
Moderate
High
Severe
N/A
The Generator Operator failed to
have Interpersonal
Communication capability with
one of the entities listed in
Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator experienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe: The performance
or product measured does not substantively meet the
intent of the requirement.
FERC VSL G1
The most comparable VSLs for a similar requirement are
for the proposed analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This requirement specifies
the two-way nature of entities having Interpersonal
Communications capability. In other words, if one entity
is required to have Interpersonal Communications
capability with another entity, then the reciprocal should
also be required or the onus would be exclusively on one
entity. Since Requirement R3 and R5 are assigned binary
VSLs, it appropriate for Requirement R7 to also be
assigned a binary VSL.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
N/A
Project 2006-06 Reliability Coordination
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Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSLs use the same terminology as used in
the associated requirement, and are, therefore,
consistent with the requirement.
The VSLs are based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Guideline 3- Consistency among Reliability Standards:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
Discussion
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
FERC VRF G4
Discussion
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R9
R#
Lower
Moderate
High
Severe
R9
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
OR
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Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
equal to 4 hours
upon an
unsuccessful test.
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
equal to 6 hours
upon an
unsuccessful test.
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
equal to 8 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Project 2006-06 Reliability Coordination
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Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5 upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes
but less than or
equal to 70
minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5 upon the
detection of a failure
of its Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
80 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified
in Requirements
R1, R3, and R5
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes
but less than or
equal to 90
minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
identified entities
identified in
Requirements R1,
R3, and R5 upon the
detection of a failure
of its Interpersonal
Communication
capability in more
than 90 minutes.
VSL Justifications – COM-001-2, R10
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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R#
R11
Lower
N/A
Moderate
N/A
High
Severe
N/A
The Distribution Provider or Generator Operator failed to
consult with its Transmission Operator and Balancing
Authority to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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FERC VSL G4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
The VSL is based on a single violation and not cumulative
violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
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Violation Risk Factor and Violation Severity Level
JustificationsAssignments
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk
factors (VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 –
Communications
COM-001-2 — Telecommunications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These
elements support the determination of an initial value range for the Base Penalty Amount
regarding violations of requirements in FERC-approved Reliability Standards, as defined in the
ERO Sanction Guidelines.
Justification for Assignment of Violation Risk Factors in COM-001-2
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria
and FERC Guidelines when proposing VRFs and VSL for the requirements under this project.in
COM-001-2:
NERC Criteria – Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal,
or restorative conditions anticipated by the preparations, directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
electric system instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly and adversely affect the electrical
state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated
by the preparations, to lead to bulk electric system instability, separation, or cascading
failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would
not be expected to adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor and control the bulk electric system; or, a
requirement that is administrative in nature and a requirement in a planning time frame
that, if violated, would not, under the emergency, abnormal, or restorative conditions
anticipated by the preparations, be expected to adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or
restore the bulk electric system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for
setting VRFs: 1 2
Guideline (1 – ) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of
Reliability Standards in these identified areas appropriately reflect their historical critical
impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where
4
violations could severely affect the reliability of the Bulk-Power System: 3
−
−
−
−
−
−
−
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
2
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶
61,145 (2007) (“VRF Rehearing Order”).
3
Id. at footnote 15.
4
Id. at footnote 15.
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
−
−
−
−
−
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief.
Guideline (2 – ) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation
Risk Factor assignments and the main Requirement Violation Risk Factor assignment.
Guideline (3 – ) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to
Requirements that address similar reliability goals in different Reliability Standards
would be treated comparably.
Guideline (4 – ) — Consistency with NERC’s Definition of the Violation Risk Factor
Level
Guideline (4) was developed to evaluate whether the assignment of a particular
Violation Risk Factor level conforms to NERC’s definition of that risk level.
Guideline (5 – ) — Treatment of Requirements that Co-mingle More Than One
Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser
risk reliability objective, the VRF assignment for such Requirements must not be watered
down to reflect the lower risk level associated with the less important objective of the
Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2
through 5. The team did not address Guideline 1 directly because of an apparent conflict
between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics that encompass
nearly all topics within NERC’s Reliability Standards and implies that these requirements should
be assigned a “High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a
specific requirement to the reliability of the system. The SDT believes that Guideline 4 is
reflective of the intent of VRFs in the first instance and therefore concentrated its approach on
the reliability impact of the requirements.
VRF for COM-001-2:
There are eleven requirements in the standardCOM-001-2. None of the eleven requirements
were assigned a “Lower” VRF. Requirements R1-R8 arewere assigned a “High” VRF while the
other three requirements are assignedwere given a “Medium” VRF.
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with VRF for
COM-001-2, Requirements R1-R6:
•
FERC’s Guideline 2 — Consistency within a requirement was not achievedReliability
Standard. Each requirement must specifies which functional entities that are required to
have at least one VSL. While it is preferable to have four VSLs Interpersonal
Communications capability and Alternative Interpersonal Communications capability. The
VRFs for each requirement, some are consistent with each other and are only applied at the
Requirement level.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. These requirements do
not have multiple “degrees” of noncompliant performance, and may have are facility
requirements that provide communications capability between functional entities. There are
no similar facility requirements in the standards. The approved VRF for COM-001-1.1, R1
(which proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability and Alternative Interpersonal Communications
capability could limit or prevent communication between entities and directly affect the
electrical state or the capability of the bulk power system and could lead to bulk power
system instability, separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirements R1-R6 contain only one objective, therefore only one,
two, or three VSLs. VRF was assigned.
VRF for COM-001-2, Requirement R7:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R7 is an analog to Parts 3.3 and 5.3 and they have the same VRF (High).
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability could limit or prevent communication between
entities and directly affect the electrical state or the capability of the bulk power system and
could lead to bulk power system instability, separation, or cascading failures. Therefore, this
requirement was assigned a High VRF.
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R7 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R8:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R8 is an analog to Parts 3.4 and 5.4 and they have the same VRF (High).
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. Failure to have
Interpersonal Communications capability could limit or prevent communication between
entities and directly affect the electrical state or the capability of the bulk power system and
could lead to bulk power system instability, separation, or cascading failures. Therefore, this
requirement was assigned a High VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R8 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R9:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R9 is a requirement for entities to test their Alternative Interpersonal
Communications capability and to take restorative action should the test fail and is a
replacement requirement for COM-001-1.1, R2, which has an approved VRF of Medium.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R9 is a requirement for entities to test their Alternative Interpersonal
Communications capability and to take restorative action should the test fail. The act of
testing in and of itself is not likely to “directly affect the electrical state or the capability of
the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk electric
system instability, separation, or cascading failures…” Therefore, this requirement was
assigned a Medium VRF.
•
FERC’s Guideline 5 — Treatment of Requirements that Co-mingle More Than One
Objective. COM-001-2, Requirement R9 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R10:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R10 is a new requirement that was assigned a Medium VRF. When evaluating
the VRF to be assigned to this requirement, the SDT took into account that this requirement
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
is a notification item, not an actual action that has a direct impact on the bulk power system.
Therefore, the simple act of failing to notify another entity of the failure of Interpersonal
Communications capability, while it may impair the entity’s ability communicate, does not,
in itself, lead to bulk power system instability, separation, or cascading failures. Therefore,
this requirement was assigned a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R10 mandates that entities notify entities of a failure of Interpersonal
Communications capability. Bulk power system instability, separation, or cascading failures
are not likely to occur due to a failure to notify another entity of the failure. Therefore, this
requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 - Treatment of Requirements that Co-mingle More Than One Objective.
TOP-001-2, Requirement R10 addresses a single objective and has a single VRF.
VRF for COM-001-2, Requirement R11:
•
FERC’s Guideline 2 — Consistency within a Reliability Standard. The requirement has no
sub-requirements; only one VRF was assigned so there is no conflict.
•
FERC’s Guideline 3 — Consistency among Reliability Standards. COM-001-2,
Requirement R11 is a new requirement that was assigned a Medium VRF. When evaluating
the VRF to be assigned to this requirement, the SDT took into account that this requirement
is a consultation item, not an actual action that has a direct impact on the bulk power system.
Therefore, the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may impair the entity’s
ability communicate, does not, in itself, lead to bulk power system instability, separation, or
cascading failures. Therefore, this requirement was assigned a Medium VRF.
•
FERC’s Guideline 4 — Consistency with NERC’s Definition of a VRF. COM-001-2,
Requirement R11 mandates that entities consult with other entities regarding restoration of
Interpersonal Communications capability. Bulk power system instability, separation, or
cascading failures are not likely to occur due to a failure to consult with another entity on
restoration times. Therefore, this requirement was assigned a Medium VRF.
•
FERC’s Guideline 5 - Treatment of Requirements that Co-mingle More Than One Objective.
TOP-001-2, Requirement R11 addresses a single objective and has a single VRF.
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
Justification for Assignment of Violation severity levels should be Severity Levels
for COM-001-2
In developing the VSLs for the TOP standard, the SDT anticipated the evidence that would be
reviewed during an audit, and developed its VSLs based on the guidelines shown in the
table belownoncompliance an auditor may find during a typical audit. The SDT based its
assignment of VSLs on the following NERC criteria:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or a
moderate percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of the
requirement.
Missing more than one
significant element (or is
missing a high
percentage) of the
required performance or
is missing a single vital
component.
The performance or
product has limited
value in meeting the
intent of the
requirement.
Missing most or all of
the significant elements
(or a significant
percentage) of the
required performance.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of the
requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs
proposed for each requirement in the standardTOP-xxx-x meet the FERC Guidelines for
assessing VSLs:
Guideline 1 – : Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes
that may encourage a lower level of compliance than was required when levels of noncompliance were used.
Guideline 2 – : Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
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Justification for Assignment of Violation Risk Factors and Violation Severity Levels for Project
2006-06 – Reliability Coordination
Guideline 3 – : Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4 – : Violation Severity Level Assignment Should Be Based on A Single Violation,
Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that
assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRF and VSL Justifications
November 30, 2011
8
VSLs for COM-001-2 Requirements R1 through R6:
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
DiscussionR#
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:1
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.Violation Severity
Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
FERC VRF G3
DiscussionR1R6.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.The proposed requirement is a revision of COM-001-1.1, R1 and its
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
subrequirements. Each subrequirement was separated out into a new stand-alone
requirement. The VSLs for the approved subrequirements are binary and this is
reflected in the proposed VSLs.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
10
VSLs for COM-001-2 Requirement R7:
Proposed VSLs for COM-001-2, R1-R6
R#
R1
R2
Lower
N/A
N/A
Moderate
High
Severe
N/A
The Reliability
Coordinator failed to
have Interpersonal
Communication
capability with one
of the entities listed
in Requirement R1,
Parts 1.1 or 1.2,
except when the
Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
The Reliability
Coordinator failed to
have Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R1,
Parts 1.1 or 1.2,
except when the
Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
N/A
The Reliability
Coordinator failed to
designate
Alternative
Interpersonal
Communication
capability with one
of the entities listed
in Requirement R2,
The Reliability
Coordinator failed to
designate
Alternative
Interpersonal
Communication
capability with two
or more of the
entities listed in
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
11
R3
R4
N/A
N/A
Parts 2.1 or 2.2.
Requirement R2,
Parts 2.1 or 2.2.
N/A
The Transmission
Operator failed to
have Interpersonal
Communication
capability with one
of the entities listed
in Requirement R3,
Parts 3.1, 3.2, 3.3,
3.4, 3.5, or 3.6,
except when the
Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
The Transmission
Operator failed to
have Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R3,
Parts 3.1, 3.2, 3.3,
3.4, 3.5, or 3.6,
except when the
Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
N/A
The Transmission
Operator failed to
designate
Alternative
Interpersonal
Communication
capability with one
of the entities listed
in Requirement R4,
Parts 4.1, 4.2, 4.3,
or 4.4.
The Transmission
Operator failed to
designate
Alternative
Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R4,
Parts 4.1, 4.2, 4.3,
or 4.4.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
12
R5
R6
N/A
N/A
N/A
The Balancing
Authority failed to
have Interpersonal
Communication
capability with one
of the entities listed
in Requirement R5,
Parts 5.1, 5.2, 5.3,
5.4, or 5.5, except
when the Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
The Balancing
Authority failed to
have Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R5,
Parts 5.1, 5.2, 5.3,
5.4, or 5.5, except
when the Reliability
Coordinator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R10.
N/A
The Balancing
Authority failed to
designate
Alternative
Interpersonal
Communication
capability with one
of the entities listed
in Requirement R6,
Parts 6.1, 6.2, or
6.3.
The Balancing
Authority failed to
designate
Alternative
Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R6,
Parts 6.1, 6.2, or
6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe:
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
13
The performance or product measured
does not substantively meet the intent
of the requirement.
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
The proposed requirement is a revision
of COM-001-1.1, R1 and its subrequirements. Each sub-requirement
was separated out into a new standalone requirement. The VSLs for the
approved sub-requirements are binary
and this is reflected in the proposed
VSLs.
FERC VSL G2
Guideline 2a:3
Guideline 2
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment Category for
"Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain Ambiguous
Language
N/A
Guideline 2b:
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
The proposed VSL does
not use any ambiguous
terminology, thereby
supporting uniformity
and consistency in the
determination of similar
penalties for similar
violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
14
The proposed VSLs do not use any ambiguous terminology, thereby
supporting uniformity and consistency in the determination of similar
penalties for similar violations.FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on
A Cumulative Number of
Violations
The proposed VSL
usesVSLs use the same
terminology as used in
the associated
requirement, and isare,
therefore, consistent
with the requirement.
The VSL is based on a single violation
and not cumulative violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
15
VSLs for COM-001-2 Requirement R8:
VRF Justifications – COM-001-2, R7
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
DiscussionR#
N/A
The requirement has no sub-requirements; only one VRF is assigned, so there
is no conflict.
Guideline 3- Consistency among Reliability Standards:1
COM-001-2, Requirement R7 is an analog to Parts 3.3 and 5.3 and they have
the same VRF (High).Violation Severity Level Assignments Should Not Have the
Unintended Consequence of Lowering the Current Level of Compliance
FERC VRF G4
DiscussionR8.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.The most comparable VSLs for a similar requirement are for the
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
16
VRF Justifications – COM-001-2, R7
Proposed VRF
High
proposed analog requirement and its parts COM-001-2, Part 3.4 and Part 5.4. This
requirement specifies the two way nature of entities having Interpersonal
Communications capability. In other words, if one entity is required to have
Interpersonal Communications capability with another entity, then the reciprocal
should also be required or the onus would be exclusively on one entity. Since
Requirement 3 and Requirement 5 are assigned binary VSLs, it appropriate for
Requirement 7 to also be assigned a binary VSL.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
17
VSLs for COM-001-2 Requirement R9:
Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
Severe
N/A
The Distribution
Provider failed to
have Interpersonal
Communication
capability with one
of the entities listed
in Requirement R7,
Parts 7.1 or 7.2,
except when the
Distribution
Provider
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R11.
The Distribution
Provider failed to
have Interpersonal
Communication
capability with two
or more of the
entities listed in
Requirement R7,
Parts 7.1 or 7.2,
except when the
Distribution Provider
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe:
The performance or product
measured does not substantively
meet the intent of the requirement.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
18
FERC VSL G1
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
The proposed requirement is a
revision of COM-001-1.1, R1 and its
sub-requirements. Each subrequirement was separated out into a
new stand-alone requirement. The
VSLs for the approved subrequirements are binary and this is
reflected in the proposed VSLs.
FERC VSL G2
Guideline 2a:3
Guideline 2
N/A
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment Category
for "Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain
Ambiguous Language
Guideline 2b:
The proposed VSL does not
use any ambiguous
terminology, thereby
supporting uniformity and
consistency in the
determination of similar
penalties for similar
violations.Violation Severity
Level Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
The proposed VSL uses the
same terminology as used in
the associated requirement,
November 30, 2011
19
Corresponding RequirementThe proposed VSL does not use any
and is, therefore, consistent
ambiguous terminology, thereby supporting uniformity and consistency in with the requirement.
the determination of similar penalties for similar violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations
The VSL is based on a single violation
and not cumulative violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
20
VSLs for COM-001-2 Requirement R10:
VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
DiscussionR#
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
Guideline 3- 2
Violation Severity Level Assignments Should Ensure Uniformity and Consistency
among Reliability Standards:in the Determination of Penalties
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High).Guideline 2a: The Single Violation Severity Level Assignment
Category for "Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain Ambiguous Language
FERC VRF G4
Guideline 4- Consistency with NERC Definitions of VRFs:
DiscussionR10.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
21
VRF Justifications – COM-001-2, R8
Proposed VRF
High
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the determination of similar
penalties for similar violations.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
22
VSLs for COM-001-2 Requirement R11:
Proposed VSLs for COM-001-2, R8
R#
R8
Lower
N/A
Moderate
High
Severe
N/A
The Generator
Operator failed to
have Interpersonal
Communication
capability with one
of the entities listed
in Requirement R8,
Parts 8.1 or 8.2,
except when a
Generator Operator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R11.
The Generator
Operator failed to
have Interpersonal
Communication
capability with two or
more of the entities
listed in
Requirement R8,
Parts 8.1 or 8.2,
except when a
Generator Operator
experienced a
failure of its
Interpersonal
Communication
capability in
accordance with
Requirement R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines - Severe:
The performance or product measured
does not substantively meet the intent
of the requirement.
FERC VSL G1
The most comparable VSLs for a similar
requirement are for the proposed
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
23
Violation Severity Level
Assignments Should Not
Have the Unintended
Consequence of Lowering
the Current Level of
Compliance
analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This
requirement specifies the two-way
nature of entities having Interpersonal
Communications capability. In other
words, if one entity is required to have
Interpersonal Communications
capability with another entity, then the
reciprocal should also be required or
the onus would be exclusively on one
entity. Since Requirement R3 and R5
are assigned binary VSLs, it appropriate
for Requirement R7 to also be assigned
a binary VSL.
FERC VSL G2
Guideline 2a:3
Guideline 2
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment Category for
"Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain
Ambiguous Language
N/A
Guideline 2b:
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement
The proposed VSLs do not
use any ambiguous
terminology, thereby
supporting uniformity and
consistency in the
determination of similar
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
24
penalties for similar
violations.
FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Corresponding RequirementThe proposed VSL does not use any
ambiguous terminology, thereby supporting uniformity and consistency in
the determination of similar penalties for similar violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations
The proposed VSLs
useVSL uses the same
terminology as used in the
associated requirement,
and areis, therefore,
consistent with the
requirement.
The VSLs are based on a single
violation and not cumulative
violations.
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
25
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
The requirement contains only one objective; therefore, only one VRF was
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
26
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
assigned.
Proposed VSLs for COM-001-2, R9
R#
Lower
Moderate
High
Severe
R9
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
OR
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
November 30, 2011
27
equal to 4 hours
upon an
unsuccessful test.
equal to 6 hours
upon an
unsuccessful test.
equal to 8 hours
upon an
unsuccessful test.
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
28
Determination of Penalties
Guideline 2b:
Guideline 2a: The Single Violation Severity
Level Assignment Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
29
VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
30
VRF Justifications – COM-001-2, R10
Proposed VRF
FERC VRF G5
Discussion
Medium
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5 upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5 upon the
detection of a failure
of its Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified
in Requirements
R1, R3, and R5
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
identified entities
identified in
Requirements R1,
R3, and R5 upon the
detection of a failure
of its Interpersonal
Communication
capability in more
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
31
but less than or
equal to 70
minutes.
80 minutes.
but less than or
equal to 90
minutes.
than 90 minutes.
VSL Justifications – COM-001-2, R10
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
32
Be Consistent with the Corresponding
Requirement
therefore, consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not
cumulative violations.
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
33
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
R#
Lower
Moderate
High
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
Severe
November 30, 2011
34
R11
N/A
N/A
N/A
The Distribution Provider or Generator Operator failed to
consult with its Transmission Operator and Balancing
Authority to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
35
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement.
The VSL is based on a single violation and not cumulative
violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 2 – April 6, 2012)
November 30, 2011
36
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 Reliability Coordination
Ballot Window Extended for COM-001-2 – Successive Ballot and Non-Binding Poll
Extended
The ballot window for the successive ballot of COM-001-2 and a non-binding poll of the associated
VRF/VSLs will be extended one day at a time until a quorum is achieved.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standards and opinion in the non-binding polls of the associated VRFs and VSLs by clicking here.
Next Steps
The drafting team will consider all comments received for COM-001-2 during the formal comment and
ballot period and, if needed, make revisions to the standard. If the comments do not show the need
for significant revisions, the standard will proceed to a recirculation ballot.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measureable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to the
scope overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from
FERC Order 693 associated with standard IRO-003-2.
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement - Project 2006-06
2
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Standards Announcement
Project 2006-06 Reliability Coordination
Ballot Windows Open through 8 p.m. Friday, July 6, 2012
Successive and Non-Binding Poll:
COM-001-2
Recirculation and Non-Binding Polls:
COM-002-3 and IRO-001-3
Now Available
A successive ballot for COM-001-2 and a non-binding poll of the associated VRF/VSLs and recirculation
ballots for COM-002-3 and IRO-001-3 and non-binding polls for the associated VRF/VSLs are open
through 8 p.m. Eastern on Friday, July 6, 2012.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standards and opinion in the non-binding polls of the associated VRFs and VSLs by clicking here.
Voters can submit their comments via the electronic comment form.
Next Steps
The drafting team will consider all comments received for COM-001-2 during the formal comment and
ballot period and, if needed, make revisions to the standard. If the comments do not show the need
for significant revisions, the standard will proceed to a recirculation ballot.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measureable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to the
scope overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from
FERC Order 693 associated with standard IRO-003-2.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement - Project 2006-06
2
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Standards Announcement
Project 2006-06 Reliability Coordination
Formal Comment Period:
June 7-July 6, 2012
Upcoming:
June 27 – July 6, 2012
Successive and Non-Binding Poll:
Recirculation and Non-Binding Polls:
COM-001-2
COM-002-3 and IRO-001-3
Now Available
A formal comment period for COM-001-2 – Communications is open through 8 p.m. Eastern on Friday, July 6,
2012. In response to industry comments, the Drafting Team made substantive changes to COM-001-2 –
Communications requiring an additional comment period and successive ballot. The Drafting Team made minor
changes to the VSLs but did not make substantive changes to COM-002-3 – Communication and Coordination
and IRO-001-3 – Reliability Coordination – Responsibilities and Authorities requirements which passed the
previous successive ballots.
Instructions for Commenting
A formal comment period for COM-001-2 is open through 8 p.m. Eastern on Friday, July 6, 2012. Please use this
electronic form to submit comments. If you experience any difficulties in using the electronic form, please
contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment form is posted
on the project page.
Commenters and voters must submit comments through the electronic comment form. Due to modifications to
NERC’s balloting software, voters are no longer able to submit comments via the balloting software.
Next Steps
A successive ballot for COM-001-2 and a non-binding poll of the associated VRF/VSLs and recirculation ballots
for COM-002-3 and IRO-001-3 and non-binding polls for the associated VRF/VSLs will be conducted on
Wednesday, June 27 through 8 p.m. Eastern on Friday, July 6, 2012.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measureable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; 3) revising
the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards Authorization
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Request (PER-004 and PRC-001) were moved to other projects due to the scope overlap. In addition, the scope
of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated with standard IRO003-2. Additional information is available on the project page.
The Project 2006-06 standards are an important part of the ERO’s strategic goal to develop technically sufficient
standards with requirements that provide clear and unambiguous performance expectations and reliability
benefits.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend out
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2006-06
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Standards Announcement
Project 2006-06 Reliability Coordination
Formal Comment Period:
June 7-July 6, 2012
Upcoming:
June 27 – July 6, 2012
Successive and Non-Binding Poll:
Recirculation and Non-Binding Polls:
COM-001-2
COM-002-3 and IRO-001-3
Now Available
A formal comment period for COM-001-2 – Communications is open through 8 p.m. Eastern on Friday, July 6,
2012. In response to industry comments, the Drafting Team made substantive changes to COM-001-2 –
Communications requiring an additional comment period and successive ballot. The Drafting Team made minor
changes to the VSLs but did not make substantive changes to COM-002-3 – Communication and Coordination
and IRO-001-3 – Reliability Coordination – Responsibilities and Authorities requirements which passed the
previous successive ballots.
Instructions for Commenting
A formal comment period for COM-001-2 is open through 8 p.m. Eastern on Friday, July 6, 2012. Please use this
electronic form to submit comments. If you experience any difficulties in using the electronic form, please
contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment form is posted
on the project page.
Commenters and voters must submit comments through the electronic comment form. Due to modifications to
NERC’s balloting software, voters are no longer able to submit comments via the balloting software.
Next Steps
A successive ballot for COM-001-2 and a non-binding poll of the associated VRF/VSLs and recirculation ballots
for COM-002-3 and IRO-001-3 and non-binding polls for the associated VRF/VSLs will be conducted on
Wednesday, June 27 through 8 p.m. Eastern on Friday, July 6, 2012.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measureable, unique, and enforceable; 2)
ensuring that this set of requirements is sufficient to maintain reliability of the Bulk Electric System; 3) revising
the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated changes
due to the work of the IROL Standards Drafting Team. Two standards from the original Standards Authorization
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Request (PER-004 and PRC-001) were moved to other projects due to the scope overlap. In addition, the scope
of Project 2006-06 was expanded to incorporate directives from FERC Order 693 associated with standard IRO003-2. Additional information is available on the project page.
The Project 2006-06 standards are an important part of the ERO’s strategic goal to develop technically sufficient
standards with requirements that provide clear and unambiguous performance expectations and reliability
benefits.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend out
thanks to all those who participate. For more information or assistance, please contact Monica Benson at
[email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2006-06
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Standards Announcement
Project 2006-06 Reliability Coordination
Successive, Recirculation and Non-Binding Poll Results
Now Available
A successive ballot for COM-001-2 – Communications and a non-binding poll of the associated
VRF/VSLs and recirculation ballots for COM-002-3 – Communication and Coordination and IRO-001-3
– Reliability Coordination – Responsibilities and Authorities and non-binding polls for the associated
VRF/VSLs concluded on Friday, July 6, 2012.
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Standard
Approval
COM-001-2 (Successive)
Quorum: 75.37%
Quorum:
Approval: 72.16%
Supportive Opinions: 73.71%
Quorum: 85.34%
Quorum:
Approval: 81.71%
Supportive Opinions: 79.16%
Quorum: 85.04%
Quorum:
Approval: 81.72%
Supportive Opinions: 86.91%
COM-002-3 (Recirculation)
IRO-001-3 (Recirculation)
Non-binding Poll Results
75.37%
84.16%
83.87 %
Next Steps
The drafting team is considering all comments submitted for COM-001-2, and based on the comments
will determine whether to make additional changes. If the drafting team determines that no
substantive changes to the standard are required, the team will submit the standard and associated
documents for a recirculation ballot. If the drafting team makes substantive changes to the standard,
the team will submit its consideration of comments, along with the revised standard and associated
documents, for a quality review prior to posting for another successive ballot.
COM-002-3 – Communication and Coordination and IRO-001-3 – Reliability Coordination –
Responsibilities and Authorities will be presented to the NERC Board of Trustees for adoption and
subsequently filed with regulatory authorities. The VRFs and VSLs for both standards (unchanged from
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
those included in the versions of the standards posted for recirculation ballot) will be presented to the
board for approval.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measureable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to the
scope overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from
FERC Order 693 associated with standard IRO-003-2.
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
Ballot Results – Project 2006-06
2
Standards
Administration
20140514-5129
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Newsroom • Site Map • Contact NERC
Advanced Search
Ballot Results
Standards Admin
Home
Ballot Name: Project 2006 -06 Successive Ballot COM-001-2
Registered Ballot
Body
Ballot Period: 6/27/2012 - 7/9/2012
Ballot Events
Ballot Type: Initial
Current Ballot Pools
Total # Votes: 257
Current Ballots
Total Ballot Pool: 341
Previous Ballots
Vetting
Quorum: 75.37 % The Quorum has been reached
Proxy Pool
NERC Home
Weighted Segment
72.16 %
Vote:
Ballot Results: The drafting team will review comments received.
Summary of Ballot Results
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot
Pool
Affirmative
Negative
Segment
Weight # Votes Fraction # Votes Fraction
88
11
85
24
69
44
0
8
4
8
341
1
0.8
1
1
1
1
0
0.7
0.3
0.6
7.4
43
5
31
13
33
24
0
4
3
5
161
0.754
0.5
0.554
0.765
0.767
0.8
0
0.4
0.3
0.5
5.34
Abstain
14
3
25
4
10
6
0
3
0
1
66
No
Vote
# Votes
0.246
0.3
0.446
0.235
0.233
0.2
0
0.3
0
0.1
2.06
11
2
5
1
7
4
0
0
0
0
30
20
1
24
6
19
10
0
1
1
2
84
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Member
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
Scott J Kinney
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Ballot
Comments
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Bonneville Power Administration
Donald S. Watkins
Central Maine Power Company
Kevin L Howes
City of Tacoma, Department of Public Utilities,
Chang G Choi
Light Division, dba Tacoma Power
City of Vero Beach
Randall McCamish
City Water, Light & Power of Springfield
Shaun Anders
Clark Public Utilities
Jack Stamper
Cleco Power LLC
Danny McDaniel
Colorado Springs Utilities
Paul Morland
Consolidated Edison Co. of New York
Christopher L de Graffenried
Dayton Power & Light Co.
Hertzel Shamash
Dominion Virginia Power
Michael S Crowley
Duke Energy Carolina
Douglas E. Hils
East Kentucky Power Coop.
George S. Carruba
Empire District Electric Co.
Ralph F Meyer
Entergy Corporation
George R. Bartlett
FirstEnergy Energy Delivery
Robert Martinko
Florida Keys Electric Cooperative Assoc.
Dennis Minton
Great River Energy
Gordon Pietsch
Hoosier Energy Rural Electric Cooperative, Inc. Bob Solomon
Hydro One Networks, Inc.
Ajay Garg
Hydro-Quebec TransEnergie
Bernard Pelletier
Idaho Power Company
Ronald D. Schellberg
International Transmission Company Holdings
Michael Moltane
Corp
Kansas City Power & Light Co.
Michael Gammon
Keys Energy Services
Stan T. Rzad
Lake Worth Utilities
Walt Gill
Lakeland Electric
Larry E Watt
Lee County Electric Cooperative
John W Delucca
Long Island Power Authority
Robert Ganley
Manitoba Hydro
Joe D Petaski
MEAG Power
Danny Dees
MidAmerican Energy Co.
Terry Harbour
Minnkota Power Coop. Inc.
Richard Burt
National Grid
Saurabh Saksena
Nebraska Public Power District
Richard L. Koch
New Brunswick Power Transmission Corporation Randy MacDonald
New York Power Authority
Arnold J. Schuff
Northeast Utilities
David Boguslawski
Northern Indiana Public Service Co.
Kevin M Largura
NorthWestern Energy
John Canavan
Oklahoma Gas and Electric Co.
Marvin E VanBebber
Omaha Public Power District
Doug Peterchuck
Oncor Electric Delivery
Michael T. Quinn
Orlando Utilities Commission
Brad Chase
Otter Tail Power Company
Daryl Hanson
PacifiCorp
Colt Norrish
PECO Energy
Ronald Schloendorn
Platte River Power Authority
John C. Collins
Portland General Electric Co.
Frank F Afranji
Potomac Electric Power Co.
David Thorne
PowerSouth Energy Cooperative
Larry D Avery
PPL Electric Utilities Corp.
Brenda L Truhe
Public Service Company of New Mexico
Laurie Williams
Public Service Electric and Gas Co.
Kenneth D. Brown
Public Utility District No. 1 of Okanogan County Dale Dunckel
Puget Sound Energy, Inc.
Catherine Koch
Rochester Gas and Electric Corp.
John C. Allen
Sacramento Municipal Utility District
Tim Kelley
Salt River Project
Robert Kondziolka
Santee Cooper
Terry L Blackwell
SCE&G
Henry Delk, Jr.
Seattle City Light
Pawel Krupa
Sierra Pacific Power Co.
Rich Salgo
South Texas Electric Cooperative
Richard McLeon
Southern California Edison Co.
Dana Cabbell
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Leesburg
City of Redding
Clearwater Power Co.
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Robert A. Schaffeld
William Hutchison
James Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Charles B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Richard J. Mandes
Bob Reeping
Kelly Nguyen
Steven Norris
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Dave Markham
Negative
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Phil Janik
Bill Hughes
Dave Hagen
Michelle A Corley
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
Scott S. Barfield-McGinnis
Sam Kokkinen
David Kiguel
Shaun Jensen
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Northern Lights Inc.
Okanogan County Electric Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Garry Baker
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Daniel D Kurowski
Richard Reynolds
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Jon Shelby
Ray Ellis
David Burke
Ballard K Mutters
John Apperson
Terry L Baker
Robert Reuter
Jeffrey Mueller
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Marc M Farmer
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Tim Beyrle
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph DePoorter
Douglas Hohlbaugh
Aleka K Scott
Henry E. LuBean
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/administration/BallotSummary.aspx?BallotGUID=9a8ba2af-a8f8-4f46-a6c6-f086f1d28639[7/10/2012 1:40:22 PM]
Standards
Administration
20140514-5129
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Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of Public Utilities,
Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group Incorporated
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Keith Morisette
Allan Morales
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul A. Cummings
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Max Emrick
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/administration/BallotSummary.aspx?BallotGUID=9a8ba2af-a8f8-4f46-a6c6-f086f1d28639[7/10/2012 1:40:22 PM]
Standards
Administration
20140514-5129
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6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
9
9
10
10
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Shell Energy North America (US), L.P.
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Snohomish County PUD No. 1
Florida Reliability Coordinating Council
Midwest Reliability Organization
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
Brandy D Olson
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Claire Warshaw
Steven J Hulet
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Paul Kerr
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Abstain
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
David F. Lemmons
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Jim Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
Negative
Affirmative
Donald Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
William Moojen
Linda Campbell
James D Burley
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
https://standards.nerc.net/administration/BallotSummary.aspx?BallotGUID=9a8ba2af-a8f8-4f46-a6c6-f086f1d28639[7/10/2012 1:40:22 PM]
Standards
Administration
20140514-5129
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New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity
Western Electricity Coordinating Council
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Larry D. Grimm
Louise McCarren
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Legal and Privacy : 609.452.8060 voice : 609.452.9550 fax : 116-390 Village Boulevard : Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801
Copyright © 2009 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/administration/BallotSummary.aspx?BallotGUID=9a8ba2af-a8f8-4f46-a6c6-f086f1d28639[7/10/2012 1:40:22 PM]
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
COM-001-2
Non-binding Poll Results
Non-binding Poll Name: Project 2006-06 Non-binding Poll COM-001-2
Poll Period: 6/27/2012 - 7/10/2012
Total # Opinions: 257
Total Ballot Pool: 341
75.37% of those who registered to participate provided an opinion or an abstention;
Summary Results: 73.71% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
1
1
1
Organization
1
1
1
1
1
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City of Vero Beach
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
1
1
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
1
1
Member
Opinions
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
Scott J Kinney
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Kevin L Howes
Abstain
Abstain
Abstain
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Chang G Choi
Affirmative
Randall McCamish
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Gordon Pietsch
Bob Solomon
Non-binding Poll Results – Project 2006-06 COM-001-2
Comments
Affirmative
Abstain
Negative
Abstain
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Sierra Pacific Power Co.
South Texas Electric Cooperative
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Michael Moltane
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Robert Ganley
Joe D Petaski
Danny Dees
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch
Randy MacDonald
Arnold J. Schuff
David Boguslawski
Kevin M Largura
John Canavan
Marvin E VanBebber
Doug Peterchuck
Michael T. Quinn
Brad Chase
Daryl Hanson
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F Afranji
David Thorne
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Dale Dunckel
Catherine Koch
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Rich Salgo
Richard McLeon
Non-binding Poll Results – Project 2006-06 COM-001-2
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Southern California Edison Co.
Dana Cabbell
Southern Company Services, Inc.
Robert A. Schaffeld
Southern Illinois Power Coop.
William Hutchison
Southwest Transmission Cooperative, Inc. James Jones
Southwestern Power Administration
Gary W Cox
Sunflower Electric Power Corporation
Noman Lee Williams
Tampa Electric Co.
Beth Young
Tennessee Valley Authority
Larry Akens
Tri-State G & T Association, Inc.
Tracy Sliman
Tucson Electric Power Co.
John Tolo
United Illuminating Co.
Jonathan Appelbaum
Westar Energy
Allen Klassen
Western Area Power Administration
Brandy A Dunn
Western Farmers Electric Coop.
Forrest Brock
Xcel Energy, Inc.
Gregory L Pieper
Alberta Electric System Operator
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Gregory Van Pelt
Electric Reliability Council of Texas, Inc. Charles B Manning
Independent Electricity System Operator Kim Warren
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Jason L Marshall
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
Tom Bowe
Southwest Power Pool
Charles H. Yeung
Alabama Power Company
Richard J. Mandes
Allegheny Power
Bob Reeping
Anaheim Public Utilities Dept.
Kelly Nguyen
APS
Steven Norris
Atlantic City Electric Company
James V. Petrella
BC Hydro and Power Authority
Pat G. Harrington
Blachly-Lane Electric Co-op
Bud Tracy
Bonneville Power Administration
Rebecca Berdahl
Central Electric Cooperative, Inc.
Dave Markham
(Redmond, Oregon)
Central Lincoln PUD
Steve Alexanderson
City of Bartow, Florida
Matt Culverhouse
City of Clewiston
Lynne Mila
City of Farmington
Linda R Jacobson
City of Garland
Ronnie C Hoeinghaus
City of Green Cove Springs
Gregg R Griffin
City of Leesburg
Phil Janik
City of Redding
Bill Hughes
Clearwater Power Co.
Dave Hagen
Cleco Corporation
Michelle A Corley
ComEd
Bruce Krawczyk
Non-binding Poll Results – Project 2006-06 COM-001-2
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
3
Georgia System Operations Corporation
3
3
3
3
3
3
3
3
3
3
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water &
Daniel D Kurowski
Power
Lost River Electric Cooperative
Richard Reynolds
Louisville Gas and Electric Co.
Charles A. Freibert
Manitoba Hydro
Greg C. Parent
MidAmerican Energy Co.
Thomas C. Mielnik
Mississippi Power
Don Horsley
Municipal Electric Authority of Georgia
Steven M. Jackson
Muscatine Power & Water
John S Bos
Nebraska Public Power District
Tony Eddleman
New York Power Authority
Marilyn Brown
Niagara Mohawk (National Grid Company) Michael Schiavone
Northern Indiana Public Service Co.
William SeDoris
Northern Lights Inc.
Jon Shelby
Okanogan County Electric Cooperative,
Ray Ellis
Inc.
Orange and Rockland Utilities, Inc.
David Burke
Orlando Utilities Commission
Ballard K Mutters
PacifiCorp
John Apperson
Platte River Power Authority
Terry L Baker
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Peter T Yost
CJ Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
Scott S. BarfieldMcGinnis
Sam Kokkinen
David Kiguel
Shaun Jensen
Garry Baker
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Non-binding Poll Results – Project 2006-06 COM-001-2
Abstain
Abstain
Affirmative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
Robert Reuter
Jeffrey Mueller
Abstain
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Marc M Farmer
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Abstain
Abstain
Affirmative
Negative
Affirmative
Negative
Timothy Beyrle
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph DePoorter
Douglas Hohlbaugh
Aleka K Scott
Affirmative
Henry E. LuBean
Affirmative
John D Martinsen
Abstain
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Non-binding Poll Results – Project 2006-06 COM-001-2
Affirmative
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source Generation,
Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul A. Cummings
Abstain
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Max Emrick
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Abstain
Abstain
Abstain
Amir Y Hammad
Abstain
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Negative
Abstain
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Kenneth Silver
Affirmative
Mike Laney
S N Fernando
Affirmative
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Non-binding Poll Results – Project 2006-06 COM-001-2
Affirmative
Affirmative
Affirmative
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group
Incorporated
Public Utility District No. 1 of Lewis
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Don Schmit
Gerald Mannarino
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Non-binding Poll Results – Project 2006-06 COM-001-2
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
7
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
9
9
10
10
10
10
10
10
10
10
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Shell Energy North America (US), L.P.
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Eric Ruskamp
Daniel Prowse
Dennis Kimm
Brandy D Olson
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Claire Warshaw
Steven J Hulet
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Paul Kerr
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Peter H Kinney
David F. Lemmons
James A Maenner
Roger C Zaklukiewicz
Edward C Stein
JDRJC Associates
Jim Cyrulewski
Pacific Northwest Generating Cooperative Margaret Ryan
Power Energy Group LLC
Peggy Abbadini
Utility Services, Inc.
Brian Evans-Mongeon
Volkmann Consulting, Inc.
Terry Volkmann
Commonwealth of Massachusetts
Donald Nelson
Department of Public Utilities
National Association of Regulatory Utility
Diane J Barney
Commissioners
Oregon Public Utility Commission
Jerome Murray
Snohomish County PUD No. 1
William Moojen
Florida Reliability Coordinating Council
Linda Campbell
Midwest Reliability Organization
James D Burley
New York State Reliability Council
Alan Adamson
Northeast Power Coordinating Council,
Guy V. Zito
Inc.
ReliabilityFirst Corporation
Anthony E Jablonski
SERC Reliability Corporation
Carter B Edge
Texas Reliability Entity
Larry D. Grimm
Western Electricity Coordinating Council Louise McCarren
Non-binding Poll Results – Project 2006-06 COM-001-2
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Name (25 Responses)
Organization (25 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
Question 1 (32 Responses)
Question 1 Comments (41 Responses)
Question 2 (31 Responses)
Question 2 Comments (41 Responses)
Question 3 (30 Responses)
Question 3 Comments (41 Responses)
Question 4 (0 Responses)
Question 4 Comments (41 Responses)
Individual
Alice Ireland
Xcel Energy
Yes
Yes
Yes
Individual
Thad Ness
American Electric Power
Yes
Yes
The definition of Alternative Interpersonal Communication is “Any Interpersonal Communication that
is able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communication used for day-to-day operation.” Does the Alternative Interpersonal
Communication have to be a different technology? For example, if a satellite phone is used, but it
calls the same land-line on the other end, does this qualify as Alternative Interpersonal
Communication? How does a TOP notify a DP of a failure in its Interpersonal Communications
capability per R10, if it there is no Alternative Interpersonal Communication required? Within
Requirement 10, the entities to be notified should not reference R1, R3, and R5 but should instead
reference R2, R4, and R6 respectively. This change is necessary because the requirements we are
referring to are those that have Alternative Interpersonnel Communications. You cannot expect
notification to entities where an Alternative Interpersonnel Communication does not exist.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
None
Group
FirstEnergy
Sam Ciccone
Yes
Yes
Yes
FE supports COM-001-2 and has no further comments. PLEASE NOTE: THE FOLLOWING COMMENTS
RELATE TO COM-002-3 AND IRO-001-3 SINCE WE WERE NOT ABLE TO PROVIDE COMMENTS ON THE
RECIRCULATION BALLOT AND WANTED TO EXPLAIN OUR REASONS FOR NOT SUPPORTING THOSE
STANDARDS: Although we believe the team made significant improvements to the standard, and
would support a 3-part communication standard, we believe the introduction of both COM-002-2
which utilizes Reliability Directives and COM-003-1 which utilizes Operating Communications cause
confusion for system operators and may in fact be detrimental to reliability. We do not support two
standards on three-part communication. We suggest, as we have in the past, that the subject of
three-part communication be addressed in a single standard, and that the requirements be developed
for simplicity. The industry is, and has been, using three-part communication for decades and
although we agree it should be more consistently practiced and standardized, the required
communications protocols should be simple while meeting the goal of BES reliability. Introducing
complicated requirements and standards that have different definitions such as Reliability Directive
and Operating Communication may cause the operator to hesitate when issuing directives in real-time
and every second counts when a potential system emergency must be mitigated. Therefore, FE does
not support the creation of both COM-003-1 nor the revisions to COM-002-2 and IRO-001-3 which
introduce the “Reliability Directive” term and ask NERC to reevaluate the need to have two separate
standards for three-part communication.
Group
PacifiCorp
Sandra Shaffer
No
No
PacifiCorp does not understand the RCSDT’s rationale for creating separate sub-requirements for
adjacent Transmission Operators that are synchronously and asynchronously connected, in both
R3.5/R3.6 and R4.3/R4.4. PacifiCorp recommends the following singular sub-requirement for both R3
and R4: “Each adjacent Transmission Operator (whether synchronously or asynchronously
connected).”
Yes
N/A
Individual
John Seelke
Public Service Enterprise Group
Yes
Yes
Yes
Change R11 and replace “experiences a failure” with “detects a failure” because one may have a
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
failure, but if it’s undetected for some period of time because no communications are taking place, it’s
unclear when one actually “experienced a failure.” We note that R10 uses the terminology “detection
of a failure.” Using consistent terminology in R10 and R11 would result in less confusion for
compliance because there would not be an issue as to whether a difference was intended by the SDT
between “experiences” and “detects” in the two requirements.
Individual
David Thorne
Pepco Holdings Inc
Yes
Yes
Yes
Individual
Karen Webb
City of Tallahassee (TAL)
Yes
Yes
Yes
For Measure 7, the first line duplicates the word "that".
TAL has no comments on COM-001-2. However, for COM-002-3, under Data Retention, the second
bullet requires the BA, TOP, GOP, and DP to retain evidence for R1, M1; however, R1 is not applicable
to the GOP or DP. This should read R2, M2. Also, there is room for debate on the clarity of the VSLs
for R3. Specifically, the use of the word "accurately" could be interpreted to mean "verbatim" in cases
where varying verbiage results in the same understanding and action between the parties, and
therefore no re-issuance of the directive is required in the eyes of the issuer.
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
Yes
(1) Both instances of “Reliability Coordinator” in the VSLs for R3 should be “Transmission Operator” to
match the language of the standard. (2) Both instances of “Reliability Coordinator” in the VSLs for R5
should be “Balancing Authority” to match the language of the standard. (3) In the VSLs for R9 and
R10 the use of “and” seems incorrect. Austin Energy suggests the following revisions for all VSL levels
(only the Lower VSL shown for simplicity and revised words suggested in capital letters): R9, Lower
VSL: “The Reliability Coordinator, Transmission Operator, OR Balancing Authority…” R10, Lower VSL:
“The Reliability Coordinator, Transmission Operator, OR Balancing Authority failed to notify the
entities identified in Requirements R1, R3, OR R5, RESPECTIVELY, upon the detection …”
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Manitoba Hydro would like additional clarification added to the definition of interpersonal
communication. The definition should explicitly state that interpersonal communication does not data
links (e.g. the ICCP data link). Also, does interpersonal communication include emails? Under the
Effective Date Section, the effective date language has a few issues in its drafting. It would be clearer
to use the word ‘following’ as opposed to the word ‘beyond’ (and this would also be more consistent
with the drafting of similar sections in other standards). The words ‘the standard becomes effective’ in
the third line are not needed. The words ‘made pursuant to the laws applicable to such ERO
governmental authorities’ may not be appropriate. It’s not the laws applicable to the governmental
authorities that are relevant, but the laws applicable to the entity itself. We would suggest wording
like ‘or as otherwise made effective pursuant to the laws applicable to the Balancing Authority’. Also,
ERO is not defined. R11 and M11 – would suggest replacing ‘action’ with ‘plan of action’ or ‘action
plan’ M3 and M4 – the word ‘and’ between asynchronously and synchronously should more
appropriately be ‘or’ M10 – the semi colon after stamped should be deleted Compliance Section –
Compliance Enforcement Authority is defined as CEA, but then both the acronym and the entire term
is later used in the document. Should either not define, or use acronym consistently.
Individual
Steve Alexanderson P.E.
Central Lincoln
Prior Central Lincoln Comment 1)The new requirement presents us with a paradoxical situation. The
communication has failed, so we must consult; yet consultation requires communication. We note
that the SDT used the word “any”, implying that multiple communication paths are required. The
reality of the situation at Central Lincoln, due to our remote location, is that a single back hoe incident
at the right location can take out all of our of our communication capability (including the terrestrial
portion of the cellular networks) with our BA/TO; making this requirement impossible to meet for this
circumstance using our present capabilities. Prior RCSDT Response 1) The RCSDT appreciates your
comment and has made clarifying changes by removing the phrase “any of” in COM-001, R11.
Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult
with the entity affected by the failure. Furthermore, R11 addresses the direction given in Order 693
that DP and GOP entities do not necessarily need to have Alternative Interpersonal Communication
capability. The requirement allows flexibility in “consult with” by not naming the method. If all
communications are out, then the DP or GOP may have to meet the requirement by an in-person
consultation. New Central Lincoln Response 1) Thank you for the changes made. We realize that inperson consultation is an option, but find it not too hard to imagine the same event that disrupts
communications might also block roads. We don’t believe entities should be found non-compliant and
sanctioned for events beyond their control. Prior Central Lincoln Comment 2) We also note that no
time limit was indicated. Most interruptions are brief, and fixed before consultation could reasonably
take place. CEAs will be finding entities non-compliant for quickly fixing problems at their end without
first consulting to ensure the restoration time was agreeable. To avoid non-compliance, entities will
be forced to delay repairs while they investigate alternative communication paths for consultation
purposes. We fail to see how such an outcome improves reliability. Prior RCSDT Response 2) The DP
and GOP are only required to have Interpersonal Communication capability. If the DP or GOP restores
its Interpersonal Communication capability before it could reasonably contact the affected entity by
another method, there is no failure to comply. The DP or GOP could then consult with the affected
entity to determine a mutually agreeable action. In this case, the RCSDT believes the "action" would
then be the entities acknowledging the failure and the repair; therefore, no mutually agreeable action
is needed. The RCSDT recognizes there is no way to account for all the various circumstances in a
failure. To comply, the DP and GOP are still required to consult the entity which the failure affected
regardless of whether the Interpersonal Communication capability was restored or is still failed. No
change made. New Central Lincoln Response 2) If consultation after restoration is acceptable, we
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
suggest that this be made clear in the requirement. Presently it is not at all clear, and there is no
accompanying guidance document to suggest so. We also remain unclear what reliability benefit
would result from such a consultation following restoration. While accounting for all the various
failures might be impossible, we would like to see a few of the more common ones discussed in a
guidance document. Prior Central Lincoln Comment 3) The new requirement is one sided, requiring
the DP and GOP to consult with no corresponding requirement for the TO or BA to have personnel
available for such a consultation. Consultation failure or failure to mutually agree due to actions or
inactions on the part of the TO or BA should not result in an enforcement action against the DP or
GOP, yet that is how the requirement is written. Prior RCSDT Response 3) The RCSDT notes that once
the failure has been detected, the responsible entity must make the consultation with the BA or TOP;
that relieves the compliance burden. While the RCSDT understands your concern about single points
of failure, the question becomes should this relieve the DP or GOP of the requirement for having
Interpersonal Communication capabilities. No change made. New Central Lincoln Response 3) The
requirement remains one-sided. If a consultation effort fails due to actions or inactions taken by the
BA/TO, the DP or GOP is the only entity that can be found non-compliant. Prior Central Lincoln
Comment 4) The new requirement fails to add any “clarity” to the other requirements, and we don’t
see that the stakeholders thought there was a problem with DP/GOP obligation clarity. Instead, it
adds new obligations with no justification for how they enhance reliability. We suggest removing the
requirement. Prior RCSDT Response 4) Based on the RCSDT’s understanding of the comments
received on the previous posting, the industry desired additional clarity on specifically what
communication capabilities the DP and GOP were required to have. There was confusion that the
standard did not specifically say that the DP and GOP were required to have Alternative Interpersonal
Communication capabilities. R11 clarifies that a DP and GOP are not required to have Alternative
Interpersonal Communication capability if the DP or GOP consult with their TOP or BA, whichever is
applicable in the given situation, and they mutually agree that the restoration action does not
adversely impact the reliability of the BES. No change made. New Central Lincoln Response 4) We
disagree that R11 clarifies anything regarding Alternative Interpersonal Communication capabilities;
the requirement says nothing on the matter. If other requirements remain unclear, we suggest they
be clarified within those requirements. We ask that R11 be removed. Alternatively we suggest that a
plan for communication failure be developed by the affected entities prior to a failure, applicable to
both the BA/TO and DP/GOP. Prior Central Lincoln Comment 5) As stated in our prior comments, we
continue to have problems with COM-002, R2 and R3 as written. The SDT’s answer (“It is the
expectation that an issuer of a Reliability Directive would request a return call by the Distribution
Provider operating personnel, then issue the Reliability Directive”) addresses our concern perfectly,
and we would agree with such an expectation. Unfortunately, the expressed expectation is not in the
proposed standard or even in a proposed guideline for the standard. Prior RCSDT Response 5) The
RCSDT believes this is a process or procedure question that should be determined by the entity in
how it handles communication with the RC. The standard, as written does, not preclude the entity
from having a procedure. No change made. New Central Lincoln Response 5) We agree that this is a
procedure issue, but disagree that the procedure lies with the entity receiving the Reliability Directive.
The SDT’s words inside the quotation marks above state it is the issuer of the Directive that should
request a return call. Procedures like this, in order to ensure the Directive gets to the party who
understands it and can take the needed action, are the responsibility of the issuer. If reliability is at
risk, it is little to ask that issuers of Relibility Directives be required to attempt to reach the proper
party prior to identifying, delivering the directive, and asking for repetition.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP (Occidental Chemical in the ballot body)
Yes
Ingleside Cogeneration LP agrees that the modification removes all doubt that a glossary definition is
inferred. We support all clarifications of this kind.
Yes
No
Ingleside Cogeneration LP would like to see the project team include references to intermediaries
which act as a single point of contact between GOPs and BAs/TOPs. This is a very common and
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
necessaray communications hierarchy – as it is just not possible for the BA/TOP to otherwise
coordinate the actions of multiple GOPs. We believe that it is appropriate that GOP must retain
evidence that Interpersonal Communication capability is maintained up to the intermediary – but the
BA or TOP must be responsible for the remainder of the link. This accountability matches the most
common contractual arrangements where both the BA/TOP and the GOP have signed agreements with
the intermediary.
Ingleside Cogeneration LP generally agrees with the modifications that the SDT has made to COM001-2. However, we cannot vote to accept the standard unless requirement R10 is modified to include
a minimum communications outage duration before consultation with the BA or TOP is necessary. This
is similar to R10, which allows an outage to extend up to 30 minutes – thus avoiding the need for a
notification that an insignificant interruption in service took place. The following language could be
added to R11 as shown in the brackets below: R11. Each Distribution Provider and Generator
Operator that experiences a failure of its Interpersonal Communication capability [that lasts 30
minutes or longer] shall consult each entity affected by the failure, as identified in Requirement R7 for
a Distribution Provider or Requirement R8 for a Generator Operator, to determine a mutually
agreeable action for the restoration of its Interpersonal Communication capability.
Group
SERC OC Standards Review Group
Gerald Beckerle
Yes
Yes
Yes
The SERC OC SRG would like to thank the Standard Drafting Team for their service. “The comments
expressed herein represent a consensus of the views of the above named members of the SERC OC
Standards Review group only and should not be construed as the position of SERC Reliability
Corporation, its board or its officers.”
Individual
Laura Lee
Duke Energy
Yes
Yes
Yes
Distribution Providers and Generator Operators have significant responsibilities that require reliable
means of communications with other entities, such as implementing load shedding and adjusting real
and reactive power. The requirements for the Distribution Provider and Generator Operator should
therefore be consistent with those for the Reliability Coordinator, Transmission Operator and
Balancing Authority, namely, they should be required to designate Alternative Interpersonal
Communication capability, to test this capability and to notify appropriate entities when its
Interpersonal Communication capability has failed. The definition of Interpersonal Communication
should also be expanded to clearly include the drafting team’s intent that the capability is NOT for the
exchange of data.
Group
Bonneville Power Administration
Chris Higgins
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
BPA thanks you for the opportunity to comment on Project 2006-06, COM-001-2 and has no
comments or concerns at this time.
Group
Luminant
Brenda Hampton
Yes
Yes
Yes
Individual
Don Jones
Texas Reliability Entity
Yes
“Adjacent Balancing Authority” is a defined term in the NERC Glossary, and use of the non-defined
term “adjacent Balancing Authority” in this draft will cause confusion. Exactly what difference is
intended by using the lower-case “a” instead of the defined term?
No
The proposed revision to include Transmission Operators asynchronously connected (Parts 3.5 and
4.4) is an appropriate revision to the Standard. The Reliability Coordinator responsibilities for
communications with a Reliability Coordinator across an asynchronous connection do not appear to be
addressed in this revision. Did the RCSDT have a particular reason not to address the RC issue? We
believe each RC should have Interpersonal Communication capability with all neighboring RCs
regardless of Interconnection boundaries, the type of connection, or whether a connection exists.
Yes
In the Measures for R3 and R4 (M3 and M4), should the phrase “each adjacent Transmission Operator
asynchronously AND synchronously connected” be changed to “each adjacent Transmission Operator
asynchronously OR synchronously connected”? In the VSLs for R3 it appears that “Reliability
Coordinator” should be “Transmission Operator”. In the VSLs for R5 it appears that “Reliability
Coordinator” should be “Balancing Authority”. In the Severe VSL for R10 the phrase “failed to notify
the identified entities identified” should probably be “failed to notify the entities identified”.
Group
Western Electricity Coordinating Council
Steve Rueckert
Yes
Yes
Yes
Group
Dominion
Connie Lowe
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Dominion has no additional comments on COM-001-2, but does have the below comments on IRO001-3: Dominion believes that our previous comment remains valid and the response provided by the
SDT does not address all aspects of our concerns. Dominion suggests that the language of ‘direction’
be changed to ‘Reliability Directive’ to remain consistent with COM-002. Another alternative would be
as written below; IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3. To avoid
confusion with a Reliability Directive (both for auditors and entities), we suggest the following: To
establish the authority of Reliability Coordinators to make requests of other entities to prevent an
Emergency or Adverse Reliability Impacts to the Bulk Electric System. R1: Each Reliability Coordinator
shall have the authority to act or request others to act (which could include issuing Reliability
Directives) to prevent identified events or mitigate the magnitude or duration of actual events that
result in an Emergency or Adverse Reliability Impacts. R2: Each Transmission Operator, Balancing
Authority, Generator Operator, and Distribution Provider shall comply with its Reliability Coordinator’s
request unless compliance with the request cannot be physically implemented, or unless such actions
would violate safety, equipment, regulatory or statutory requirements, or unless the TOP, BA, GOP or
DP convey a business reason not to comply with the request but express that they will comply if a
Reliability Directive is given. R3: Each Transmission Operator, Balancing Authority, Generator
Operator, and Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as requested in accordance with Requirement R2.” Or we could cite Southwest
Transmission Cooperative, Inc. comments which read “COM-002-3 R1 really compels the Reliability
Coordinator to use a Reliability Directive for Emergencies and Adverse Reliability Impacts with the
opening clause: “When a Reliability Coordinator, Transmission Operator, or Balancing Authority
determines actions need to be executed as a Reliability Directive.” What else could be more important
for a Reliability Coordinator to issue a Reliability Directive than for an Emergency or Adverse
Reliability Impact? Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts
and Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. For clarity and consistency,
IRO-001-3 Requirement R2 and R3 should also be clear that the responsible entities will respond to
the Reliability Coordinator’s Reliability Directives.
Individual
John Brockhan
CenterPoint Energy Houston Electric, LLC
Yes
Yes
Yes
1. For R10, there can be a large number of entities to notify for an Interpersonal Communication
failure. During normal operations, 60 minutes can be enough time to make all the notifications.
However, during emergency or adverse conditions, 60 minutes may not be sufficient. Thus, at the end
of R10, the following should be added: “unless certain adverse conditions (e.g. severe weather,
multiple events) prevent the completion of notification within the 60 minutes.” 2. For R11, the change
from “mutually agreeable time” to “mutually agreeable action” is not an improvement. It should not
be the concern of the other entities how (what action) the capability is restored, only that it is
restored and that the entity with the failure can be reached in the interim. Thus, we suggest the
following: “to determine a mutually agreeable alternative until Interpersonal Communication
capability is restored.”
Individual
Michael Falvo
Independent Electricity System Operator
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Notwithstanding our opposition to R1.2.
Yes
Yes
Notwithstanding our opposition to R1.2.
1. COM-001 We continue to disagree with R1.2, the phrase “within the same Interconnection” is
troublesome. RCs between two Interconnections still need to communicate with each other for
reliability coordination (e.g. between Quebec and the other RCs in the NPCC region to curtail
interchange transactions crossing Interconnection boundary). The SDT’s previous response that the
phrase was added to address the ERCOT situation and citing that ERCOT does not need to
communicate with other RCs leaves a reliability gap. The SDT’s latest response that R1 as written
does not preclude or limit the Reliability Coordinator from establishing Interpersonal Communication
capability with others is inconsistent with the basic principle for having a reliability standard. A
standard should stipulate the requirements based on what is needed to ensure reliability, not on what
is not precluded. If there is a reliability need for RCs across Interconnection boundary to coordination
operations, then Interpersonal Communication shall be provided. If we apply the SDT’s philosophy
(that the standard does not preclude…), then one can argue that the standard does not need to
stipulate a requirement to have Interpersonal Communication as without such a requirement, the
standard does not preclude any operating entities to have it. Finally, we would reiterate the fact that
RCs between asynchronously interconnected systems do communicate, e.g. between Quebec and its
neighbor RCs. We are also aware that RCs in the Western Interconnection and those in the Eastern
Interconnection do communicate as needed to coordinate TLR for transactions crossing
Interconnection boundary. 2. The follow comments address data retention for COM-002-3: a. The first
bullet in Section D1.3 stipulates that “The Reliability Coordinator, Transmission Operator, and
Balancing Authority shall retain evidence of Requirement R1 and R3, Measure M1 and M2 for the most
recent 3 calendar months.” We believe M2 should be M3. b. The second bullet: “The Balancing
Authority, Transmission Operator, Generator Operator, and Distribution Provider shall retain evidence
of Requirement R1, Measure M1 for the most recent 3 calendar months.” We believe R1 and M1
should read R2 and M2 since DP is only responsible for meeting R2. c. Section 2 “Violation Severity
Levels” : R# R2 Severe includes the Balancing Authority as one of the listed entities; however this is
inconsistent with R2 / M2 which do not include the Balancing Authority. To be consistent with R2 /
M2, the Balancing Authority should be removed from VSL R# R2. While these can be regarded as
typos, and do not contribute to a show-stopper vote for some, we urge the SDT and the Standards
Committee to pay closer attention to the accuracy of all elements in the standard. 3. IRO-001-3: o
Section 1.3 Data Retention (second bullet) states: ♣ The Operator, Balancing Authority, Generator
Operator, or Distribution Provider shall retain for Requirements R2 and R3, Measures M2 and M3 shall
retain voice recordings for the most recent 90 calendar days or documentation for the most recent 12
calendar months. • The statement above appears to be missing “Transmission” before the word
Operator. • The statement above repeats “shall retain” and the highlighted instance is not required. •
The statement above states “or” Distribution provider, implying that one entity needs to retain
evidence. Starting the sentence with “Each” rather than “The” and replacing “or” with “and” may
provide clarity. The same would apply to the introduction sentence prior to the bullets. COM-002-3
section D. Compliance 1.3 Data Retention provides an example of the suggested format. ♣ Here is an
example of the revised sentence: “Each Transmission Operator, Balancing Authority, Generator
Operator, and Distribution Provider shall retain voice recordings for the most recent 90 calendar days
or documentation for the most recent 12 calendar months, for Requirements R2 and R3, Measures M2
and M3”.
Group
Detroit Edison
Kent Kujala
Defining Interpersonal Communication as “Any medium that allows two or more individuals to
interact, consult, or exchange information” will also include all Alternative Interpersonal
Communications since “Any medium” is all inclusive. Consider replacing the definition of Interpersonal
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Communication with the following: Primary Interpersonal Communication: The normal communication
medium that two or more individuals use to interact, consult, or exchange information relating to dayto-day operations. Consider replacing the definition of Alternative Interpersonal Communication with
the following: Alternative Interpersonal Communication: Any communication medium that is able to
serve as a substitute for, and does not utilize the same infrastructure (medium) as the designated
Primary Interpersonal Communication. R1, R3, R5, R7, R8 should require entities to designate
Primary Interpersonal Communication. R10 and R11 should address failures to designated Primary
and Alternate Interpersonal Communication. R9 in all VSL levels the phrase "failed to initiate action to
repair" or designate a replacement is subject to interpretation. Does "initiate action" include
notification to the proper party to investigate and repair or does it require repairs to begin within
specified times as listed in severity levels?
Individual
Steve Alexanderson P.E.
Central Lincoln
Prior Central Lincoln Comment 1)The new requirement presents us with a paradoxical situation. The
communication has failed, so we must consult; yet consultation requires communication. We note
that the SDT used the word “any”, implying that multiple communication paths are required. The
reality of the situation at Central Lincoln, due to our remote location, is that a single back hoe incident
at the right location can take out all of our of our communication capability (including the terrestrial
portion of the cellular networks) with our BA/TO; making this requirement impossible to meet for this
circumstance using our present capabilities. Prior RCSDT Response 1) The RCSDT appreciates your
comment and has made clarifying changes by removing the phrase “any of” in COM-001, R11.
Additionally, the RCSDT made a clarifying change to indicate the DP and GOP only need to consult
with the entity affected by the failure. Furthermore, R11 addresses the direction given in Order 693
that DP and GOP entities do not necessarily need to have Alternative Interpersonal Communication
capability. The requirement allows flexibility in “consult with” by not naming the method. If all
communications are out, then the DP or GOP may have to meet the requirement by an in-person
consultation. New Central Lincoln Response 1) Thank you for the changes made. We realize that inperson consultation is an option, but find it not too hard to imagine the same event that disrupts
communications might also block roads. We don’t believe entities should be found non-compliant and
sanctioned for events beyond their control. Prior Central Lincoln Comment 2) We also note that no
time limit was indicated. Most interruptions are brief, and fixed before consultation could reasonably
take place. CEAs will be finding entities non-compliant for quickly fixing problems at their end without
first consulting to ensure the restoration time was agreeable. To avoid non-compliance, entities will
be forced to delay repairs while they investigate alternative communication paths for consultation
purposes. We fail to see how such an outcome improves reliability. Prior RCSDT Response 2) The DP
and GOP are only required to have Interpersonal Communication capability. If the DP or GOP restores
its Interpersonal Communication capability before it could reasonably contact the affected entity by
another method, there is no failure to comply. The DP or GOP could then consult with the affected
entity to determine a mutually agreeable action. In this case, the RCSDT believes the "action" would
then be the entities acknowledging the failure and the repair; therefore, no mutually agreeable action
is needed. The RCSDT recognizes there is no way to account for all the various circumstances in a
failure. To comply, the DP and GOP are still required to consult the entity which the failure affected
regardless of whether the Interpersonal Communication capability was restored or is still failed. No
change made. New Central Lincoln Response 2) If consultation after restoration is acceptable, we
suggest that this be made clear in the requirement. Presently it is not at all clear, and there is no
accompanying guidance document to suggest so. We also remain unclear what reliability benefit
would result from such a consultation following restoration. While accounting for all the various
failures might be impossible, we would like to see a few of the more common ones discussed in a
guidance document. Prior Central Lincoln Comment 3) The new requirement is one sided, requiring
the DP and GOP to consult with no corresponding requirement for the TO or BA to have personnel
available for such a consultation. Consultation failure or failure to mutually agree due to actions or
inactions on the part of the TO or BA should not result in an enforcement action against the DP or
GOP, yet that is how the requirement is written. Prior RCSDT Response 3) The RCSDT notes that once
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
the failure has been detected, the responsible entity must make the consultation with the BA or TOP;
that relieves the compliance burden. While the RCSDT understands your concern about single points
of failure, the question becomes should this relieve the DP or GOP of the requirement for having
Interpersonal Communication capabilities. No change made. New Central Lincoln Response 3) The
requirement remains one-sided. If a consultation effort fails due to actions or inactions taken by the
BA/TO, the DP or GOP is the only entity that can be found non-compliant. Prior Central Lincoln
Comment 4) The new requirement fails to add any “clarity” to the other requirements, and we don’t
see that the stakeholders thought there was a problem with DP/GOP obligation clarity. Instead, it
adds new obligations with no justification for how they enhance reliability. We suggest removing the
requirement. Prior RCSDT Response 4) Based on the RCSDT’s understanding of the comments
received on the previous posting, the industry desired additional clarity on specifically what
communication capabilities the DP and GOP were required to have. There was confusion that the
standard did not specifically say that the DP and GOP were required to have Alternative Interpersonal
Communication capabilities. R11 clarifies that a DP and GOP are not required to have Alternative
Interpersonal Communication capability if the DP or GOP consult with their TOP or BA, whichever is
applicable in the given situation, and they mutually agree that the restoration action does not
adversely impact the reliability of the BES. No change made. New Central Lincoln Response 4) We
disagree that R11 clarifies anything regarding Alternative Interpersonal Communication capabilities;
the requirement says nothing on the matter. If other requirements remain unclear, we suggest they
be clarified within those requirements. We ask that R11 be removed. Alternatively we suggest that a
plan for communication failure be developed by the affected entities prior to a failure, applicable to
both the BA/TO and DP/GOP. Prior Central Lincoln Comment 5) As stated in our prior comments, we
continue to have problems with COM-002, R2 and R3 as written. The SDT’s answer (“It is the
expectation that an issuer of a Reliability Directive would request a return call by the Distribution
Provider operating personnel, then issue the Reliability Directive”) addresses our concern perfectly,
and we would agree with such an expectation. Unfortunately, the expressed expectation is not in the
proposed standard or even in a proposed guideline for the standard. Prior RCSDT Response 5) The
RCSDT believes this is a process or procedure question that should be determined by the entity in
how it handles communication with the RC. The standard, as written does, not preclude the entity
from having a procedure. No change made. New Central Lincoln Response 5) We agree that this is a
procedure issue, but disagree that the procedure lies with the entity receiving the Reliability Directive.
The SDT’s words inside the quotation marks above state it is the issuer of the Directive that should
request a return call. Procedures like this, in order to ensure the Directive gets to the party who
understands it and can take the needed action, are the responsibility of the issuer. If reliability is at
risk, it is little to ask that issuers of Relibility Directives be required to attempt to reach the proper
party prior to identifying, delivering the directive, and asking for repetition.
Group
SPP Standards Review Group
Robert Rhodes
Yes
Yes
Yes
There are a couple of cut & paste errors in the VSLs for R3 and R5. In R3, Reliability Coordinator in
the High and Severe VSLs should be replaced with Transmission Operator. In R5, Reliability
Coordinator in the High and Severe VSLs should be replaced with Balancing Authority.
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Individual
Daniel Duff
Liberty Electric Power
Yes
Yes
Yes
R11 remains an issue even with the revision. The purpose of R11 should be to inform the BA and TO
of a loss of interpersonal communications capability so that the BA or TO can react effectively to grid
conditions in an emergency. The methods of repair for generator telephone and data lines are
properly the business decisions of the generator, and there is no benefit to the reliability of the BES if
a standard requires a generator to attempt to gain consensus from the BA and TO on his repair
actions. Taking the time to discuss a "mutually agreed action" will delay the start of repairs, and
lengthen the time of a communications outage as generators first must discuss the issue with the BA
and TO instead of initiating the action on their own and informing those entities of the failure. Further,
failure to follow a mutually agreed action plan could become a topic of exploration for audit staff. As
telecommunications repairs are generally not in the scope of expertise of electrical generators, this
places the entities at the mercy of contractor repair schedules, making following any mutually agreed
action problematic. Further, there is no duration trigger on R11, as opposed to the RC/TO/BA
requirement in R10. This forces the generator to inform the listed entities even of losses of capability
which last a handful of seconds. If a small generator has a single line into the control room, and the
control room operator is on the phone to the TOP, does he then have to inform the TO and BA at the
end of the call that they would have received a busy signal? If the operator knocks the phone from
the cradle, is the requirement to inform triggered? In a strict reading of the language, it would be.
Suggested rewrite of R11:" Upon discovery of an unresolved loss of interpersonal communications
which has the potential to last more than 15 minutes, the GOP shall inform the entities listed in R8 of
the status of interpersonal communications. The GOP shall initiate the process to restore the
interpersonal communications, and inform the entities listed in R8 of the restoration of
communications when repairs are complete. "
Group
MRO NSRF
WILL SMITH
Yes
Yes
Yes
: The NSRF understands the importance of Interpersonal Communications and Alternate Interpersonal
Communications and always having the ability to communicate with others. The NSRF questions why
per R9 (and similar time requirement per R10) that when testing the Alternate Interpersonal
Communications is unsuccessful, why there is a two hour time limit to initiate an action, repair, or
designate a replacement. Project 2012-08.1 defines “Reliable Operation” means operating the
Elements of the Bulk Power System within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or Cascading failures of such system will
not occur as a result of a sudden disturbance, including a Cyber Security Incident, or unanticipated
failure of system Elements. The loss of an Alternate Interpersonal Communication will not
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immediately impact the Reliable Operations of the BPS. Recommend that this not be contained within
the Standard as entity’s will view this as a Good Utility Practice. R10 The NSRF recommends that
“applicable” be inserted between “…notify entities…” . This will assure that RC’s will inform per R1,
TOP’s will inform per R3 and BA’s will inform per R5. This will assure that an interpretation is not
require as in Interpretation 2010-INT-01, TOP-006.
Group
Northeast Power Coordinating Council
Guy Zito
Yes
No
If 3.5 and 4.3 were made to read: “Each connected adjacent Transmission Operator.” then 3.6 and
4.4 (not 3.4 as indicated in the question) would not be required. If 3.6 and 4.4 are to be kept, then
the wording of 3.6 and 4.4 should be made to read: “Each adjacent Transmission Operator
asynchronously connected through a DC tie.” Systems cannot be asynchronously connected.
Yes
Group
LG&E and KU Services
Brent.Ingebrigtson
Regarding COM-001-2 and proposed definitions, LG&E and KU Services recommends changing the
terms being defined from “Interpersonal Communications” and “Alternative Interpersonal
Communication” to “Means for Interpersonal Communication” and “Alternative Means for
Interpersonal Communication.” A communication is an exchange of information, not a medium. The
medium is simply the means. LG&E and KU Services Company further recommend that each
requirement be rewritten with these new defined terms as appropriate and that the word
“capabilities” currently following the defined terms be removed from each of the requirements. We
suggest the definition for “Means for Interpersonal Communication” be: “A medium utilizing
electromagnetic energy that allows two or more individuals to interact, consult or exchange
information.” We suggest the definition for “Alternative Means for Interpersonal Communication” be:
“Any Means for Interpersonal Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Means for Interpersonal Communications used for dayto-day operation.” Regarding R1 through R10, , it is unclear what “shall have Interpersonal
Communications capability” means. That could mean that the responsible entity simply has to have
an IC capability that is different from our designated AIC capability (as R1 through R8 suggest). That
could also mean, differently, that the responsible entity has to designate an IC capability (as R10
suggests). It is also unclear whether the IC capability can change, e.g. from email to land line. There
is nothing in the Standard that makes this clear. Regarding R11, as written it is unclear who would be
responsible for non-compliance if the consulting entities did not “determine a mutually agreeable
action for the restoration of its Interpersonal Communication capability.”
Individual
Chris Mattson
Tacoma Power
Yes
Yes
This seems excessive. It should be sufficient to say “each adjacient TOP” regardless of whether they
are connected synchronously or via a DC tie.
Yes
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R9 – The Standard requires that when there is a failure to a primary or alternate communication
system that action is initiated within 2 hours of the communication failure. It is not clear what the
term “action” means. Tacoma requests clarification for what “actions” are intended by the standard.
R10 – Interpersonal Communication is defined as “any medium that allows two or more individuals to
interact, consult, or exchange information”. As it is written, R10 requires an entity to contact another
entity “within 60 minutes of the detection of a failure of its Interpersonal Communication capability
that lasts 30 minutes or longer”. This contact may not be possible in a situation where there is “a
failure of Interpersonal Communication capability”. R11 - The lack of a time line in R11 seems
inconsistent with the time line requirements in R9 and R10. If there is a communication failure
affecting the GO and DP then the standard only requires that they agree on an action to restore
communication but does not assign a timeline.
Group
Colorado Springs Utilities
Jennifer Eckels
No
Adjacent is still an ambiguous term. Does the SDT mean to refer to entities which share an
interface/tie-line; entities which have geographically abutting service territories or Areas; entities
within the same geographical region but not necessarily “touching”; etc.? Is this the same as or
different from “neighboring,” and what is the meaning of that term? Perhaps this term deserves a
glossary entry.
No
See previous comment on “adjacent”.
No
See the comment on "evidence" included in the comment section of question 4.
CSU appreciates the work the SDT has put into this standard, along with the others in this project and
the opportunity to comment. We agree with the goal to encourage consistent communications and
availability of robust & redundant communication paths. CSU appreciates that the SDT appears to
have tried to write some flexibility into this standard. As written, however, this draft of COM-001-2 in
its entirety seems to us unwieldy and unmanageable. It appears each entity may choose its own
‘primary’ and Alternate “Interpersonal Communication” capabilities. Entity A may select email as its
‘primary’ capability, while Entity B might not select that among either ‘primary’ or “Alternate,” and
may not pay any attention on the real-time desk to email (only the designated “Alternate” requires
testing). Also, DOs & GOs are not expected to maintain a backup (“Alternate”) communications
capability. It is unclear how those entities can then comply with R11 if their one and only
interpersonal communication capability has failed. Sufficient evidence includes “physical assets.” Does
that mean we can point to the phone on the desk and the email program on the desktop PC and we’re
compliant? Are photographs of physical assets sufficient evidence to submit for the pre-audit
questionnaire? There is no requirement for the communications capabilities to be either diverse or
redundant. If both our capabilities, in the end, rely on the POTS/PSTN system, is that acceptable?
Individual
Patrick Brown
Essential Power, LLC
It is unclear what we are trying to accomplish in R11. If the intent is to coordinate the restoration of
communications, then there should be an additional requirement that the GOP have a
Communications Recovery Plan, and R11 should focus on the coordination and implementation of that
Plan. If the intent is to maintain continuous communications, then there should be an additional
requirement for the GOP to maintain an Alternative Interpersonal Communications capability, and R11
should focus on the coordination and implementation of that capability.
Individual
Maggy Powell
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Exelon Corporation and its affiliates
The definition of Interpersonal Communication requires further clarification. The use of the term “Any
medium” opens the definition up to broad interpretation. It’s not clear whether the definition means
to apply to the point of communication owned, managed, and operated by the entity, or the total
communications pathway? For example if entity A’s phone system is working fine, but Entity B is
experiencing trouble, does Entity A have a compliance concern if Entity B experiences a
communication breakdown on their end of the medium? Please provide greater insight on the
intended compliance obligation and consider the following revision to the definition: Interpersonal
Communication: Any medium, owned, managed, or operated by the applicable entity, that allows two
or more individuals to interact, consult, or exchange information. R9 provides ambiguous instruction
for the resolution process surrounding tests and failures of Alternative Interpersonal Communication
capability. Please confirm whether the intent of the requirement is to initiate repairs within two hours,
or to effect repairs within two hours, with the alternate option being to designate a replacement
Alternative Interpersonal Communication if repairs cannot be completed within two hours. R10 has
similar ambiguity, referencing a 60 minute notification timeframe requirement upon the detection of a
failure lasting 30 minutes or longer. Please confirm the intended start of the requirement notification.
Does the clock for notification begins at the point of failure, at the point of discovery, or at the point
that the failure is discovered to have been effective for 30 minutes or greater? Thank you for the
opportunity to comment.
Individual
Jay Campbell
NV Energy
No
If "Adjacent", a capitalized word, must be in the Definitions section merely because it's capitalized,
what about "Each"? Other sentances have capitalized words, such as "If", "Its" and "All". If "Adjacent"
is in the Definitions merely because it's capitalized, please also add "If", "Its" and "All".
No
What difference does a synchronous or asynchronous connection make? Do not both have a reliability
impact on the two entities on either side? Since there is a reliability impact, regardless of connection
type, a separate Requirement is superfluous.
Yes
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes
Yes
Oncor takes the position that the premise of R3 does not provide a reliability enhancement but may in
effect; increase the risk to reliability by placing notification requirements on the Transmission
Operator that could best be managed by the Reliability Coordinator. In fact, Oncor takes the position
that as a Transmission Operator, it is being placed into the position of having to continually validate
the registration status of every entity that may be registered as a Distribution Provider, Transmission
Operator, and Generator Operator within its Transmission Operator Area. Oncor takes the position
that since each of these entities are in the applicability section of the standard, the Distribution
Provider, Transmission Operator, and Generator Operator should be responsible for seeking
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Interpersonal Communication capability with the Transmission Operator and the Transmission
Operator should then reciprocate Interpersonal Communication capability in response to their initial
request. This eliminates an unnecessary compliance obligation of the Transmission Operator to
manage "who is" and "who is not" registered as a Generator Operator, Distribution Provider or
Transmission Operator. Oncor recommends the following change to the standard language Remove
3.3 & 3.4 because R7 and R8 already cover the GO and DP seeking Interpersonal Communication
capability with the Transmission Operator. Oncor also takes the position that the Reliability
Coordinator (RC) is in the best position and not the Transmission Operator to make extensive
notifications on a broad basis in the event of a failure of its Interpersonal Communication. In
accordance with that position, the Transmission Operator should make a single notification to the RC,
and the RC would then make the notification to all impacted entities in the event of the failure of the
Transmission Operator’s Interpersonal Communication. Oncor proposes the following language for
R10 “R10. Each Transmission Operator shall notify the Reliability Coordinator and the Balancing
Authority within 60 minutes of the detection of a failure of its Interpersonal Communication capability
that lasts 30 minutes or longer. After notification by any Transmission Operator, the Reliability
Coordinator shall immediately notify entities as identified in Requirements R1, R3, and R5 of any
Transmission Operator's detection of a failure of its Interpersonal Communication capability that lasts
30 minutes or longer Each Reliability Coordinator and Balancing Authority shall notify entities as
identified in Requirements R1, R3, and R5 within 60 minutes of the detection of a failure of its own
Interpersonal Communication capability that lasts 30 minutes or longer."
Individual
Greg Travis
Idaho Power Company
Yes
Yes
Yes
Individual
Marie Knox
MISO
No
While MISO disagrees with the modifications to COM-001-1 proposed in COM-001-2 generally, it does
not disagree with the clarity provided in the proposed addition of “Each” in front of “Adjacent”.
No
While MISO disagrees with the modifications to COM-001-1 proposed in COM-001-2 generally, it does
not disagree with the proposed removal of “within the same interconnection” .
No
While MISO appreciates the SDT’s modifications to Measure M10 since the last draft, the Measure
remains ambiguous as to which parties should be contacted when an entity experiences a failure of its
Interpersonal Communication capability that lasts 30 minutes or longer. MISO respectfully submits
the following changes for Measure 10: “Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have and provide upon request evidence that it notified the entities as
identified in Requirements R1, R3, and R5, as applicable, within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer. Evidence could
include, but is not limited to dated and time-stamped: test records, operator logs, voice recordings,
transcripts of voice recordings, or electronic communications. (R10.)”
MISO respectfully submits that the subject matter of COM-001-1 is better addressed through an
official NERC certification – that is, by having NERC certify that a registered entity has the appropriate
communications facilities – than through a formal Reliability Standard. Furthermore, the Reliability
Standards surroiunding communications should be performance based and specifically targeted
toward testing, maintenance, and implementation of corrective actions when an issue arises or is
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otherwise detected. As a result of narrowing the focus of these standards, enforcement would then be
tailored toward a Registered Entity’s failure to take such actions when necessary, a direct benefit and
correlation to enhancement of the reliability of the BES. Under the currently proposed approach, the
lack of a communication medium or a finding that a communication medium is “inadequate” or does
not otherwise qualify under the standard would result in a non-compliance. Finally, MISO respectfully
submits that: • Distribution Providers (DPs) and Generator Operators (GOPs) should have alternate
communication media as well. • If an alternate communication tool is tested once a month, there is
no need to address deficiencies within two hours; six hours is sufficient in such instances. • The
standard should acknowledge that if more than two independent communication mechanisms are
available, the VRF/VSL associated with missing a timing requirement is minimal.The SDT should
require reporting times of failed mediums for GOP and DP similar to that for RC/BA/TOP.
Individual
Scott Berry
Indiana Municipal Power Agency
IMPA does not like the wording in R11 that states "mutually agreeable action for the restoration of its
Interpersonal Communication capability." IMPA sees that entities will have to prove that the action
taken by entities was "mutually agreeable" to the parties involved wich will be very problematic. IMP
believes as long as the entities who owns the equipment is taking steps to get it back into service that
is all that should be required by any requirement of this standard.
Group
ACES Power Marketing Standards Collaborators
Jason Marshall
Yes
Yes
No
We continue to believe that use of “physical asets” instead of “demonstration of physical assets” is
problematic. Auditors must be able to take evidence with them and they could not take the physical
assets. They could, however, takes notes they record from demonstration of the physical assets with
them. While we understand that the auditors will understand they can’t take the “physical assets”, it
does not change the fact that the listing “physical assets” as evidence is technically not correct.
(1) The definition of Alternative Interpersonal Communication needs further refinement. As it is
written, the primary Interpersonal Communication that is used to satisfy R1, R3, and R5 is also an
Alternative Intepersonal Communication. This primary Interpersonal Communication established in
R1, R3, and R5 meet all of the requirements of Alternative Interpersonal Communication. It is a
Interpersonal Communication and it is capable of replacing the Interpersonal Communication used as
the Alternative Interpersonal Communication (which by definition is an Interpersonal Communication)
in R2, R4, and R6. Thus, each Interpersonal Communication used in R1, R3, and R5 really are an
Interpersonal Communication and Alternative Interpersonal Communication. One solution may be to
add a third definition: Primary Interpersonal Communication. It would essentially be an Interpersonal
Communication that is designated as primary or the normal communication system. Then Alternative
Interpersonal Communication would be defined based on the ability of the Interpersonal
Communication to substitute for the Primary. R1, R3, and R5 would need to be changed to refer to
the Primary Interpersonal Communication. Another option might be to simply stick with the two
existing definitions and use “primary” in R1, R3, and R5. Regardless of the option selected, “another”
needs to be added before the second use of Interpersonal Communication for absolute clarity. (2) We
appreciate that the drafting team added another VSL for requirements R1 through R8, however, we
believe additional levels should be populated. For example, if a Transmission Operator or Balancing
Authority failed to have Interpersonal Communications capability with a Distribution Provider but had
Interpersonal Communications capability with all other required entities, it has met the vast majority
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
of the requirement. Since VSLs are a measure of how much the requirement was missed by the
responsible entity, a Lower VSL seems most appropriate for failing to have Interpersonal
Communication capability with a DP. (3) It seems odd to change the effective date language from
what NERC has consistently used throughout the standards. “Following” was replaced with “beyond
the date this standard is approved”. For consistency with the rest of NERC standards, we recommend
changing it back to the original language. (4) We appreciate the changes to R1, R3, R5, R7 and R8
that attempt to clarify that a failure of the primary Interpersonal Communication capability is not a
violation of these requirements. However, we believe these requirements will never be approved by
the Commission. As they are written, they literally say that R1, R3, R5, R7, and R8 apply when the
responsible entity has Interpersonal Communication capability and they don’t apply when you don’t
have the capability but rather other requirements apply. This means R1, R3, R5, R7 and R8 could
never be violated which begs the question why are they even needed. Because Commission approval
is unlikely for these requirements, we continue to believe the best solution is to focus the
requirements on having a communication medium rather than capability. If “capability” were struck
from all of the requirements, the requirements would then focus on a communication medium as
defined in Interpersonal Communication and Alternative Interpersonal Communication. This solution
would still keep the requirements technology neutral since a medium could be any communication
system or device and actually provide more flexibility in the requirements. Because the requirements
would focus on having a medium in place rather than a capability, failure of the medium would not
automatically translate into a violation which means the problematic “unless [responsible entity]
experiences a failure of its Interpersonal Communication capability …” language could be dropped.
Dropping this language would improve the likelihood that the Commission would approve the
standard. (5) The VRF for R7 should be Medium. Failure for the DP to have Intepersonal
Communication with its BA or TOP does not meet the basic requirement of a High VRF. A High VRF
requires that violation of the requirement would “directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system at
an unacceptable risk of instability, separation, or cascading failures.” We cannot fathom any situation
where failure of a BA and TOP being able to communicate would directly lead to or cause instability,
separation, or cascading. It could, however, lead to the inability to know the electrical state of part of
the transmission system. This fits the Medium VRF definition. Furthermore, the fact that R4 and R6 do
not include DP in the list of functional entities for a TOP and BA to have Alternative Interpersonal
Communication further supports a Medium VRF. (6) In Measure M11, we believe entity affected
should be replaced with its TOP and BA. This makes the measure clearer and easier to read without
the need to refer back to the requirement. (7) We disagree with the data retention period. Because
voice recordings are mentioned in the measures as one type of evidence for demonstrating
compliance to the requirements, the data retention period should not exceed 90 days. Many
companies do not store voice recordings longer than this. To compel a responsible entity to store
voice recordings for longer should be justified. We do not see this justification. (8) We continue to
believe that the DP should not be included in this standard. However, we recognize that the drafting
team is attempting to address a FERC directive. An equally efficient and effective alternative would be
to leave the responsibility to the BA and TOP. Parts 3.3 and 5.3 require the TOP and BA respectively
to have Interpersonal Communication capability with the DP. This will be required whether the
standard applies to DP or not based on the Commission directive because the Commission expressed
concern about the BA and TOP having communications with the DP during an emergency such as a
blackstart event. Because DPs will have to follow directives from the RC, TOP, and BA per IRO-001-3,
it is in the best interest of the DP to cooperate with assisting the BA and TOP in establishing this
capability. Thus, Parts 3.3 and 5.3 could be relied on exclusively for establishing this Interpersonal
Communication Capability without adding unnecessary additional compliance burden on the DP that
does not support reliability.
Individual
Kathleen Goodman
ISO New England Inc
No
The ISO-NE continues to believe that these a certification types of requirements and that they do not
belong in a standard.
No
The ISO-NE continues to believe that these a certification types of requirements and that they do not
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
belong in a standard.
The ISO-NE continues to believe that these a certification types of requirements and that they do not
belong in a standard. ISO-NE believes that the requirement to have a medium to communicate should
be required to be certified. When you are operating as a registered entity, the requirements should be
performance based such as taking corrective actions and if you fail to communicate for any reason
you will be found non-compliance. The lack of a communication medium should not be a defense for
non compliance of the performance based standards. The SDT should require reporting times of failed
mediums for GOP and DP similar to that for RC/BA/TOP.
Group
ISO/RTO Standards Review Committee
Gregory Campoli
The IRC continues to believe that these a certification types of requirements and that they do not
belong in a standard. The SRC believes that the requirement to have a medium to communicate
should be required to be certified. When you are operating as a registered entity, the requirements
should be performance based such as taking corrective actions and if you fail to communicate for any
reason you will be found non-compliance. The lack of a communication medium should not be a
defense for non compliance of the performance based standards. The SDT should require reporting
times of failed mediums for GOP and DP similar to that for RC/BA/TOP.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments
Project 2006-06 Reliability Coordination
The Reliability Coordination Standard Drafting Team (RCSDT) thanks all commenters who submitted
comments on the successive posting of the COM-01-2 reliability standard for Project 2006-06—
Reliability Coordination. These standards were posted for a 30-day public comment period from June
7, 2012 through July 6, 2012. Stakeholders were asked to provide feedback on the standards and
associated documents through a special electronic comment form. There were 41 sets of comments,
including comments from approximately 136 different people from approximately 90 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Summary Consideration
The RCSDT received comments from stakeholders, where a majority of those comments were focused
on compliance elements of the standards, various typographical errors, and other minor ambiguities.
The RCSDT believes it has been responsive to the many comments and has either provided adequate
explanation, where applicable, as well as incorporating the suggested clarifications or corrections.
There was one minority issue raised by several commenters which the RCSDT addressed, but did not
make a revision to the standard. These commenters suggested adding a time threshold to
Requirement R11 that would trigger the Distribution Provider and Generation Operator to consult with
its Balancing Authority and Transmission Operator after losing its Interpersonal Communication
capability for a defined period. The RCSDT believed this would be unnecessarily prescriptive and notes
that each entity along with its affected neighbors, should, by procedures, identify what constitutes the
detection of a failure of its capability and the acceptable time threshold for restoration. Revisions
made to the standards are summarized in the following sections by standard.
COM-001-2
In the last posting and successive ballot, the standard received approval from 72.16% of the ballot body
and fewer overall comments from previous postings. The RCSDT made minor, non-substantive changes
to the standard based on these comments. The RCSDT believes it has addressed stakeholder
comments and concerns in such a way that the standard is improved and meets the expectations
expressed in comments for reliability and industry approval. Now that the standard has achieved
industry consensus, this standard will advance to a recirculation ballot.
Purpose: No change.
Effective Date: No change.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
R equirem ents: Changes were minor. The RCSDT for Requirements R1, R3, R5, R7, R8, and R11
changed the term “experiences” in the phrase “experiences a failure” to “detects.” This more
appropriately aligns with the performance expectation that an entity must detect a failure first which
would start the threshold for performance. The change maintains the intent while adding clarity and
measurability.
The RCSDT also notes a minor change in Requirement R5, Part 5.5 and Requirement R6, Part 6.3
concerning “adjacent.” The team, during the revisions of draft 6, inadvertently changed “Adjacent” to
a lower case when making revisions to the two parts that began with capitalized term. Commenters
regarding draft 5 were concerned that the capitalized term would imply a NERC Glossary term, such as,
“Adjacent Reliability Coordinator,” and cause confusion since there was no such term. The RCSDT
recognizes that the glossary term should have remained, in the case of Parts 5.5 and 6.3, “Adjacent
Balancing Authority.”
One commenter argued that the Violation Risk Factor (VRF) for Requirement R7 should be Medium, not
High. The RCSDT considered this argument and concluded the change had merit based on the risk a
Distribution Provider has in the scope of communications. Furthermore, the RCSDT also considered the
VRF with regard to the Generator Operator in Requirement R8, but concluded the VRF should remain
High because the Generator Operator may have a role as a blackstart resource in a Reliability
Coordinator’s restoration plan.
Other commenters raised a concern that the relationship in Requirement R10 between the functions
and the requirements listed were not clear. The suggested solution was to use the phrase, “as
applicable”; however, the RCSDT opted to use the term “respectively” to more appropriately make the
distinction between the functions and the listed requirements (i.e., the Reliability Coordinator (R1),
Transmission Operator (R3), and Balancing Authority (R5)). This change was also applied to Measure
M11.
M easures: One commenter recognized an error in Measure M3. The conjunction between
asynchronously and synchronously should have been “or,” not “and” to accurately reflect the situation
in Requirement R3, Parts 3.5 and 3.6. The extra word “that” was removed from Measure M7, as it was
a typographical error. Measure M10 was updated to include the word “respectively” to coincide with
the revision to Requirement R10. The Measure M11 was revised to reflect the changes in Requirement
R11 to change the word “experiences” to “detects.” Last, the colon in Measures M9, M10, and M11
was moved to the appropriate location in each sentence.
Com pliance, Com pliance Enforcem ent Authority: No change.
Consideration of Comments: Project 2006-06 (Draft 6)
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Com pliance, Data Retention: A commenter raised the question about the Measures allowing voice
recordings, but requiring an entity to maintain this evidence for 12 calendar months. Standard drafting
guidelines recommend that voice recordings be retained for 90 calendar days. The RCSDT agreed that
90 calendar days is the recommended practice and modified each of the data retention bulleted items
to reflect the specific case of voice recordings.
Violation Severity Levels: Several of the Violation Severity Levels (VSL) required updating to
account for the term changes in the requirements and the correction of certain typographical errors.
For the word change from “experiences” to “detects,” the following VSLs were revised; R1, R3, R5, R7,
R8, and R11. The Requirement R3 VSL had the “Reliability Coordinator” listed where it should have
been the “Transmission Operator.” Likewise, the same error appeared in the Requirement R5 VSL
where “Reliability Coordinator” should have been “Balancing Authority.” A commenter discovered a
minor conjunction error in the Requirement R9 VSL in the listing of functional entities. The conjunction
was changed from “and” to “or” to accurately reflect the construction of the VSLs. The same issue was
revealed in the Requirement R10 VSL and was corrected, as well as removing the additional “identified”
that was not needed.
Additional Information
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
Consideration of Comments: Project 2006-06 (Draft 6)
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Index to Questions, Comments, and Responses
1.
The RCSDT has revised the parts of Requirements R1, R2, R3, R4, R5, and R6 of COM-001-2 that
began only with “Adjacent…” to begin with “Each adjacent…” to avoid the appearance of creating
a defined glossary phrase. Do you agree with the changes? If not, please explain in the comment
area below. …..............................................................................................................15
2.
The RCSDT has revised parts of two requirements (Parts 3.5 and 4.3) in COM-001-2 and added two
additional parts (Parts 3.6 and 3.4) to address concerns about the phrase “synchronously
connected within the same Interconnection.” Do you agree these changes address concerns
where entities might only be adjacent across an Interconnection for where connected by a Direct
Current (DC) tie? If not, please explain in the comment area below. …...................................20
3.
The RCSDT made minor changes and reformatted the evidence examples in the Measures of COM001-2 for greater clarity. Do you agree with these revisions? If not, please explain in the comment
area below. …. ............................................................................................................26
4.
Do you have any other comments on COM-001-2, not expressed in questions above, for the
RCSDT? …. ..................................................................................................................30
Consideration of Comments: Project 2006-06 (Draft 6)
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Sam Ciccone
FirstEnergy
X
2
3
X
4
X
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. L. Raczkowski
FE
RFC
2. D. Hohbaugh
FE
RFC
Consideration of Comments: Project 2006-06 (Draft 6)
5
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2.
Group
Additional Member
Gerald Beckerle
Additional Organization
SERC OC Standards Review Group
X
2
3
4
5
6
7
8
9
10
X
Region Segment Selection
1.
Joe Riels
SMEPA
SERC
1, 3, 4, 5
2.
Jake Miller
Dynegy
SERC
5
3.
Stuart Goza
TVA
SERC
1, 3, 5, 6
4.
Jim Case
Entergy
SERC
1, 3, 6
5.
Larry Rodriquez
Entegra
SERC
6
6.
Tim Hattaway
PowerSouth
SERC
1, 5
7.
William Berry
OMU
SERC
3, 5
8.
Raleigh Nobles
GA. System Operations
SERC
3
9.
Tom Hanzlik
SCE&G
SERC
1, 3, 5, 6
10. Bill Thigpen
PowerSouth
SERC
1, 5
11. Marie Knox
MISO
SERC
2
12. J.T. Wood
Southern
SERC
1, 5
13. Joel Wise
TVA
SERC
5, 6, 1, 3
14. Wayne Van Liere
LGE-KU
SERC
3
15. Mike Hardy
Southern
SERC
1, 5
Consideration of Comments: Project 2006-06 (Draft 6)
6
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
16. Andy Burch
Electric Energy, Inc.
SERC
5
17. Scott Brame
NCEMC
SERC
1, 3, 4, 5
18. John Troha
SERC Reliability Corporation SERC
3.
Group
Chris Higgins
2
3
4
5
6
7
8
9
10
10
Bonneville Power Administration
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Huy
Ngo
WECC 1
2.
Chris
Sanford
WECC 1
3.
Paul
Blake
WECC 1
4.
Group
Brenda Hampton
Luminant
Additional Member Additional Organization
1.
5.
Mike Laney
Group
Region
X
Segment
Selection
Luminant Generation Company LLC ERCOT
Steve Rueckert
5
Western Electricity Coordinating Council
X
No additional members listed.
6.
Group
Connie Lowe
Dominion
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Mike Garton
MRO
5, 6
Consideration of Comments: Project 2006-06 (Draft 6)
7
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Louis Slade
RFC
3. Randi Heise
NPCC 5, 6
4. Michael Crowley
SERC
7.
Group
Kent Kujala
2
3
4
5
6
7
8
9
10
5, 6
1, 3, 5, 6
Detroit Edison
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Jeffrey DePriest
RFC
3, 4, 5
2. Alexander Eizans
RFC
3, 4, 5
3. Barbara Holland
NPCC
8.
Group
Additional Member
Robert Rhodes
SPP Standards Review Group
Additional Organization
Region Segment Selection
1. Michelle Corley
Cleco Power
SPP
1, 3, 5
2. Bo Jones
Westar Energy
SPP
1, 3, 5, 6
3. Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
4. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
5. Julie Lux
Westar Energy
SPP
1, 3, 5, 6
6. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
7. Sean Simpson
Board of Public Utilities of Kansas City, KS SPP
Consideration of Comments: Project 2006-06 (Draft 6)
X
NA
8
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8. Bryan Taggart
9.
Group
Westar Energy
WILL SMITH
SPP
2
3
4
5
6
7
8
9
10
1, 3, 5, 6
MRO NSRF
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
OPPD
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
3.
TOM WEBB
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
ALICE IRELAND
XCEL
MRO
1, 3, 5, 6
7.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
8.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
9.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
10. SCOTT NICKELS
RPU
MRO
4
11. TERRY HARBOUR
MEC
MRO
5, 6, 1, 3
12. MARIE KNOX
MISO
MRO
2
13. LEE KITTELSON
OTP
MRO
1, 3, 5, 6
14. SCOTT BOS
MPW
MRO
1, 3, 5, 6
Consideration of Comments: Project 2006-06 (Draft 6)
9
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
15. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
16. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
17. DAN INMAN
MPC
MRO
1, 3, 5, 6
10.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
9.
Michael Jones
National Grid
NPCC 1
Hydro One Networks Inc.
NPCC 1
11. Michael R. Lombardi Northeast Utilities
NPCC 1
12. Randy MacDonald
NPCC 9
New Brunswick Power Transmission
Consideration of Comments: Project 2006-06 (Draft 6)
3
4
5
6
7
8
9
10
X
Region Segment Selection
1.
10. David Kiguel
2
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13. Bruce Metruck
New York Power Authority
NPCC 5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Brian Robinson
Utility Services
NPCC 8
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
Group
Jennifer Eckels
3
4
5
6
7
8
9
10
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
11.
2
Colorado Springs Utilities
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Paul Morland
WECC 1
2. Charles Morgan
WECC 3
3. Lisa Rosintoski
WECC 6
12.
Group
Jason Marshall
ACES Power Marketing Standards
Consideration of Comments: Project 2006-06 (Draft 6)
X
11
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Collaborators
Additional Member
Additional Organization
Region Segment Selection
1. Bill Hutchison
Southern Illinois Power Cooperative
SERC
1
2. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
3. Mark Ringhausen
Old Dominion Electric Cooperative
RFC
3, 4
4. Shari Heino
Brazos Electric Power Cooperative, Inc. ERCOT 1, 5
13.
Group
Gregory Campoli
ISO/RTO Standards Review Committee
X
Additional Member Additional Organization Region Segment Selection
1. Stephanie Monzon
PJM
RFC
2
2. Ben Li
IESO
NPCC
2
3. Matt Goldberg
ISO-NE
NPCC
2
4. Gary DeShazo
CAISO
WECC 2
5. Steve Myers
ERCOT
ERCOT 2
6. Ken Gardner
AESO
WECC 2
7. Bill Phillips
MISO
RFC
2
8. Don Weaver
NBSO
NPCC
2
9. Charles Yeung
SPP
SPP
2
Consideration of Comments: Project 2006-06 (Draft 6)
12
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
X
X
X
X
15.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
16.
Individual
Brent.Ingebrigtson
LG&E and KU Services
X
X
X
X
17.
Individual
Alice Ireland
Xcel Energy
X
X
X
X
18.
Individual
Thad Ness
American Electric Power
X
X
X
X
19.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
20.
Individual
David Thorne
Pepco Holdings Inc
X
X
21.
Individual
Karen Webb
City of Tallahassee (TAL)
22.
Individual
Andrew Gallo
City of Austin dba Austin Energy
X
X
23.
Individual
Kasia Mihalchuk
Manitoba Hydro
X
X
Individual
Steve Alexanderson
P.E.
Central Lincoln
Individual
Michelle D'Antuono
Ingleside Cogeneration LP (Occidental
Chemical in the ballot body)
26.
Individual
Laura Lee
Duke Energy
27.
Individual
Don Jones
Texas Reliability Entity
14.
24.
25.
8
9
10
X
X
Consideration of Comments: Project 2006-06 (Draft 6)
7
X
X
X
X
X
X
X
X
X
X
X
X
X
13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
28.
Individual
John Brockhan
CenterPoint Energy Houston Electric, LLC
29.
Individual
Michael Falvo
Independent Electricity System Operator
Individual
Steve Alexanderson
P.E.
Central Lincoln
31.
Individual
Andrew Z. Pusztai
American Transmission Company
32.
Individual
Daniel Duff
Liberty Electric Power
33.
Individual
Chris Mattson
Tacoma Power
34.
Individual
Patrick Brown
Essential Power, LLC
35.
Individual
Maggy Powell
Exelon Corporation and its affiliates
X
X
36.
Individual
Jay Campbell
NV Energy
X
X
37.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
X
38.
Individual
Greg Travis
Idaho Power Company
X
39.
Individual
Marie Knox
MISO
40.
Individual
Scott Berry
Indiana Municipal Power Agency
41.
Individual
Kathleen Goodman
ISO New England Inc
30.
5
6
7
8
9
10
X
X
X
Consideration of Comments: Project 2006-06 (Draft 6)
4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
14
1.
The RCSDT has revised the parts of Requirements R1, R2, R3, R4, R5, and R6 of COM-001-2 that began only with “Adjacent…”
to begin with “Each adjacent…” to avoid the appearance of creating a defined glossary phrase. Do you agree with the
changes? If not, please explain in the comment area below.
Summary Consideration: Twenty-seven stakeholders completing the comment form support the changes by the RCSDT. Of those,
there were two commenters not in support of the RCSDT’s change to the sentence structure from “Adjacent…” to “Each adjacent…”
This change was made to eliminate the ambiguity that a glossary term was intended by the drafting team and to achieve greater
clarity. Another comment concerned the meaning of “adjacent” in terms of geography. The RCSDT notes that due to asynchronous
connection (DC tie), some entities may not be geographically adjacent, but electrically adjacent; therefore, adjacency for
synchronously connected entities is applied in the typical manner for entities which are, as a rule, geographically adjacent.
Additionally, one commenter questioned the revision in Draft 6, Requirement R5, Part 5.5 and Requirement R6, Part 6.3, when the
RCSDT applied “Each” before “adjacent,” and by doing so inadvertently changed the glossary term “Adjacent Balancing Authority” to
just “adjacent Balancing Authority” which is not a glossary term. The RCSDT notes that the spirit of the phrase “adjacent Balancing
Authority” remains accurate and that this was a clerical error.
A single entity argued the requirements should be certification requirements, and not in a standard. The RCSDT directs the
commenter to Section 500 of the NERC Rules of Procedure which address certification. The certification process is a program to
identify entities that are applicable to and responsible for the reliability standards.
Organization
Colorado Springs Utilities
Yes or No
No
Question 1 Comment
Adjacent is still an ambiguous term. Does the SDT mean to refer to entities
which share an interface/tie-line; entities which have geographically
abutting service territories or Areas; entities within the same geographical
region but not necessarily “touching”; etc.? Is this the same as or different
from “neighboring,” and what is the meaning of that term? Perhaps this
term deserves a glossary entry.
Response: The RCSDT believes this standard is not about geographical neighbors, it is about the effect of being electrical
neighbors. No change made.
NV Energy
No
Consideration of Comments: Project 2006-06 (Draft 6)
If "Adjacent", a capitalized word, must be in the Definitions section merely
15
Organization
Yes or No
Question 1 Comment
because it's capitalized, what about "Each"? Other sentences have
capitalized words, such as "If", "Its" and "All". If "Adjacent" is in the
Definitions merely because it's capitalized, please also add "If", "Its" and
"All".
Response: The RCSDT modified the usage of “Adjacent” in draft 5 of COM-001-2 to eliminate the appearance of a defined term to
achieve clarity within the requirements because it started the sentence. No change made.
MISO
No
While MISO disagrees with the modifications to COM-001-1 proposed in
COM-001-2 generally, it does not disagree with the clarity provided in the
proposed addition of “Each” in front of “Adjacent”.
Response: The RCSDT thanks you for your support of the modification to “Adjacent.” No change made.
ISO New England Inc
No
The ISO-NE continues to believe that these a certification types of
requirements and that they do not belong in a standard.
Response: NERC maintains an Organization Certification Program, the goal of which is to ensure that organizations who apply to
register or are registered to perform certain reliability functions deemed particularly crucial to the reliability of the bulk power
system will meet or exceed certain minimum criteria (i.e., Reliability Standards) demonstrating they are capable of performing the
tasks (i.e., Requirements) for these functions. The process for certification of organizations is included in the NERC Rules of
Procedure, Section 500 and Appendix 5A. For example, the first paragraph of Section 500 – Organization Registration and
Certification states: “The purpose of the Organization Registration Program is to clearly identify those entities that are responsible
for compliance with the FERC approved reliability standards. Organizations that are registered are included on the NERC
Compliance Registry (NCR) and are responsible for knowing the content of and for complying with all applicable reliability
standards…” No change made.
PacifiCorp
No
Ingleside Cogeneration LP
(Occidental Chemical in the ballot
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
Ingleside Cogeneration LP agrees that the modification removes all doubt
that a glossary definition is inferred. We support all clarifications of this
16
Organization
Yes or No
body)
Question 1 Comment
kind.
Response: The RCSDT thanks you for your comment.
Texas Reliability Entity
Yes
“Adjacent Balancing Authority” is a defined term in the NERC Glossary, and
use of the non-defined term “adjacent Balancing Authority” in this draft will
cause confusion. Exactly what difference is intended by using the lowercase “a” instead of the defined term?
Response: The RCSDT agrees “adjacent Balancing Authority” should be “Adjacent Balancing Authority,” the defined NERC Glossary
term. This change was made during the draft 6 process and a typo was made during editing of the other usages of “adjacent.”
Error correction made.
Independent Electricity System
Operator
Yes
Notwithstanding our opposition to R1.2.
Response: Thank you for your support. No change made.
FirstEnergy
Yes
SERC OC Standards Review Group
Yes
Luminant
Yes
Western Electricity Coordinating
Council
Yes
Dominion
Yes
SPP Standards Review Group
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
17
Organization
Yes or No
MRO NSRF
Yes
Northeast Power Coordinating
Council
Yes
ACES Power Marketing Standards
Collaborators
Yes
Arizona Public Service Company
Yes
Xcel Energy
Yes
American Electric Power
Yes
Public Service Enterprise Group
Yes
Pepco Holdings Inc
Yes
City of Tallahassee (TAL)
Yes
City of Austin dba Austin Energy
Yes
Manitoba Hydro
Yes
Duke Energy
Yes
CenterPoint Energy Houston Electric,
LLC
Yes
American Transmission Company
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
Question 1 Comment
18
Organization
Yes or No
Liberty Electric Power
Yes
Tacoma Power
Yes
Oncor Electric Delivery Company LLC
Yes
Idaho Power Company
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
Question 1 Comment
19
2.
The RCSDT has revised parts of two requirements (Parts 3.5 and 4.3) in COM-001-2 and added two additional parts (Parts 3.6
and 3.4) to address concerns about the phrase “synchronously connected within the same Interconnection.” Do you agree these
changes address concerns where entities might only be adjacent across an Interconnection for where connected by a Direct
Current (DC) tie? If not, please explain in the comment area below.
Summary Consideration: Thirty-one stakeholders completing the comment form support the changes by the RCSDT. Of those, seven
provided comments. Two comments suggested combining Requirements R3, Parts 3.5 and 3.6 and Requirement R4, Parts 4.3 and 4.4 to
have one part each that says “…synchronously or asynchronously connected.” The RCSDT believes this is a semantic change and having
each condition in each requirement separates the emphases and provides the desired clarity. One commenter raised the issue of
“adjacent” addressed in Question 1 above. A commenter expressed concern about the Reliability Coordinator not being required to
have an Interpersonal Communication capability across an interconnection. The RCSDT notes that some Reliability Coordinators
communicate with other Reliability Coordinators across interconnections; however, the requirement is to have the Interpersonal
Communication capability within the same interconnection. Two commenters questioned why the synchronous and asynchronous
conditions were in the requirements. The RCSDT added these to achieve a greater level of clarity that not all Transmission Operators
are geographically adjacent. For example, the RCSDT considered phrases like “electrically connected,” but that creates the problem that
all Transmission Operators are electrically connected. The use of adjacent and the synchronous and asynchronous conditions in each
part achieve the necessary clarity based on transmission operations.
A single entity argued the requirements should be certification requirements and not in a standard. The RCSDT directs the commenter
to Section 500 of the NERC Rules of Procedure which address certification. The certification process is a program to identify entities that
are applicable to and responsible for the reliability standards.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 2 Comment
No
If 3.5 and 4.3 were made to read: “Each connected adjacent Transmission Operator.”
Then 3.6 and 4.4 (not 3.4 as indicated in the question) would not be required.
If 3.6 and 4.4 are to be kept, then the wording of 3.6 and 4.4 should be made to read:
“Each adjacent Transmission Operator asynchronously connected through a DC tie.”
Systems cannot be asynchronously connected.
Response: The RCSDT thanks you for your comments. These are semantic changes and the current Requirement R3, Parts 3.5 and
3.6 and Requirement R4, Parts 4.3 and 4.4 provide the clarity requested by industry stakeholders represented by the ballot. No
Consideration of Comments: Project 2006-06 (Draft 6)
20
Organization
Yes or No
Question 2 Comment
change made.
Colorado Springs Utilities
No
See previous comment on “adjacent”.
Response: Please see the RCSDT’s response above in question 1. No change made.
PacifiCorp
No
PacifiCorp does not understand the RCSDT’s rationale for creating separate subrequirements for adjacent Transmission Operators that are synchronously and
asynchronously connected, in both R3.5/R3.6 and R4.3/R4.4. PacifiCorp recommends
the following singular sub-requirement for both R3 and R4: “Each adjacent
Transmission Operator (whether synchronously or asynchronously connected).”
Response: The RCSDT thanks you for your comments. These are semantic changes and the current Requirement R3, Parts 3.5 and
3.6 and Requirement R4, Parts 4.3 and 4.4 provide the clarity requested by industry stakeholders represented by the ballot. No
change made.
Texas Reliability Entity
No
The proposed revision to include Transmission Operators asynchronously connected
(Parts 3.5 and 4.4) is an appropriate revision to the Standard.
The Reliability Coordinator responsibilities for communications with a Reliability
Coordinator across an asynchronous connection do not appear to be addressed in
this revision. Did the RCSDT have a particular reason not to address the RC issue?
We believe each RC should have Interpersonal Communication capability with all
neighboring RCs regardless of Interconnection boundaries, the type of connection, or
whether a connection exists.
Response: The RCSDT thanks you for your support of the improvements to Requirements R3 part 3.5 and R4 part 4.4. The RCSDT
made additional clarifying changes from draft 5 to draft 6 in Requirements R3 and R4 to address the issue that some Transmission
Operators (not Reliability Coordinators) that may not be adjacent for situations other than synchronously connected within the same
Interconnection in the traditional understanding. For example, some entities have connections beyond the interconnection and some
connections are asynchronous. To address this concern, the RCSDT separated the requirements to identify “synchronously
Consideration of Comments: Project 2006-06 (Draft 6)
21
Organization
Yes or No
Question 2 Comment
connected” and “asynchronously connected,” and removed the “within the same Interconnection” to achieve this clarity. No change
made.
Requirements for the Reliability Coordinator are addressed in Requirements R1 and R2, which do not specify the synchronous or
asynchronous connection. Additionally, the parts 1.2 and 2.2 only require the Reliability Coordinator to have an Interpersonal
Communication and Alternative Interpersonal Communication capability with other Reliability Coordinators within the same
Interconnection. For example, the loss of a DC tie does not result in a negative reliability impact and is analogous to a load or
generator loss because flows would not redistribute. Each end of the DC tie must adjust generation to account for the loss of the DC
tie; therefore, no coordination is required between entities. The standard does not preclude the Reliability Coordinator from having
a capability with another Reliability Coordinator in another Interconnection. No change made.
NV Energy
No
What difference does a synchronous or asynchronous connection make? Do not both
have a reliability impact on the two entities on either side? Since there is a reliability
impact, regardless of connection type, a separate Requirement is superfluous.
Response: The RCSDT made additional clarifying changes from draft 5 to draft 6 in Requirements R3 and R4 to address the issue that
some Transmission Operators may not be adjacent for situations other than synchronously connected within the same
Interconnection in the traditional understanding. For example, some entities have connections beyond the interconnection and
some connections are asynchronous. To address this concern, the RCSDT separated the requirements to identify “synchronously
connected” and “asynchronously connected,” and removed the “within the same Interconnection” to achieve this clarity. For
example, the loss of a DC-Tie does not result in a negative reliability impact and is analogous to a load or generator loss because
flows would not redistribute. Each end of the DC-Tie must adjust generation to account for the loss of the DC-Tie; therefore, no
coordination is required between entities. No change made.
MISO
No
While MISO disagrees with the modifications to COM-001-1 proposed in COM-001-2
generally, it does not disagree with the proposed removal of “within the same
interconnection.”
Response: The RCSDT thanks you for your support in removing “…within the same Interconnection.” No change made.
ISO New England Inc
No
The ISO-NE continues to believe that these a certification types of requirements and
Consideration of Comments: Project 2006-06 (Draft 6)
22
Organization
Yes or No
Question 2 Comment
that they do not belong in a standard.
Response: NERC maintains an Organization Certification Program, the goal of which is to ensure that organizations who apply to
register or are registered to perform certain reliability functions deemed particularly crucial to the reliability of the bulk power
system will meet or exceed certain minimum criteria (i.e., Reliability Standards) demonstrating they are capable of performing the
tasks (i.e., Requirements) for these functions. The process for certification of organizations is included in the NERC Rules of
Procedure, Section 500 and Appendix 5A. For example, the first paragraph of Section 500 – Organization Registration and
Certification states: “The purpose of the Organization Registration Program is to clearly identify those entities that are responsible
for compliance with the FERC approved reliability standards. Organizations that are registered are included on the NERC Compliance
Registry (NCR) and are responsible for knowing the content of and for complying with all applicable reliability standards…” No
change made.
Tacoma Power
Yes
This seems excessive. It should be sufficient to say “each adjacent TOP” regardless of
whether they are connected synchronously or via a DC tie.
Response: The RCSDT thanks you for your comment. The clarifications for asynchronous and synchronous were based on industry
stakeholder comment. No change made.
FirstEnergy
Yes
SERC OC Standards Review
Group
Yes
Luminant
Yes
Western Electricity
Coordinating Council
Yes
Dominion
Yes
SPP Standards Review Group
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
23
Organization
Yes or No
MRO NSRF
Yes
ACES Power Marketing
Standards Collaborators
Yes
Arizona Public Service
Company
Yes
Xcel Energy
Yes
American Electric Power
Yes
Public Service Enterprise
Group
Yes
Pepco Holdings Inc
Yes
City of Tallahassee (TAL)
Yes
Manitoba Hydro
Yes
Ingleside Cogeneration LP
(Occidental Chemical in the
ballot body)
Yes
Duke Energy
Yes
CenterPoint Energy Houston
Electric, LLC
Yes
Independent Electricity
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
Question 2 Comment
24
Organization
Yes or No
Question 2 Comment
System Operator
American Transmission
Company
Yes
Liberty Electric Power
Yes
Oncor Electric Delivery
Company LLC
Yes
Idaho Power Company
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
25
3.
The RCSDT made minor changes and reformatted the evidence examples in the Measures of COM-001-2 for greater clarity. Do
you agree with these revisions? If not, please explain in the comment area below.
Summary Consideration: Twenty-eight stakeholders completing the comment form question support the changes by the RCSDT. Of
those, three offered substantive comments. One commenter noted that having “physical assets” listed as one type of evidence in the
Measures M1 through M8 is problematic. The RCSDT believes an entity may utilize any number of options to demonstrate compliance
with the requirements. One commenter had concerns about the use of an intermediary for Interpersonal Communication capability.
The RCSDT emphasizes that an entity may employ any number of approaches to achieve the requirements. Another commenter
suggested inserting “applicable” as a clarification in Measure M10 to more clearly state the relationship between the entities and the
associated requirements. In consideration of the suggestion, the RCSDT inserted the word “respectively,” rather than “applicable” to
more accurately note the relationship. Additionally, the RCSDT applied the same consideration to Requirement R10 to achieve the same
clarity. The RCSDT also removed a typographical error revealed by a commenter.
Organization
Colorado Springs Utilities
Yes or No
No
Question 3 Comment
See the comment on "evidence" included in the comment section of question 4.
Response: Please see the RCSDT’s response in question 4. No change made.
ACES Power Marketing
Standards Collaborators
No
We continue to believe that use of “physical assets” instead of “demonstration of physical
assets” is problematic. Auditors must be able to take evidence with them and they could not
take the physical assets. They could, however, takes notes they record from demonstration
of the physical assets with them. While we understand that the auditors will understand
they can’t take the “physical assets”, it does not change the fact that the listing “physical
assets” as evidence is technically not correct.
Response: The RCSDT believes that physical assets are demonstration of evidence for Interpersonal Communication capability. The responsible
entity may exercise other methods of evidence for the physical assets (e.g., photographs or other documentation). No change made.
Ingleside Cogeneration LP
(Occidental Chemical in the
No
Ingleside Cogeneration LP would like to see the project team include references to
intermediaries which act as a single point of contact between GOPs and BAs/TOPs. This is a
very common and necessary communications hierarchy - as it is just not possible for the
Consideration of Comments: Project 2006-06 (Draft 6)
26
Organization
Yes or No
ballot body)
Question 3 Comment
BA/TOP to otherwise coordinate the actions of multiple GOPs. We believe that it is
appropriate that GOP must retain evidence that Interpersonal Communication capability is
maintained up to the intermediary - but the BA or TOP must be responsible for the remainder
of the link. This accountability matches the most common contractual arrangements where
both the BA/TOP and the GOP have signed agreements with the intermediary.
Response: The RCSDT believes the standard provides the “what” to do, not the “how” to implement the standard. Having an intermediary for
communication is one approach in “how” the entity may implement the standard. No change made.
MISO
No
While MISO appreciates the SDT’s modifications to Measure M10 since the last draft, the
Measure remains ambiguous as to which parties should be contacted when an entity
experiences a failure of its Interpersonal Communication capability that lasts 30 minutes or
longer.
MISO respectfully submits the following changes for Measure 10:
”Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have and
provide upon request evidence that it notified the entities as identified in Requirements R1,
R3, and R5, as applicable, within 60 minutes of the detection of a failure of its Interpersonal
Communication capability that lasted 30 minutes or longer. Evidence could include, but is not
limited to dated and time-stamped: test records, operator logs, voice recordings, transcripts
of voice recordings, or electronic communications. (R10.)”
Response: The RCSDT agrees with the ambiguity in Measure M10 and proposes to clarify Requirement R10, Measure M10, and R10 VSL by
inserting the word “respectively,” rather than the suggested “as applicable.” The word “respectively” is used rather than “applicable” because
“applicable” is open to interpretation. For example, adding the word “respectively” means that the Reliability Coordinator in R1 is not required
to notify the entities identified in Requirement R3 or R5. The RCSDT intended the requirements to map to the entity. Clarifying changes made.
City of Tallahassee (TAL)
Yes
For Measure 7, the first line duplicates the word "that".
Response: The RCSDT appreciates you bringing awareness to this typo. The additional “that” has been removed from Measure M7 in COM-001Consideration of Comments: Project 2006-06 (Draft 6)
27
Organization
Yes or No
Question 3 Comment
2. Error correction made.
Independent Electricity System
Operator
Yes
Notwithstanding our opposition to R1.2.
Response: Thank you for your support. No change made.
FirstEnergy
Yes
SERC OC Standards Review
Group
Yes
Luminant
Yes
Western Electricity Coordinating
Council
Yes
Dominion
Yes
SPP Standards Review Group
Yes
MRO NSRF
Yes
Northeast Power Coordinating
Council
Yes
Arizona Public Service Company
Yes
PacifiCorp
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
28
Organization
Yes or No
Xcel Energy
Yes
Public Service Enterprise Group
Yes
Pepco Holdings Inc
Yes
City of Austin dba Austin Energy
Yes
Manitoba Hydro
Yes
Duke Energy
Yes
Texas Reliability Entity
Yes
CenterPoint Energy Houston
Electric, LLC
Yes
American Transmission Company
Yes
Liberty Electric Power
Yes
Tacoma Power
Yes
NV Energy
Yes
Oncor Electric Delivery Company
LLC
Yes
Idaho Power Company
Yes
Consideration of Comments: Project 2006-06 (Draft 6)
Question 3 Comment
29
4.
Do you have any other comments on COM-001-2, not expressed in questions above, for the RCSDT?
Summary Consideration: There were several minority comments concerning the proposed standards COM-002-3 and IRO-001-3 that
the RCSDT could not respond to because they were approved by industry. Other comments revealed errors in the standard that the
RCSDT corrected. Most comments were continuances from previous comment periods, along with various minority comments which
the RCSDT provided. Commenters raised the issue that having a communication capability should be a matter of the NERC Certification
process, as raised in the above questions. The RCSDT noted that certification was the process to ensure registered entities could
perform those tasks associated with the reliability standards and that each entity should address this issue with NERC if further
information is needed. Also from previous comment periods, commenters noted this standard should be a Results-Based Standard
(RBS). The RCSDT did not disagree that the RBS format would be beneficial, but the current standard, as written, achieves the necessary
goals set forth in the Standards Authorization Request (SAR).
Other minority continuances from previous comment periods include the use of “means,” “primary,” and other words or suggestions in
the proposed definitions. The RCSDT maintains that these words are problematic and did not alter the definitions. Additionally, the
definitions describe the “what” for communications, not the “how.” Some commenters noted that requiring the Generation Operator
or Distribution Provider to have an Interpersonal Communication capability is redundant and unnecessary because they would already
have a capability by virtue of it being established by the Balancing Authority and Transmission Operator. The RCSDT responded that
each entity (i.e., both ends of the communication) is required to have the communication capability which is coordinated with the other
entity to establish the capability. Other comments included requests to specifically say that the proposed COM-001-2 is “not for the
exchange of data.” The RCSDT did not feel it necessary to insert such a clause, but pointed the commenter to reliability standards IRO010 and IRO-014 which address data and information.
A commenter questioned having the ability to select other communications as needed; however, the RCSDT notes that an entity cannot
randomly choose or designate other communication capabilities without coordinating the capability with other parties. Each applicable
entity must know what its Interpersonal Communication capability is with others and, if applicable, its Alternative Interpersonal
Communication capability with others. The same commenter questioned how the standard achieves “diversely routed,” as written in
the current standard COM-001-1. The RCSDT contends “diversely routed” is achieved through the proposed definitions. The proposed
definition of Alternative Interpersonal Communication contains, “…not utilize the same infrastructure (medium) as Interpersonal
Communication used for day-to-day operation.”
There were other minority comments about time limits and notifications. One commenter suggested having a defined notification
process using a hierarchal format. The RCSDT did not agree with this concept due to the diverse relationships between entities making
it impractical. One noted that the 60-minute notification time was insufficient. The RCSDT considered this, as in previous drafts, and
contends the period is adequate. Another did not agree with the two-hour limit on initiating action to repair or designating an
Consideration of Comments: Project 2006-06 (Draft 6)
30
Alternative Interpersonal Communication capability. Again, the RCSDT holds that the time elements have been considered and
supported by industry.
There were minority comments about the Measures and VSLs. The RCSDT inserted the word “respectively” in Requirement R10 and
similarly in Measure M10 to clarify the expected relationship between the listed functional entities and the listed requirements. Some
commenters noted that the use of “physical assets” is an inappropriate listing of evidence in the measures. The RCSDT disagreed that
having the asset can be one form of demonstrating the necessary evidence. A commenter requested additional granularity in the VSLs
in addition to what the RCSDT provided in the draft 6 posting. The RCSDT believes that having two (High and Severe) VSLs is the
appropriate VSL granularity given the expected number of entities required to have a communication capability. More importantly, the
reliability need is not to miss having a communication capability with any entity necessary for reliability operations. The same
commenter requested a lower VSL for Requirements R1, R3 and R5 because, in this case, the Reliability Coordinator, Transmission
Operator, and Balancing Authority are all required to have an Alternative Interpersonal Communication capability. The RCSDT contends
that a violation should not be contingent on the preponderance of other mitigating requirements. Both VRFs and VSLs are to be
evaluated on an individual requirement level without regard to other contributing circumstances. A comment suggested lowering the
VRF on Requirement R7 from High to Medium. The RCSDT agreed and made the change since the loss of a communication capability
with the Distribution Provider does not present the same level of risk that a Generator Operator would (e.g., during blackstart
restoration).
Other minority comments related to the effective date language and data retention. The effective date language governed by NERC
staff and the RCSDT only addresses the time elements within the template language. A question was raised about voice recordings
generally having only a 90-calendar day retention, but the data retention specified 12 calendar months. The RCSDT recognizes this
oversight and added clarifying language to account for voice recordings.
The majority comments in Question 4, also raised in previous comment periods, are related to Requirement R11, which had six distinct
reoccurring themes: (1) A threshold for determining when to report a failure of the Generation Operator or Distribution Provider
communication capability. (2) The reliability benefit of having to consult with the Balancing Authority or Transmission Operator when
neither the Generation Operator nor Distribution Provider are required to have an Alternative Interpersonal Communication capability.
(3) Consultation for the purpose of determining a mutually agreeable action for the restoration of its Interpersonal Communication
capability. (4) What does “action” constitute? (5) Changing the language to specifically name the entities to be notified in the
corresponding Measure M11. (6) The Generation Operator and Distribution Provider should be required to have an Alternative
Interpersonal Communication capability. The RCSDT appropriately responded to all six issues as follows:
For item (1) a threshold is not provided to allow flexibility for the Generation Operator or Distribution Provider to determine what
constitutes a failure of its Interpersonal Communication capability. The reliability benefit argued in (2) about consulting with the
Balancing Authority or Transmission Operator is for the purpose of bringing awareness to these entities that communications are
Consideration of Comments: Project 2006-06 (Draft 6)
31
compromised and to know what is being done to restore the capability. In issue (3) the purpose is to consult, the requirement clarifies
the reliability purpose to determine a mutually agreeable action for restoration. The reliability goal is for the Balancing Authority or
Transmission Operator to maintain awareness the communication capability has failed and what is being done to restore the capability.
The Generation Operator or Distribution Provider is free to employ an Alternative Interpersonal Communication capability, but has no
requirement to do so. The RCSDT responded to item (4) regarding what “action” meant. Action can be a number of things which the
entity under takes to restore its capability. It could include, but is not limited to: contacting internal staff to initiate a repair, contacting
a third party for repair, seeking assistance to troubleshoot the problem, or implementing its procedure(s) regarding the restoration of
the capability. There was a suggestion concerning item (5) to explicitly name the entities in Requirement R11. The RCSDT agreed it
would improve readability, but it would not be inconsistent with the way the measure is written using the reference to the two
requirements. Item (6) was also raised in previous comment periods and the RCSDT noted that only requiring the Generation Operator
and Distribution Provider to have an Interpersonal Communication capability is consistent with the direction provided in Order 693.
Organization
City of Austin dba Austin
Energy
Yes or No
Question 4 Comment
(1) Both instances of “Reliability Coordinator” in the VSLs for R3 should be
“Transmission Operator” to match the language of the standard.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R3 VSL. The reference to “Reliability Coordinator” has been changed to
Transmission Operator for Requirement R3 in both the High and Severe VSL. Error
correction made.
(2) Both instances of “Reliability Coordinator” in the VSLs for R5 should be “Balancing
Authority” to match the language of the standard.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R5. The reference to “Reliability Coordinator” has been changed to
Balancing Authority for Requirement R5 in both the High and Severe VSL. Error
correction made.
(3) In the VSLs for R9 and R10 the use of “and” seems incorrect.
Austin Energy suggests the following revisions for all VSL levels (only the Lower VSL
shown for simplicity and revised words suggested in capital letters):
Consideration of Comments: Project 2006-06 (Draft 6)
32
Organization
Yes or No
Question 4 Comment
R9, Lower VSL: “The Reliability Coordinator, Transmission Operator, OR Balancing
Authority...”
Response: RCSDT appreciates you bringing awareness to this error in Requirement
R9 VSL. The use of “and” between the responsible entities and the requirement
references has been corrected to “or” for proper construction in Requirements R9
and R10 VSLs. Error correction made.
R10, Lower VSL: “The Reliability Coordinator, Transmission Operator, OR Balancing
Authority failed to notify the entities identified in Requirements R1, R3, OR R5,
RESPECTIVELY, upon the detection ...”
Response: The RCSDT agrees with the ambiguity in Measure M10 and proposes to
clarify Requirement R10, Measure M10, and R10 VSL by inserting the word
“respectively.” For example, adding the word “respectively” means that the
Reliability Coordinator in R1 is not required to notify the entities identified in
Requirement R3 or R5. The RCSDT intended the requirements to map to the entity.
Clarifying changes made.
Response: Please see responses above.
ACES Power Marketing
Standards Collaborators
(1) The definition of Alternative Interpersonal Communication needs further
refinement. As it is written, the primary Interpersonal Communication that is used to
satisfy R1, R3, and R5 is also an Alternative Interpersonal Communication. This
primary Interpersonal Communication established in R1, R3, and R5 meet all of the
requirements of Alternative Interpersonal Communication. It is an Interpersonal
Communication and it is capable of replacing the Interpersonal Communication used
as the Alternative Interpersonal Communication (which by definition is an
Interpersonal Communication) in R2, R4, and R6. Thus, each Interpersonal
Communication used in R1, R3, and R5 really are an Interpersonal Communication
and Alternative Interpersonal Communication. One solution may be to add a third
definition: Primary Interpersonal Communication. It would essentially be an
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Interpersonal Communication that is designated as primary or the normal
communication system. Then Alternative Interpersonal Communication would be
defined based on the ability of the Interpersonal Communication to substitute for the
Primary. R1, R3, and R5 would need to be changed to refer to the Primary
Interpersonal Communication. Another option might be to simply stick with the two
existing definitions and use “primary” in R1, R3, and R5. Regardless of the option
selected, “another” needs to be added before the second use of Interpersonal
Communication for absolute clarity.
Response: The definitions clarify the need to differentiate the communication
capabilities. The RCSDT notes that, in this last ballot, industry stakeholder consensus
does not support the use of “primary” as a part of Interpersonal Communication. No
change made.
(2) We appreciate that the drafting team added another VSL for requirements R1
through R8, however, we believe additional levels should be populated. For example,
if a Transmission Operator or Balancing Authority failed to have Interpersonal
Communications capability with a Distribution Provider but had Interpersonal
Communications capability with all other required entities, it has met the vast
majority of the requirement. Since VSLs are a measure of how much the requirement
was missed by the responsible entity, a Lower VSL seems most appropriate for failing
to have Interpersonal Communication capability with a DP.
Response: The RCSDT added the High VSL for Requirements R1 through R8 from
draft 5 to draft 6 to account for greater granularity in a violation. For each applicable
responsible entity named in each of the requirements, the number of entities for
which it must have an Interpersonal Communication or Alternative Interpersonal
Communication may vary significantly. The RCSDT believed that adding one
additional VSL was an appropriate solution to account for variability in the number of
entities. No change made.
(3) It seems odd to change the effective date language from what NERC has
consistently used throughout the standards. “Following” was replaced with “beyond
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the date this standard is approved”. For consistency with the rest of NERC standards,
we recommend changing it back to the original language.
Response: The RCSDT appreciates your comment. The language in the Effective Date
section is standard language adopted by NERC and used throughout the body of
standards currently under development by teams. The RCSDT is not able to alter this
language. No change made
(4) We appreciate the changes to R1, R3, R5, R7 and R8 that attempt to clarify that a
failure of the primary Interpersonal Communication capability is not a violation of
these requirements. However, we believe these requirements will never be
approved by the Commission. As they are written, they literally say that R1, R3, R5,
R7, and R8 apply when the responsible entity has Interpersonal Communication
capability and they don’t apply when you don’t have the capability but rather other
requirements apply. This means R1, R3, R5, R7 and R8 could never be violated which
begs the question why are they even needed. Because Commission approval is
unlikely for these requirements, we continue to believe the best solution is to focus
the requirements on having a communication medium rather than capability. If
“capability” were struck from all of the requirements, the requirements would then
focus on a communication medium as defined in Interpersonal Communication and
Alternative Interpersonal Communication. This solution would still keep the
requirements technology neutral since a medium could be any communication
system or device and actually provide more flexibility in the requirements. Because
the requirements would focus on having a medium in place rather than a capability,
failure of the medium would not automatically translate into a violation which means
the problematic “unless [responsible entity] experiences a failure of its Interpersonal
Communication capability ...” language could be dropped. Dropping this language
would improve the likelihood that the Commission would approve the standard.
Response: The RCSDT thoughtfully considered the comments about where an entity
might be exempt from the requirement(s). No situation exempts an applicable entity
from the requirement(s) of this standard. No change made.
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(5) The VRF for R7 should be Medium. Failure for the DP to have Interpersonal
Communication with its BA or TOP does not meet the basic requirement of a High
VRF. A High VRF requires that violation of the requirement would “directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of
failures, or could place the bulk electric system at an unacceptable risk of instability,
separation, or cascading failures.” We cannot fathom any situation where failure of a
BA and TOP being able to communicate would directly lead to or cause instability,
separation, or cascading. It could, however, lead to the inability to know the
electrical state of part of the transmission system. This fits the Medium VRF
definition. Furthermore, the fact that R4 and R6 do not include DP in the list of
functional entities for a TOP and BA to have Alternative Interpersonal Communication
further supports a Medium VRF.
Response: The RCSDT thanks you for your comments and changed Requirement R7
to Medium VRF. Further consideration has been given to the Requirement R8 VRF;
however, the RCSDT concluded the Generator Operator has a higher importance and
risk to reliability, particularly blackstart capability. Change made to Requirement R7
VRF. No change made to Requiremnt R8 VRF.
(6) In Measure M11, we believe entity affected should be replaced with its TOP and
BA. This makes the measure clearer and easier to read without the need to refer
back to the requirement.
Response: The RCSDT agrees that naming the specific entities in the measure adds to
the readability; however, changing the word “entity” to the named entities in
Requirements R7 and R8 would be inconsistent with the way the measure is written
using the reference to the two requirements. No change made.
(7) We disagree with the data retention period. Because voice recordings are
mentioned in the measures as one type of evidence for demonstrating compliance to
the requirements, the data retention period should not exceed 90 days. Many
companies do not store voice recordings longer than this. To compel a responsible
entity to store voice recordings for longer should be justified. We do not see this
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justification.
Response: The RCSDT agrees with the comment about the issue concerning the time
period for retaining voice recording. The data retention has been revised to reflect a
period of 90 calendar days for all evidence related to the requirements. Clarifying
change made.
(8) We continue to believe that the DP should not be included in this standard.
However, we recognize that the drafting team is attempting to address a FERC
directive. An equally efficient and effective alternative would be to leave the
responsibility to the BA and TOP. Parts 3.3 and 5.3 require the TOP and BA
respectively to have Interpersonal Communication capability with the DP. This will be
required whether the standard applies to DP or not based on the Commission
directive because the Commission expressed concern about the BA and TOP having
communications with the DP during an emergency such as a blackstart event.
Because DPs will have to follow directives from the RC, TOP, and BA per IRO-001-3, it
is in the best interest of the DP to cooperate with assisting the BA and TOP in
establishing this capability. Thus, Parts 3.3 and 5.3 could be relied on exclusively for
establishing this Interpersonal Communication Capability without adding unnecessary
additional compliance burden on the DP that does not support reliability.
Response: The RCSDT thanks you for your comment and agrees that the standard is
addressing FERC directives concerning the Distribution Provider. Entities on each end
of the communication capability must have a responsibility to have communications.
No change made.
Response: Please see responses above.
MRO NSRF
The NSRF understands the importance of Interpersonal Communications and
Alternate Interpersonal Communications and always having the ability to
communicate with others. The NSRF questions why per R9 (and similar time
requirement per R10) that when testing the Alternate Interpersonal Communications
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is unsuccessful, why there is a two-hour time limit to initiate an action, repair, or
designate a replacement.
Response: The RCSDT believes that the Reliability Coordinator, Transmission
Operator and Balancing Authority, as reliability entities for Requirement R9, must
initiate action to repair or designate an Alternative Interpersonal Communication
capability timely so that in the event the Alternative Interpersonal Communication
capability is called upon, the capability will be available. Having the measurable time
period in the requirement ensures that entities will not delay action in addressing the
unsuccessful testing of the capability. No change made.
Project 2012-08.1 defines “Reliable Operation” means operating the Elements of the
Bulk Power System within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or Cascading failures of
such system will not occur as a result of a sudden disturbance, including a Cyber
Security Incident, or unanticipated failure of system Elements. The loss of an
Alternate Interpersonal Communication will not immediately impact the Reliable
Operations of the BPS. Recommend that this not be contained within the Standard
as entity’s will view this as a Good Utility Practice.
Response: The RCSDT agrees that the loss of an entity’s Alternative Interpersonal
Communication capability should not affect “Reliable Operation” of the Bulk Power
System; however, the regulatory directive in Order No. 693 addressing the proposed
definitions of “Bulk Power System,” “Reliability Standard,” and “Reliable Operations”
must be reviewed collectively. The proposed definition for “Reliability Standard”
contains the defined term “Reliable Operations,” and is defined as: “A requirement to
provide for Reliable Operation of the Bulk Power System, including without limiting
the foregoing, requirements for the operation of existing Bulk Power System Facilities,
including cyber security protection, and including the design of planned additions or
modifications to such Facilities to the extent necessary for Reliable Operation of the
Bulk Power System, but the term does not include any requirement to enlarge Bulk
Power System Facilities or to construct new transmission capacity or generation
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capacity. A Reliability Standard shall not be effective in the United States until
approved by the Federal Energy Regulatory Commission and shall not be effective in
other jurisdictions until made or allowed to become effective by the Applicable
Governmental Authority.” In the current paradigm, having an Alternative
Interpersonal Communication capability is: “A requirement to provide for Reliable
Operation of the Bulk Power System,” as the proposed definition of “Reliability
Standard” defines and is necessary to support communications between and among
the applicable entities in the standard. The RCSDT has addressed the scope of the
SAR in addressing communication requirements for entities through an open industry
consensus process.
R10 The NSRF recommends that “applicable” be inserted between “...notify
entities...” This will assure that RC’s will inform per R1, TOP’s will inform per R3 and
BA’s will inform per R5. This will assure that an interpretation is not required as in
Interpretation 2010-INT-01, TOP-006.
Response: The RCSDT agrees with the ambiguity in Measure M10 and proposes to
clarify Requirement R10, Measure M10, and R10 VSL by inserting the word
“respectively,” rather than the suggested: “as applicable.” The word “respectively” is
used rather than “applicable” because “applicable” is open to interpretation. For
example, adding the word “respectively” means that the Reliability Coordinator in R1
is not required to notify the entities identified in Requirement R3 or R5. The RCSDT
intended the requirements to map to the entity. Clarifying changes made.
Response: See responses above.
CenterPoint Energy Houston
Electric, LLC
1. For R10, there can be a large number of entities to notify for an Interpersonal
Communication failure. During normal operations, 60 minutes can be enough time to
make all the notifications. However, during emergency or adverse conditions, 60
minutes may not be sufficient. Thus, at the end of R10, the following should be
added: “unless certain adverse conditions (e.g. severe weather, multiple events)
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prevent the completion of notification within the 60 minutes.”
Response: The RCSDT contends that 60 minutes is sufficient for notification because
the BA, RC, and TOP are required to have an Alternative Interpersonal Communication
capability, and should have the ability to accomplish the required notification. Also, the loss
of Interpersonal Communication capability may not always impact the entire capability. This
time frame does not apply to the DP and GOP since the Alternative Interpersonal
Communication capability is not required for these functional entities. No change made.
2. For R11, the change from “mutually agreeable time” to “mutually agreeable
action” is not an improvement. It should not be the concern of the other entities how
(what action) the capability is restored, only that it is restored and that the entity
with the failure can be reached in the interim. Thus, we suggest the following: “to
determine a mutually agreeable alternative until Interpersonal Communication
capability is restored.”
Response: The RCSDT agrees the desired end result is restoring the capability, and
appreciates the suggested modification; however, the suggestion presents other
issues; such as: What if an alternative is not available? The RCSDT believes the most
appropriate and measureable way to address the loss of the Distribution Provider or
Generation Operator’s capability is to require the entities to communicate the action
taken to restore the capability. No change made.
Response: Please see responses above.
Independent Electricity
System Operator
1. COM-001:
We continue to disagree with R1.2, the phrase “within the same Interconnection” is
troublesome. RCs between two Interconnections still need to communicate with each
other for reliability coordination (e.g. between Quebec and the other RCs in the NPCC
region to curtail interchange transactions crossing Interconnection boundary). The
SDT’s previous response that the phrase was added to address the ERCOT situation
and citing that ERCOT does not need to communicate with other RCs leaves a
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reliability gap. The SDT’s latest response that R1 as written does not preclude or limit
the Reliability Coordinator from establishing Interpersonal Communication capability
with others is inconsistent with the basic principle for having a reliability standard. A
standard should stipulate the requirements based on what is needed to ensure
reliability, not on what is not precluded. If there is a reliability need for RCs across
Interconnection boundary to coordination operations, then Interpersonal
Communication shall be provided. If we apply the SDT’s philosophy (that the standard
does not preclude...), then one can argue that the standard does not need to
stipulate a requirement to have Interpersonal Communication as without such a
requirement, the standard does not preclude any operating entities to have it.
Finally, we would reiterate the fact that RCs between asynchronously interconnected
systems do communicate, e.g. between Quebec and its neighbor RCs. We are also
aware that RCs in the Western Interconnection and those in the Eastern
Interconnection do communicate as needed to coordinate TLR for transactions
crossing Interconnection boundary.
Response: From the Functional Model V5, Functional Entity - Reliability Coordinator,
the RCSDT notes the following: “Balancing operations. The Reliability Coordinator
ensures that the generation-demand balance is maintained within its Reliability
Coordinator Area; which, in turn, ensures that the Interconnection frequency remains
within acceptable limits. The Balancing Authority has the responsibility for
generation-demand-interchange balance in the Balancing Authority Area. The
Reliability Coordinator may direct a Balancing Authority within its Reliability
Coordinator Area to take whatever action is necessary to ensure that this balance
does not adversely impact reliability.” Based on the last sentence, the Reliability
Coordinator does not have the responsibility for these transactions. No change
made.
2. The follow comments address data retention for COM-002-3:
a. The first bullet in Section D 1.3 stipulates that “The Reliability Coordinator,
Transmission Operator, and Balancing Authority shall retain evidence of Requirement
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R1 and R3, Measure M1 and M2 for the most recent 3 calendar months.” We believe
M2 should be M3.
Response: The RCSDT agrees with your assessment that M2 should be M3 and has
advised NERC staff of the typo in COM-002-3. Error correction made.
b. The second bullet: “The Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider shall retain evidence of Requirement R1,
Measure M1 for the most recent 3 calendar months.” We believe R1 and M1 should
read R2 and M2 since DP is only responsible for meeting R2.
Response: The RCSDT agrees with your assessment that R1 and M1 should be R2 and
M2. The RCSDT has advised NERC staff of the typo in COM-002-3. Error correction
made.
c. Section 2 “Violation Severity Levels”: R# R2 Severe includes the Balancing
Authority as one of the listed entities; however, this is inconsistent with R2 / M2
which do not include the Balancing Authority. To be consistent with R2 / M2, the
Balancing Authority should be removed from VSL R# R2.
Response: The RCSDT agrees with your assessment and has advised NERC staff that
the VSL for Requirement R2 should have the entity “Reliability Coordinator” replaced
with “Balancing Authority” in COM-002-3 to be consistent with the named entities in
Requirement R2. Error correction made.
While these can be regarded as typos, and do not contribute to a show-stopper vote
for some, we urge the SDT and the Standards Committee to pay closer attention to
the accuracy of all elements in the standard.
3. IRO-001-3:
Section 1.3 Data Retention (second bullet) states:
The Operator, Balancing Authority, Generator Operator, or Distribution Provider shall
retain for Requirements R2 and R3, Measures M2 and M3 shall retain voice
recordings for the most recent 90 calendar days or documentation for the most
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recent 12 calendar months.
- The statement above appears to be missing “Transmission” before the word
Operator.
Response: The RCSDT agrees with your assessment of IRO-001-3 and has advised
NERC staff that in the second bullet of Section D, 1.3 section, the word
“Transmission” needs to be inserted in front of “Operator.” Error correction made.
- The statement above repeats “shall retain” and the highlighted instance is not
required.
Response: The RCSDT agrees with your assessment of IRO-001-3 and has advised
NERC staff that in the second bullet of Section D, 1.3, the first occurrence of “shall
retain” needs to be removed. Error correction made.
- The statement above states “or” Distribution provider, implying that one entity
needs to retain evidence. Starting the sentence with “Each” rather than “The” and
replacing “or” with “and” may provide clarity. The same would apply to the
introduction sentence prior to the bullets. COM-002-3 section D. Compliance 1.3
Data Retention provides an example of the suggested format.
Response: The RCSDT agrees with your assessment of IRO-001-3 and has advised
NERC staff that in the second bullet of Section D, 1.3, the “or” between the
responsible entities should be an “and.” Error correction made.
Here is an example of the revised sentence: “Each Transmission Operator, Balancing
Authority, Generator Operator, and Distribution Provider shall retain voice recordings
for the most recent 90 calendar days or documentation for the most recent 12
calendar months, for Requirements R2 and R3, Measures M2 and M3”.
Response: Please see responses above.
Bonneville Power
BPA thanks you for the opportunity to comment on Project 2006-06, COM-001-2 and
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has no comments or concerns at this time.
Response: The RCSDT thanks you for your comment.
Public Service Enterprise
Group
Change R11 and replace “experiences a failure” with “detects a failure” because one
may have a failure, but if it’s undetected for some period of time because no
communications are taking place, it’s unclear when one actually “experienced a
failure.” We note that R10 uses the terminology “detection of a failure.” Using
consistent terminology in R10 and R11 would result in less confusion for compliance
because there would not be an issue as to whether a difference was intended by the
SDT between “experiences” and “detects” in the two requirements.
Response: The RCSDT agrees with your assessment of the differences in terms and has changed “experiences” to “detects” in
Requirement R11 to be consistent with Requirement R10. Change made.
Colorado Springs Utilities
CSU appreciates the work the SDT has put into this standard, along with the others in
this project and the opportunity to comment. We agree with the goal to encourage
consistent communications and availability of robust & redundant communication
paths. CSU appreciates that the SDT appears to have tried to write some flexibility
into this standard. As written, however, this draft of COM-001-2 in its entirety seems
to us unwieldy and unmanageable.
It appears each entity may choose its own ‘primary’ and Alternate “Interpersonal
Communication” capabilities. Entity A may select email as its ‘primary’ capability,
while Entity B might not select that among either ‘primary’ or “Alternate,” and may
not pay any attention on the real-time desk to email (only the designated “Alternate”
requires testing).
Response: The requirements require the applicable entity to have a communication
capability with the defined entities in each requirement. An applicable entity should
not be changing its Interpersonal Communication capability independently without
coordinating the change with the defined entities in a given requirement. The
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proposed definition says, “…between two or more individuals…” No change made.
Also, DOs & GOs are not expected to maintain a backup (“Alternate”)
communications capability. It is unclear how those entities can then comply with R11
if their one and only interpersonal communication capability has failed.
Response: The RCSDT, from draft 5 to 6 of COM-001-3, added clarifying language in
Requirement R7 for the Distribution Provider and in Requirement R8 for the
Generator Operator to account for the potential gap of compliance. The language
was: “… (unless the experiences a failure of its Interpersonal
Communication capability in which case Requirement R11 shall apply).” The RCSDT
also notes this parenthetic was updated to more appropriately address the detection
of the failure and now reads: “… (unless the detects a failure of
its Interpersonal Communication capability in which case Requirement R11 shall
apply).” No change made.
Sufficient evidence includes “physical assets.” Does that mean we can point to the
phone on the desk and the email program on the desktop PC and we’re compliant?
Are photographs of physical assets sufficient evidence to submit for the pre-audit
questionnaire?
Response: The RCSDT believes that physical assets are demonstration of evidence
for Interpersonal Communication capability. The responsible entity may exercise
other methods of evidence for the physical assets (e.g., photographs or other
documentation). No change made.
There is no requirement for the communications capabilities to be either diverse or
redundant. If both our capabilities, in the end, rely on the POTS/PSTN system, is that
acceptable?
Response: The RCSDT agrees that the requirements do not specifically address this
condition within the requirements themselves; however, the issue of redundancy is
addressed within the proposed defined term “Alternative Interpersonal
Communication.” The definition reads: “Any Interpersonal Communication that is
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able to serve as a substitute for, and does not utilize the same infrastructure
(medium) as, Interpersonal Communication used for day-to-day operation.” No
change made.
Response: Please see responses above.
Detroit Edison
Defining Interpersonal Communication as “Any medium that allows two or more
individuals to interact, consult, or exchange information” will also include all
Alternative Interpersonal Communications since “Any medium” is all inclusive.
Consider replacing the definition of Interpersonal Communication with the following:
Primary Interpersonal Communication: The normal communication medium that two
or more individuals use to interact, consult, or exchange information relating to dayto-day operations.
Response: The RCSDT notes that previous drafts received comments recommending
the use of terms; such as, “primary,” “secondary,” “device,” “means,” and “medium”
with regard to the proposed definitions. The RCSDT thanks you for your suggestion;
however, the requirements are for “capability” and adding such proposed terms is
not needed to achieve the necessary clarity. No change made.
Consider replacing the definition of Alternative Interpersonal Communication with
the following:
Alternative Interpersonal Communication: Any communication medium that is able
to serve as a substitute for, and does not utilize the same infrastructure (medium) as
the designated Primary Interpersonal Communication.
Response: This suggestion has only added the word “Primary” to the definition. The
RCSDT contends that the use of terms, such as, “primary,” “secondary,” “device,”
“means,” and “medium” with regard to the proposed definitions is not needed to
achieve the necessary clarity. No change made.
R1, R3, R5, R7, R8 should require entities to designate Primary Interpersonal
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Communication.
Response: This suggestion has only added the word “Primary” to the defined term.
The RCSDT contends that the use of terms, such as, “primary,” “secondary,” “device,”
“means,” and “medium” with regard to the proposed definitions is not needed to
achieve the necessary clarity. No change made.
R10 and R11 should address failures to designated Primary and Alternate
Interpersonal Communication.
Response: This suggestion has only added the word “Primary” to Requirements R10
and R11. The RCSDT contends that the use of terms, such as, “primary,” “secondary,”
“device,” “means,” and “medium” with regard to the proposed definitions is not
needed to achieve the necessary clarity. No change made.
R9 in all VSL levels the phrase "failed to initiate action to repair" or designate a
replacement is subject to interpretation. Does "initiate action" include notification to
the proper party to investigate and repair or does it require repairs to begin within
specified times as listed in severity levels?
Response: The RCSDT notes that the requirement is for the entity to “initiate action,”
which may include, but is not limited to, notifying or request repair to restore the
capability. The available alternative is to designate an Alternative Interpersonal
Communication capability. No change made.
Response: Please see response above.
Duke Energy
Distribution Providers and Generator Operators have significant responsibilities that
require reliable means of communications with other entities, such as implementing
load shedding and adjusting real and reactive power. The requirements for the
Distribution Provider and Generator Operator should therefore be consistent with
those for the Reliability Coordinator, Transmission Operator and Balancing Authority,
namely, they should be required to designate Alternative Interpersonal
Communication capability, to test this capability and to notify appropriate entities
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when its Interpersonal Communication capability has failed.
Response: The RCSDT thanks you for your comment about requiring the Distribution
Provider and Generation Operator to have the requirements similar to that of the
Reliability Coordinator, Transmission Operator, and Balancing Authority. The
standard, as proposed, has included the Distribution Provider and Generation
Operator in accordance with the regulatory statements in Order No. 693,
Pparagraphs 483, 491, 495, 496, and 503 which recognized the need for Distribution
Providers and Generation Operators to have flexibility in meeting the communication
capability requirements and not to burden smaller entities (i.e., DPs and GOPs) with
the additional requirement of adding communication redundancy. No change made.
The definition of Interpersonal Communication should also be expanded to clearly
include the drafting team’s intent that the capability is NOT for the exchange of data.
With respect to the standard being tacit on “not for the exchange of data,” the RCSDT
believes this concern is addressed within the earlier IRO-014-1 – Procedures,
Processes, or Plans to Support Coordination Between Reliability Coordinators
standard and now the proposed IRO-014-2 – Coordination Among Reliability
Coordinators adopted by the NERC Board of Trustees August 4, 2011. No change
made.
Response: Please see the responses above.
Dominion
Dominion has no additional comments on COM-001-2, but does have the below
comments on IRO-001-3:
Dominion believes that our previous comment remains valid and the response
provided by the SDT does not address all aspects of our concerns. Dominion suggests
that the language of ‘direction’ be changed to ‘Reliability Directive’ to remain
consistent with COM-002. Another alternative would be as written below;
IRO-001-3 uses the term ‘direct’ in its purpose statement, R1, R2 and R3. To avoid
confusion with a Reliability Directive (both for auditors and entities), we suggest the
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following: To establish the authority of Reliability Coordinators to make requests of
other entities to prevent an Emergency or Adverse Reliability Impacts to the Bulk
Electric System.
R1: Each Reliability Coordinator shall have the authority to act or request others to
act (which could include issuing Reliability Directives) to prevent identified events or
mitigate the magnitude or duration of actual events that result in an Emergency or
Adverse Reliability Impacts.
R2: Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall comply with its Reliability Coordinator’s request unless
compliance with the request cannot be physically implemented, or unless such
actions would violate safety, equipment, regulatory or statutory requirements, or
unless the TOP, BA, GOP or DP convey a business reason not to comply with the
request but express that they will comply if a Reliability Directive is given.
R3: Each Transmission Operator, Balancing Authority, Generator Operator, and
Distribution Provider shall inform its Reliability Coordinator upon recognition of its
inability to perform as requested in accordance with Requirement R2.”
Or we could cite Southwest Transmission Cooperative, Inc. comments which read
“COM-002-3 R1 really compels the Reliability Coordinator to use a Reliability
Directive for Emergencies and Adverse Reliability Impacts with the opening clause:
“When a Reliability Coordinator, Transmission Operator, or Balancing Authority
determines actions need to be executed as a Reliability Directive.” What else could
be more important for a Reliability Coordinator to issue a Reliability Directive than for
an Emergency or Adverse Reliability Impact?
Thus, not requiring the use of Reliability Directives for Adverse Reliability Impacts and
Emergencies makes IRO-001-3 R1 and COM-002-3 R1 inconsistent. For clarity and
consistency, IRO-001-3 Requirement R2 and R3 should also be clear that the
responsible entities will respond to the Reliability Coordinator’s Reliability Directives.
Response: The RCSDT thanks you for your support of COM-001-2. The standards COM-002-3 and IRO-001-3 were approved by
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industry in July 2012; therefore, the RCSDT is not able to respond to Dominion’s comments and consider changes to the standard.
No change made.
FirstEnergy
FE supports COM-001-2 and has no further comments.
PLEASE NOTE: THE FOLLOWING COMMENTS RELATE TO COM-002-3 AND IRO-001-3
SINCE WE WERE NOT ABLE TO PROVIDE COMMENTS ON THE RECIRCULATION BALLOT
AND WANTED TO EXPLAIN OUR REASONS FOR NOT SUPPORTING THOSE STANDARDS:
Although we believe the team made significant improvements to the standard, and
would support a 3-part communication standard, we believe the introduction of both
COM-002-2 which utilizes Reliability Directives and COM-003-1 which utilizes
Operating Communications cause confusion for system operators and may in fact be
detrimental to reliability.
We do not support two standards on three-part communication. We suggest, as we
have in the past, that the subject of three-part communication be addressed in a
single standard, and that the requirements be developed for simplicity. The industry
is, and has been, using three-part communication for decades and although we agree
it should be more consistently practiced and standardized, the required
communications protocols should be simple while meeting the goal of BES reliability.
Introducing complicated requirements and standards that have different definitions
such as Reliability Directive and Operating Communication may cause the operator to
hesitate when issuing directives in real-time and every second counts when a
potential system emergency must be mitigated.
Therefore, FE does not support the creation of both COM-003-1 nor the revisions to
COM-002-2 and IRO-001-3 which introduce the “Reliability Directive” term and ask
NERC to reevaluate the need to have two separate standards for three-part
communication.
Response: The RCSDT thanks you for your support of COM-001-2. The standards COM-002-3 and IRO-001-3 were approved by
industry in July 2012; therefore, the RCSDT is not able to respond to FirstEnergy’s comments and consider changes to the standard.
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No change made.
Indiana Municipal Power
Agency
IMPA does not like the wording in R11 that states "mutually agreeable action for the
restoration of its Interpersonal Communication capability." IMPA sees that entities
will have to prove that the action taken by entities was "mutually agreeable" to the
parties involved which will be very problematic. IMPA believes as long as the entity
who owns the equipment is taking steps to get it back into service that is all that
should be required by any requirement of this standard.
Response: The RCSDT addressed the concern about “mutually agreeable restoration time” by revising the phrase to “mutually
agreeable action,” which allows the applicable entities to reach consensus on the effort needed to restore communications.
Additionally, working toward a mutually agreeable action also ensures that both parties understand the magnitude of the loss of
their Interpersonal Communication capability and agree to the actions needed to restore and minimize the time the capability is
unavailable. From a compliance standpoint, the Distribution Provider and Generation Operator that is working to restore its
Interpersonal Communication capability is not out of compliance as far as the entity is meeting the requirement for taking action to
restore its capability. It is practical on the part of the Balancing Authority or Transmission Operator to reach a mutual agreement, as
it will facilitate restoring the capability. No change made.
Texas Reliability Entity
In the Measures for R3 and R4 (M3 and M4), should the phrase “each adjacent
Transmission Operator asynchronously AND synchronously connected” be changed
to “each adjacent Transmission Operator asynchronously OR synchronously
connected”?
Response: The RCSDT agrees with your assessment in COM-001-2 and has changed
the word in Measure M3 from “and” to “or” between the words “asynchronously and
synchronously.” Error correction made.
In the VSLs for R3 it appears that “Reliability Coordinator” should be “Transmission
Operator”.
Response: The RCSDT agrees with your assessment and has advised NERC staff that
the VSL for Requirement R3 should have the entity “Reliability Coordinator” replaced
with “Transmission Operator” in COM-002-3 to be consistent with the named entities
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in Requirement R3. Error correction made.
In the VSLs for R5 it appears that “Reliability Coordinator” should be “Balancing
Authority”.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R5 VSL. The reference to “Reliability Coordinator” has been changed to
Balancing Authority for Requirement R5 in both the High and Severe VSL. Error
correction made.
In the Severe VSL for R10 the phrase “failed to notify the identified entities
identified” should probably be “failed to notify the entities identified”.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R10 VSL Severe column. The first occurrence of “identified” has been
removed. Error correction made.
Response: Please see the above responses.
Ingleside Cogeneration LP
(Occidental Chemical in the
ballot body)
Ingleside Cogeneration LP generally agrees with the modifications that the SDT has
made to COM-001-2. However, we cannot vote to accept the standard unless
requirement R10 is modified to include a minimum communications outage duration
before consultation with the BA or TOP is necessary. This is similar to R10, which
allows an outage to extend up to 30 minutes - thus avoiding the need for a
notification that an insignificant interruption in service took place.
The following language could be added to R11 as shown in the brackets below:
R11. Each Distribution Provider and Generator Operator that experiences a failure of
its Interpersonal Communication capability [that lasts 30 minutes or longer] shall
consult each entity affected by the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a Generator Operator, to determine a
mutually agreeable action for the restoration of its Interpersonal Communication
capability.
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Response: The RCSDT notes that the requirement allows flexibility for the Distribution Provider and Generator Operator to define
what constitutes a failure of its Interpersonal Communication capability. The RCSDT believes it is inappropriate to establish a single
defined threshold applicable to the numerous entities applicable to this standard. No change made.
Essential Power, LLC
It is unclear what we are trying to accomplish in R11. If the intent is to coordinate the
restoration of communications, then there should be an additional requirement that
the GOP have a Communications Recovery Plan, and R11 should focus on the
coordination and implementation of that Plan.
If the intent is to maintain continuous communications, then there should be an
additional requirement for the GOP to maintain an Alternative Interpersonal
Communications capability, and R11 should focus on the coordination and
implementation of that capability.
Response: The RCSDT thanks you for your comments. The intent of Requirement R11 is to require the Distribution Provider and
Generator Operator to consult with its Balancing Authority or Transmission Operator, as the case may be, to mutually agree on the
action needed to restore the Interpersonal Communication capability. Additionally, working toward a mutually agreeable action also
ensures that both parties understand the magnitude of the loss of their Interpersonal Communication capability and impact to
reliability; therefore, both need to agree on the actions needed to restore and minimize the time the capability is unavailable. It is
practical on the part of the Balancing Authority or Transmission Operator to reach a mutual agreement, as it will facilitate restoring
the capability. No change made.
Manitoba Hydro
Manitoba Hydro would like additional clarification added to the definition of
interpersonal communication. The definition should explicitly state that interpersonal
communication does not data links (e.g. the ICCP data link). Also, does interpersonal
communication include emails?
Response: With respect to the standard being tacit on “not for the exchange of
data,” the RCSDT believes this concern is addressed within the earlier IRO-014-1 –
Procedures, Processes, or Plans to Support Coordination Between Reliability
Coordinators standard and now the proposed IRO-014-2 – Coordination Among
Reliability Coordinators adopted by the NERC Board of Trustees August 4, 2011.
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Additionally, Requirement R3 in IRO-010-1a – Reliability Coordinator Data
Specification and Collection states: Each Balancing Authority, Generator Owner,
Generator Operator, Interchange Authority, Load-serving Entity, Reliability
Coordinator, Transmission Operator, and Transmission Owner shall provide data and
information, as specified, to the Reliability Coordinator(s) with which it has a
reliability relationship. No change made.
Under the Effective Date Section, the effective date language has a few issues in its
drafting. It would be clearer to use the word ‘following’ as opposed to the word
‘beyond’ (and this would also be more consistent with the drafting of similar sections
in other standards). The words ‘the standard becomes effective’ in the third line are
not needed. The words ‘made pursuant to the laws applicable to such ERO
governmental authorities’ may not be appropriate. It’s not the laws applicable to the
governmental authorities that are relevant, but the laws applicable to the entity
itself. We would suggest wording like ‘or as otherwise made effective pursuant to the
laws applicable to the Balancing Authority’.
Response: NERC staff note that the phrase: “… the standard becomes effective” is a
clarifying statement that needs to remain. This phrase would become more
important if the heading “Effective Date” was not used. The phrase, “made
pursuant to the laws applicable to such ERO governmental authorities” is a reference
to governmental entities that have authority over BPS reliability within a jurisdictional
territory; for example, in the United States, the Federal Energy Regulatory
Commission; and in Canada, those parties delegated authority by Canadian provinces.
Therefore, the statement is appropriate because the laws that are applicable to “such
ERO governmental entities” will determine the effective date under the
circumstances, not necessarily the laws that are applicable to functional entities. No
change made.
Also, ERO is not defined.
Response: The RCSDT appreciates your comment. The language in the Effective Date
section is standard language adopted by NERC and used throughout the body of
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standards currently under development by teams. The RCSDT is not able to alter this
language. No change made
R11 and M11 - would suggest replacing ‘action’ with ‘plan of action’ or ‘action plan’
Response: The RCSDT believes the use of “action” is sufficient for Requirement R11
and Measure M11 and that adding “plan” does not add clarity. The RCSDT
understands that whatever actions are mutually agreed upon will constitute a plan
which the Distribution Provider or Generation Operator will use in the restoration of
its Interpersonal Communication capability. No change made.
M3 and M4 - the word ‘and’ between asynchronously and synchronously should
more appropriately be ‘or’
Response: The RCSDT agrees with your assessment and has changed the word in
Measure M3 from “and” to “or” between the words “asynchronously and
synchronously”. Error correction made.
M10 - the semi colon after stamped should be deleted
Response: The RCSDT agrees with your assessment and has added a colon at the
appropriate location and changed the current colon to a comma for the Measures
M9, M10, and M11. Error correction made.
Compliance Section - Compliance Enforcement Authority is defined as CEA, but then
both the acronym and the entire term is later used in the document. Should either
not define, or use acronym consistently.
Response: The RCSDT notes that the usage of the acronyms is consistent with the
NERC style guide. No change made.
Response: Please see responses above.
MISO
MISO respectfully submits that the subject matter of COM-001-1 is better addressed
through an official NERC certification - that is, by having NERC certify that a registered
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entity has the appropriate communications facilities - than through a formal
Reliability Standard.
Response: NERC maintains an Organization Certification Program, the goal of which
is to ensure that organizations who apply to register or are registered to perform
certain reliability functions deemed particularly crucial to the reliability of the bulk
power system will meet or exceed certain minimum criteria (i.e., Reliability
Standards) demonstrating they are capable of performing the tasks (i.e.,
Requirements) for these functions. The process for certification of organizations is
included in the NERC Rules of Procedure, Section 500 and Appendix 5A. For example,
the first paragraph of Section 500 – Organization Registration and Certification states:
“The purpose of the Organization Registration Program is to clearly identify those
entities that are responsible for compliance with the FERC approved reliability
standards. Organizations that are registered are included on the NERC Compliance
Registry (NCR) and are responsible for knowing the content of and for complying with
all applicable reliability standards…” The RCSDT has addressed the scope of the SAR
in addressing communication requirements for entities through an open industry
consensus process.
Furthermore, the Reliability Standards surrounding communications should be
performance based and specifically targeted toward testing, maintenance, and
implementation of corrective actions when an issue arises or is otherwise detected.
As a result of narrowing the focus of these standards, enforcement would then be
tailored toward a Registered Entity’s failure to take such actions when necessary, a
direct benefit and correlation to enhancement of the reliability of the BES.
Response: The RCSDT thanks you for your comment. Although this standard is not a
Results-Based Standard (RBS), it achieves the need to require both Interpersonal
Communication and Alternative Interpersonal Communication capability of the
applicable entities to ensure reliable operations of the Bulk Electric System. The
RCSDT believes the requirements achieve the needed level of communications to
ensure reliable operations. No change made.
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Under the currently proposed approach, the lack of a communication medium or a
finding that a communication medium is “inadequate” or does not otherwise qualify
under the standard would result in a non-compliance.
Response: The RCSDT is not sure what is meant by a “lack of communication
medium.” The applicable entity either has the necessary Interpersonal
Communication and Alternative Interpersonal Communication capability or does not.
The requirements account for conditions where the capability is unavailable and has
provided language to avoid situations of non-compliance due to the strict language
construction of the requirements. No change made.
Finally, MISO respectfully submits that:
-Distribution Providers (DPs) and Generator Operators (GOPs) should have alternate
communication media as well.
Response: The RCSDT thanks you for your comment about requiring the Distribution
Provider and Generation Operator to have the requirements similar to that of the
Reliability Coordinator, Transmission Operator, and Balancing Authority. The
standard, as proposed, has included the Distribution Provider and Generation
Operator in accordance with the regulatory statements in Order No. 693, Paragraphs
483, 491, 495, 496, and 503 which recognized the need for Distribution Providers and
Generation Operators to have flexibility in meeting the communication capability
requirements and not to burden smaller entities (i.e., DPs and GOPs) with the
additional requirement of adding communication redundancy. No change made.
-If an alternate communication tool is tested once a month, there is no need to
address deficiencies within two hours; six hours is sufficient in such instances.
Response: The RCSDT contends the time frame has been through industry
consensus, and two hours has been determined acceptable. No change made.
-The standard should acknowledge that if more than two independent
communication mechanisms are available, the VRF/VSL associated with missing a
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timing requirement is minimal.
Response: The RCSDT agrees that the applicable entities in Requirements R1, R3, and
R6 are required to designate an Alternative Interpersonal Communication capability;
however, this does not create a rationale for lowering the VRF/VSL. The VRF is a
measure of the risk, if violated, and the VSL is a measure of non-compliance with the
specific requirement.
The RCSDT added the High VSL for Requirements R1 through R8 from draft 5 to draft
6 to account for greater granularity in a violation. For each applicable responsible
entity named in each of the requirements, the number of entities for which it must
have an Interpersonal Communication or Alternative Interpersonal Communication
may vary significantly. The RCSDT believed that adding one additional VSL was an
appropriate solution to account for variability in the number of entities. No change
made.
The SDT should require reporting times of failed mediums for GOP and DP similar to
that for RC/BA/TOP.
Response: The RCSDT thanks you for your comment about requiring the Distribution
Provider and Generation Operator to have the requirements similar to that of the
Reliability Coordinator, Transmission Operator, and Balancing Authority. The
standard, as proposed, has included the Distribution Provider and Generation
Operator in accordance with the regulatory statements in Order No. 693, Paragraphs
483, 491, 495, 496, and 503 which recognized the need for Distribution Providers and
Generation Operators to have flexibility in meeting the communication capability
requirements and not to burden smaller entities (i.e., DPs and GOPs) with the
additional requirement of adding communication redundancy. No change made.
Response: Please see responses above.
Oncor Electric Delivery
Company LLC
Oncor takes the position that the premise of R3 does not provide a reliability
enhancement but may in effect; increase the risk to reliability by placing notification
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requirements on the Transmission Operator that could best be managed by the
Reliability Coordinator. In fact,
Oncor takes the position that as a Transmission Operator, it is being placed into the
position of having to continually validate the registration status of every entity that
may be registered as a Distribution Provider, Transmission Operator, and Generator
Operator within its Transmission Operator Area. Oncor takes the position that since
each of these entities are in the applicability section of the standard, the Distribution
Provider, Transmission Operator, and Generator Operator should be responsible for
seeking Interpersonal Communication capability with the Transmission Operator and
the Transmission Operator should then reciprocate Interpersonal Communication
capability in response to their initial request. This eliminates an unnecessary
compliance obligation of the Transmission Operator to manage "who is" and "who is
not" registered as a Generator Operator, Distribution Provider or Transmission
Operator.
Response: The RCSDT notes this is not within the scope of the SAR. No change
made.
Oncor recommends the following change to the standard language:
Remove 3.3 & 3.4 because R7 and R8 already cover the GO and DP seeking
Interpersonal Communication capability with the Transmission Operator.
Response: The RCSDT thanks you for your comment and notes that the standard is
addressing FERC directives concerning the Generation Owner and Distribution
Provider. Entities on each end of the communication capability must have a
responsibility to have communications. No change made.
Oncor also takes the position that the Reliability Coordinator (RC) is in the best
position and not the Transmission Operator to make extensive notifications on a
broad basis in the event of a failure of its Interpersonal Communication. In
accordance with that position, the Transmission Operator should make a single
notification to the RC, and the RC would then make the notification to all impacted
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entities in the event of the failure of the Transmission Operator’s Interpersonal
Communication.
Response: The RCSDT notes this implementation is entity-specific and is not
achievable by all entities. Each entity is required to make the notifications as
applicable to the requirements. No change made.
Oncor proposes the following language for R10
“R10. Each Transmission Operator shall notify the Reliability Coordinator and the
Balancing Authority within 60 minutes of the detection of a failure of its Interpersonal
Communication capability that lasts 30 minutes or longer.
After notification by any Transmission Operator, the Reliability Coordinator shall
immediately notify entities as identified in Requirements R1, R3, and R5 of any
Transmission Operator's detection of a failure of its Interpersonal Communication
capability that lasts 30 minutes or longer.
Each Reliability Coordinator and Balancing Authority shall notify entities as identified
in Requirements R1, R3, and R5 within 60 minutes of the detection of a failure of its
own Interpersonal Communication capability that lasts 30 minutes or longer."
Response: The RCSDT disagrees with the method. Each entity is required to make
the notifications as applicable to the requirements. No change made.
Response: Please see the above responses.
Central Lincoln
Prior Central Lincoln Comment
1) The new requirement presents us with a paradoxical situation. The communication
has failed, so we must consult; yet consultation requires communication. We note
that the SDT used the word “any”, implying that multiple communication paths are
required. The reality of the situation at Central Lincoln, due to our remote location, is
that a single back hoe incident at the right location can take out all of our of our
communication capability (including the terrestrial portion of the cellular networks)
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with our BA/TO; making this requirement impossible to meet for this circumstance
using our present capabilities.
Prior RCSDT Response
1) The RCSDT appreciates your comment and has made clarifying changes by
removing the phrase “any of” in COM-001, R11. Additionally, the RCSDT made a
clarifying change to indicate the DP and GOP only need to consult with the entity
affected by the failure. Furthermore, R11 addresses the direction given in Order 693
that DP and GOP entities do not necessarily need to have Alternative Interpersonal
Communication capability. The requirement allows flexibility in “consult with” by not
naming the method. If all communications are out, then the DP or GOP may have to
meet the requirement by an in-person consultation.
New Central Lincoln Response
1) Thank you for the changes made. We realize that in-person consultation is an
option, but find it not too hard to imagine the same event that disrupts
communications might also block roads. We don’t believe entities should be found
non-compliant and sanctioned for events beyond their control.
Response: The RCSDT understands the paradoxical situation presented here. The
standard addresses the essential communication capability needed to operate the
Bulk Electric System reliably. No change made.
Prior Central Lincoln Comment
2) We also note that no time limit was indicated. Most interruptions are brief, and
fixed before consultation could reasonably take place. CEAs will be finding entities
non-compliant for quickly fixing problems at their end without first consulting to
ensure the restoration time was agreeable. To avoid non-compliance, entities will be
forced to delay repairs while they investigate alternative communication paths for
consultation purposes. We fail to see how such an outcome improves reliability.
Prior RCSDT Response
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2) The DP and GOP are only required to have Interpersonal Communication
capability. If the DP or GOP restores its Interpersonal Communication capability
before it could reasonably contact the affected entity by another method, there is no
failure to comply. The DP or GOP could then consult with the affected entity to
determine a mutually agreeable action. In this case, the RCSDT believes the "action"
would then be the entities acknowledging the failure and the repair; therefore, no
mutually agreeable action is needed. The RCSDT recognizes there is no way to
account for all the various circumstances in a failure. To comply, the DP and GOP are
still required to consult the entity which the failure affected regardless of whether
the Interpersonal Communication capability was restored or is still failed. No change
made.
New Central Lincoln Response
2) If consultation after restoration is acceptable, we suggest that this be made clear
in the requirement. Presently it is not at all clear, and there is no accompanying
guidance document to suggest so. We also remain unclear what reliability benefit
would result from such a consultation following restoration. While accounting for all
the various failures might be impossible, we would like to see a few of the more
common ones discussed in a guidance document.
Response: The RCSDT notes that the requirement allows flexibility for the
Distribution Provider and Generator Operator to define what constitutes a failure of
its Interpersonal Communication capability. The RCSDT believes it is inappropriate to
establish a single-defined threshold or attempt to make a list of the various failures
which may potentially affect the numerous entities applicable to this standard. No
change made.
Prior Central Lincoln Comment
3) The new requirement is one sided, requiring the DP and GOP to consult with no
corresponding requirement for the TO or BA to have personnel available for such a
consultation. Consultation failure or failure to mutually agree due to actions or
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inactions on the part of the TO or BA should not result in an enforcement action
against the DP or GOP, yet that is how the requirement is written.
Prior RCSDT Response
3) The RCSDT notes that once the failure has been detected, the responsible entity
must make the consultation with the BA or TOP; that relieves the compliance burden.
While the RCSDT understands your concern about single points of failure, the
question becomes should this relieve the DP or GOP of the requirement for having
Interpersonal Communication capabilities. No change made.
New Central Lincoln Response
3) The requirement remains one-sided. If a consultation effort fails due to actions or
inactions taken by the BA/TO, the DP or GOP is the only entity that can be found noncompliant.
Response: The RCSDT addressed the concern about “mutually agreeable restoration
time” by revising the phrase to “mutually agreeable action,” which allows the
applicable entities to reach consensus on the effort needed to restore
communications. Additionally, working toward a mutually agreeable action also
ensures that both parties understand the magnitude of the loss of their Interpersonal
Communication capability and agree to the actions needed to restore and minimize
the time the capability is unavailable. From a compliance standpoint, the Distribution
Provider and Generation Operator that is working to restore its Interpersonal
Communication capability is not out of compliance as far as the entity is meeting the
requirement for taking action to restore its capability. It is practical on the part of the
Balancing Authority or Transmission Operator to reach a mutual agreement, as it will
facilitate restoring the capability. No change made.
Prior Central Lincoln Comment
4) The new requirement fails to add any “clarity” to the other requirements, and we
don’t see that the stakeholders thought there was a problem with DP/GOP obligation
clarity. Instead, it adds new obligations with no justification for how they enhance
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reliability. We suggest removing the requirement.
Prior RCSDT Response
4) Based on the RCSDT’s understanding of the comments received on the previous
posting, the industry desired additional clarity on specifically what communication
capabilities the DP and GOP were required to have. There was confusion that the
standard did not specifically say that the DP and GOP were required to have
Alternative Interpersonal Communication capabilities. R11 clarifies that a DP and GOP
are not required to have Alternative Interpersonal Communication capability if the
DP or GOP consult with their TOP or BA, whichever is applicable in the given
situation, and they mutually agree that the restoration action does not adversely
impact the reliability of the BES. No change made.
New Central Lincoln Response
4) We disagree that R11 clarifies anything regarding Alternative Interpersonal
Communication capabilities; the requirement says nothing on the matter. If other
requirements remain unclear, we suggest they be clarified within those
requirements. We ask that R11 be removed. Alternatively, we suggest that a plan for
communication failure be developed by the affected entities prior to a failure,
applicable to both the BA/TO and DP/GOP.
Response: The RCSDT contends the desired result is restoring the capability and that
the most appropriate and measureable way to address the loss of the Distribution
Provider or Generation Operator’s capability is to require the entities to
communicate the action taken to restore the capability. No change made.
Prior Central Lincoln Comment
5) As stated in our prior comments, we continue to have problems with COM-002, R2
and R3 as written. The SDT’s answer (“It is the expectation that an issuer of a
Reliability Directive would request a return call by the Distribution Provider operating
personnel, then issue the Reliability Directive”) addresses our concern perfectly, and
we would agree with such an expectation. Unfortunately, the expressed expectation
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is not in the proposed standard or even in a proposed guideline for the standard.
Prior RCSDT Response
5) The RCSDT believes this is a process or procedure question that should be
determined by the entity in how it handles communication with the RC. The
standard, as written does, not preclude the entity from having a procedure. No
change made.
New Central Lincoln Response
5) We agree that this is a procedure issue, but disagree that the procedure lies with
the entity receiving the Reliability Directive. The SDT’s words inside the quotation
marks above state it is the issuer of the Directive that should request a return call.
Procedures like this, in order to ensure the Directive gets to the party who
understands it and can take the needed action, are the responsibility of the issuer. If
reliability is at risk, it is little to ask that issuers of Reliability Directives be required to
attempt to reach the proper party prior to identifying, delivering the directive, and
asking for repetition.
Response: The standard COM-002-3 was approved by industry in July 2012;
therefore, the RCSDT is not able to respond to Central Lincoln’s comments and
consider changes to the standard. No change made.
Response: Please see responses above.
Liberty Electric Power
R11 remains an issue even with the revision. The purpose of R11 should be to inform
the BA and TO of a loss of interpersonal communications capability so that the BA or
TO can react effectively to grid conditions in an emergency. The methods of repair for
generator telephone and data lines are properly the business decisions of the
generator, and there is no benefit to the reliability of the BES if a standard requires a
generator to attempt to gain consensus from the BA and TO on his repair actions.
Taking the time to discuss a "mutually agreed action" will delay the start of repairs,
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and lengthen the time of a communications outage as generators first must discuss
the issue with the BA and TO instead of initiating the action on their own and
informing those entities of the failure. Further, failure to follow a mutually agreed
action plan could become a topic of exploration for audit staff. As
telecommunications repairs are generally not in the scope of expertise of electrical
generators, this places the entities at the mercy of contractor repair schedules,
making following any mutually agreed action problematic.
Response: The RCSDT notes that the purpose of consulting with the appropriate
entities ensures those entities are aware of the loss of Interpersonal Communication
capabilities and will have the necessary information to adjust reliability operations
accordingly. There is nothing in Requirement R11 preventing the Distribution
Provider or Generator Operator from taking action beforehand. No change made.
Further, there is no duration trigger on R11, as opposed to the RC/TO/BA
requirement in R10. This forces the generator to inform the listed entities even of
losses of capability which last a handful of seconds. If a small generator has a single
line into the control room, and the control room operator is on the phone to the TOP,
does he then have to inform the TO and BA at the end of the call that they would
have received a busy signal? If the operator knocks the phone from the cradle, is the
requirement to inform triggered? In a strict reading of the language, it would be.
Suggested rewrite of R11:
"Upon discovery of an unresolved loss of interpersonal communications which has
the potential to last more than 15 minutes, the GOP shall inform the entities listed in
R8 of the status of interpersonal communications. The GOP shall initiate the process
to restore the interpersonal communications, and inform the entities listed in R8 of
the restoration of communications when repairs are complete."
Response: The RCSDT notes that the requirement allows flexibility for the
Distribution Provider and Generator Operator to define what constitutes a failure of
its Interpersonal Communication capability. The RCSDT believes it is inappropriate to
Consideration of Comments: Project 2006-06 (Draft 6)
66
Organization
Yes or No
Question 4 Comment
establish a single-defined threshold applicable to the numerous entities applicable to
this standard. No change made.
Response: Please see responses above.
Tacoma Power
R9 - The Standard requires that when there is a failure to a primary or alternate
communication system that action is initiated within 2 hours of the communication
failure. It is not clear what the term “action” means. Tacoma requests clarification
for what “actions” are intended by the standard.
Response: The RCSDT notes that the requirement is for the entity to “initiate action,”
which may include, but is not limited to, notifying or requesting repair to restore the
capability. The option is to designate an Alternative Interpersonal Communication
capability. Additionally, there is no time constraint for the Interpersonal
Communication capability, only the AIC. No change made.
R10 - Interpersonal Communication is defined as “any medium that allows two or
more individuals to interact, consult, or exchange information”. As it is written, R10
requires an entity to contact another entity “within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasts 30 minutes or longer”.
This contact may not be possible in a situation where there is “a failure of
Interpersonal Communication capability”.
Response: The RCSDT notes that the responsible entities named in Requirement R10
are also required to have a designated Alternative Interpersonal Communication
capability and should be able to make the necessary notifications. No change made.
R11 – The lack of a time line in R11 seems inconsistent with the time line
requirements in R9 and R10. If there is a communication failure affecting the GO and
DP then the standard only requires that they agree on an action to restore
communication but does not assign a timeline.
Response: The RCSDT notes that the requirement allows flexibility for the
Distribution Provider and Generator Operator to define what constitutes a failure of
Consideration of Comments: Project 2006-06 (Draft 6)
67
Organization
Yes or No
Question 4 Comment
its Interpersonal Communication capability. The RCSDT believes it is inappropriate to
establish a single-defined threshold applicable to the numerous entities applicable to
this standard. No change made.
Response: Please see responses above.
LG&E and KU Services
Regarding COM-001-2 and proposed definitions, LG&E and KU Services recommends
changing the terms being defined from “Interpersonal Communications” and
“Alternative Interpersonal Communication” to “Means for Interpersonal
Communication” and “Alternative Means for Interpersonal Communication.” A
communication is an exchange of information, not a medium. The medium is simply
the means. LG&E and KU Services Company further recommend that each
requirement be rewritten with these new defined terms as appropriate and that the
word “capabilities” currently following the defined terms be removed from each of
the requirements.
Response: The RCSDT notes that commenters recommended using the terms, such
as, “primary,” “secondary,” “device,” “means,” and “medium” with regard to the
proposed definitions. The RCSDT thanks you for your suggestion; however, the
requirements are for “capability” and adding such proposed terms is not needed to
achieve the necessary clarity. No change made.
We suggest the definition for “Means for Interpersonal Communication” be: “A
medium utilizing electromagnetic energy that allows two or more individuals to
interact, consult or exchange information.”We suggest the definition for “Alternative
Means for Interpersonal Communication” be: “Any Means for Interpersonal
Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Means for Interpersonal Communications used for dayto-day operation.” Regarding R1 through R10, it is unclear what “shall have
Interpersonal Communications capability” means. That could mean that the
responsible entity simply has to have an IC capability that is different from our
designated AIC capability (as R1 through R8 suggest). That could also mean,
Consideration of Comments: Project 2006-06 (Draft 6)
68
Organization
Yes or No
Question 4 Comment
differently, that the responsible entity has to designate an IC capability (as R10
suggests). It is also unclear whether the IC capability can change, e.g. from email to
land line. There is nothing in the Standard that makes this clear. Regarding R11, as
written it is unclear who would be responsible for non-compliance if the consulting
entities did not “determine a mutually agreeable action for the restoration of its
Interpersonal Communication capability.”
Response: The RCSDT believes the definitions and requirements are clear and does
not agree with the proposed definition changes. The requirements and definition
allow the entity to determine the medium. No change made.
Response: Please see responses above.
City of Tallahassee (TAL)
TAL has no comments on COM-001-2.
However, for COM-002-3, under Data Retention, the second bullet requires the BA,
TOP, GOP, and DP to retain evidence for R1, M1; however, R1 is not applicable to the
GOP or DP. This should read R2, M2.
Response: The RCSDT agrees with your assessment that R1 and M1 should be R2 and
M2. The RCSDT has advised NERC staff of the typo in COM-002-3.
Also, there is room for debate on the clarity of the VSLs for R3. Specifically, the use of
the word "accurately" could be interpreted to mean "verbatim" in cases where
varying verbiage results in the same understanding and action between the parties,
and therefore no re-issuance of the directive is required in the eyes of the issuer.
Response: The standard COM-002-3 was approved by industry in July 2012;
therefore, the RCSDT is not able to respond to the City of Tallahassee’s comment to
consider changes to the standard. No change made.
Response: Please see responses above.
American Electric Power
The definition of Alternative Interpersonal Communication is “Any Interpersonal
Consideration of Comments: Project 2006-06 (Draft 6)
69
Organization
Yes or No
Question 4 Comment
Communication that is able to serve as a substitute for, and does not utilize the same
infrastructure (medium) as, Interpersonal Communication used for day-to-day
operation.” Does the Alternative Interpersonal Communication have to be a different
technology? For example, if a satellite phone is used, but it calls the same land-line
on the other end, does this qualify as Alternative Interpersonal Communication?
Response: The proposed definitions only specify that the alternative has to utilize a
separate medium. The standard is not technology dependent and allows entities
flexibility in selecting the capability appropriate for its need. No change made.
How does a TOP notify a DP of a failure in its Interpersonal Communications
capability per R10, if it there is no Alternative Interpersonal Communication
required? Within Requirement 10, the entities to be notified should not reference R1,
R3, and R5 but should instead reference R2, R4, and R6 respectively. This change is
necessary because the requirements we are referring to are those that have
Alternative Interpersonal Communications. You cannot expect notification to entities
where an Alternative Interpersonal Communication does not exist.
Response: The RCSDT notes that Requirement R10 applies to the TOP and that the
TOP is required to have AIC per Requirement R4. The RCSDT disagrees with the
suggested change in the requirement references because the current references are
specific to the entities that apply to the Interpersonal Communication capability. No
change made.
With regard to the requirement references in R10, the RCSDT agrees with the
ambiguity in both the Requirement R10 and Measure M10 and proposes to clarify
Requirement R10, Measure M10, and R10 VSL by inserting the word “respectively.”
For example, adding the word “respectively” means that the Reliability Coordinator in
R1 is not required to notify the entities identified in Requirement R3 or R5. The
RCSDT intended the requirements to map to the entity. Clarifying changes made.
Response: Please see the responses above.
Consideration of Comments: Project 2006-06 (Draft 6)
70
Organization
Exelon Corporation and its
affiliates
Yes or No
Question 4 Comment
The definition of Interpersonal Communication requires further clarification. The use
of the term “Any medium” opens the definition up to broad interpretation. It’s not
clear whether the definition means to apply to the point of communication owned,
managed, and operated by the entity, or the total communications pathway? For
example if entity A’s phone system is working fine, but Entity B is experiencing
trouble, does Entity A have a compliance concern if Entity B experiences a
communication breakdown on their end of the medium?
Please provide greater insight on the intended compliance obligation and consider
the following revision to the definition:
Interpersonal Communication: Any medium, owned, managed, or operated by the
applicable entity, that allows two or more individuals to interact, consult, or
exchange information.
Response: The RCSDT notes that each requirement does not prescribe the “how,”
“why,” “who,” or “where” concerning the failure or loss of its Interpersonal
Communication (or Alternative Interpersonal Communication) capability. It is the
responsibility of the applicable entity to perform the “what” of each requirement.
There is no compliance risk based on the “how,” “why,” “who,” or “where.” No
change made.
The RCSDT appreciates the suggested changes to the defined term. The suggestion
introduces specifics which make the definition less flexible and more prescriptive.
Such a change could potentially be invalidated by the way an entity operates in the
future. No change made.
R9 provides ambiguous instruction for the resolution process surrounding tests and
failures of Alternative Interpersonal Communication capability. Please confirm
whether the intent of the requirement is to initiate repairs within two hours, or to
effect repairs within two hours, with the alternate option being to designate a
replacement Alternative Interpersonal Communication if repairs cannot be
completed within two hours.
Consideration of Comments: Project 2006-06 (Draft 6)
71
Organization
Yes or No
Question 4 Comment
Response: The RCSDT notes that the requirement is for the entity to “initiate action,”
which may include, but is not limited to, notifying or request repair to restore the
capability. The option is to designate an Alternative Interpersonal Communication
capability. No change made.
R10 has similar ambiguity, referencing a 60 minute notification timeframe
requirement upon the detection of a failure lasting 30 minutes or longer. Please
confirm the intended start of the requirement notification. Does the clock for
notification begins at the point of failure, at the point of discovery, or at the point
that the failure is discovered to have been effective for 30 minutes or greater? Thank
you for the opportunity to comment.
Response: The RCSDT notes the 60-minute clock starts at the point the failure has
reached the 30-minute threshold. This is to allow time for intermittent failures to be
resolved. No change made.
Response: Please see the responses above.
ISO/RTO Standards Review
Committee
The IRC continues to believe that these a certification types of requirements and that
they do not belong in a standard.
The SRC believes that the requirement to have a medium to communicate should be
required to be certified.
Response: NERC maintains an Organization Certification Program, the goal of which
is to ensure that organizations who apply to register or are registered to perform
certain reliability functions deemed particularly crucial to the reliability of the bulk
power system will meet or exceed certain minimum criteria (i.e., Reliability
Standards) demonstrating they are capable of performing the tasks (i.e.,
Requirements) for these functions. The process for certification of organizations is
included in the NERC Rules of Procedure, Section 500 and Appendix 5A. For example,
the first paragraph of Section 500 – Organization Registration and Certification states:
“The purpose of the Organization Registration Program is to clearly identify those
Consideration of Comments: Project 2006-06 (Draft 6)
72
Organization
Yes or No
Question 4 Comment
entities that are responsible for compliance with the FERC approved reliability
standards. Organizations that are registered are included on the NERC Compliance
Registry (NCR) and are responsible for knowing the content of and for complying with
all applicable reliability standards…” The RCSDT has addressed the scope of the SAR
in addressing communication requirements for entities through an open industry
consensus process. No change made.
When you are operating as a registered entity, the requirements should be
performance based such as taking corrective actions and if you fail to communicate
for any reason you will be found non-compliance. The lack of a communication
medium should not be a defense for non-compliance of the performance based
standards.
Response: The RCSDT thanks you for your comment. Although this standard is not a
Results-Based Standard (RBS), it achieves the need to require both Interpersonal
Communication and Alternative Interpersonal Communication capability of the
applicable entities to ensure reliable operations of the Bulk Electric System. The
RCSDT believes the requirements achieve the needed level of communications to
ensure reliable operations. No change made.
The SDT should require reporting times of failed mediums for GOP and DP similar to
that for RC/BA/TOP.
Response: The RCSDT notes that the requirement allows flexibility for the
Distribution Provider and Generator Operator to define what constitutes a failure of
its Interpersonal Communication capability. The RCSDT believes it is inappropriate to
establish a single-defined threshold applicable to the numerous entities applicable to
this standard. No change made.
Response:
ISO New England Inc
The ISO-NE continues to believe that these a certification types of requirements and
that they do not belong in a standard.
Consideration of Comments: Project 2006-06 (Draft 6)
73
Organization
Yes or No
Question 4 Comment
ISO-NE believes that the requirement to have a medium to communicate should be
required to be certified.
Response: NERC maintains an Organization Certification Program, the goal of which
is to ensure that organizations who apply to register or are registered to perform
certain reliability functions deemed particularly crucial to the reliability of the bulk
power system will meet or exceed certain minimum criteria (i.e., Reliability
Standards) demonstrating they are capable of performing the tasks (i.e.,
Requirements) for these functions. The process for certification of organizations is
included in the NERC Rules of Procedure, Section 500 and Appendix 5A. For example,
the first paragraph of Section 500 – Organization Registration and Certification states:
“The purpose of the Organization Registration Program is to clearly identify those
entities that are responsible for compliance with the FERC approved reliability
standards. Organizations that are registered are included on the NERC Compliance
Registry (NCR) and are responsible for knowing the content of and for complying with
all applicable reliability standards…” The RCSDT has addressed the scope of the SAR
in addressing communication requirements for entities through an open industry
consensus process. No change made.
When you are operating as a registered entity, the requirements should be
performance based such as taking corrective actions and if you fail to communicate
for any reason you will be found non-compliance. The lack of a communication
medium should not be a defense for non compliance of the performance based
standards.
Response: The RCSDT thanks you for your comment. Although this standard is not a
Results-Based Standard (RBS), it achieves the need to require both Interpersonal
Communication and Alternative Interpersonal Communication capability of the
applicable entities to ensure reliable operations of the Bulk Electric System. The
RCSDT believes the requirements achieve the needed level of communications to
ensure reliable operations. No change made.
The SDT should require reporting times of failed mediums for GOP and DP similar to
Consideration of Comments: Project 2006-06 (Draft 6)
74
Organization
Yes or No
Question 4 Comment
that for RC/BA/TOP.
Response: The RCSDT notes that the requirement allows flexibility for the
Distribution Provider and Generator Operator to define what constitutes a failure of
its Interpersonal Communication capability. The RCSDT believes it is inappropriate to
establish a single-defined threshold applicable to the numerous entities applicable to
this standard. No change made.
Response: Please see responses above.
SERC OC Standards Review
Group
The SERC OC SRG would like to thank the Standard Drafting Team for their
service.”The comments expressed herein represent a consensus of the views of the
above named members of the SERC OC Standards Review group only and should not
be construed as the position of SERC Reliability Corporation, its board or its officers.”
Response: The RCSDT thanks you for your support.
SPP Standards Review Group
There are a couple of cut & paste errors in the VSLs for R3 and R5.
In R3, Reliability Coordinator in the High and Severe VSLs should be replaced with
Transmission Operator.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R3 VSL. The reference to “Reliability Coordinator” has been changed to
Transmission Operator for Requirement R3 in both the High and Severe VSL. Error
correction made.
In R5, Reliability Coordinator in the High and Severe VSLs should be replaced with
Balancing Authority.
Response: The RCSDT appreciates you bringing awareness to this error in
Requirement R5. The reference to “Reliability Coordinator” has been changed to
Balancing Authority for Requirement R5 in both the High and Severe VSL. Error
correction made.
Consideration of Comments: Project 2006-06 (Draft 6)
75
Organization
Yes or No
Question 4 Comment
Response: Please see responses above.
PacifiCorp
N/A
Arizona Public Service
Company
None
END OF REPORT
Consideration of Comments: Project 2006-06 (Draft 6)
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To establish Interpersonal Communication capabilities necessary to
maintain reliability.
4.
Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal Communication capability with
the following entities (unless the Reliability Coordinator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
1.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communication capability with
the following entities (unless the Transmission Operator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
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Standard COM-001-2 — Communications
3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
5.1.
Its Reliability Coordinator.
5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.3.
Each Distribution Provider within its Balancing Authority Area.
5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
5.5.
Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
1.1.
Its Reliability Coordinator.
1.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
1.3.
Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider detects a failure of its Interpersonal
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]
7.1.
Its Balancing Authority.
7.2.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator detects a failure of its Interpersonal
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Standard COM-001-2 — Communications
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5, respectively within 60
minutes of the detection of a failure of its Interpersonal Communication capability that
lasts 30 minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
R11. Each Distribution Provider and Generator Operator that detects a failure of its
Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communication capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with each adjacent
Reliability Coordinator within the same Interconnection, which could include, but is
not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with each adjacent Reliability Coordinator within the same Interconnection,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R2.)
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Standard COM-001-2 — Communications
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
or synchronously connected, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Transmission Operator and its
Balancing Authority, which could include, but is not limited to:
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Standard COM-001-2 — Communications
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detected a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generator Operator, to
determine mutually agreeable action to restore the Interpersonal Communication
capability. Evidence could include, but is not limited to: dated operator logs, voice
recordings, transcripts of voice recordings, or electronic communications. (R11.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
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Standard COM-001-2 — Communications
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
The Reliability Coordinator for Requirements R1, R2, R9, and R10,
Measures M1, M2, M9, and M10 shall retain written documentation for the
most recent twelve calendar months and voice recordings for the most recent
90 calendar days.
The Transmission Operator for Requirements R3, R4, R9, and R10,
Measures M3, M4, M9, and M10 shall retain written documentation for the
most recent twelve calendar months and voice recordings for the most recent
90 calendar days.
The Balancing Authority forRequirements R5, R6, R9, and R10, Measures
M5, M6, M9, and M10 shall retain written documentation for the most
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
The Distribution Provider for Requirements R7 and R11, Measures M7 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
The Generator Operator for Requirements R8 and R11, Measures M8 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, or Generator Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Page 6 of 11
2.
R#
R1
R2
R3
R4
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
High VSL
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Transmission
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
N/A
N/A
Severe VSL
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Standard COM-001-2 — Communications
R#
R5
R6
R7
Lower VSL
N/A
N/A
N/A
Moderate VSL
High VSL
Severe VSL
N/A
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
N/A
N/A
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Standard COM-001-2 — Communications
R#
R8
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R11.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 2 hours
and less than or equal to 4 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 4 hours
and less than or equal to 6 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 6 hours
and less than or equal to 8 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to test the Alternative
Interpersonal Communication
capability once each calendar month.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
OR
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 8 hours
upon an unsuccessful test.
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Standard COM-001-2 — Communications
R#
R11
Lower VSL
N/A
Moderate VSL
N/A
High VSL
N/A
Severe VSL
The Distribution Provider or
Generator Operator that detected a
failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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Standard COM-001-2 — Communications
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Standard COM-001-2 — Communications
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
November 7, 2012
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Replaced R1
with R1-R8; R2
replaced by R9; R3
included within new
R1; R4 remains enforce
pending Project 200702; R5 redundant with
EOP-008-0, retiring R5
as redundant with
EOP-008-0, R1;
retiring R6, relates to
ERO procedures; R10
& R11, new.
1.1
2
Page 11 of 11
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R8
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R11.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 2 hours
and less than or equal to 4 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 4 hours
and less than or equal to 6 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 6 hours
and less than or equal to 8 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to test the Alternative
Interpersonal Communication
capability once each calendar month.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
Draft 7: September 4, 2012
OR
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 8 hours
upon an unsuccessful test.
Page 12 of 14
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R11
Lower VSL
N/A
Draft 7: September 4, 2012
Moderate VSL
N/A
High VSL
N/A
Severe VSL
The Distribution Provider or
Generator Operator that detected a
failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised in accordance with SAR for
Project 2006-06, Reliability
Coordination (RC SDT). Replaced R1
with R1-R8; R2 replaced by R9; R3
included within new R1; R4 remains
enforce pending Project 2007-02; R5
redundant with EOP-008-0, retiring R5
as redundant with EOP-008-0, R1;
retiring R6, relates to ERO procedures;
R10 & R11, new.
Revised
Draft 7: September 4, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. Draft SAR Version 1 posted January 15, 2007.
2. Draft SAR Version 1 Comment Period ended February 14, 2007.
3. Draft SAR Version 2 and comment responses on SAR version 1 posted March 19, 2007.
4. Draft Version 2 SAR comment period ended April 17, 2007.
5. SAR version 2 and comment responses for SAR version 2 accepted by SC and SDT
appointed in June 2007.
6. First posting of revised standards on August 5, 2008 with comment period closed on
September 16, 2008.
7. Draft Version 2 of standards and response to comments September 16, 2008–May 26,
2009.
8. Second posting of revised standards on July 10, 2009 with comment period closed on
August 9, 2009.
9. RC SDT coordinated with OPCP SDT and RTO SDT on definitions relating to directives
and three part communication and Draft Version 3 of standards and response to
comments August 9–November 20, 2009.
10. Third posting of revised standards on January 4, 2010 with comment period closed on
February 18, 2010.
11. Fourth posting of revised standards on January 25, 2011 with comment period closed on
March 7, 2011.
12. Initial ballot conducted February 25 through March 7, 2011.
13. Draft version 5 of the standard and response to comments March 7, 2011 – January 9,
2012.
14. Fifth posting of revised standards on January 9, 2012 with comment period closed on
February 9, 2012.
15. Successive ballot conducted January 30 through February 9, 20112012.
16. Draft version 6 of the standard and response to comments February 9, 2011 2012 – June
57, 2012.
17. Sixth posting of revised standard on June 7, 2012 with comment period closed on July 6,
2012.
18. Successive ballot conducted June 27 through July 6, 2012.
19. DraftRevised version 6 of the standard and response to comments July 6, 20112 – July
XXSeptember 5, 2012.
Draft 7: July 19September 4, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
20. Recirculation ballot conducted July XXSeptember 5 through August XXSeptember 14,
2012.
Proposed Action Plan and Description of Current Draft:
The SDT began working on revisions to the standards in August 2007. The current posting
contain revisions based on stakeholder comments on the initial ballot. The team is posting for a
successive ballot.
Future Development Plan:
Anticipated Actions
1. Post standards for a successive ballot.
2. Respond to comments on successive ballot.
3. Standard posted for second successive ballot.
Anticipated Date
January-February 2012
March - April 2012
June 2012
4. Standard posted for recirculation ballot.
September 2012
5. Standard to be sent to BOT for approval.
November 2012
6. Standard filed with regulatory authorities.
January 2013
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
The RC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to
interact, consult, or exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is
able to serve as a substitute for, and does not utilize the same infrastructure (medium) as,
Interpersonal Communication used for day-to-day operation.
Draft 7: July 19September 4, 2012
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
A. Introduction
1.
Title:
Communications
2.
Number:
COM-001-2
3.
Purpose: To establish Interpersonal Communication capabilities necessary to
maintain reliability.
4.
Applicability:
4.1. Transmission Operator
4.2. Balancing Authority
4.3. Reliability Coordinator
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1. Each Reliability Coordinator shall have Interpersonal Communication capability with
the following entities (unless the Reliability Coordinator detectsexperiences a failure of
its Interpersonal Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High] [Time Horizon: Real-time Operations]
1.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
1.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
2.1.
All Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communication capability with
the following entities (unless the Transmission Operator detectsexperiences a failure of
its Interpersonal Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority detectsexperiences a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
5.1.
Its Reliability Coordinator.
5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.3.
Each Distribution Provider within its Balancing Authority Area.
5.4.
Each Generator Operator that operates Facilities within its Balancing Authority
Area.
5.5.
Each Aadjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time Operations]
6.1.
Its Reliability Coordinator.
6.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
6.3.
Each Aadjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider detectsexperiences a failure of its
Interpersonal Communication capability in which case Requirement R11 shall apply):
[Violation Risk Factor: MediumHigh] [Time Horizon: Real-time Operations]
7.1.
Its Balancing Authority.
7.2.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator detectsexperiences a failure of its
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Interpersonal Communication capability in which case Requirement R11 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5, respectively within 60
minutes of the detection of a failure of its Interpersonal Communication capability that
lasts 30 minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
R11. Each Distribution Provider and Generator Operator that detectsexperiences a failure of
its Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator shall have and provide upon request evidence that it has
Interpersonal Communication capability with all Transmission Operators and
Balancing Authorities within its Reliability Coordinator Area and with each adjacent
Reliability Coordinator within the same Interconnection, which could include, but is
not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R1.)
M2. Each Reliability Coordinator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with all
Transmission Operators and Balancing Authorities within its Reliability Coordinator
Area and with each adjacent Reliability Coordinator within the same Interconnection,
which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R2.)
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
orand synchronously connected, which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that that it
has Interpersonal Communication capability with its Transmission Operator and its
Balancing Authority, which could include, but is not limited to:
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•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to:
•
physical assets, or
•
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to: dated and time-stamped: test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer.
Evidence could include, but is not limited to: dated and time-stamped: test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detectedexperienced a failure
of its Interpersonal Communication capability shall have and provide upon request
evidence that it consulted with each entity affected by the failure, as identified in
Requirement R7 for a Distribution Provider or Requirement R8 for a Generator
Operator, to determine mutually agreeable action to restore the Interpersonal
Communication capability. Evidence could include, but is not limited to: dated:
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R11.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Draft 7: July 19September 4, 2012
Page 8 of 16
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
1.2. Compliance Monitoring and Enforcement Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
The Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, and Generator Operator shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•
The Reliability Coordinator forshall retain evidence of Requirements R1,
R2, R9, and R10, Measures M1, M2, M9, and M10 shall retain written
documentation for the most recent twelve calendar months and voice
recordings for the most recent 90 calendar days.
•
The Transmission Operator forshall retain evidence of Requirements R3,
R4, R9, and R10, Measures M3, M4, M9, and M10 shall retain written
documentation for the most recent twelve calendar months and voice
recordings for the most recent 90 calendar days.
•
The Balancing Authority forRequirements shall retain evidence of
Requirements R5, R6, R9, and R10, Measures M5, M6, M9, and M10 shall
retain written documentation for the most recent twelve calendar months
and voice recordings for the most recent 90 calendar days.
•
The Distribution Provider forshall retain evidence of Requirements R7 and
R11, Measures M7 and M11 shall retain written documentation for the most
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
•
The Generator Operator forshall retain evidence of Requirements R8 and
R11, Measures M8 and M11 shall retain written documentation for the most
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Distribution Provider, or Generator Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time specified above, whichever is longer.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.4. Additional Compliance Information
None.
Draft 7: July 19September 4, 2012
Page 10 of 16
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
2.
R#
R1
R2
R3
Violation Severity Levels
Lower VSL
Moderate VSL
N/A
N/A
Draft 6: April 6, 2012
Page 11 of 16
Severe VSL
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detectedexperienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator
detectedexperienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
N/A
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator
detectedReliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Transmission
Operator detectedReliability
Coordinator experienced a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.
N/A
N/A
High VSL
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R4
R5
R6
Lower VSL
Moderate VSL
N/A
N/A
N/A
N/A
N/A
Draft 6: April 6, 2012
N/A
Page 12 of 16
High VSL
Severe VSL
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Balancing Authority
detectedReliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detectedReliability Coordinator
experienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R7
R8
Lower VSL
Moderate VSL
N/A
N/A
N/A
Draft 6: April 6, 2012
N/A
Page 13 of 16
High VSL
Severe VSL
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detectedexperienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider
detectedexperienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detectedexperienced a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator
detectedexperienced a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 2 hours and less than or
equal to 4 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 4 hours and less than or
equal to 6 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in
more than 6 hours and less than or
equal to 8 hours upon an
unsuccessful test.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority failed to test the
Alternative Interpersonal
Communication capability once each
calendar month.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5, respectively upon
the detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5, respectively upon
the detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority failed to notify
the entities identified in Requirements
R1, R3, and R5, respectively upon
the detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority failed to notify
the identified entities identified in
Requirements R1, R3, and R5,
respectively upon the detection of a
failure of its Interpersonal
Communication capability in more
than 90 minutes.
Draft 6: April 6, 2012
Page 14 of 16
OR
The Reliability Coordinator,
Transmission Operator, orand
Balancing Authority tested the
Alternative Interpersonal
Communication capability but failed
to initiate action to repair or designate
a replacement Alternative
Interpersonal Communication in more
than 8 hours upon an unsuccessful
test.
S ta n d a rd COM-001-2 — Co m m u nic a tio n s
R#
R11
Lower VSL
Moderate VSL
N/A
Draft 6: April 6, 2012
N/A
Page 15 of 16
High VSL
Severe VSL
N/A
The Distribution Provider or
Generator Operator that
detectedexperienced a failure of its
Interpersonal Communication
capability failed to consult with each
entity affected by the failure, as
identified in Requirement R7 for a
Distribution Provider or Requirement
R8 for a Generator Operator, to
determine a mutually agreeable
action for the restoration of the
Interpersonal Communication
capability.
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S ta n d a rd COM-001-2 — Co m m u nic a tio n s
E. Regional Differences
None identified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
2
TBD
Revised in accordance with SAR for
Project 2006-06, Reliability
Coordination (RC SDT). Replaced R1
with R1-R8; R2 replaced by R9; R3
included within new R1; R4 remains
enforce pending Project 2007-02; R5
redundant with EOP-008-0, retiring R5
as redundant with EOP-008-0, R1;
retiring R6, relates to ERO procedures;
R10 & R11, new.
Revised
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Standard COM-001-2 — Communications
A. Introduction
1.
Title:
TelecommunicationsCommunications
2.
Number:
COM-001-1.12
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating informationTo establish Interpersonal
Communication capabilities necessary to maintain reliability.
4.
Applicability:
4.1. Transmission Operators.Operator
4.2. Balancing Authorities.Authority
4.3. Reliability Coordinators.Coordinator
4.4. NERCNet User Organizations.
5.
Effective Date:
May 13, 2009
4.4. Distribution Provider
4.5. Generator Operator
5.
Effective Date:
The first day of the second calendar quarter beyond the date that
this standard is approved by applicable regulatory authorities, or in those jurisdictions
where regulatory approval is not required, the standard becomes effective on the first
day of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1. Between shall have Interpersonal Communication capability with the following entities
(unless the Reliability Coordinator and itsdetects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
R1.2.
All Transmission Operators and Balancing Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
1.1.
Each within its Reliability Coordinator, Transmission Operator, and Balancing
Authority shall manage, alarm, test and/or actively monitor vital telecommunications
facilities. Special attention shall be given to emergency telecommunications facilities
and equipment not used for routine communications Area.
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Standard COM-001-2 — Communications
R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
1.2.
Unless agreed to otherwise, each Each adjacent Reliability Coordinator within the
same Interconnection.
R2. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use
English as the language for all communications between and among operating personnel
responsible for the real shall designate an Alternative Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High] [Time Horizon:
Real-time generation control and operation of the interconnected Bulk Electric System.
Operations]
R3. 2.1.
All Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
Eachwithin its Reliability Coordinator, Area.
2.2.
Each adjacent Reliability Coordinator within the same Interconnection.
R3. Each Transmission Operator shall have Interpersonal Communication capability with
the following entities (unless the Transmission Operator detects a failure of its
Interpersonal Communication capability in which case Requirement R10 shall apply):
[Violation Risk Factor: High] [Time Horizon: Real-time Operations]
3.1.
Its Reliability Coordinator.
3.2.
Each Balancing Authority within its Transmission Operator Area.
3.3.
Each Distribution Provider within its Transmission Operator Area.
3.4.
Each Generator Operator within its Transmission Operator Area.
3.5.
Each adjacent Transmission Operator, and synchronously connected.
3.6.
Each adjacent Transmission Operator asynchronously connected.
R4. Each Transmission Operator shall designate an Alternative Interpersonal
Communication capability with the following entities: [Violation Risk Factor: High]
[Time Horizon: Real-time Operations]
4.1.
Its Reliability Coordinator.
4.2.
Each Balancing Authority within its Transmission Operator Area.
4.3.
Each adjacent Transmission Operator synchronously connected.
4.4.
Each adjacent Transmission Operator asynchronously connected.
R5. Each Balancing Authority shall have Interpersonal Communication capability with the
following entities (unless the Balancing Authority detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
5.1.
Its Reliability Coordinator.
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Standard COM-001-2 — Communications
5.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
5.1.5.3. Each Distribution Provider within its Balancing Authority shall have written
operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilitiesArea.
5.4.
Each NERCNet User OrganizationGenerator Operator that operates Facilities
within its Balancing Authority Area.
5.5.
Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall adhere to designate an Alternative Interpersonal
Communication capability with the requirementsfollowing entities: [Violation Risk
Factor: High] [Time Horizon: Real-time Operations]
1.1.
Its Reliability Coordinator.
1.2.
Each Transmission Operator that operates Facilities within its Balancing
Authority Area.
1.3.
Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication capability with the
following entities (unless the Distribution Provider detects a failure of its Interpersonal
Communication capability in Attachment which case Requirement R11 shall apply):
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
7.1-COM-001, “NERCNet Security Policy.”. Its Balancing Authority.
7.2.
Its Transmission Operator.
R8. Each Generator Operator shall have Interpersonal Communication capability with the
following entities (unless the Generator Operator detects a failure of its Interpersonal
Communication capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High] [Time Horizon: Real-time Operations]
8.1.
Its Balancing Authority.
8.2.
Its Transmission Operator.
R9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
test its Alternative Interpersonal Communication capability at least once each calendar
month. If the test is unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication capability within 2
hours. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations, Sameday Operations]
R10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
notify entities as identified in Requirements R1, R3, and R5, respectively within 60
minutes of the detection of a failure of its Interpersonal Communication capability that
lasts 30 minutes or longer. [Violation Risk Factor: Medium] [Time Horizon: Realtime Operations]
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Standard COM-001-2 — Communications
R11. Each Distribution Provider and Generator Operator that detects a failure of its
Interpersonal Communication capability shall consult each entity affected by the
failure, as identified in Requirement R7 for a Distribution Provider or Requirement R8
for a Generator Operator, to determine a mutually agreeable action for the restoration
of its Interpersonal Communication capability. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have
and provide upon request evidence that it has Interpersonal Communication capability
with all Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area and with each adjacent Reliability Coordinator within the same
Interconnection, which could include, but is not limited to communication facility testprocedure documents, records of testing, and maintenance records for communication
facilities:
physical assets, or equivalent that will be used to confirm that it manages, alarms, tests
and/or actively monitors vital telecommunications facilities. (Requirement 2 part 1)
The Reliability Coordinator, Transmission Operator or Balancing Authority shall have
and provide upon requestdated evidence that could include, but is not limited to, such
as, equipment specifications and installation documentation, test records, operator
logs, voice recordings or, transcripts of voice recordings, or electronic
communications, or equivalent, that will be used to determine compliance to
Requirement 4.. (R1.)
M1.M2.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
have and provide upon request its current operating instructions and procedures, either
electronic or hard copy that will be used to confirm that it meets Requirement 5. shall have
and provide upon request evidence that it designated an Alternative Interpersonal
Communication capability with all Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area and with each adjacent Reliability Coordinator
within the same Interconnection, which could include, but is not limited to:
The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to documented proceduresphysical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings or, transcripts of voice recordings, or
electronic communications. (R2.)
M3. Each Transmission Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Balancing Authority, Distribution Provider, and Generator Operator within its
Transmission Operator Area, and each adjacent Transmission Operator asynchronously
or synchronously connected, which could include, but is not limited to:
physical assets, or
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Standard COM-001-2 — Communications
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings,
electronic communications, etcor electronic communication. (R3.)
M4. Each Transmission Operator shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Balancing Authority within its Transmission Operator Area, and
each adjacent Transmission Operator asynchronously and synchronously connected,
which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R4.)
M5. Each Balancing Authority shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Reliability Coordinator, each
Transmission Operator and Generator Operator that operates Facilities within its
Balancing Authority Area, each Distribution Provider within its Balancing Authority
Area, and each adjacent Balancing Authority, which could include, but is not limited
to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R5.)
M6. Each Balancing Authority shall have and provide upon request evidence that it
designated an Alternative Interpersonal Communication capability with its Reliability
Coordinator, each Transmission Operator that operates Facilities within its Balancing
Authority Area, and each adjacent Balancing Authority, which could include, but is not
limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R6.)
M7. Each Distribution Provider shall have and provide upon request evidence that will be
usedit has Interpersonal Communication capability with its Transmission Operator and
its Balancing Authority, which could include, but is not limited to:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R7.)
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Standard COM-001-2 — Communications
M8. Each Generator Operator shall have and provide upon request evidence that it has
Interpersonal Communication capability with its Balancing Authority and its
Transmission Operator, which could include, but is not limited to determine if it adhered:
physical assets, or
dated evidence, such as, equipment specifications and installation documentation,
test records, operator logs, voice recordings, transcripts of voice recordings, or
electronic communications. (R8.)
M2.M9. Each Reliability Coordinator, Transmission Operator, and Balancing Authority
shall have and provide upon request evidence that it tested, at least once each calendar
month, its Alternative Interpersonal Communication capability designated in
Requirements R2, R4, or R6. If the test was unsuccessful, the entity shall have and
provide upon request evidence that it initiated action to the (User Accountability and
Compliance) requirements in Attachment 1-COM-001. (Requirement 6)repair or designated a
replacement Alternative Interpersonal Communication capability within 2 hours.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R9.)
M10. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall
have and provide upon request evidence that it notified entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of the detection of a
failure of its Interpersonal Communication capability that lasted 30 minutes or longer.
Evidence could include, but is not limited to: dated and time-stamped test records,
operator logs, voice recordings, transcripts of voice recordings, or electronic
communications. (R10.)
M11. Each Distribution Provider and Generator Operator that detected a failure of its
Interpersonal Communication capability shall have and provide upon request evidence
that it consulted with each entity affected by the failure, as identified in Requirement
R7 for a Distribution Provider or Requirement R8 for a Generator Operator, to
determine mutually agreeable action to restore the Interpersonal Communication
capability. Evidence could include, but is not limited to: dated operator logs, voice
recordings, transcripts of voice recordings, or electronic communications. (R11.)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring ResponsibilityEnforcement Authority
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
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Standard COM-001-2 — Communications
1.2. Compliance Monitoring and Reset Time FrameEnforcement Processes
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Data Retention
For Measure 1 eachThe Reliability Coordinator, Transmission Operator, Balancing
Authority, Distribution Provider, and Generator Operator shall keep data or
evidence ofto show compliance for the previous two calendar years plus the current
year. as identified below unless directed by its Compliance Enforcement Authority
to retain specific evidence for a longer period of time as part of an investigation:
For Measure 2 eachThe Reliability Coordinator, Transmission Operator for
Requirements R1, R2, R9, and Balancing AuthorityR10, Measures M1, M2,
M9, and M10 shall keepretain written documentation for the most recent
twelve calendar months and voice recordings for the most recent 90 calendar
days of historical data (evidence)..
For Measure 3, each Reliability Coordinator,The Transmission Operator, for
Requirements R3, R4, R9, and R10, Measures M3, M4, M9, and M10 shall
retain written documentation for the most recent twelve calendar months
and voice recordings for the most recent 90 calendar days.
The Balancing Authority shall have its current operating instructions and
procedures to confirm that it meets Requirement 5. forRequirements R5, R6, R9,
and R10, Measures M5, M6, M9, and M10 shall retain written
documentation for the most recent twelve calendar months and voice
recordings for the most recent 90 calendar days.
For Measure 4, eachThe Distribution Provider for Requirements R7 and R11,
Measures M7 and M11 shall retain written documentation for the most
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Standard COM-001-2 — Communications
recent twelve calendar months and voice recordings for the most recent 90
calendar days.
The Generator Operator for Requirements R8 and R11, Measures M8 and
M11 shall retain written documentation for the most recent twelve calendar
months and voice recordings for the most recent 90 calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority and
NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity, Distribution Provider, or Generator Operator is found non-compliant
the entity, it shall keep information related to the noncompliance non-compliance
until found compliantmitigation is complete and approved or for two years plus the
current yeartime specified above, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance MonitorEnforcement Authority shall keep the last periodic audit
reportrecords and all requested and submitted subsequent complianceaudit records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.2
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities as
specified in R5.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
None.
Page 8 of 15
2.
R#
R1
R2
R3
R4
Violation Severity Levels
Lower VSL
N/A
N/A
N/A
N/A
Moderate VSL
High VSL
N/A
The Reliability Coordinator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R1,
Parts 1.1 or 1.2, except when the
Reliability Coordinator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R2,
Parts 2.1 or 2.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Transmission Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R3,
Parts 3.1, 3.2, 3.3, 3.4, 3.5, or 3.6,
except when the Transmission
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R4,
Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3,
or 4.4.
N/A
N/A
Severe VSL
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Standard COM-001-2 — Communications
R#
R5
R6
R7
Lower VSL
N/A
N/A
N/A
Moderate VSL
High VSL
Severe VSL
N/A
The Balancing Authority failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R5,
Parts 5.1, 5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with one of
the entities listed in Requirement R6,
Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with two or
more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or
6.3.
The Distribution Provider failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R7,
Parts 7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement R11.
N/A
N/A
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Standard COM-001-2 — Communications
R#
R8
R9
R10
Lower VSL
Moderate VSL
High VSL
Severe VSL
N/A
N/A
The Generator Operator failed to
have Interpersonal Communication
capability with one of the entities
listed in Requirement R8, Parts 8.1 or
8.2, except when a Generator
Operator detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Generator Operator failed to
have Interpersonal Communication
capability with two or more of the
entities listed in Requirement R8,
Parts 8.1 or 8.2, except when a
Generator Operator detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R11.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 2 hours
and less than or equal to 4 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 4 hours
and less than or equal to 6 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 6 hours
and less than or equal to 8 hours
upon an unsuccessful test.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to test the Alternative
Interpersonal Communication
capability once each calendar month.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 60 minutes
but less than or equal to 70 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 70 minutes
but less than or equal to 80 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 80 minutes
but less than or equal to 90 minutes.
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority failed to notify the entities
identified in Requirements R1, R3,
and R5, respectively upon the
detection of a failure of its
Interpersonal Communication
capability in more than 90 minutes.
OR
The Reliability Coordinator,
Transmission Operator, or Balancing
Authority tested the Alternative
Interpersonal Communication
capability but failed to initiate action
to repair or designate a replacement
Alternative Interpersonal
Communication in more than 8 hours
upon an unsuccessful test.
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Standard COM-001-2 — Communications
R#
R11
Lower VSL
N/A
Moderate VSL
N/A
High VSL
N/A
Severe VSL
The Distribution Provider or
Generator Operator that detected a
failure of its Interpersonal
Communication capability failed to
consult with each entity affected by
the failure, as identified in
Requirement R7 for a Distribution
Provider or Requirement R8 for a
Generator Operator, to determine a
mutually agreeable action for the
restoration of the Interpersonal
Communication capability.
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Standard COM-001-2 — Communications
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Standard COM-001-1.1 — Telecommunications
E. Regional Differences
None Identifiedidentified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
November 7, 2012
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Replaced R1
with R1-R8; R2
replaced by R9; R3
included within new
R1; R4 remains enforce
pending Project 200702; R5 redundant with
EOP-008-0, retiring R5
as redundant with
EOP-008-0, R1;
retiring R6, relates to
ERO procedures; R10
& R11, new.
1.1
2
Page 13 of 15
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Standard COM-001-1.1 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
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Standard COM-001-1.1 — Telecommunications
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation
or reporting requirement of any law enforcement or government body.
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Standard COM-001-1.1 — Telecommunications
E. Regional Differences
None Identifiedidentified.
F. Associated Documents
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 4, 2007
Regulatory Approval — Effective Date
New
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29,
2008TBD
BOT adopted errata changes; updated
version number to “1.1”Revised in
ErrataRevised
1.12
accordance with SAR for Project 200606, Reliability Coordination (RC SDT).
Replaced R1 with R1-R8; R2 replaced
by R9; R3 included within new R1; R4
remains enforce pending Project 200702; R5 redundant with EOP-008-0,
retiring R5 as redundant with EOP-0080, R1; retiring R6, relates to ERO
procedures; R10 & R11, new.
Page 16 of 18
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Standard COM-001-1.1 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and to
a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Page 17 of 18
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Standard COM-001-1.1 — Telecommunications
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation
or reporting requirement of any law enforcement or government body.
Page 18 of 18
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Implementation Plan and Mapping Document
COM-001-2 Communications
Requested Approval
COM-001-2 – Communications
Definition: Interpersonal Communication
Definition: Alternative Interpersonal Communication
Requested Retirement
COM-001-1.1 – Telecommunications, except Requirement R4
Requirement R4 is being revised for inclusion in Standard COM-002-4, Operating Personnel
Communications Protocols and will be requested for retirement upon the effective date
COM-002-4.
Prerequisite Approvals
None.
Defined Terms in the NERC Glossary
The RCSDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication
used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
The RCSDT proposes retiring COM-001-1.1 Requirement R5 as it is redundant with EOP-008-0,
Requirement R1 as well as EOP-008-1 Requirement R1.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1.1 standard proposes retiring four Requirements (R1, R4, R5, and R6).
The COM-001-1.1 standard, Requirement R1 is proposed for replacement with COM-001-2,
Requirements R1, R2, R3, R4, R5, R6, R7, and R8 to achieve clarity to which entities are required to have
to reliable communications. Requirement R2 in COM-001-1.1 will become Requirement R9 in COM001-2. Requirement R3 in COM-001-1.1 is included within Requirement R1 of COM-001-2.
Requirement R4 will remain effective until its inclusion in COM-003-1 that is currently under
development in Project 2007-02 – Operating Personnel Communication Protocols. Requirement R5 in
COM-001-1.1 is redundant with EOP-008-0, Requirement R1 and EOP-008-1, Requirement R1 and is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
proposed for retirement upon the effective date of COM-001-2. The COM-001-1.1 standard,
Requirement R6 is proposed for retirement as it is an ERO procedural requirement and does not impact
reliability. Requirements R10 and R11 are new requirements. Changes were made to eliminate
redundancies between standards (existing and proposed), to align with the ERO Rules of Procedure and
to address known issues and certain directives in FERC Order 693.
Applicable Entities
•
Reliability Coordinator
•
Balancing Authority
•
Transmission Operator
•
Generator Operator
•
Distribution Provider
Effective Date
New or Revised Standards
COM-001-2
The first day of the second calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day
of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard COM-003-1
currently under development.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
2
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New or Revised Definitions
Interpersonal Communication – The first day of the second calendar quarter beyond the date that this
standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective on the first day of the first calendar quarter
beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Alternative Interpersonal Communication – The first day of the second calendar quarter beyond the
date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day of the first calendar
quarter beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
3
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard becomes effective. If the
drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R1. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1. Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1. Internally. [Violation Risk Factor: High]
R1.2. Between the Reliability Coordinator and its Transmission
Operators and Balancing Authorities. [Violation Risk
Factor: High]
R1.3. With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary to
maintain reliability. [Violation Risk Factor: High]
R1.4. Where applicable, these facilities shall be redundant and
diversely routed. [Violation Risk Factor: High]
R1.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R2.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R2.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R3. Each Transmission Operator shall have Interpersonal
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
4
Already Approved Standard
Proposed Replacement Requirement(s)
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply): [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R3.1. Its Reliability Coordinator.
R3.2. Each Balancing Authority within its Transmission Operator
Area.
R3.3. Each Distribution Provider within its Transmission Operator
Area.
R3.4. Each Generator Operator within its Transmission Operator
Area.
R3.5. Each adjacent Transmission Operator synchronously
connected.
R3.6. Each adjacent Transmission Operator asynchronously
connected.
R4. Each Transmission Operator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.1. Its Reliability Coordinator.
R4.2. Each Balancing Authority within its Transmission Operator
Area.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
5
Already Approved Standard
Proposed Replacement Requirement(s)
R4.3. Each adjacent Transmission Operator synchronously
connected.
R4.4. Each adjacent Transmission Operator asynchronously
connected.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable communications.
COM-001-1.1
COM-001-2
R1.
R5. Each Balancing Authority shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R10 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R5.1. Its Reliability Coordinator.
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing Authorities.
[Violation Risk Factor: High]
R5.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R1.3.
R1.4.
With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary
to maintain reliability. [Violation Risk Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation Risk
Factor: High]
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
R5.3. Each Distribution Provider within its Balancing Authority
Area.
R5.4. Each Generator Operator that operates Facilities within its
Balancing Authority Area.
R5.5. Each Adjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
6
Already Approved Standard
Proposed Replacement Requirement(s)
Operations]
R6.1. Its Reliability Coordinator.
R6.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R6.3. Each Adjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R7.1. Its Transmission Operator.
R7.2. Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R11 shall apply): [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1. Its Balancing Authority.
R8.2. Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable interpersonal
communications. Requirements R7 and R8 were created to address the FERC directive (Order No. 693, P508) to “(1) expand the applicability to
include generator operators and distribution providers and includes Requirements for their telecommunications facilities;”
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
7
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation Risk
Factor: Medium]
R9. Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall test its Alternative Interpersonal Communication
capability at least once each calendar month. If the test is
unsuccessful, the responsible entity shall initiate action to repair or
designate a replacement Alternative Interpersonal Communication
capability within 2 hours. [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
Notes:
COM-001-1.1
COM-001-2
R3. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide a means to coordinate
telecommunications among their respective areas. This
coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas. [Violation Risk Factor: Lower]
R1. Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R1.1. All Transmission Operators and Balancing Authorities within
its Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
Notes:
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
None - retire
This requirement is being vetted by the OPCPSDT in Project
8
Already Approved Standard
English as the language for all communications between and
among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
2007-02 – Operating Personnel Communication Protocols
(COM-003-1). This requirement and measure will be removed
from COM-001-1.1 upon the effective date of COM-003-1.
Notes:
COM-001-1.1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall have a plan to continue reliability operations in the
event its control center becomes inoperable. The contingency plan
must meet the following requirements:
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions
and procedures to enable continued operation of the system
during the loss of telecommunications facilities. [Violation Risk
Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be
viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that
there is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control
of critical transmission facilities, generation control, voltage
control, time and frequency control, control of critical
substation devices, and logging of significant power system
events. The plan shall list the critical facilities.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
9
Already Approved Standard
Proposed Replacement Requirement(s)
R1.4. The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with
other areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure
viability of the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating personnel
are able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take
more than one hour to implement the contingency plan for
loss of primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and Transmission
Operator shall have a current Operating Plan describing the
manner in which it continues to meet its functional obligations
with regard to the reliable operations of the BES in the event that
its primary control center functionality is lost. This Operating Plan
for backup functionality shall include the following, at a minimum:
[Violation Risk Factor = Medium] [Time Horizon = Operations
Planning]
1.1.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
The location and method of implementation for providing
backup functionality for the time it takes to restore the
10
Already Approved Standard
Proposed Replacement Requirement(s)
primary control center functionality.
1.2.
A summary description of the elements required to support
the backup functionality. These elements shall include, at a
minimum:
1.2.1. Tools and applications to ensure that System
Operators have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
1.3.
An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4.
Operating Procedures, including decision authority, for use
in determining when to implement the Operating Plan for
backup functionality.
1.5.
A transition period between the loss of primary control
center functionality and the time to fully implement the
backup functionality that is less than or equal to two hours.
1.6.
An Operating Process describing the actions to be taken
during the transition period between the loss of primary
control center functionality and the time to fully implement
backup functionality elements identified in Requirement R1,
Part 1.2. The Operating Process shall include at a minimum:
11
Already Approved Standard
Proposed Replacement Requirement(s)
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the
transition from primary to backup functionality as
well as during outages of the primary or backup
functionality.
1.6.3. Identification of the roles for personnel involved
during the initiation and implementation of the
Operating Plan for backup functionality.
Notes: The RCSDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0, Requirement R1 as well as EOP-008-1
Requirement R1.
COM-001-1.1
R6. Each NERCNet User Organization shall adhere to the
requirements in Attachment 1-COM-001, “NERCNet Security
Policy.” [Violation Risk Factor: Lower]
None – retire
Notes: The RCSDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It should be
included in the ERO Rules of Procedure.
None
New Requirement
R10. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall notify entities as identified in
Requirements R1, R3, and R5, respectively within 60 minutes of
the detection of a failure of its Interpersonal Communication
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
12
Already Approved Standard
Proposed Replacement Requirement(s)
capability that lasts 30 minutes or longer. [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations]
None
New Requirement
R11.Each Distribution Provider and Generator Operator that detects a
failure of its Interpersonal Communication capabilities shall
consult with their Transmission Operator or Balancing Authority to
determine a mutually agreeable action to restore the
Interpersonal Communication capability. [Violation Risk Factor:
Medium][Time Horizon: Real-time Operations]
Notes:
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Communications
Reliability
Coordinator
Balancing
Authority
X
X
Implementation Plan (Draft 7: September 4, 2012)
COM-001-2 Communications
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan and Mapping Document
COM-001-2 Communications
Requested Approval
The RC SDT requests the approval of COM-001-2 – Communications and two new NERC Glossary terms.
Definition: Interpersonal Communication
Definition: Alternative Interpersonal Communication
Requested Retirement
The RC SDT request the retirement of standard COM-001-1.1 – Telecommunications, Requirements R1,
R2, R3, R5, R6 and the associated sub-requirements, except Requirement R4. This Requirement R4 is
being revised for inclusion in Standard COM-002-4, Operating Personnel Communications Protocols
and will be requested for retirement upon theretired when COM-003-1 becomes effective date
COM-002-4.
Prerequisite Approvals
None.
Defined Terms in the NERC Glossary
The RCSDTRC SDT proposes the following new definitions:
Interpersonal Communication: Any medium that allows two or more individuals to interact, consult, or
exchange information.
Alternative Interpersonal Communication: Any Interpersonal Communication that is able to serve as a
substitute for, and does not utilize the same infrastructure (medium) as, Interpersonal Communication
used for day-to-day operation.
Conforming Changes to Requirements in Already Approved Standards
The RCSDTRC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0,
Requirement R1 as well as EOP-008-1, Requirement R1.
Revisions to Approved Standards and Definitions
The RCSDT revised the COM-001-1.1 standard proposesand is proposing retiring four Requirements (R1,
R4, R5, and R6). The COM-001-1.1 standard, Requirement R1 is proposed for replacementto be
replaced with COM-001-2, Requirements R1, R2, R3, R4, R5, R6, R7, and R8 to achieve clarity to which
entities arewere required to have to reliable communications. Requirement R2 in COM-001-1.1 will
become Requirement R9 in COM-001-2. Requirement R3 in COM-001-1.1 is has been included within
Requirement R1 of COM-001-2. Requirement R4 will remain effectiveenforceable until its inclusion
revision is included in COM-003-1 that is currentlybeing developed under development in Project 200702 – Operating Personnel Communication Protocols. Requirement R5 in COM-001-1.1 is redundant
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
with EOP-008-0, Requirement R1 and EOP-008-1, Requirement R1 and is proposed for retirementwill be
retired upon the effective date of COM-001-2. The COM-001-1.1 standard, Requirement R6 is proposed
for retirementwill be retired as it is an ERO procedural requirement and does not impact reliability.
Requirements R10 and R11 are new requirements. Changes were made to eliminate redundancies
between standards (existing and proposed), to align with the ERO Rules of Procedure and to address
known issues and certain directives in FERC Order 693.
Applicable Entities
•
Reliability Coordinator
•
Balancing Authority
•
Transmission Operator
•
Generator Operator
•
Distribution Provider
Effective Date
New or Revised Standards
COM-001-2
The first day of the second calendar quarter beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day
of the first calendar quarter beyond the date this standard is approved by the NERC
Board of Trustees, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard COM-003-1
currently under development.
Implementation Plan (Draft 7: July 196September 4: April 6, 2012)
COM-001-2 Communications
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
New or Revised Definitions
Interpersonal Communication – The first day of the second calendar quarter beyond the date that this
standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective on the first day of the first calendar quarter
beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.
Alternative Interpersonal Communication – The first day of the second calendar quarter beyond the
date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where
regulatory approval is not required, the standard becomes effective on the first day of the first calendar
quarter beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
New or Revised Standards
COM-001-2
In those jurisdictions where regulatory approval is required, this standard shall
become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required,
this standard shall become effective on the first day of the first calendar quarter
after Board of Trustees adoption.
Standard for Retirement
COM-001-1.1,
Requirements
R1, R2, R3, R5,
and R6
Midnight of the day immediately prior to the Effective Date of COM-001-2 in the
particular Jurisdiction in which the new standard is becoming effective. Note:
Requirement R4 will remain effective until its inclusion in the standard COM-003-1
currently under development.
Implementation Plan for Definitions
Interpersonal Communication – Entities shall use this definition when implementing the standard
COM-001-2, which uses this defined term.
Alternative Interpersonal Communication – Entities shall use this definition when implementing the
standard COM-001-2, which uses this defined term.
Implementation Plan (Draft 7: July 196September 4: April 6, 2012)
COM-001-2 Communications
3
Revisions or Retirements to Already Approved Standards
The following tables identify the sections of approved standards that shall be retired or revised when this standard
becomes effective. If the drafting team is recommending the retirement or revision of a requirement, that text is blue.
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R1. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1. Each Reliability Coordinator shall have Interpersonal
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply):: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R1.1. Internally. [Violation Risk Factor: High]
R1.2. Between the Reliability Coordinator and its
Transmission Operators and Balancing Authorities.
[Violation Risk Factor: High]
R1.3. With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as necessary to
maintain reliability. [Violation Risk Factor: High]
R1.4. Where applicable, these facilities shall be redundant
and diversely routed. [Violation Risk Factor: High]
R1.1. All Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R2. Each Reliability Coordinator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R2.1. All Transmission Operators and Balancing Authorities
within its Reliability Coordinator Area.
R2.2. Each adjacent Reliability Coordinator within the same
Interconnection.
R3. Each Transmission Operator shall have Interpersonal
Communication capability with the following entities (unless the
4
Already Approved Standard
Proposed Replacement Requirement(s)
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R10 shall
apply):: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R3.1. Its Reliability Coordinator.
R3.2. Each Balancing Authority within its Transmission
Operator Area.
R3.3. Each Distribution Provider within its Transmission
Operator Area.
R3.4. Each Generator Operator within its Transmission
Operator Area.
R3.5. Each adjacent Transmission Operator synchronously
connected.
R3.6. Each adjacent Transmission Operator asynchronously
connected.
R4. Each Transmission Operator shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R4.1. Its Reliability Coordinator.
R4.2. Each Balancing Authority within its Transmission
Operator Area.
R4.3. Each adjacent Transmission Operator synchronously
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
5
Already Approved Standard
Proposed Replacement Requirement(s)
connected.
R4.4. Each adjacent Transmission Operator asynchronously
connected.
Notes: The requirements were made clearer as to which capabilities specific entities were required to have to reliable communications.
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
6
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R1.
R5. Each Balancing Authority shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R10 shall apply):: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide adequate and reliable
telecommunications facilities for the exchange of
Interconnection and operating information: [Violation Risk
Factor: High]
R1.1.
Internally. [Violation Risk Factor: High]
R5.1. Its Reliability Coordinator.
R1.2.
Between the Reliability Coordinator and its
Transmission Operators and Balancing
Authorities. [Violation Risk Factor: High]
R5.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R1.3.
R1.4.
With other Reliability Coordinators, Transmission
Operators, and Balancing Authorities as
necessary to maintain reliability. [Violation Risk
Factor: High]
Where applicable, these facilities shall be
redundant and diversely routed. [Violation Risk
Factor: High]
R5.3. Each Distribution Provider within its Balancing Authority
Area.
R5.4. Each Generator Operator that operates Facilities within its
Balancing Authority Area.
R5.5. Each Aadjacent Balancing Authority.
R6. Each Balancing Authority shall designate an Alternative
Interpersonal Communication capability with the following
entities: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R6.1. Its Reliability Coordinator.
R6.2. Each Transmission Operator that operates Facilities within
its Balancing Authority Area.
R6.3. Each Aadjacent Balancing Authority.
R7. Each Distribution Provider shall have Interpersonal
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
7
Already Approved Standard
Proposed Replacement Requirement(s)
Communication capability with the following entities (unless the
Reliability Coordinator detects a failure of its Interpersonal
Communication capability in which case Requirement R11 shall
apply):: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
R7.1. Its Transmission Operator.
R7.2. Its Balancing Authority.
R8. Each Generator Operator shall have Interpersonal Communication
capability with the following entities (unless the Reliability
Coordinator detects a failure of its Interpersonal Communication
capability in which case Requirement R11 shall apply):: [Violation
Risk Factor: High][Time Horizon: Real-time Operations]
R8.1. Its Balancing Authority.
R8.2. Its Transmission Operator.
Notes: The requirements we made clearer as to which capabilities specific entities were required to have for reliable interpersonal
communications. Requirements R7 and R8 were created to address the FERC directive (Order No. 693, P508) to “(1) expand the applicability to
include generator operators and distribution providers and includes Requirements for their telecommunications facilities;”
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
8
Already Approved Standard
Proposed Replacement Requirement(s)
COM-001-1.1
COM-001-2
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall manage, alarm, test and/or actively
monitor vital telecommunications facilities. Special attention
shall be given to emergency telecommunications facilities and
equipment not used for routine communications. [Violation
Risk Factor: Medium]
R9. Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall test its Alternative Interpersonal Communication
capability at least once each calendar month. If the test is unsuccessful,
the responsible entity shall initiate action to repair or designate a
replacement Alternative Interpersonal Communication capability within
2 hours. [Violation Risk Factor: Medium][Time Horizon: Real-time
Operations]
Notes:
COM-001-1.1
COM-001-2
R3. Each Reliability Coordinator, Transmission Operator and
Balancing Authority shall provide a means to coordinate
telecommunications among their respective areas. This
coordination shall include the ability to investigate and
recommend solutions to telecommunications problems within
the area and with other areas. [Violation Risk Factor: Lower]
R1. Each Reliability Coordinator shall have Interpersonal Communication
capability with the following entities: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
R1.1. All Transmission Operators and Balancing Authorities within its
Reliability Coordinator Area.
R1.2. Each adjacent Reliability Coordinator within the same
Interconnection.
Notes:
COM-001-1.1
R4.
Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use
English as the language for all communications between and
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
None - retire
This requirement is being vetted by the OPCPSDT in Project 2007-02
9
Already Approved Standard
among operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations. [Violation Risk Factor: Medium]
Proposed Replacement Requirement(s)
– Operating Personnel Communication Protocols (COM-003-1). This
requirement and measure will be removed from COM-001-1.1 upon
the effective date of COM-003-1.
Notes:
COM-001-1.1
EOP-008-0
R5.
R1. Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall have a plan to continue reliability operations in the
event its control center becomes inoperable. The contingency plan
must meet the following requirements:
Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall have written operating instructions
and procedures to enable continued operation of the system
during the loss of telecommunications facilities. [Violation
Risk Factor: Lower]
R1.1. The contingency plan shall not rely on data or voice
communication from the primary control facility to be viable.
R1.2. The plan shall include procedures and responsibilities for
providing basic tie line control and procedures and for
maintaining the status of all inter-area schedules, such that there
is an hourly accounting of all schedules.
R1.3. The contingency plan must address monitoring and control of
critical transmission facilities, generation control, voltage control,
time and frequency control, control of critical substation devices,
and logging of significant power system events. The plan shall list
the critical facilities.
R1.4. The plan shall include procedures and responsibilities for
maintaining basic voice communication capabilities with other
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
10
Already Approved Standard
Proposed Replacement Requirement(s)
areas.
R1.5. The plan shall include procedures and responsibilities for
conducting periodic tests, at least annually, to ensure viability of
the plan.
R1.6. The plan shall include procedures and responsibilities for
providing annual training to ensure that operating personnel are
able to implement the contingency plans.
R1.7. The plan shall be reviewed and updated annually.
R1.8. Interim provisions must be included if it is expected to take more
than one hour to implement the contingency plan for loss of
primary control facility.
EOP-008-1
R1. Each Reliability Coordinator, Balancing Authority, and Transmission
Operator shall have a current Operating Plan describing the manner in
which it continues to meet its functional obligations with regard to the
reliable operations of the BES in the event that its primary control
center functionality is lost. This Operating Plan for backup functionality
shall include the following, at a minimum: [Violation Risk Factor =
Medium] [Time Horizon = Operations Planning]
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
1.1.
The location and method of implementation for providing backup
functionality for the time it takes to restore the primary control
center functionality.
1.2.
A summary description of the elements required to support the
backup functionality. These elements shall include, at a
11
Already Approved Standard
Proposed Replacement Requirement(s)
minimum:
1.2.1. Tools and applications to ensure that System Operators
have situational awareness of the BES.
1.2.2. Data communications.
1.2.3. Voice communications.
1.2.4. Power source(s).
1.2.5. Physical and cyber security.
1.3.
An Operating Process for keeping the backup functionality
consistent with the primary control center.
1.4.
Operating Procedures, including decision authority, for use in
determining when to implement the Operating Plan for backup
functionality.
1.5.
A transition period between the loss of primary control center
functionality and the time to fully implement the backup
functionality that is less than or equal to two hours.
1.6.
An Operating Process describing the actions to be taken during
the transition period between the loss of primary control center
functionality and the time to fully implement backup
functionality elements identified in Requirement R1, Part 1.2. The
Operating Process shall include at a minimum:
1.6.1. A list of all entities to notify when there is a change in
operating locations.
1.6.2. Actions to manage the risk to the BES during the transition
from primary to backup functionality as well as during
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
12
Already Approved Standard
Proposed Replacement Requirement(s)
outages of the primary or backup functionality.
1.6.3. Identification of the roles for personnel involved during the
initiation and implementation of the Operating Plan for
backup functionality.
Notes: The RCSDTRC SDT proposes retiring COM-001-1.1, Requirement R5 as it is redundant with EOP-008-0, Requirement R1 as well as EOP008-1 Requirement R1.
COM-001-1.1
R6. Each NERCNet User Organization shall adhere to the
requirements in Attachment 1-COM-001, “NERCNet Security
Policy.” [Violation Risk Factor: Lower]
None – retire
Notes: The RCSDTRC SDT is recommending that R6 be retired. This is an ERO procedural issue and should not be in a reliability standard. It
should be included in the ERO Rules of Procedure.
None
New Requirement
R10. Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall notify entities as identified in Requirements R1, R3, and
R5, respectively within 60 minutes of the detection of a failure of its
Interpersonal Communication capability that lasts 30 minutes or longer.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
None
New Requirement
R11. Each Distribution Provider and Generator Operator that
detectsexperiences a failure of its Interpersonal Communication
capabilities shall consult with their Transmission Operator or
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
13
Already Approved Standard
Proposed Replacement Requirement(s)
Balancing Authority to determine a mutually agreeable action to
restore the Interpersonal Communication capability. [Violation
Risk Factor: Medium][Time Horizon: Real-time Operations]
Notes:
Functions that Must Comply with the Requirements in the Standards
Functions that Must Comply With the Requirements
Standard
COM-001-2
Communications
Reliability
Coordinator
Balancing
Authority
X
X
Implementation Plan (Draft 6: April 6, 2012)
COM-001-2 Communications
Purchasing
Selling
Entity
Transmission
Operator
Transmission
Service
Provider
X
X
Load
Serving
Entity
Generator
Operator
Distribution
Provider
X
X
14
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Violation Risk Factor and Violation
Severity Level Justifications
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 – Communications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and
FERC Guidelines when proposing VRFs and VSL for the requirements under this project.
NERC Criteria – Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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Low er R isk Requirem ent
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs: 1
Guideline 1 – Consistency w ith the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
Id. at footnote 15.
2
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•
Appropriate use of transmission loading relief
Guideline 2 – Consistency w ithin a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Guideline 3 – Consistency am ong Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline 4 – Consistency w ith NER C’s Definition of the Violation R isk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline 5 – Treatm ent of Requirem ents that Co-m ingle M ore Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
There are eleven requirements in the standard. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 are assigned a “High” VRF while the other three requirements
are assigned a “Medium” VRF.
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs
for each requirement, some requirements do not have multiple “degrees” of noncompliant
performance, and may have only one, two, or three VSLs.
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Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance
or is missing a single
vital component.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.
The performance or
product has limited
value in meeting the
intent of the
requirement.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed
for each requirement in the standard meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2 – Violation Severity Level Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3 – Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
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Guideline 4 – Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Guideline 5- Treatment of Requirements that Co-mingle More than One
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
Project 2006-06 Reliability Coordination
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VRF Justifications – COM-001-2, R1-R6
Proposed VRF
Discussion
High
Obligation:
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Proposed VSLs for COM-001-2, R1-R6
R#
R1
R2
R3
Lower
N/A
N/A
N/A
Moderate
High
Severe
N/A
The Reliability Coordinator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R1, Parts 1.1
or 1.2, except when the
Reliability Coordinator
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Reliability Coordinator failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R1, Parts 1.1 or
1.2, except when the Reliability
Coordinator detected a failure of
its Interpersonal Communication
capability in accordance with
Requirement R10.
N/A
The Reliability Coordinator
failed to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R2, Parts 2.1 or 2.2.
The Reliability Coordinator failed
to designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R2, Parts 2.1 or 2.2.
N/A
The Transmission Operator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R3, Parts 3.1,
3.2, 3.3, 3.4, 3.5, or 3.6,
except when the
Transmission Operator
detected a failure of its
Interpersonal Communication
The Transmission Operator failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R3, Parts 3.1, 3.2,
3.3, 3.4, 3.5, or 3.6, except when
the Transmission Operator
detected a failure of its
Interpersonal Communication
capability in accordance with
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Proposed VSLs for COM-001-2, R1-R6
R4
R5
R6
N/A
N/A
N/A
capability in accordance with
Requirement R10.
Requirement R10.
N/A
The Transmission Operator
failed to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R4, Parts 4.1, 4.2, 4.3, or 4.4.
The Transmission Operator failed
to designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R4, Parts 4.1, 4.2, 4.3, or 4.4.
N/A
The Balancing Authority failed
to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R5, Parts 5.1,
5.2, 5.3, 5.4, or 5.5, except
when the Balancing Authority
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R10.
The Balancing Authority failed to
have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R5, Parts 5.1, 5.2,
5.3, 5.4, or 5.5, except when the
Balancing Authority detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R10.
N/A
The Balancing Authority failed
to designate Alternative
Interpersonal Communication
capability with one of the
entities listed in Requirement
R6, Parts 6.1, 6.2, or 6.3.
The Balancing Authority failed to
designate Alternative
Interpersonal Communication
capability with two or more of
the entities listed in Requirement
R6, Parts 6.1, 6.2, or 6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a revision of COM001-1.1, R1 and its sub-requirements. Each subViolation Severity Level Assignments
requirement was separated out into a new standShould Not Have the Unintended
Consequence of Lowering the Current Level alone requirement. The VSLs for the approved
sub-requirements are binary; however, proposed
of Compliance
in these VSLs are increments because each entity
may have multiple entities for which it must have
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Proposed VSLs for COM-001-2, R1-R6
an Interpersonal Communication capability.
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments
Should Ensure Uniformity and Consistency
in the Determination of Penalties
N/A
Guideline 2a: The Single Violation Severity
Level Assignment Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R7
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
The requirement has no sub-requirements; only one VRF is assigned, so there
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VRF Justifications – COM-001-2, R7
Proposed VRF
Medium
is no conflict.
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, the Distribution Provider VRF is Medium because is not required
to have an Alternative Interpersonal Communication and is not subject to
Blackstart situations like that of the Generator Owner in Requirement R8.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly; however, Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Project 2006-06 Reliability Coordination
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Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
Severe
N/A
The Distribution Provider
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R7, Parts 7.1
or 7.2, except when the
Distribution Provider
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
The Distribution Provider failed
to have Interpersonal
Communication capability with
two or more of the entities listed
in Requirement R7, Parts 7.1 or
7.2, except when the Distribution
Provider detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to the violation and the VSLs follow the guidelines
for incremental violations.
FERC VSL G1
The proposed requirement is a revision of COM-001-1.1,
R1 and its sub-requirements. Each sub-requirement was
separated out into a new stand-alone requirement. The
VSLs for the approved sub-requirements are incremental
and this is reflected in the proposed VSLs.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
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Proposed VSLs for COM-001-2, R7
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as used in
the associated requirement, and is, therefore, consistent
with the requirement.
The VSL is based on a single violation and not cumulative
violations.
VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High). The Generator Owner may be subject to Blackstart plans
and system restoration.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
Project 2006-06 Reliability Coordination
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VRF Justifications – COM-001-2, R8
Proposed VRF
High
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R8
R#
R8
Lower
N/A
Moderate
High
N/A
The Generator Operator
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R8, Parts 8.1
or 8.2, except when a
Generator Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
Severe
The Generator Operator failed
to have Interpersonal
Communication capability with
two or more of the entities
listed in Requirement R8, Parts
8.1 or 8.2, except when a
Generator Operator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to the violation and the VSLs follow the guidelines
for incremental violations..
FERC VSL G1
The most comparable VSLs for a similar requirement are
for the proposed analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This requirement specifies
the two-way nature of entities having Interpersonal
Communications capability. In other words, if one entity
is required to have Interpersonal Communications
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
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Proposed VSLs for COM-001-2, R8
capability with another entity, then the reciprocal should
also be required or the onus would be exclusively on one
entity. Since Requirement R3 and R5 are assigned
incremental VSLs, it appropriate for Requirement R8 to
also be assigned an incremental VSL.
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSLs use the same terminology as used in
the associated requirement, and are, therefore,
consistent with the requirement.
The VSLs are based on a single violation and not
cumulative violations.
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VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
The requirement contains only one objective; therefore, only one VRF was
assigned.
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Proposed VSLs for COM-001-2, R9
R#
R9
Lower
Moderate
High
Severe
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
equal to 4 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
equal to 6 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
equal to 8 hours
upon an
unsuccessful test.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
OR
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
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Proposed VSLs for COM-001-2, R9
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
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VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
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Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes but
less than or equal to
70 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
80 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1, R3,
and R5, respectively
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes but
less than or equal to
90 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing
Authority failed to
notify the entities
identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 90 minutes.
VSL Justifications – COM-001-2, R10
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
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Proposed VSLs for COM-001-2, R10
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
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VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
R#
R11
Lower
N/A
Moderate
N/A
High
Severe
N/A
The Distribution Provider or Generator Operator that
detected a failure of its Interpersonal Communication
capability failed to consult with each entity affected by
the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a Generator
Operator, to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
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Proposed VSLs for COM-001-2, R11
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement.
The VSL is based on a single violation and not cumulative
violations.
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Violation Risk Factor and Violation
Severity Level Justifications
COM-001-2 - Communications
Violation Risk Factor and Violation Severity Level Justifications
This document provides the drafting team’s justification for assignment of violation risk factors
(VRFs) and violation severity levels (VSLs) for each requirement in: COM-001-2 – Communications
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements
support the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the ERO Sanction
Guidelines.
The Reliability Coordination Standard Drafting Team (SDT) applied the following NERC criteria and
FERC Guidelines when proposing VRFs and VSL for the requirements under this project.
NERC Criteria – Violation Risk Factors
High Risk Requirem ent
A requirement that, if violated, could directly cause or contribute to bulk electric system
instability, separation, or a cascading sequence of failures, or could place the bulk electric system
at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions
anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a
normal condition.
M edium R isk Requirem ent
A requirement that, if violated, could directly affect the electrical state or the capability of the
bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures; or, a requirement in a planning time frame that, if
violated, could, under emergency, abnormal, or restorative conditions anticipated by the
preparations, directly and adversely affect the electrical state or capability of the bulk electric
system, or the ability to effectively monitor, control, or restore the bulk electric system.
However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system
instability, separation, or cascading failures, nor to hinder restoration to a normal condition.
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Low er R isk Requirem ent
A requirement that is administrative in nature and a requirement that, if violated, would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor and control the bulk electric system; or, a requirement that is
administrative in nature and a requirement in a planning time frame that, if violated, would not,
under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system, or the
ability to effectively monitor, control, or restore the bulk electric system. A planning requirement
that is administrative in nature.
FERC Violation Risk Factor Guidelines
The SDT also considered consistency with the FERC Violation Risk Factor Guidelines for setting
VRFs: 1
Guideline 1 – Consistency w ith the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability
Standards in these identified areas appropriately reflect their historical critical impact on the
reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could
severely affect the reliability of the Bulk-Power System: 2
•
Emergency operations
•
Vegetation management
•
Operator personnel training
•
Protection systems and their coordination
•
Operating tools and backup facilities
•
Reactive power and voltage control
•
System modeling and data exchange
•
Communication protocol and facilities
•
Requirements to determine equipment ratings
•
Synchronized data recorders
•
Clearer criteria for operationally critical facilities
1
North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 (2007) (“VRF Rehearing
Order”).
Id. at footnote 15.
2
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•
Appropriate use of transmission loading relief
Guideline 2 – Consistency w ithin a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor
assignments and the main Requirement Violation Risk Factor assignment.
Guideline 3 – Consistency am ong Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements
that address similar reliability goals in different Reliability Standards would be treated comparably.
Guideline 4 – Consistency w ith NER C’s Definition of the Violation R isk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk
Factor level conforms to NERC’s definition of that risk level.
Guideline 5 – Treatm ent of Requirem ents that Co-m ingle M ore Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability
objective, the VRF assignment for such Requirements must not be watered down to reflect the
lower risk level associated with the less important objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5.
The team did not address Guideline 1 directly because of an apparent conflict between Guidelines
1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly all topics within
NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF,
Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the
reliability of the system. The SDT believes that Guideline 4 is reflective of the intent of VRFs in the
first instance and therefore concentrated its approach on the reliability impact of the
requirements.
There are eleven requirements in the standard. None of the eleven requirements were assigned a
“Lower” VRF. Requirements R1-R8 are assigned a “High” VRF while the other three requirements
are assigned a “Medium” VRF.
NERC Criteria – Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not
achieved. Each requirement must have at least one VSL. While it is preferable to have four VSLs
for each requirement, some requirements do not have multiple “degrees” of noncompliant
performance, and may have only one, two, or three VSLs.
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Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor
element (or a small
percentage) of the
required performance
The performance or
product measured has
significant value as it
almost meets the full
intent of the
requirement.
Moderate
High
Severe
Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
Missing more than one
significant element (or
is missing a high
percentage) of the
required performance
or is missing a single
vital component.
Missing most or all of
the significant
elements (or a
significant percentage)
of the required
performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.
The performance or
product has limited
value in meeting the
intent of the
requirement.
The performance
measured does not
meet the intent of the
requirement or the
product delivered
cannot be used in
meeting the intent of
the requirement.
FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed
for each requirement in the standard meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignm ents Should Not Have the Unintended
Consequence of Low ering the Current Level of Com pliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may
encourage a lower level of compliance than was required when levels of non-compliance were
used.
Guideline 2 – Violation Severity Level Assignm ents Should Ensure Uniform ity and
Consistency in the Determ ination of Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant
performance.
Guideline 3 – Violation Severity Level Assignm ent Should Be Consistent w ith the
Corresponding Requirem ent
VSLs should not expand on what is required in the requirement.
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Guideline 4 – Violation Severity Level Assignm ent Should Be Based on A Single
Violation, Not on A Cum ulative Num ber of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a
requirement is a separate violation. Section 4 of the Sanction Guidelines states that assessing
penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications
VRF Justifications – COM-001-2, R1-R6
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
FERC VRF G3
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
Guideline 2- Consistency within a Reliability Standard:
Each requirement specifies which functional entities that are required to have
Interpersonal Communication capability and Alternative Interpersonal
Communication capability. The VRFs for each requirement are consistent with
each other and are only applied at the Requirement level.
Guideline 3- Consistency among Reliability Standards:
These requirements are facility requirements that provide communications
capability between functional entities. There are no similar facility
requirements in the standards. The approved VRF for COM-001-1.1, R1 (which
proposed R1-R6 replaces) is High and therefore the proposed VRF for R1-R6 is
consistent.
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Guideline 5- Treatment of Requirements that Co-mingle More than One
Failure to have Interpersonal Communication capability and Alternative
Interpersonal Communication capability could limit or prevent communication
between entities and directly affect the electrical state or the capability of the
Bulk Power System and could lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
High VRF.
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VRF Justifications – COM-001-2, R1-R6
Proposed VRF
Discussion
High
Obligation:
Each of the six requirements, R1-R6, contains only one objective; therefore,
only one VRF was assigned.
Proposed VSLs for COM-001-2, R1-R6
R#
R1
Lower
N/A
Moderate
High
Severe
N/A
The Reliability
Coordinator failed to
have Interpersonal
Communication
capability with one of
the entities listed in
Requirement R1, Parts
1.1 or 1.2, except when
the Reliability
Coordinator detected a
failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
The Reliability Coordinator failed to
havedesignate Alternative
Interpersonal Communication capability
with twoone or more of the entities
listed in Requirement R1R2, Parts 12.1
or 1.2, except when the Reliability
Coordinator detected a failure of its
Interpersonal Communication capability
in accordance with Requirement
R102.2.
The Reliability Coordinator failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R2, Parts 2.1 or 2.2.
The Transmission Operator failed to
have Interpersonal Communication
capability with twoone or more of the
R2
N/A
N/A
The Reliability
Coordinator failed to
designate Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R2, Parts
2.1 or 2.2.N/A
R3
N/A
N/A
The Transmission
Operator failed to have
Interpersonal
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Proposed VSLs for COM-001-2, R1-R6
R4
R5
N/A
N/A
Communication
capability with one of
the entities listed in
Requirement R3, Parts
3.1, 3.2, 3.3, 3.4, 3.5, or
3.6, except when the
Transmission Operator
detected a failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
entities listed in Requirement R3, Parts
3.1, 3.2, 3.3, 3.4, 3.5, or 3.6, except
when the Transmission Operator
detected a failure of its Interpersonal
Communication capability in
accordance with Requirement R10.
N/A
The Transmission
Operator failed to
designate Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R4, Parts
4.1, 4.2, 4.3, or 4.4.N/A
The Transmission Operator failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R4, Parts 4.1, 4.2, 4.3, or
4.4.
N/A
The Balancing Authority
failed to have
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R5, Parts
5.1, 5.2, 5.3, 5.4, or 5.5,
except when the
Balancing Authority
detected a failure of its
Interpersonal
Communication
capability in accordance
with Requirement
R10.N/A
The Balancing Authority failed to have
Interpersonal Communication capability
with twoone or more of the entities
listed in Requirement R5, Parts 5.1, 5.2,
5.3, 5.4, or 5.5, except when the
Balancing Authority detected a failure
of its Interpersonal Communication
capability in accordance with
Requirement R10.
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Proposed VSLs for COM-001-2, R1-R6
R6
N/A
N/A
The Balancing Authority
failed to designate
Alternative
Interpersonal
Communication
capability with one of
the entities listed in
Requirement R6, Parts
6.1, 6.2, or 6.3.N/A
The Balancing Authority failed to
designate Alternative Interpersonal
Communication capability with twoone
or more of the entities listed in
Requirement R6, Parts 6.1, 6.2, or 6.3.
VSL Justifications – COM-001-2, R1-R6
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is
an incremental aspect to - Severe: The
performance or product measured does
not substantively meet the violation
andintent of the VSLs follow the
guidelines for incremental
violationsrequirement.
FERC VSL G1
The proposed requirement is a revision
of COM-001-1.1, R1 and its subrequirements. Each sub-requirement
was separated out into a new standalone requirement. The VSLs for the
approved sub-requirements are binary;
however, proposed in these VSLs are
increments because each entity may
have multiple entities for which it must
have an Interpersonal Communication
capability. and this is reflected in the
proposed VSLs.
Violation Severity Level Assignments Should Not
Have the Unintended Consequence of Lowering the
Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should Ensure
Uniformity and Consistency in the Determination of
Penalties
N/A
Guideline 2a: The Single Violation Severity Level
Assignment Category for "Binary" Requirements Is
Guideline 2b:
The proposed VSL does not use any
ambiguous terminology, thereby
supporting uniformity and consistency
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
8
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Proposed VSLs for COM-001-2, R1-R6
Not Consistent
Guideline 2b: Violation Severity Level Assignments
that Contain Ambiguous Language
FERC VSL G3
in the determination of similar
penalties for similar violations.
The proposed VSL uses the same
terminology as used in the associated
requirement, and is, therefore,
consistent with the requirement.
Violation Severity Level Assignment Should Be
Consistent with the Corresponding Requirement
FERC VSL G4
Violation Severity Level Assignment Should Be Based
on A Single Violation, Not on A Cumulative Number
of Violations
The VSL is based on a single violation
and not cumulative violations.
VRF Justifications – COM-001-2, R7
Proposed VRF
MediumHigh
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
N/A
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF is assigned, so there
is no conflict.
COM-001-2, the Distribution Provider VRF is Medium because is not required
to have an Alternative Interpersonal Communication and is not subject to
Blackstart situations like that of the Generator Owner in Requirement
R8.COM-001-2, Requirement R7 is an analog to Parts 3.3 and 5.3 and they
have the same VRF (High).
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
9
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VRF Justifications – COM-001-2, R7
Proposed VRF
MediumHigh
Discussion
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly; however, affect the electrical
state or the capability of the Bulk Power System and could lead to Bulk Power
System instability, separation, or cascading failures are not likely to occur due
to a failure to notify another entity of the failure.. Therefore, this requirement
is assigned a MediumHigh VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R7
R#
R7
Lower
N/A
Moderate
High
N/A
The Distribution Provider
failed to have Interpersonal
Communication capability
with one of the entities listed
in Requirement R7, Parts 7.1
or 7.2, except when the
Distribution Provider
detected a failure of its
Interpersonal Communication
capability in accordance with
Requirement R11.N/A
Severe
The Distribution Provider failed
to have Interpersonal
Communication capability with
twoone or more of the entities
listed in Requirement R7, Parts
7.1 or 7.2, except when the
Distribution Provider detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R7
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to - Severe: The performance or product measured
does not substantively meet the violation andintent of the
VSLs follow the guidelines for incremental
violationsrequirement.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
10
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Proposed VSLs for COM-001-2, R7
FERC VSL G1
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
The proposed requirement is a revision of COM-001-1.1,
R1 and its sub-requirements. Each sub-requirement was
separated out into a new stand-alone requirement. The
VSLs for the approved sub-requirements are
incrementalbinary and this is reflected in the proposed
VSLs.
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b:
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as used in
the associated requirement, and is, therefore, consistent
with the requirement.
The VSL is based on a single violation and not cumulative
violations.
VRF Justifications – COM-001-2, R8
Proposed VRF
High
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
11
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VRF Justifications – COM-001-2, R8
Proposed VRF
High
NERC VRF
Discussion
FERC VRF G1
Discussion
Guideline 1- Consistency w/ Blackout Report:
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
N/A
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R8 is an analog to Parts 3.4 and 5.4 and they have
the same VRF (High). The Generator Owner may be subject to Blackstart plans
and system restoration.
Failure to have Interpersonal Communication capability could limit or prevent
communication between entities and directly affect the electrical state or the
capability of the Bulk Power System and could lead to Bulk Power System
instability, separation, or cascading failures. Therefore, this requirement is
assigned a High VRF.
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R8
R#
Lower
Moderate
R8
N/A
N/A
High
The Generator Operator
failed to have Interpersonal
Communication capability
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
Severe
The Generator Operator failed
to have Interpersonal
Communication capability with
12
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Proposed VSLs for COM-001-2, R8
with one of the entities listed
in Requirement R8, Parts 8.1
or 8.2, except when a
Generator Operator detected
a failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.N/A
twoone or more of the entities
listed in Requirement R8, Parts
8.1 or 8.2, except when a
Generator Operator detected a
failure of its Interpersonal
Communication capability in
accordance with Requirement
R11.
VSL Justifications – COM-001-2, R8
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an incremental
aspect to - Severe: The performance or product
measured does not substantively meet the violation
andintent of the VSLs follow the guidelines for
incremental violations..requirement.
FERC VSL G1
The most comparable VSLs for a similar requirement are
for the proposed analog requirement and its parts COM001-2, Part 3.4 and Part 5.4. This requirement specifies
the two-way nature of entities having Interpersonal
Communications capability. In other words, if one entity
is required to have Interpersonal Communications
capability with another entity, then the reciprocal should
also be required or the onus would be exclusively on one
entity. Since Requirement R3 and R5 are assigned
incrementalbinary VSLs, it appropriate for Requirement
R8R7 to also be assigned an incrementala binary VSL.
Violation Severity Level
Assignments Should Not Have the
Unintended Consequence of
Lowering the Current Level of
Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in the
Determination of Penalties
N/A
Guideline 2a: The Single Violation
Severity Level Assignment
Category for "Binary"
Requirements Is Not Consistent
Guideline 2b:
The proposed VSLs do not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
Guideline 2b: Violation Severity
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
13
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Proposed VSLs for COM-001-2, R8
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be Consistent
with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on A
Single Violation, Not on A
Cumulative Number of Violations
The proposed VSLs use the same terminology as used in
the associated requirement, and are, therefore,
consistent with the requirement.
The VSLs are based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
COM-001-2, Requirement R9 is a requirement for entities to test their
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R9 is a requirement for entities to test their
Alternative Interpersonal Communication capability and to take restorative
action should the test fail and is a replacement requirement for COM-001-1.1,
R2, which has an approved VRF of Medium.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
14
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VRF Justifications – COM-001-2, R9
Proposed VRF
Medium
Discussion
Alternative Interpersonal Communication capability and to take restorative
action should the test fail. The act of testing in and of itself is not likely to
“directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system.
However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures…” Therefore, this
requirement is assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R9
R#
Lower
Moderate
High
Severe
R9
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 2 hours
and less than or
equal to 4 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 4 hours
and less than or
equal to 6 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate
a replacement
Alternative
Interpersonal
Communication in
more than 6 hours
and less than or
equal to 8 hours
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to test the
Alternative
Interpersonal
Communication
capability once each
calendar month.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
OR
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
tested the
15
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Proposed VSLs for COM-001-2, R9
upon an
unsuccessful test.
upon an
unsuccessful test.
upon an
unsuccessful test.
Alternative
Interpersonal
Communication
capability but failed
to initiate action to
repair or designate a
replacement
Alternative
Interpersonal
Communication in
more than 8 hours
upon an unsuccessful
test.
VSL Justifications – COM-001-2, R9
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
FERC VSL G1
The proposed requirement is a new and there
Violation Severity Level Assignments Should are no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
16
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Proposed VSLs for COM-001-2, R9
Be Consistent with the Corresponding
Requirement
therefore, consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not
cumulative violations.
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
NERC VRF
Discussion
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R10 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a notification item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to notify another entity of the failure of Interpersonal
Communication capability, while it may impair the entity’s ability
communicate, does not, in itself, lead to Bulk Power System instability,
separation, or cascading failures. Therefore, this requirement is assigned a
Medium VRF.
COM-001-2, Requirement R10 mandates that entities notify entities of a
failure of Interpersonal Communications capability. Bulk Power System
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
17
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VRF Justifications – COM-001-2, R10
Proposed VRF
Medium
instability, separation, or cascading failures are not likely to occur due to a
failure to notify another entity of the failure. Therefore, this requirement is
assigned a Medium VRF.
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R10
R#
Lower
Moderate
High
Severe
R10
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 60 minutes but
less than or equal to
70 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 70 minutes but
less than or equal to
80 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing Authority
failed to notify the
entities identified in
Requirements R1, R3,
and R5, respectively
upon the detection
of a failure of its
Interpersonal
Communication
capability in more
than 80 minutes but
less than or equal to
90 minutes.
The Reliability
Coordinator,
Transmission
Operator, or
Balancing
Authority failed to
notify the
identified entities
identified in
Requirements R1,
R3, and R5,
respectively upon
the detection of a
failure of its
Interpersonal
Communication
capability in more
than 90 minutes.
VSL Justifications – COM-001-2, R10
NERC VSL Guidelines
Meets NERC’s VSL guidelines. There is an
incremental aspect to the violation and the VSLs
follow the guidelines for incremental violations.
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
18
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Proposed VSLs for COM-001-2, R10
FERC VSL G1
The proposed requirement is new and there are
Violation Severity Level Assignments Should no comparable VSLs.
Not Have the Unintended Consequence of
Lowering the Current Level of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level Assignments Should N/A
Ensure Uniformity and Consistency in the
Guideline 2b:
Determination of Penalties
The proposed VSL does not use any ambiguous
Guideline 2a: The Single Violation Severity
terminology, thereby supporting uniformity and
Level Assignment Category for "Binary"
consistency in the determination of similar
Requirements Is Not Consistent
penalties for similar violations.
Guideline 2b: Violation Severity Level
Assignments that Contain Ambiguous
Language
FERC VSL G3
Violation Severity Level Assignment Should
Be Consistent with the Corresponding
Requirement
FERC VSL G4
Violation Severity Level Assignment Should
Be Based on A Single Violation, Not on A
Cumulative Number of Violations
The proposed VSL uses the same terminology as
used in the associated requirement, and is,
therefore, consistent with the requirement.
The VSL is based on a single violation and not
cumulative violations.
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
NERC VRF
Discussion
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
19
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
VRF Justifications – COM-001-2, R11
Proposed VRF
Medium
FERC VRF G1
Discussion
FERC VRF G2
Discussion
Guideline 2- Consistency within a Reliability Standard:
FERC VRF G3
Discussion
Guideline 3- Consistency among Reliability Standards:
FERC VRF G4
Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G5
Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One
Obligation:
The requirement has no sub-requirements; only one VRF was assigned so
there is no conflict.
COM-001-2, Requirement R11 is a new requirement that was assigned a
Medium VRF. When evaluating the VRF to be assigned to this requirement,
the SDT took into account that this requirement is a consultation item, not an
actual action that has a direct impact on the Bulk Power System. Therefore,
the simple act of failing to consult with another entity on the failure of
Interpersonal Communications capability and its restoration, while it may
impair the entity’s ability communicate, does not, in itself, lead to Bulk Power
System instability, separation, or cascading failures. Therefore, this
requirement is assigned a Medium VRF.
COM-001-2, Requirement R11 mandates that entities consult with other
entities regarding restoration of Interpersonal Communication capability. Bulk
Power System instability, separation, or cascading failures are not likely to
occur due to a failure to consult with another entity on restoration times.
Therefore, this requirement is assigned a Medium VRF.
The requirement contains only one objective; therefore, only one VRF was
assigned.
Proposed VSLs for COM-001-2, R11
R#
Lower
Moderate
High
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
Severe
20
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Proposed VSLs for COM-001-2, R11
R11
N/A
N/A
N/A
The Distribution Provider or Generator Operator that
detected a failure of its Interpersonal Communication
capability failed to consult with each entity affected by
the failure, as identified in Requirement R7 for a
Distribution Provider or Requirement R8 for a
Generatorits Transmission Operator, and Balancing
Authority to determine a mutually agreeable action for
the restoration of the Interpersonal Communication
capability.
VSL Justifications – COM-001-2, R11
NERC VSL Guidelines
Meets NERC’s VSL guidelines. This is a binary requirement
and the VSL is severe.
FERC VSL G1
The proposed requirement is new and there are no
comparable existing VSLs.
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Guideline 2a:
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
N/A
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b:
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
21
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Proposed VSLs for COM-001-2, R11
Assignment Should Be
Consistent with the
Corresponding Requirement
requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative
violations.
Violation Severity Level
Assignment Should Be Based
on A Single Violation, Not on A
Cumulative Number of
Violations
Project 2006-06 Reliability Coordination
VRF and VSL Justifications (COM-001-2, Draft 3 – July 192 – April 6, 2012)
22
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Standards Announcement
Project 2006-06 Reliability Coordination
Recirculation Ballot Windows Open through 8 p.m. Monday, September 17, 2012
Now Available
The drafting team for COM-001-2 – Communications has posted its consideration of comments
received during a parallel formal comment period and successive ballot that ended July 11, 2012. The
drafting team made the following clarifying changes to the standard:
•
In Requirements R1, R3, R5, R7, R8 and R 11 the word ‘experiences’ was changed to ‘detects’.
Respective changes were also made to the measures.
•
In Requirement R7 the VRF was changed from high to medium.
•
In Requirement R10 the word ‘respectively’ was added to connect referenced requirements to
the responsible entities named in the requirement. The respective change was also made in the
measure.
•
In Measure M3 ‘and’ was changed to ‘or’.
•
The Data Retention section was updated for readability and retention of voice recordings was
added.
A recirculation ballot of COM-001-1 is open from Thursday, September 6, 2012 through 8 p.m. Eastern
on Monday, September 17, 2012.
Instructions
In the recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast a
ballot; all ballot pool members may change their previously cast votes. A ballot pool member who
failed to cast a ballot during the last ballot window may cast a ballot in the recirculation ballot window.
If a ballot pool member does not participate in the recirculation ballot, that member’s vote cast in the
previous ballot will be carried over as that member’s vote in the recirculation ballot.
Members of the ballot pool associated with this project may log in and submit their vote by clicking
here.
Next Steps
If approved, the standard will be presented to the Board of Trustees for adoption and then filed with
the appropriate regulatory authorities.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measureable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to the
scope overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from
FERC Order 693 associated with standard IRO-003-2.
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement - Project 2006-06
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2006-06 Reliability Coordination
Recirculation Ballot Results
Now Available
A recirculation ballot of COM-001-2 – Communications concluded on Monday, September 17, 2012.
Voting statistics are listed below, and the Ballots Results page provides a link to the detailed results.
Approval
Quorum: 80.35%
Approval: 75.01%
Next Steps
The standard will be presented to the Board of Trustees in November.
Background
The Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliabilityrelated requirements applicable to the Reliability Coordinator are clear, measureable, unique, and
enforceable; 2) ensuring that this set of requirements is sufficient to maintain reliability of the Bulk
Electric System; 3) revising the group of standards based on FERC Order 693.
During the course of this project, the Reliability Coordination Standards Drafting Team incorporated
changes due to the work of the IROL Standards Drafting Team. Two standards from the original
Standards Authorization Request (PER-004 and PRC-001) were moved to other projects due to the
scope overlap. In addition, the scope of Project 2006-06 was expanded to incorporate directives from
FERC Order 693 associated with standard IRO-003-2.
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2006-06 COM-001 Recirculation Ballot August 2012_in
Password
Ballot Period: 9/6/2012 - 9/17/2012
Ballot Type: Initial
Log in
Total # Votes: 274
Register
Total Ballot Pool: 341
Quorum: 80.35 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
75.01 %
Vote:
Ballot Results: The Standard has Passed
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
88
11
85
24
69
44
0
8
4
8
341
#
Votes
1
0.8
1
1
1
1
0
0.7
0.2
0.7
7.4
#
Votes
Fraction
50
6
35
14
36
27
0
5
2
6
181
Negative
No
# Votes Vote
Fraction
0.781
0.6
0.565
0.737
0.75
0.818
0
0.5
0.2
0.6
5.551
Abstain
14
2
27
5
12
6
0
2
0
1
69
0.219
0.2
0.435
0.263
0.25
0.182
0
0.2
0
0.1
1.849
8
2
2
1
6
4
0
0
1
0
24
16
1
21
4
15
7
0
1
1
1
67
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Avista Corp.
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Member
Rodney Phillips
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
Scott J Kinney
Gregory S Miller
Patricia Robertson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Ballot
Comments
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
NERC
Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Beaches Energy Services
Bonneville Power Administration
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
Kansas City Power & Light Co.
Keys Energy Services
Lake Worth Utilities
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
SCE&G
Seattle City Light
Joseph S Stonecipher
Donald S. Watkins
Kevin L Howes
Abstain
Affirmative
Affirmative
Chang G Choi
Affirmative
Randall McCamish
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Ralph F Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Gordon Pietsch
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Negative
Negative
Affirmative
Michael Moltane
Negative
Michael Gammon
Stan T. Rzad
Walt Gill
Larry E Watt
John W Delucca
Robert Ganley
Joe D Petaski
Danny Dees
Terry Harbour
Richard Burt
Saurabh Saksena
Richard L. Koch
Negative
Randy MacDonald
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Arnold J. Schuff
David Boguslawski
Kevin M Largura
John Canavan
Marvin E VanBebber
Doug Peterchuck
Michael T. Quinn
Brad Chase
Daryl Hanson
Colt Norrish
Ronald Schloendorn
John C. Collins
Frank F Afranji
David Thorne
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Dale Dunckel
Affirmative
Catherine Koch
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Henry Delk, Jr.
Pawel Krupa
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
NERC
Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Sierra Pacific Power Co.
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Western Farmers Electric Coop.
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Anaheim Public Utilities Dept.
APS
Atlantic City Electric Company
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Lincoln PUD
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Leesburg
City of Redding
Clearwater Power Co.
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Solutions
Georgia Power Company
Georgia System Operations Corporation
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Rich Salgo
Richard McLeon
Dana Cabbell
Robert A. Schaffeld
William Hutchison
James Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Forrest Brock
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Charles B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H. Yeung
Richard J. Mandes
Bob Reeping
Kelly Nguyen
Steven Norris
James V. Petrella
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Abstain
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Dave Markham
Negative
Steve Alexanderson
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Phil Janik
Bill Hughes
Dave Hagen
Michelle A Corley
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
David A. Lapinski
Roman Gillen
Roger Meader
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Bryan Case
Kevin Querry
Anthony L Wilson
Scott S. Barfield-McGinnis
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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3
3
3
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Great River Energy
Hydro One Networks, Inc.
Idaho Power Company
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Lost River Electric Cooperative
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Northern Lights Inc.
Okanogan County Electric Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Umatilla Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
Blue Ridge Power Agency
Central Lincoln PUD
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Madison Gas and Electric Co.
Ohio Edison Company
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
Sam Kokkinen
David Kiguel
Shaun Jensen
Garry Baker
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Michael Henry
Bruce Merrill
Daniel D Kurowski
Richard Reynolds
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Jon Shelby
Ray Ellis
David Burke
Ballard K Mutters
John Apperson
Terry L Baker
Robert Reuter
Jeffrey Mueller
Greg Lange
Heber Carpenter
James Leigh-Kendall
Ken Dizes
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Steve Eldrige
Marc M Farmer
James R Keller
Gregory J Le Grave
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Kevin McCarthy
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Tim Beyrle
John Allen
David Frank Ronk
Rick Syring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Bob C. Thomas
Joseph DePoorter
Douglas Hohlbaugh
Aleka K Scott
Henry E. LuBean
Affirmative
Abstain
Negative
John D Martinsen
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Electric Power Supply Association
Entergy Corporation
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Indeck Energy Services, Inc.
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Public Service Enterprise Group Incorporated
Public Utility District No. 1 of Lewis County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Edward F. Groce
Clement Ma
Francis J. Halpin
Jeff Mead
Paul A. Cummings
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Max Emrick
Affirmative
Alan Gale
Stephanie Huffman
Mike D Hirst
Wilket (Jack) Ng
Amir Y Hammad
James B Lewis
Bob Essex
Robert B Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
John R Cashin
Stanley M Jaskot
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Greg Froehling
Rex A Roehl
Scott Heidtbrink
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
Abstain
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Dominick Grasso
Steven Grega
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Affirmative
Affirmative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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6
6
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6
6
6
6
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
US Power Generating Company
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Shell Energy North America (US), L.P.
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
JDRJC Associates
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Brenda K. Atkins
Sam Nietfeld
William D Shultz
RJames Rocha
Scott M. Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bohdan M Dackow
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
Justin Thompson
andrew heinle
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda L Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
Brandy D Olson
William Palazzo
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Claire Warshaw
Steven J Hulet
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Paul Kerr
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Peter H Kinney
Affirmative
David F Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Jim Cyrulewski
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Terry Volkmann
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J. Barney
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
9
9
10
10
10
10
10
10
10
10
Oregon Public Utility Commission
Snohomish County PUD No. 1
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity
Western Electricity Coordinating Council
Jerome Murray
William Moojen
Linda Campbell
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Larry D. Grimm
Louise McCarren
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
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Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=0941c8d6-8697-4e5f-a0f3-1d557798a631[9/19/2012 9:03:12 AM]
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit N
Summary of Development History and Complete Record of Development COM-002-4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Summary of Development History
Project 2007-02 – Operating Personnel Communications Protocols
The development record for proposed Reliability Standard COM-002-4 is summarized
below.
I.
Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give
“due weight” to the technical expertise of the ERO 1. The technical expertise of the ERO is
derived from the standard drafting team. For this project, the standard drafting team consisted of
industry experts, all from a diverse set of experiences. A roster of the standard drafting team
members is included in Exhibit P.
II.
Standard Development History
A. Standard Authorization Request (SAR) Development
Project 2007-02- Operating Personnel Communications Protocols was initiated on March
1, 2007 as a SAR for revisions to existing standards and development of a new standard. The
SAR was posted for 30-day comment period from March 15, 2007 to April 17, 2007. NERC
received 23 sets of comments, including comments from sixty-nine different individuals from
more than forty-five companies representing 9 of the 10 industry segments. Based on comments
received, a revised SAR was posted with a solicitation for drafting team members from April 18,
2007 to May 2, 2007.
B. First Posting – COM-003-1 Comment Period
COM-003-1 was first posted for a 45-day comment period from November 30, 2009 to
January 15, 2010. NERC received 71 sets of comments from more than 280 different individuals
1
Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d) (2) (2012).
1
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from over 100 companies representing nine of the 10 industry segments. In response to
comments, the standard drafting team made the following changes to the draft COM-003-1
Standard:
•
The three proposed defined terms (Communications Protocol, Three-part Communication
and Interoperability Communication) were removed.
•
The term “Operating Communication” was introduced, replacing “Interoperability
Communication.”
•
The requirement to have a Communications Protocol Operating Procedure was removed,
based on comments that it was administrative in nature.
•
Transmission Service Providers and Load Serving Entities were removed from the
applicability section based on their roles and expected communications.
•
Requirement R4 was modified to no longer mandate “Central Standard Time” and
allowed entities to specify the time zone in the communication.
•
The requirement for repeat-back of communications, Requirement R5, was modified to
add the phrase “not necessarily verbatim” to address concerns regarding potential audit
citations if a repeat-back was not word-for-word or verbatim.
•
The requirement to use the NATO alphabet was modified to allow other alpha-numeric
clarifiers to address the concern that requiring strict adherence to and precise
pronunciation of the NATO phonetic alphabet is overly prescriptive, and the proposed
standard should allow for other phonetic clarifiers where clarity on alpha-numeric
information is necessary.
2
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•
The requirement to use pre-determined, mutually agreed upon line and equipment
identifiers was modified to apply only to interface Elements, not Elements or Facilities
internal to the footprint of an entity.
C. Second Posting – COM-003-1 Comment Period
The second draft of the COM-003-1 standard was posted for a 45-day comment period
from May 7, 2012 to June 20, 2012. NERC received 94 sets of comments from approximately
292 different individuals from approximately 166 companies representing all 10 industry
segments. A common theme among many entities was that the approach to COM-003-1 should
be changed. Most agreed with the comments submitted by the NERC Operating Committee that
applicable entities should be required to
a. develop written communication protocols that address the elements in COM-003-1,
b. train on those protocols, and
c. develop internal controls to find and correct deviances from those protocols.
In response to comments, the proposed standard was modified to use the approach suggested by
the NERC Operating Committee. Additionally, the term “Operating Communication” was
changed to “Operating Instruction” and modified to limit the communications that were
applicable to the standard to just those that were a command to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System.
D. Third Posting – COM-003-1 Comment Period
The third draft of the COM-003-1 standard was posted for a 30-day comment period from
August 22, 2012 to September 20, 2012. NERC received 80 sets of comments from
approximately 232 different individuals from approximately 141 companies representing all 10
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
industry segments. In response to comments, the standard drafting team made the following
changes to the draft COM-003-1 Standard:
•
The term “Operating Instruction” was modified to clarify the scope and intent of the
term; and
•
The concept of “identify, assess, and correct” introduced in the development of version 5
of the CIP standards was incorporated.
E. Fourth Posting – COM-003-1 Comment Period
The fourth draft of the COM-003-1 standard was posted for a 30-day comment period
from November 14, 2012 to December 13, 2012. In response to comments, the standard drafting
team made the following changes to the draft COM-003-1 Standard:
•
The concept of “identify, assess, and correct” was removed.
•
References to the term “Reliability Directive” were added to clarify the protocols
applied to Reliability Directives and Operating Instructions.
•
The requirement to use a 24 hour clock reference was modified to allow
flexibility for entities to define their time specification.
•
The requirement to use three part communication for all Operating Instructions
was modified to allow entities the flexibility to determine when three part
communication was required.
•
A requirement for coordination of communication protocols among entities was
added.
•
A requirement for entities to develop method(s) to assess System Operators’
communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols was added.
4
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F. Fifth Posting – COM-003-1 Comment Period
The fifth draft of the COM-003-1 standard was posted for a 30-day comment period from
March 7, 2013 to April 5, 2013. NERC received 78 sets of comments from approximately 215
different individuals from approximately 130 companies representing all 10 industry segments.
In response to comments, the standard drafting team made the following changes to the draft
COM-003-1 Standard:
•
References to the term “Reliability Directive” were removed to address concerns
of double jeopardy with COM-002-3.
•
References to “all call” communications was removed to address concerns of
double jeopardy with COM-002-3.
•
The requirement for coordination of communication protocols among entities was
modified to require entities to jointly develop protocols.
G. Sixth Posting – COM-003-1 Comment Period
The sixth draft of the COM-003-1 standard was posted for a 30-day comment period
from June 20, 2013 to July 19, 2013. NERC received 80 sets of comments from approximately
50 different organizations or individuals. Following draft 6, the standard drafting team created
draft 7 as COM-002-4, a single combined standard of the Board-approved COM-002-3
Reliability Standard and proposed COM-003-1.
H. First Posting – COM-002-4 Comment Period
COM-002-4 was first posted for a 14-day comment period from October 21, 2013 to
November 4, 2013. NERC received 77 sets of comments from approximately 178 different
individuals from approximately 115 companies representing all 10 industry segments. In
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
response to comments, the standard drafting team made the following changes to the draft COM002-4 Standard:
•
The definition of Operating Instruction was revised to remove the reference to Reliability
Directive.
•
The standard was revised to clarify that DPs and GOPs are required to train their
operators prior to receiving an Operating Instruction and also use three-part
communication when receiving an Operating Instruction during an Emergency.
•
Requirement R1 was revised to provide more clarity, as well as provide more latitude to
operating personnel issuing an Operating Instruction.
•
Part 1.8 was removed, which required entities to specify which instances required alphanumeric clarifiers in their communications protocols.
•
The seventh posting’s Requirement R2 was removed, which required documented
communications protocols for GOPs and DPs that receive Operating Instructions.
•
Requirements R3 and R4 were removed and Requirements R2 and R3 were added in the
eighth posting.
•
The phrase “consistent pattern” was removed for the revised VRFs and VSLs.
•
The VRFs and VSLs was modified to better reflect the differences in severity of violating
documents requirement (i.e. Requirement R1), violating a training or assessment
requirement (i.e. Requirement R2, R3 and R4) and violating a requirement when issuing
or receiving an Operation Instruction during an Emergency (i.e. Requirements R5, R6
and R7).
6
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I. Second Posting – COM-002-4 Comment Period
The second draft of the COM-002-4 standard was posted for a 30-day public comment
period from January 2, 2014 to January 31, 2014. NERC received 70 sets of comments from
approximately 185 different individuals from approximately 125 companies representing all 10
industry segments. In response to comments, the standard drafting team made the following
changes to the draft COM-002-4 Standard:
•
Requirement R4.1 was altered from “as appropriate “ to “as deemed appropriate
by the entity”
•
In Measure M2 the words “its initial” was added to the sentence “shall provide its
initial training records …” in order to align the language in Measure M2 with the
language in Requirement R2
•
Measure M4 was altered to include the phrase “as part of its assessment” and “of
any corrective actions taken” within the sentence “The entity shall provide, as part
of its assessment, evidence of any corrective actions taken”
•
Measure M6 and M7 were changes to add the parenthetical “(if an entity has such
recording)” after the words “time-stamped recordings,” and the second entry for
“time-stamped recordings” was removed due to redundancy.
J. Final Ballot
Proposed Reliability Standard COM-002-4 was posted for a 10-day final ballot period
from March 28, 2014 through April 7, 2014. The proposed Reliability Standard received a
quorum of 78.21% and an approval of 77.62%.
K. Board of Trustees Approval
7
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Proposed Reliability Standard COM-002-4 was adopted by NERC Board of Trustees on
May 6, 2014.
8
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Program Areas & Departments > Standards > Project 2007-02 Operating Personnel Communications Protocols
Project 2007-02 Operating Personnel Communications Protocols
Related Files
Status:
A final ballot for COM-002-4 - Operating Personnel Communications Protocols concluded at 8 p.m. Eastern on Monday, April 7, 2014. The standard achieved a quorum and received sufficient votes for approval. Voting statistics can be found via the
link below. The standard will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Purpose/Industry Need:
This SAR calls for the development of communications protocols for use by Real-time System Operators to improve situational awareness and shorten response time.
Background:
The purpose of the proposed COM-002-4 Reliability Standard is to improve communications for the issuance of Operating Instructions with predefined communications protocols to reduce the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of the Bulk Electric System (BES). The proposed Reliability Standard, similar to posting 7, combines COM-002-3 and former draft COM-003-1 into one standard that addresses communications protocols for operating personnel in
Emergency, and non-emergency conditions. The Operating Personnel Communications Protocols Standard Drafting Draft (OPCP SDT) continues to believe that one communications protocols standard that addresses emergency and non-emergency situations will
improve communications because operating personnel will not need to refer to a different set of protocols during the different operating conditions.
In preparing Posting 8, the OPCP SDT revised the first draft of COM-002-4 in Posting 7 to develop a single communications standard that addresses protocols for operating personnel in Emergency and non-emergency conditions. The OPCP SDT considered the
comments provided on Posting 7 and also drew from a variety of other resources including:
•
•
•
The NERC Board of Trustees’ November 7th, 2013 Resolution for Operating Personnel Communication Protocols, discussed below.
A survey distributed to a sample of industry experts by the Director of Standards Development and the Standards Committee Chair requesting feedback on the draft standard in Posting 8; and
Consultation on the use of the term “Reliability Directive” in the COM-002-4 standard with the Project 2007-03 Real-time Transmission Operations Standard Drafting Team and the Project 2006-06 Reliability Coordination Standard Drafting Team.
On December 11, 2013, the NERC Standards Committee authorized a waiver of the standard process, in accordance with Section 16 of the Standard Processes Manual, to shorten this comment period from 45 days to 30 days with a ballot during the last 10 days
of the comment period to meet the NERC Board of Trustees requested deadline. The standard drafting team is posting this standard for a shortened 30 day formal Comment and 10 day Ballot period per the Standards Committee wavier.
Draft
COM-002-4
Clean (142) | Redline to last Posting (143)
Action
Final Ballot
Info>> (146)
Implementation Plan
Clean (144) | Redline to last Posting (145)
Vote>>
COM-002-4
Clean (122)| Redline to last Posting (123)
Additional Ballot and NonBinding Poll
Implementation Plan
Clean (124) | Redline to last Posting (125)
Updated Info>> (134)
RSAW (126)
Supporting Materials:
Unofficial Comment Form (Word) (127)
Rationale and Technical Justification (128)
Mapping Document (129)
Dates
Results
Summary>> (147)
03/28/14 - 04/07/14
Ballot Results>> (148)
Summary>> (137)
Info>> (135)
01/22/14 – 02/04/14
Ballot Results>> (138)
Extended an additional day to
achieve quorum
Vote>>
Non-Binding Poll
Results>> (139)
RSAW Industry Comment Period
RSAW Feedback Form>>
01/02/14 – 01/31/14
Please send RSAW Feedback
forms to:
Consideration of
Comments
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
VRF/VSL Justification (130)
Table of Issues and Directives (131)
[email protected]
Request to Waive the Standard Process (Authorized on
December 11, 2013) (132)
Standard Comment Period
Posting 8
FAQ Document (133)
Info>> (136)
Submit Comments>>
COM-002-4 (105)
Implementation Plan (106)
Supporting Materials:
Additional Ballot and Nonbinding Poll
Updated Info>> (114)
Info>> (115)
Unofficial Comment Form (Word) (107)
Rationale and Technical Justification (108)
01/02/14 – 02/04/14
Extended an additional day to
achieve quorum
Comments Received>>
(140)
Summary>> (117)
10/25/13 – 11/07/13
Extended an additional day to
achieve quorum
Ballot Results>> (118)
(closed)
Non-Binding Poll
Results>> (119)
Vote>>
Mapping Document (109)
VRF/VSL Justification (110)
Table of Issues and Directives (111)
Comment Period
Info>> (116)
Reliability Standard Audit Worksheet (112)
Request to Waive the Standard Process (Authorized on
October 17, 2013) (113)
Consideration of
Comments>> (141)
10/21/13 – 11/07/13
(closed)
Comments Received>>
(120)
Submit Comments>>
Responses to NERC Board of Trustees' Questions
[SEE BOARD EXHIBIT]
Independent Experts Review Panel
Submit Comments>>
Reliability Issues Steering Committee
NERC Management
Successive Ballot and Nonbinding Poll
07/10/13 - 07/19/13
(closed)
Summary>> (100)
Consideration of
Comments>> (121)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COM-003-1
Clean (88)| Redline to last posting (89)
Implementation Plan
Clean (90) |Redline to last posting (91)
Ballot Results>> (101)
Updated Info>> (98)
Supporting Materials:
Non-binding Poll Results>>
(102)
Vote>>
Unofficial Comment Form (Word) (92)
Comment Period
Technical White Paper (93)
Mapping Document
Clean (94)| Redline to last posting (95)
VRF/VSL Justification
Clean (96)| Redline to last posting (97)
06/20/13 - 07/19/13
Info>> (99)
(closed)
Submit Comments>>
COM-003-1
Clean (69) | Redline to last posting (70)
Implementation Plan
Clean (71)| Redline to last posting (72)
Supporting Materials:
Unofficial Comment Form (Word) (73)
Summary>> (83)
Successive Ballot and Nonbinding Poll
Info>> (81)
03/27/13 - 04/05/13
(closed)
Vote>>
Ballot Results>> (84)
Rationale and Technical Justification
Clean (74)| Redline to last posting (75)
Mapping Document
Clean (76)| Redline to last posting (77)
VRF/VSL Justification
Clean (78)| Redline to last posting (79)
COM-003, Draft 5
FAQ Document (80)
Comments Received>>
(103)
Non-binding Poll Results>>
(85)
RSAW Industry Comment Period
(Now Available)
RSAW Feedback Form>>
03/07/13 - 04/05/13
Please send RSAW Feedback
Forms to:
(closed)
[email protected]
Consideration of
Comments>> (104)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Comment Period
03/07/13 - 04/05/13
Info>> (82)
(closed)
Comments Received>>
(86)
Consideration of
Comments>> (87)
Submit Comments>>
Draft 4
COM-003-1
Clean (52)| Redline to last posting (53)
Successive Ballot and Nonbinding Poll
Updated Info>> (62)
Summary>> (65)
12/4/2012 – 12/13/2012
(closed)
Info>> (63)
Implementation Plan
Clean (54)| Redline (55)
Supporting Materials:
Unofficial Comment Form (Word) (56)
Rationale and Technical Justification (57)
Mapping Document
Clean (58) | Redline (59)
VRF/VSL Justification
Clean (60)| Redline (61)
Ballot Results>> (66)
Non-binding Poll Results>>
(67)
Vote>>
RSAW Industry Comment Period
RSAW Feedback Form>>
Please send RSAW Feedback
Forms to:
11/14/2012 - 12/13/2012
(closed)
[email protected]
Standard Comment Period
Info>> (64)
11/14/2012 - 12/13/2012
(closed)
Comments Received>>
(68)
Submit Comments>>
Draft 3
COM-003-1
Clean (34)
Implementation Plan
Clean (35)| Redline (36)
Successive Ballot and Nonbinding Poll
Updated Info>> (44)
Summary>> (47)
9/11/2012 - 09/20/2012
(closed)
Info>> (45)
Ballot Results>> (48)
Non-binding Poll Results>>
(49)
Vote>>
Supporting Materials:
Comment Form (Word) (37)
Rationale and Technical Justification (38)
Mapping Document
Clean (39)| Redline (40)
VRF/VSL Justification
Clean (41)
COM-001-2
Clean (42)| Redline to Last Approved (43)
RSAW Industry Comment Period
RSAW Feedback Form>>
Please send RSAW Feedback
Forms to:
8/22/12 - 9/20/2012
(closed)
[email protected]
Standard Comment Period
Info>> (46)
8/22/12 - 09/20/2012
(closed)
Comments Received>>
(50)
Consideration of
Comments>> (51)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Submit Comments>>
Initial Ballot and Non-binding
Poll
Updated Info (061112)>> (25)
Summary>> (29)
Draft2
COM-003-1
Clean (16)
Supporting Materials:
Comment Form (Word) (17)
White Paper Info>> (26)
6/11/12 - 6/20/2012
(closed)
Ballot Results>> (30)
Non-binding Poll Results>>
(31)
Info>> (27)
Vote>>
Implementation Plan
Clean (18) | Redline (19)
Mapping Document (20)
VRF/VSL Justification (21)
Comment Period
Info>> (28)
5/7/2012 - 6/20/2012
(closed)
Comments Received>>
(32)
Consideration of
Comments>> (33)
Comments Received>>
(14)
Consideration of
Comments>> (15)
Submit Comments>>
White Paper (22)
COM-001-2
Clean (23)| Redline to Last Approved (24)
Join Ballot Pool>>
5/7/2012 - 6/5/2012
(closed)
Draft 1 Standard
COM-003-1 (9)
Implementation Plan (10)
Disposition of Requirements Identified in SAR (11)
Comment Period
Info>> (13)
11/30/2009 - 1/15/2010
(closed)
Submit Comments>>
Supporting Materials:
Comment Form (Word) (12)
Standard Drafting Team Nominations
Draft SAR Version 2
Clean (6)| Redline (7)
Nomination Period
Info>> (8)
Submit Nomination>>
4/18/2007 - 5/02/2007 (closed)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Period
SAR for Communications Protocols
Draft SAR Version 1 (2)
Info>> (3)
3/19/2007 - 4/17/2007 (closed) Comments Received>> (4)
Submit Comments>>
Nomination Period
SAR Drafting Team Nominations
Info>> (1)
Submit Nomination>>
3/15/2007 - 3/29/2007
(closed)
Consideration of
Comments>> (5)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Maureen E. Long
Standards Process Manager
March 19, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for SAR for Reliability Coordination, SAR for
Operating Personnel Communications Protocols, and Relay Loadability Standard
The Standards Committee (SC) announces the following standards actions:
SAR to Modify the Reliability Coordinator Standards (March 19–April 17, 2007)
The Reliability Coordination SAR drafting team posted the second draft of its SAR for Project
2006-06 for a 30-day comment period from March 19 through April 17, 2007.
The SAR proposes retiring, modifying or moving to other standards the Reliability Coordinator
requirements contained within a set of ten already approved standards. The purpose of making
these modifications is to ensure that the remaining requirements are clear, measurable, unique
and enforceable; and to ensure that this set of requirements is sufficient to maintain reliability of
the Bulk Electric System. This project also involves addressing concerns raised by FERC and
stakeholders and involves bringing the set of standards into conformance with the ERO Rules of
Procedure and the latest version of the Reliability Standards Development Procedure. Please use
the comment form to provide comments on this SAR.
SAR for Project 2007-02 Operating Personnel Communications Protocols (March 19–April
17, 2007)
The Operating Personnel Communications Protocols SAR for Project 2007-02 is posted for a 30day comment period from March 19 through April 17, 2007.
This SAR calls for the development of communications protocols for use by real-time system
operators to improve situational awareness and shorten response time. The need for improved
real-time communications protocols was identified during the investigation of the August 2003
Blackout. Please use the comment form to provide comments on this SAR.
Transmission Relay Loadability Standard (March 19–April 17, 2007)
The Transmission Relay Loadability drafting team posted the third draft of its standard for a 30day comment period from March 19 through April 17, 2007. The drafting team is seeking
comments on a change in the requirements that assigns responsibility for identifying certain
critical facilities to the planning coordinator, in support of the latest approved version of the
Functional Model.
The standard codifies the relay loadability criteria embodied in the NERC Recommendation 8a,
Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S.–
Canada Power System Outage Task Force Recommendation 21A, Make More Effective and
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
REGISTERED BALLOT BODY
March 19, 2007
Page Two
Wider Use of System Protection Measures. Please use the comment form to provide comments
on this standard.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Authorization Request Form
Title of Proposed Standard:
Operating Personnel Communications Protocols
Request Date:
March 1, 2007
SAR Requester Information
Name:
Harry Tom - to be replaced with SAR
drafting team chair when SAR drafting team is
appointed.
SAR Type (Check one box.)
Company:
NERC
New Standard
Telephone:
609-452-8060
Revision to Existing Standard
Fax:
609-452-9550
Withdrawal of Existing Standard
E-mail:
[email protected]
Urgent Action
-1-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Purpose (Describe the purpose of the proposed standard – what the standard will achieve in support of
reliability.)
Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve
situational awareness and shorten response time. The purpose of
revising and expanding the existing requirements that address realtime system operator communications is to:
1.
Provide an adequate level of reliability for the North American
bulk power systems – by ensuring that the standards are complete
and the requirements are set at an appropriate level to ensure
reliability.
2.
Ensure the standard or standards are enforceable as mandatory
reliability standards with financial penalties - the
applicability to bulk power system owners, operators, and users,
are clearly defined; the purpose, requirements, and measures are
results-focused and unambiguous; the consequences of violating
the requirements are clear.
3.
Consider other general improvements described in the standards
development work plan.
4.
Consider stakeholder comments received during the initial
development of the standards and other comments received from
Electric Reliability Organization (ERO) regulatory authorities,
as noted in the attached review sheets.
5.
Satisfy the standards procedure requirement for five-year review
of the standards.
Industry Need (Provide a detailed statement justifying the need for the proposed standard, along with
any supporting documentation.)
The need for improved real-time communications protocols was
identified during the investigation of the August 2003 Blackout.
Blackout Recommendation #26 is: “Tighten communications protocols,
especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate.” (Note that this SAR
does not include the second part of this recommendation regarding the
upgrade to communication system hardware.)
-2-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Brief Description (Describe the proposed standard in sufficient detail to clearly define the scope in a
manner that can be easily understood by others.)
This standard will require the use of specific communication
protocols, especially for communications during alerts and
emergencies. The standard will be applicable to transmission
operators, balancing authorities, reliability coordinators, generator
operators and distribution providers.
Requirements will include protocols for communicating changes to realtime operating states and protocols for issuing and responding to
operating directives.
The project may involve moving some requirements that address
communications protocols from existing standards into this new
standard and will involve adding new requirements that more fully
address communications protocols under various operating scenarios.
-3-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Reliability Functions
The Standard will Apply to the Following Functions (Check all applicable boxes.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Coordinator
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads within
a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk Electric
System within its portion of the Planning Coordinator area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market Operator
Interface point for reliability functions with commercial functions.
-4-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all boxes that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained, and implemented.
5. Facilities for communication, monitoring, and control shall be provided, used, and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement actions.
7. The reliability of the interconnected bulk power systems shall be assessed, monitored,
and maintained on a wide-area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface Principles?
(Select ‘yes’ or ‘no’ from the drop-down box.)
Recognizing that reliability is an essential requirement of a robust North American economy:
1. A reliability standard shall not give any market participant an unfair competitive advantage.Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
-5-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Detailed Description (Provide enough detail so that an independent entity familiar with the industry could
draft a standard based on this description.)
Scope
The scope of the proposed standard or revised standards is to
establish a common lexicon of communications protocols and
communications paths such that all operators and users of the North
American bulk electric system have the same understanding as to its
meaning, usage and take pre-determined action in response. The August
2003 Blackout Recommendation Number 26 calls for a tightening of
communications protocols. This standard is to ensure that effective
communication is practiced and delivered in clear language via preestablished communications paths among pre-identified operating
entities. References to communication protocols in other NERC
Standards may be moved to this new standard.
Applicability
Medical, law enforcement, air traffic control and other fields
routinely use mutually defined and understood terminology or codes.
Clear and mutually established communications protocols used during
real time operations under normal and emergency conditions ensure
universal understanding of terms and reduce errors.
Communications protocols shall precisely define terms, codes, phrases,
words, etc. as to their connotation, conditions for use, context of
use and expected responses in reply to these terms, codes, phrases,
words, etc. Furthermore the protocols shall define a rigorous script
for the Sender and Receiver of information. Effective communications
with proper communications protocols among the operating entities are
essential for maintaining reliable system operations.
The standard will include requirements for the following:
1. Real—time system operators will be required to use specific
communications protocols under normal, abnormal and emergency
conditions to quickly relay critical reliability-related
information.
2. Reliability Coordinators, Balancing Authorities, Generation
Operators, Transmission Operators and Distribution Providers will
be required to adopt and employ directives that use pre-defined
terms, and will require entities that receive those directives to
respond to the reliability coordinator using pre-defined terms.
3. The standard will include requirements for entities that
experience abnormal conditions to use pre-defined terms to
communicate the operating situation to other entities that are in
a position to either assist in resolving the operating situation
or to entities that are impacted by the operating situation.
4. The standard may include other requirements that involve
communications protocols for real-time system operators.
The standard should consider the FERC staff’s Preliminary Assessment
of NERC Standards (dated May 11, 2006) in which the FERC staff cited
-6-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
various Blackout Report excerpts pertaining to ineffective
communications as a factor common to the August 14 blackout and other
previous major outages in North America. The Commission staff
interprets Blackout Report recommendation #26 that urges “effective
communications” with “tightened communications protocols” among
operating entities to include two key components:
(i) Effective communications that are delivered in clear language via
pre-established communications paths among pre-identified
operating entities, and
(ii)Communications protocols which clearly identify that any operating
actions with reliability impact beyond a local area or beyond a
Reliability Coordinator’s area must be communicated to the
appropriate Reliability Coordinator for assessment and approval
prior to their implementation to ensure reliability of the
interconnected systems.
The communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or
more specialized standards.
-7-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Related Standards
Standard No.
COM-001-1
COM-002-2
Explanation – these requirement may need to be modified or moved to the new
standard
R4 is a requirement for the Reliability Coordinator’s, Transmission Operator’s, and
Balancing Authority’s real-time operating personnel to use English when
communicating between entities.
R1.1 is a requirement for the Balancing Authority and Transmission Operator to make
notifications when there is a threat to reliability.
R2 is a requirement for the Reliability Coordinator, Transmission Operator and
Balancing Authority relative to issuing and receiving operating directives.
EOP-001-9
R4.1 includes a requirement for the Transmission Operator and Balancing Authority
to have communications protocols for use during emergencies
EOP-002-2
R6.5 and R7.2 require the Balancing Authority to ask the Reliability Coordinator to
declare an Energy Emergency or an Energy Emergency Alert under certain
conditions
R8 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R9.1 requires the Load-serving Entity to ask the Reliability Coordinator to declare an
Energy Emergency Alert under certain conditions
EOP-006-1
R4 requires the Reliability Coordinator to disseminate information regarding
restoration to neighboring Reliability Coordinators and Transmission Operators or
Balancing Authorities
R5 requires the Reliability Coordinator to approve, communicate, and coordinate the
re-synchronizing of major system islands or synchronizing points
CIP-001-1
R1 and R2 require operating entities to have procedures for communicating
information relative to sabotage of bulk power system facilities
CIP-008-1
R1.2 requires the responsible entity to have a communication plan for response to a
cyber security incident
IRO-001-1
R3 requires the Reliability Coordinator to direct entities to act and R8 requires entities
to respond to the Reliability Coordinator’s directives
IRO-004-1
R6 requires the Reliability Coordinator to direct entities to act and R7 requires entities
to respond to the Reliability Coordinator’s directives
IRO-005-2
R4 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R3, R5, R8, R11, F15, and R17 require the Reliability Coordinator to direct actions to
alleviate various types of abnormal or emergency situations
IRO-014-1
R1.1 requires Reliability Coordinators to have procedures processes or plans that
address communications and notifications made between Reliability Coordinators
under various operating scenarios
PRC-001-1
R6 requires the Transmission Operator and Balancing Authority to make notifications
when there is a change in the status of a special protection system
TOP-001-1
R3 requires some responsible entities to comply with the Reliability Coordinator’s and
Transmission Operator’s directives
R4 requires some responsible entities to comply with the Transmission Operator’s
directives
R5 requires the Transmission Operator to notify its Reliability Coordinator of certain
emergency situations
-8-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
TOP-002-2
R14, R16 and R17 require responsible entities to notify their Reliability Coordinator of
various changes to operating parameters
R18 requires the use of uniform line identifiers when referring to transmission facilities
of an interconnected network
TOP-007-0
R1 requires the Transmission Operator to notify its Reliability Coordinator when it
exceeds an SOL or IROL
R4 requires the Reliability Coordinator to direct entities to take actions to restore the
system to within SOLs or IROLs
TOP-008-1
R3 requires the Transmission Operator to make notifications if it disconnects an
overloaded facility
VAR-001-1
R8 and R12 require the Transmission Operator to direct actions to maintain voltage
within limits and to prevent voltage collapse
VAR-002-1
R2.2 and R5.1 require the Generator Operator to comply with directives
Rr3 requires the Generator Operator to notify the Transmission Operator of various
status or capability changes
Related SARs
SAR ID
Explanation
Regional Variances
Region
ERCOT
Explanation
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
-9-
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Maureen E. Long
Standards Process Manager
March 19, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement: Comment Periods Open for SAR for Reliability Coordination, SAR for
Operating Personnel Communications Protocols, and Relay Loadability Standard
The Standards Committee (SC) announces the following standards actions:
SAR to Modify the Reliability Coordinator Standards (March 19–April 17, 2007)
The Reliability Coordination SAR drafting team posted the second draft of its SAR for Project
2006-06 for a 30-day comment period from March 19 through April 17, 2007.
The SAR proposes retiring, modifying or moving to other standards the Reliability Coordinator
requirements contained within a set of ten already approved standards. The purpose of making
these modifications is to ensure that the remaining requirements are clear, measurable, unique
and enforceable; and to ensure that this set of requirements is sufficient to maintain reliability of
the Bulk Electric System. This project also involves addressing concerns raised by FERC and
stakeholders and involves bringing the set of standards into conformance with the ERO Rules of
Procedure and the latest version of the Reliability Standards Development Procedure. Please use
the comment form to provide comments on this SAR.
SAR for Project 2007-02 Operating Personnel Communications Protocols (March 19–April
17, 2007)
The Operating Personnel Communications Protocols SAR for Project 2007-02 is posted for a 30day comment period from March 19 through April 17, 2007.
This SAR calls for the development of communications protocols for use by real-time system
operators to improve situational awareness and shorten response time. The need for improved
real-time communications protocols was identified during the investigation of the August 2003
Blackout. Please use the comment form to provide comments on this SAR.
Transmission Relay Loadability Standard (March 19–April 17, 2007)
The Transmission Relay Loadability drafting team posted the third draft of its standard for a 30day comment period from March 19 through April 17, 2007. The drafting team is seeking
comments on a change in the requirements that assigns responsibility for identifying certain
critical facilities to the planning coordinator, in support of the latest approved version of the
Functional Model.
The standard codifies the relay loadability criteria embodied in the NERC Recommendation 8a,
Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S.–
Canada Power System Outage Task Force Recommendation 21A, Make More Effective and
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
REGISTERED BALLOT BODY
March 19, 2007
Page Two
Wider Use of System Protection Measures. Please use the comment form to provide comments
on this standard.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Howard Rulf
Organization: We Energies
Telephone:
262-574-6046
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The scope should be limited to communications between entities and should not
prescribe communication protocols for communication within an organization. Intra-company
communications are most appropriately addressed by interal policies and procedures tailored to an
entity's specific needs and characteristics.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: Scope should be limited to communication among separate entities/organizations. For
example, the standard should not address communication protocols between a Balancing Authority,
Generaotr Operator and a Distribution Provider tha are the same corporate entity. The requirement
to maintain situational awareness within a given entiy is addressed by other standards.
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jeff Hackman
Organization: Ameren Services
Telephone:
314.554.2839
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: There is no doubt that during alerts and emergencies, both parties in communication
require a common defintion. To the extent the standard requires neighboring BAs, TOs and RCs to
use the same word with the same meaning, then the scope of the proposed standard makes sense.
However, as written the standard appears to indicate the kind of scripting that is better suited to
selling magazines from a boiler room. No defined protocol can match every situation. And if in fact
that was even a goal, the operators would have the time-consumign task of identifying which script
currently was needed when their time would be better spent resolving the situation.
The SAR also proposes that any reliability impacts beyond a Reliability Coordinator's area must be
coordinated and approved by the impacted Reliability Coordinator. Clearly, if time permits, this
coordination is appropriate. However, in an emergency, the RC nay have to use independent
judgement.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Jason Shaver
Organization: American Transmission Co.
Telephone:
262 506 6885
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The SAR needs further clarification before it is moved into the next stage. The SAR
should identify at a minimum the words and procedures that the SDT is going to consider for a
reliability standard.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The SAR should be expanded to include local control center’s system operators.
See our comments to question 3.
The SAR should specify how each of the identified standards will be addressed through this process.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: Issue 1:
The recommendation from the blackout report is overly broad and vague. Tightening does not sound
like a complete overhaul but rather tweaking the existing protocols and documenting them if they are
informal. This may not even require a standard across all functional entities. TOPs and BAs in a
given region have long history of communication and differing terms are already understood.
However, for communications that occur between regional areas, there may be a need for common
terms.
ATC does not agree with the concept of a rigorous script for communications. This may sound like it
would require the team to identify any operational situation that could ever occur and then establish a
script. If this were possible, it would be great. However, it is not possible. This is why we have
trained operators to make decisions when new operational situations occur.
Issue 2:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
The SAR needs to include local control center’s system operators. The inclusion of this group of
system operators will not be simple because local control centers are not an identified entity in
NERC’s functional model. Never the less if the SDT is going to create a common lexicon and
procedures it’s important that these system operators are required to follow the standard. ATC
believes that the purpose behind this SAR would be better address through NERC’s CEH program
then through reliability standards.
SAR Scope:
“The scope of the proposed standard or reviewed standards is to establish a common lexicon of
communications protocols and communications paths such that all operators and users of the North
American bulk electric system have the same understanding as to its meaning, usage and take predetermined action in response.”
PER FERC Final Rule RM06“1343. Clearly, in a region where an RTO or ISO performs the transmission operator function, its
personnel with primary responsibility for real-time operations must receive formal training pursuant to
PER-002-0. IN addition, personnel who are responsible for implementing instructions at a local
control center also affect the reliability of the Bulk Power System. These entities may take
independent action under certain circumstances, for example, to protect assets, personnel safety and
during system restorations. Whether the RTO or the local control center is ultimately responsible for
compliance is a separate issue addressed above, but regardless of which entity registers for that
responsibility, these local control center employees must receive formal training consistent with their
roles, responsibilities and tasks. Thus, while we direct the ERO to develop modifications to PER-0020 to include formal training for local control center personnel, that training should be tailored to the
needs of the positions.”
“1345. Another organization structure, typically representative of relative smaller entities, consists of
a single control center that implements operating instructions from its transmission operator, e.g., an
RTO, ISO or pooled resources. Similar to the discussion above, operators at these control centers
also may take independent action to protect assets, safety and system restoration. Such control
center personnel must also receive formal training pursuant to PER-002-0.”
Because NERC has been order to create training plans for local control center’s system operator any
common lexicon and communications protocols could be dealt with for all entities most effectively in
NERC’s CEH program.
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Susan Renne
Organization: Bonneville Power Administration
Telephone:
(360) 418-2912
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments: Non identified
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments: No additional comments
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
CJ Ingersoll
Organization: Constellation
Telephone:
713-332-2906
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: CECD believes there is a reliability reason for establishing a set of communication
protocols.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: CECD agrees with the scope, however, CECD would caution that pre-defined action in
response to grid operations would need to be broad enough to allow the flexibility that is required by a
diverse system. The statement that raises this concern in the Scope is the first sentence which
states, the scope of the proposed standard or revised standards is to establish a common lexicon of
communications protocols and communication paths such that all operators and users of the North
American bulk electric system have the same understanding as to its meaning, usage and take predetermined action in response. The standard should focus on the communication paths, perdetermined contacts (regular communication/testing), the applicable langage and the terminology but
not necessarily a specific action.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 13, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ed Davis
Organization: Entergy Services
Telephone:
504-576-3029
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
We have the following suggestions concerning this SAR:
1. The use of the phrase “communications protocols” is not the best choice of labels for
the purposes at hand because of the widespread and multi-faceted use of this phrase in
the field of data communications. As an alternative we would recommend using the
term "communication procedures".
2. The scope of this standard should be constrained to inter-operator human
communications vocabulary solely about the bulk electric system. A different SAR
should be written for cyber communication standards.
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Colleen Frosch
Organization: ERCOT
Telephone:
512-248-4219
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: There may be a need for pre-defined terms, however we do not agree with the concept
of a rigorous script for communications. It would not be possible to identify every operational
situation.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
David L. Folk
Organization: FirstEnergy Corp.
Telephone:
330-384-4668
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments: No additional comments
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Roger Champagne
Organization: Hydro-Québec TransÉnergie (HQT)
Telephone:
514 289-2211, X 2766
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: HQT supports establishing communication protocols to define consistent emergency
determinations. However, the standard should not extend to establishing pre-defined scripts that
operators must follow in their communications without the element of judgement and discussion that
are needed in such situations.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: See response Question #1.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments: No others.
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Falsetti
Organization: IESO
Telephone:
905-855-6187
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The scope of the SAR is too broad and too prescriptive. The Applicability section of the
SAR where it states "... the protocol shall define a rigorous script for the Sender and Receiver of
information…" is too prescriptive yet not exhaustive enough to cover all situations. We support the
notion of defining standard terms to be used in operation personnel communication, but do not
believe predetermined script is required in every communication situation, nor do we think it is
possible to have a set of scripts that covers all possible cases.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
SRC Standards Review Committee
Lead Contact:
Charles Yeung
Contact Organization:
SPP
Contact Segment:
2
Contact Telephone:
832-724-6142
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Calimano
NYISO
NPCC
2
Alicia Daugherty
PJM
RFC
2
Ron Falsetti
IESO
NPCC
2
Matt Goldberg
ISO-NE
NPCC
2
Brent Kingsford
CAISO
WECC
2
Steve Myers
ERCOT
ERCOT
2
William Phillips
MISO
RFC+SERC+MRO
2
Anita Lee
AESO
WECC
2
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: We are concerned that the scope of "... the protocol shall define a rigorous script for the
Sender and Receiver of information" is too prescriptive yet not exhaustive enough to cover all
situations. We support the notion of defining standard terms to be used in operation personnel
communication, but do not believe predetermined script is required in every communication situation,
nor do we think it is possible to have a set of scripts that covers all possible cases.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Kathleen Goodman
Organization: ISO New England
Telephone:
(413) 535-4111
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: ISO New England supports establishing communication protocols to define consistent
emergency determinations. However, the standard should not extend to establishing pre-defined
scripts that operators must follow in their communications without the element of judgement and
discussion that are needed in such situations.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: See response Question #1.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments: No others.
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Brian F Thumm
Organization: ITC Transmission
Telephone:
248-374-7846
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The SAR scope needs to be clear in that it refers to specific protocols for
communication, and not to "scripted" responses for every situation. Although the SAR discusses the
use of protocols, other context of the remaining passages in the SAR lead one to believe otherwise.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Gammon
Organization: Kansas City Power & Light
Telephone:
816-654-1242
E-mail:
816-654-1245
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: Not to the extent this SAR is addressing itself. The Black Out Report is overly broad
and vague regarding this issue. This SAR would make more sense if it were addressing itself to
tightening existing protocols and documenting them between entities. The way this SAR has been
presented, pre-defined terms would have to be developed. Who would be responsible to determine
what these pre-defined terms would be and would the terms be applicable to all operating entities?
Adjacent operating entities have a long history of communicating and differing terms are understood.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The SAR description suggests establishment of "protocols shall define a rigorous script"
to be followed. It would be impracticle to presume to think through every operating condition that
scripting would require. Although the notion of everyone using the same terms or phrases sounds
good, the development of such an operating "dictionary" is not practicle. Who will be the final word
on terminology the industry must adopt that changes the way in which operating entities have
described their adopted practices and procedures for decades?
The scope of the SAR should limit itself to the principles of effective communication for operating
entities to follow and not so prescriptive such as pre-definition of terms. Operating entities are smart
enough to be able to use effective communication principles in a standard to determine and
document communication protocols and terminology between them that provides effective
communication. The same should apply between Reliability Coordinators. Follow the basic
standards development: a standard should not say how something should be done, it should say
what the required outcome should be.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Robert Coish
Organization: Manitoba Hydrot
Telephone:
204-487-5479
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The scope of this SAR is much to far reaching. It appears that the intention is for the
this Standard to reach into the intra region operation. This could become a safety issue as Utility
Safety Rule Books could be in conflict with terminalogy being proposed by the standard writer.
Getting this standard accepted by the industry at large will be a major hurtle to jump.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments: If it is the intention of the standard writer to re write these requirements into scripts than
we see problems, especially if it is intended to push these scripts into the entities' intra region operating
procedures.
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments: We believe that there is a need to clean up the communication protocol in
as far as full name identification of all parties for all communications between entities
and three part comunication: the sender giving the information or direction, the receiver
repeating the information or direction back as to his understanding, and the reciever
confirming or correcting the repeated statement. If there is a correction than the
process is repeated.
A glossary of terms for industry standard operating terms is essential. This glossary with
input from the entities should be an integral part of this SAR.
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Standards Collaboration Group
Lead Contact:
Terry Bilke
Contact Organization:
Midwest ISO
Contact Segment:
2
Contact Telephone:
317-249-5463
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
David Lemmons
Xcel Energy
MRO
6
Jim Cyrulewski
JDRJC Associates
MRO
8
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The recommendation from the blackout report is overly broad and vague. Tightening
does not sound like a complete overhaul but rather tweaking the existing protocols and documenting
them if they are informal. This may not even require a standard across all functional entities. For
instance, establishing a common lexicon makes sense at face value; however, it may not be needed
for communications between neighboring BAs. BAs and TOPs in a given region have long history of
communication and differing terms are already understood. However, for communications that occur
between regional areas, there may be a need for common terms.
We do not agree with the concept of a rigorous script for communications. This sounds like it would
require the team to identify any operational situation that could ever occur and then establish a script.
If this were possible, it would be great. However, it is not possible. This is why we have trained (yes
there is a training standard) operators to make decisions when new operational situations occur.
The SAR also proposes that any reliability impacts beyond a Reliability Coordinator's area must be
coordinated and approved by the impacted Reliability Coordinator. This is certainly a laudable goal
but is not reasonable in all cases. If there is an IROL violation in RC A's area and the action the RC
would take would impact the area of RC B, RC A could not take action until RC B approved the
action. Let's assume the impact on RC B is that a small load would be radialized when RC A opens a
circuit to correct the IROL. This seems like a small risk to subject to RC B since the action will
immediately correct the IROL. After the IROL is corrected, then RC A and RC B could begin
determining other options. With the proposed language in the SAR, RC A would have violated this
standard even though they eliminated that risk of more widespread outages.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments: We agree that these functional entities should be considered for applicability; however,
it is possible that the final standard should not apply to all of them. Further examination of the reason
for the recommendation of the from the blackout report would help determine this.
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Midwest Reliability Organization
Lead Contact:
Neal Balu
Contact Organization:
MRO for Group ( WPS Corporation for Contact)
Contact Segment:
10
Contact Telephone:
920-433-1846
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Terry Bilke
MISO
MRO
10
Alan Boesch
NPPD
MRO
10
Robert Coish, Chair
MHEB
MRO
10
Carol Gerou
MP
MRO
10
Ken Goldsmith
ALT
MRO
10
Todd Gosnell
OPPD
MRO
10
Jim Haigh
WAPA
MRO
10
Tom Mielnik
MEC
MRO
10
Pam Oreschnick
Xcel
MRO
10
Dick Pursley
GRE
MRO
10
Dave Rudolph
BEPC
MRO
10
Eric Ruskamp
LES
MRO
10
Michael Brytowski, Secretary
MRO
MRO
10
MRO
10
27 Additional members
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: .
The scope need not be so expansive , it should start at a high level with no scripted message.
We do not agree with the concept of a rigorous script for communications. This sounds like it would
require the team to identify any operational situation that could ever occur and then establish a script.
If this were possible, it would be great. However, it is not possible. This is why we have trained (yes
there is a training standard) operators to make decisions when new operational situations occur.
The Communication Training can be made part of Operator Training Procedures.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: We agree that these functional entities should be considered for applicability; and in
addition it should apply to Interchange Coordinator Function.
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications: EOP-001-0 Attachment 1
Page 4 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments: Proof of the pudding is in tightly defining the Requirements and stipulating
the Severity Levels and VRFs accurately so that the penalties are commensurate with
the severity level and the VRF.
Is there a consistent methodology between IRO-014-1 R1.1 footnote 1 and CIP-008-1
R1.2?
Is IRO-001-1 R3 a repeat of IRO-005-2 R3?
There is an overlapping request for requirements for communication facilities for use
during emergencies. These requests are made in this SAR (Operating Personnel
Communications Protocols Project 2007-02) and in the SAR for Project 2006-06
Reliability Coordination-Attachment 1. Perhaps both the associated drafting teams could
work together so that there are no overlapping requirements among developed
standards. We do not see the purpose behind not including the recommendation
regarding the upgrade to communication system hardware in this SAR. This SAR should
include , if need be, the recommendations to upgrade communication system hardware.
Page 5 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
NPCC CP9, Reliability Standards Working Group
Lead Contact:
Guy V. Zito
Contact Organization:
Northeast Power Coordinating Council
Contact Segment:
10
Contact Telephone:
212-840-1070
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Ralph Rufrano
New York Power Authority
NPCC
1
Ron Falsetti
The IESO, Ontario
NPCC
2
Roger Champagne
TransEnergie, HydroQuebec
NPCC
1
Randy Macdonald
New Brunswick System
Operator
NPCC
2
Herb Schrayshuen
National Grid US
NPCC
1
Al Adamson
New York State Reliability
Council
NPCC
10
Kathleen Goodman
ISO New England
NPCC
2
David Kiguel
Hydro One Networks
NPCC
1
William Shemley
ISO New England
NPCC
2
Murale Gopinathan
Northeast Utilities
NPCC
1
Guy V. Zito
NPCC
NPCC
10
Greg Campoli
New York ISO
NPCC
2
Donald Nelson
MA Department of Tel and
Energy
NPCC
9
Ed Thompson
ConEd
NPCC
1
Michael Ranalli
National Grid US
NPCC
1
Michael Gildea
Constallation Energy
NPCC
5
Michael Schiavone
National Grid US
NPCC
1
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: NPCC participating members agree with the need to establish communication protocols
to define consistent emergency determinations. However, the standard should not extend to
establishing pre-defined scripts that operators must follow in their communications without the
element of judgement and discussion that are needed in such situations.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: See our comments to question 1
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments: No others.
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments: NPCC participating members agree with the concepts in the SAR.
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Michael Calimano
Organization: New York Independent System Operator
Telephone:
518-356-6129
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: see comment in #2
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The NYISO is concerned that the scope of "... the protocol shall define a rigorous script
for the Sender and Receiver of information" is too prescriptive yet not exhaustive enough to cover all
situations. We support the notion of defining standard terms to be used in operation personnel
communication, but do not believe predetermined script is required in every communication situation,
nor do we think it is possible to have a set of scripts that covers all possible cases.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 4 of 4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Public Service Commission of South Carolina
Lead Contact:
Phil Riley
Contact Organization:
Public Service Commission of South Carolina
Contact Segment:
9
Contact Telephone:
803-896-5154
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mignon L. Clyburn
Public Service Commission
of South Carolina
SERC
9
Elizabeth B. "Lib" Fleming
Public Service Commission
of South Carolina
SERC
9
G. O'Neal Hamilton
Public Service Commission
of South Carolina
SERC
9
John E. "Butch" Howard
Public Service Commission
of South Carolina
SERC
9
Randy Mitchell
Public Service Commission
of South Carolina
SERC
9
C. Robert "Bob" Moseley
Public Service Commission
of South Carolina
SERC
9
David A. Wright
Public Service Commission
of South Carolina
SERC
9
Page 2 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments: The PSCSC believes the SAR should specifically acknowledge the power and
effectiveness of three-part communications in ensuring common understanding of verbal
exchanges. Three-part communications include the sender giving the information, the
receiver repeating the information back, and the sender acknowledging the correctness
of the repeated information. This form of communication is used in nuclear plant
Page 4 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
communications and in other industries where it is critical that everyone involved has a
common understanding of the intended message.
Page 5 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Southern Company Transmission
Lead Contact:
Roman Carter
Contact Organization:
Southern Co. Transmission
Contact Segment:
1
Contact Telephone:
205-257-6027
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Marc Butts
Southern Co. Transmission
SERC
1
Fred Waites
Alabama Power Co.
SERC
3
JT Wood
Southern Co. Transmission
SERC
1
Jim Busbin
Southern Co. Transmission
SERC
1
Jim Griffith
Southern Co. Transmission
SERC
1
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: If all Owners, Operators, and Users of the Bulk Electric system adhered to the current
NERC standards (and previous Operating Policies), we do not believe this standard would be
necessary. However, we understand that this SAR is an attempt to make it very clear what is
expected of a RC, TOP, BA, GO, and DP in way of communciations during emergency situations.
We feel that this communication protocol should be only applicable under the current EEA Level 1
and above state or with the new Transmission Emergency state currrently being developed.
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: As mentioned in the answer to question #1, we feel it should be applicable for EEA
Level 1 and above or with the new Transmission Emergency state currently being developed.
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: However, there is only one "real time" requirement that is applicable to the DP. It is
contained in TOP-001-1, R4.
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications: IRO-016-1, R1
Comments: We do not recommend bringing the requirement over to this SAR. It is better to leave in
the IRO standards.
Page 4 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
*Under FERC staff's Preliminary Assessment contained on page 7 of the SAR (items i and
ii), item ii should not be addressed in this SAR. There are numerous requirements in the
IRO standards already that adequately cover communications to other RCs for situations
in which a reliability impact may go beyond a RC's area of view. In particular, the
IRO-001-1, Req. 7;
following standard requirements address the 2nd part (ii):
IRO-003-2, Req.1; IRO-004-1, Req.2; IRO-014-1, Req.1,2,3; IRO-015-1, Req.1,2;
IRO-016-1, Req.1;
*If the SAR drafting team removes the requirements of the standards referenced in the
"Related Standards" section of this SAR and move them to this SAR, it will become
difficult for a Reliability Coordinator to know where to go for standards applicable to
them. For example, currently most of the requirements related to real time actions
taken by a RC are contained in the IRO standards. If the 4 IRO standard requirements
are removed from the IRO standards and placed into this SAR, the RC system operators
will now have to refer to more standards to find requirements related to their
responsibilities. This same scenario also applies to the other standard drafting teams
who are considering the same actions.
It would be helpful if NERC were to provide on the Standards Homepage a listing of
standards by Function: RC, BA, TOP, etc. Then the RC could review the RC function and
know all standards that are applicable to them in a quick and easy fashion.
Page 5 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 13, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Ron Taylor
Organization: Salt River Project
Telephone:
602-236-8957
E-mail:
[email protected]
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
Lead Contact:
Contact Organization:
Contact Segment:
Contact Telephone:
Contact E-mail:
Additional Member Name
Additional Member
Organization
Region*
Segment*
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Page 4 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Comments: The SAR is a proposal for protocols to be used over "pre-established
communications paths". This is good as far as it goes. When Operations sits down to write
up these protocols with their peers, I recommend that they have a Communications person
from at least one of the utilities on the panel to initially clearly delineate what the
recommended path(s) are between the subject utilities. This will be based on use of private
systems first with the possibility of widespread unavailability of commercial services, etc.
Page 5 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Please use this form to submit comments on the proposed SAR for Operating Personnel
Communications Protocols. Comments must be submitted by April 17, 2007. You may
submit the completed form by e-mail to [email protected] with the abbreviation
“Protocols” in the subject line. If you have questions please contact Harry Tom at
[email protected] or by telephone at 609-452-8060.
Individual Commenter Information
(Complete this page for comments from one organization or individual.)
Name:
Organization:
Telephone:
E-mail:
NERC
Region
Registered Ballot Body Segment
ERCOT
1 — Transmission Owners
FRCC
2 — RTOs, ISOs
MRO
3 — Load-serving Entities
NPCC
4 — Transmission-dependent Utilities
RFC
5 — Electric Generators
SERC
6 — Electricity Brokers, Aggregators, and Marketers
SPP
7 — Large Electricity End Users
WECC
NA – Not
Applicable
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government
Entities
10 - Regional Reliability Organizations and Regional Entities
Page 1 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Group Comments (Complete this page if comments are from a group.)
Group Name:
WECC Reliability Coordination Comments Work Group
Lead Contact:
Nancy Bellows
Contact Organization:
WECC Reliability Coordination Subcommittee
Contact Segment:
10
Contact Telephone:
970-461-7246
Contact E-mail:
[email protected]
Additional Member Name
Additional Member
Organization
Region*
Segment*
Mike Gentry
SRP
WECC
10
Bob Johnson
Xcel (PSC)
WECC
10
Frank McElvain
RDRC
WECC
10
Greg Tillitson
CMRC
WECC
10
*If more than one region or segment applies, indicate the best fit for the purpose of these
comments. Regional acronyms and segment numbers are shown on prior page.
Page 2 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
Background Information
The need for improved real-time communications protocols was identified during the
investigation of the August 2003 Blackout. Blackout Recommendation #26 is: “Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate.” (Note that this SAR does not
include the second part of this recommendation regarding the upgrade to communication
system hardware.)
This SAR proposes developing a set of standardized communication protocols for system
operators to use during normal and emergency operations to improve situational awareness
and shorten response time.
The requirements for communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more specialized
standards.
Please review the SAR and then answer the questions on the following page.
Page 3 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
You do not have to answer all questions.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you believe that there is a reliability-related need to establish a set of
communications protocols to improve situational awareness and shorten
response time?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments:
2. Do you agree with the scope of the proposed standard?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: While the WECC RCCWG agrees in general with the scope of the proposed standard,
the work group has some questions and comments regarding terms used in the scope. The scope of
the SAR may be widened to "establish and implement a lexicon of communications protocols and
communications paths." Please define "communication path" as used in the scope - is this the
expected communications between entities as opposed to the actual physical paths of those
communications? Additionally, there is a general comment that establishment of a lexicon does not,
in itself ensure pre-determined action as noted in the scope. What type of pre-determined actions are
expected, operating or communications?
3. The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution
Providers. Do you agree with the proposed applicability?
Yes
No
If “No,” please explain why in the comment area below and provide supporting
information.
Comments: The WECC RCCWG generally agrees, but some questions remain. The standard will
apply to TO, BA, GO, DP; however, the SAR (Applicability Section #2) states that all those entities
"will be required to adopt and employ directives that use pre-defined terms, and will require entities
that receive those directives to respond to the reliability coordinator using pre-defined terms." Entities
that receive those directives should respond to the entity issuing the directives using pre-defined
terms. Additionally, the WECC RCCWG believes that the SAR drafting committee should consider
adopting the term "directive" for reliability coordinator issue only and adopt another term, such as
"operating instructions" for those actions directed by other than the reliability coordinator to
distinguish between the two terms.
Page 4 of 5
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Comment Form — 1st Draft of SAR for Operating Personnel Communications
Protocols
4. The SAR includes a list of standards that include requirements that involve the
issuing or receipt of real-time communications. If you are aware of additional
requirements, beyond those listed on pages 8-9, please identify them here.
The following list of requirements involves the issuing or receipt of real-time
communications:
Comments:
5. Please provide any other comments (that you have not already provided in
response to the first four questions on this form) that you have on the revised
SAR.
Comments:
Page 5 of 5
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Consideration of Comments on First Draft of SAR for Operating Personnel
Communications Protocols
The Operating Personnel Communications Protocols SAR requesters thank all commenters who
submitted comments on Draft 1 of the Communications Protocols SAR. This SAR was posted for a
30-day public comment period from March 15 through April 17, 2007. The requesters asked
stakeholders to provide feedback on the standard through a special standard Comment Form. There
were 23 sets of comments, including comments from 69 different people from more than 45
companies representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Based on the comments received, the drafting team is recommending the SAR be submitted to the
Standards Committee for authorization to proceed to the standard drafting step. The SAR was not
materially changed. The description of the SAR scope was re-written to convey the intent of the
standard more clearly.
In this “Consideration of Comments” document stakeholder comments have been organized so that
it is easier to see the responses associated with each question. All comments received on the
standards can be viewed in their original format at:
http://www.nerc.com/~filez/standards/Op_Comm_Protocol_Project_2007-02.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to
give every comment serious consideration in this process! If you feel there has been an error or
omission, you can contact the Director of Standards, Gerry Adamski, at 609-452-8060 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
1
The appeals process is in the Reliability Standards Development Procedure manual:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Consideration of Comments — 1st Draft of SAR for Operating Personnel
Communications Protocols
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 – Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Anita Lee (G1)
AESO
2.
Fred Waites (G6)
Alabama Power
Company
3.
Ken Goldsmith (G3)
ALT
2
6
7
8
9
10
9
Jeff Hackman
Ameren Services
5.
Jason Shaver
American Transmission
Co.
9
6.
Dave Rudolph (G3)
BEPC
7.
Susan Renne
BPA
8.
Brent Kingsford (G1)
CAISO
9.
Ed Thompson (G4)
ConEd
10.
CJ Ingersoll
Constellation
11.
Michael Gildea (G4)
Constellation Energy
12.
Ed Davis
Entergy Services, Inc.
13.
Coleen Frosch
ERCOT
9
14.
Steve Myers (G1)
ERCOT
9
15.
David Folk
FirstEnergy Corp.
16.
Dick Pursley (G3)
GRE
9
9
9
9
9
9
9
9
9
9
9
9
17.
David Kiguel (G4)
Hydro One Networks
9
18.
Roger Champagne (I)
(G4)
Hydro-Québec
TransÉnergie (HQT)
9
19.
Ron Falsetti (I) (G1)
(G4)
IESO
9
20.
Matt Goldberg (G1)
ISO-NE
9
21.
Kathleen Goodman (I)
(G4)
ISO-NE
9
22.
William Shemley (G4)
ISO-NE
9
23.
Brian Thumm
ITC Transco
24.
Jim Cyrulewski (G2)
JDRJC Associates
KCPL
5
9
4.
Mike Gammon
4
9
9
25.
3
9
9
9
Page 2 of 24
June 8, 2007
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Consideration of Comments — 1st Draft of SAR for Operating Personnel
Communications Protocols
Commenter
Organization
Industry Segment
1
2
3
4
5
6
7
8
9
10
9
26.
Eric Ruskamp (G3)
LES
27.
Donald Nelson (G4)
MA Dept. of Tel. and
Energy
28.
Robert Coish (I) (G3)
Manitoba Hydro
29.
Tom Mielnik (G3)
MEC
30.
Terry Bilke (G2) (G3)
MISO
9
31.
William Phillips (G1)
MISO, SERC, MRO
9
32.
Carol Gerou (G3)
MP
33.
Michael Brytowski (G3)
MRO
9
9
9
9
9
9
9
9
9
34.
Randy Macdonald (G4)
NBSO
35.
Herb Schrayshuen (G4)
NGRID
9
36.
Michael Ranalli (G4)
NGRID
9
37.
Michael Schiavone (G4)
NGRID
9
38.
Guy V. Zito (G4)
NPCC
9
39.
Alan Boesch (G3)
NPPD
9
40.
Murale Gopinathan (G4)
NU
41.
Mike Calimano (I) (G1)
NYISO
42.
Greg Campoli (G4)
NYISO
43.
Al Adamson (G4)
NYSRC
44.
Alicia Daugherty (G1)
PJM
45.
Phil Riley (G5)
Public Service
Commission of SC
9
46.
Mignon L. Clyburn (G5)
Public Service
Commission of SC
9
47.
Elizabeth B. Fleming
(G5)
Public Service
Commission of SC
9
48.
G. O’Neal Hamilton
(G5)
Public Service
Commission of SC
9
49.
John E. Howard (G5)
Public Service
Commission of SC
9
50.
Randy Mitchell (G5)
Public Service
Commission of SC
9
51.
C. Robert Moseley (G5)
Public Service
Commission of SC
9
52.
David A. Wright (G5)
Public Service
Commission of SC
9
53.
Roman Carter (G6)
Southern Company
Transmission
9
54.
Marc Butts (G6)
Southern Company
Transmission
9
55.
J.T. Wood (G6)
Southern Company
Transmission
9
9
9
9
9
9
Page 3 of 24
June 8, 2007
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Consideration of Comments — 1st Draft of SAR for Operating Personnel
Communications Protocols
Commenter
Organization
Industry Segment
1
56.
Jim Busbin (G6)
Southern Company
Transmission
9
57.
Jim Griffith (G6)
Southern Company
Transmission
9
58.
Charles Yeung (G1)
SPP
2
3
4
5
6
7
8
9
10
9
9
59.
Ron Taylor
SRP
60.
Jim Haigh (G3)
WAPA
9
61.
Neal Balu (G3)
WPS
9
62.
Pam Oreschnik (G3)
Xcel
9
63.
David Lemmons (G2)
Xcel Energy
64.
Nancy Bellows (G7)
WAPA
9
65.
Mike Gentry (G7)
SRP
9
66.
Bob Johnson (G7)
Xcel (PSC)
9
67.
Frank McElvain (G7)
RDRC
9
68.
Greg Tillitson (G7)
CMRC
9
69.
Howard Rulf
We Energies
9
9
9
9
I – Indicates that individual comments were submitted in addition to comments submitted as part of a
group
G1 – IRC Standards Review Committee (IRC SRC)
G2 – Midwest Standards Collaboration Group (Midwest SCG)
G3 – MRO Members
G4 – NPCC CP9 Reliability Standards Working Group (NPCC CP9)
G5 – Public Service Commission of South Carolina
G6 – Southern Company Transmission
G7 – WECC Reliability Coordination Comments Work Group (WECC RCCWG)
Page 4 of 24
June 8, 2007
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Consideration of Comments — 1st Draft of SAR for Operating Personnel
Communications Protocols
Index to Questions, Comments, and Responses
1.
Do you believe that there is a reliability-related need to establish a set of communications
protocols to improve situational awareness and shorten response time? If “No,” please
explain why. .......................................................................................................... 6
2.
Do you agree with the scope of the proposed standard? If “No,” please explain why........10
3.
The proposed standard will be applicable to Transmission Operators, Balancing
Authorities, Reliability Coordinators, Generator Operators and Distribution Providers. Do
you agree with the proposed applicability? If “No,” please explain why ..........................17
4.
The SAR includes a list of standards that include requirements that involve the issuing or
receipt of real-time communications. If you are aware of additional requirements, beyond
those listed on pages 8-9, please identify them here. .................................................21
5.
Please provide any other comments (that you have not already provided in response to
the first four questions on this form) that you have on the revised SAR. ........................22
Page 5 of 24
June 8, 2007
1. Do you believe that there is a reliability-related need to establish a set of communications protocols to improve situational
awareness and shorten response time? If “No,” please explain why.
Summary Consideration: The majority of comments indicate that there is a reliability need for this SAR. Many comments
took issue with the phrase “pre-defined scripts” and the SAR DT has re-written the SAR scope description to clarify that it is not
the intent of the standard to require an extensive list of scripts to be used for all operating conditions. The SAR DT intent is for
the Standard DT to develop requirements for communications protocols that include essential elements such that when applied,
information is efficiently conveyed and mutually understood.
Question #1
Commenter
Ameren Services
BPA
Entergy Services
ERCOT
FirstEnergy
IESO
IRC SRC
ITC Transco
Manitoba Hydro
Midwest SCG
MRO Members
PSC of South
Carolina
WECC RCCWG
We Energies
Yes
No
Comment
;
;
;
;
;
;
;
;
;
;
;
;
;
;
Response:
The SAR DT acknowledges the commenters’ affirmative response to this question and appreciates their submission.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #1
Commenter
ATC LLC
Yes
Constellation
;
Hydro-Québec
TransÉnergie
;
;
ISO-NE
;
;
No
Comment
The
SAR
needs
further
clarification
before
it is moved into the next stage. The SAR
;
should identify at a minimum the words and procedures that the SDT is going to
consider for a reliability standard.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
ECD believes there is a reliability reason for establishing a set of communication
protocols.
Response: The SAR DT acknowledges the commenter’s affirmative response to this question and appreciates its submission.
HQT supports establishing communication protocols to define consistent emergency
determinations. However, the standard should not extend to establishing pre-defined
scripts that operators must follow in their communications without the element of
judgment and discussion that are needed in such situations.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
ISO New England supports establishing communication protocols to define consistent
emergency determinations. However, the standard should not extend to establishing
pre-defined scripts that operators must follow in their communications without the
element of judgment and discussion that are needed in such situations.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
NPCC CP9
;
;
NPCC participating members agree with the need to establish communication protocols
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #1
Commenter
Comment
to define consistent emergency determinations. However, the standard should not
extend to establishing pre-defined scripts that operators must follow in their
communications without the element of judgment and discussion that are needed in such
situations.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
NYISO
Yes
No
;
;
See comments in Question #2.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
Southern Company
Transmission
;
;
If all Owners, Operators, and Users of the Bulk Electric system adhered to the current
NERC standards (and previous Operating Policies), we do not believe this standard would
be necessary. However, we understand that this SAR is an attempt to make it very clear
what is expected of a RC, TOP, BA, GO, and DP in way of communciations during
emergency situations.
We feel that this communication protocol should be only applicable under the current
EEA Level 1 and above state or with the new Transmission Emergency state currrently
being developed.
Response: The SAR DT believes that communications protocols that enable information to be efficiently conveyed and
mutually understood are necessary under all operating conditions and not only during emergency or abnormal operating
conditions.
KCPL
;
Not to the extent this SAR is addressing itself. The Black Out Report is overly broad and
vague regarding this issue. This SAR would make more sense if it were addressing itself
to tightening existing protocols and documenting them between entities. The way this
SAR has been presented, pre-defined terms would have to be developed. Who would be
responsible to determine what these pre-defined terms would be and would the terms be
applicable to all operating entities? Adjacent operating entities have a long history of
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #1
Commenter
Yes
No
Comment
communicating and differing terms are understood.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
2. Do you agree with the scope of the proposed standard? If “No,” please explain why
Summary Consideration: Many commenters expressed concern with “pre-defined scripts”. The SAR DT did not intend to
prescribe scripts for all possible conditions, and the SAR DT has re-written the SAR’s description to clarify that it is not the
intent of the standard to require an extensive list of scripts to be used for all operating conditions but rather for the Standard
DT to develop requirements for communications protocols that include essential elements such that when applied, information
is efficiently conveyed and mutually understood.
There was a comment that the standard should apply to “local control centers”. The SAR DT noted that although the system
operators who work in local control centers operate under the direction of a TOP or RC, the local control center is typically
owned and operated by the Transmission Owner. The SAR DT has added the functional entity of Transmission Owner as an
applicable entity to give the standard DT maximum flexibility to do their work.
Question #2
Commenter
BPA
Entergy Services
FirstEnergy
Yes
No
Comment
;
;
;
;
PSC of South
Carolina
Response:
The SAR DT acknowledges the commenters’ affirmative response to this question and appreciates their submission.
Southern Company
As mentioned in the answer to question #1, we feel it should be applicable for EEA Level
;
Transmission
1 and above or with the new Transmission Emergency state currently being developed.
Response: The SAR DT believes that communications protocols that enable information to be efficiently conveyed and
mutually understood are necessary under all operating conditions and not only during emergency or abnormal operating
conditions.
Constellation
;
CECD agrees with the scope, however, CECD would caution that pre-defined action in
response to grid operations would need to be broad enough to allow the flexibility that is
required by a diverse system. The statement that raises this concern in the Scope is the
first sentence which states, the scope of the proposed standard or revised standards is
to establish a common lexicon of communications protocols and communication paths
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
Yes
No
Comment
such that all operators and users of the North American bulk electric system have the
same understanding as to its meaning, usage and take pre-determined action in
response. The standard should focus on the communication paths, per-determined
contacts (regular communication/testing), the applicable langage and the terminology
but not necessarily a specific action.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
WECC RCCWG
;
Hydro-Québec
TransÉnergie
IESO
;
;
See response to Question #1.
;
;
ISO-NE
;
;
;
;
The scope of the SAR is too broad and too prescriptive. The Applicability section of the
SAR where it states "... the protocol shall define a rigorous script for the Sender and
Receiver of information…" is too prescriptive yet not exhaustive enough to cover all
situations. We support the notion of defining standard terms to be used in operation
personnel communication, but do not believe predetermined script is required in every
communication situation, nor do we think it is possible to have a set of scripts that
covers all possible cases.
See response to Question #1.
While the WECC RCCWG agrees in general with the scope of the proposed standard, the
work group has some questions and comments regarding terms used in the scope. The
scope of the SAR may be widened to "establish and implement a lexicon of
communications protocols and communications paths." Please define "communication
path" as used in the scope - is this the expected communications between entities as
opposed to the actual physical paths of those communications? Additionally, there is a
general comment that establishment of a lexicon does not, in itself ensure predetermined action as noted in the scope. What type of pre-determined actions are
expected, operating or communications?
Response: The SAR DT defines communications path as the means/method used to communicate. The SAR DT does not
intend to prescribe which means/method to use but that one is in place. Pre-determined actions are previously agreed upon
communication actions taken in response to specific operating conditions.
NPCC CP9
See our comments to Question #1.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
Yes No
Comment
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
Ameren Services
;
There is no doubt that during alerts and emergencies, both parties in communication
require a common definition. To the extent the standard requires neighboring BAs, TOs
and RCs to use the same word with the same meaning, then the scope of the proposed
standard makes sense. However, as written the standard appears to indicate the kind of
scripting that is better suited to selling magazines from a boiler room. No defined
protocol can match every situation. And if in fact that was even a goal, the operators
would have the time-consuming task of identifying which script currently was needed
when their time would be better spent resolving the situation.
The SAR also proposes that any reliability impacts beyond a Reliability Coordinator's area
must be coordinated and approved by the impacted Reliability Coordinator. Clearly, if
time permits, this coordination is appropriate. However, in an emergency, the RC nay
have to use independent judgment.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
The coordination between RC and TOP/BA is addressed in a separate project 2006-6 Reliability Coordination and is not part of
this SAR.
ATC LLC
; The SAR should be expanded to include local control center’s system operators.
See our comments to question 3.
The SAR should specify how each of the identified standards will be addressed through
this process.
Response: The SAR DT believes that while “local control centers” are under the purview of either a Transmission
Operator/Balancing Authority or Distribution Service Provider the SAR DT have added the functional entity of Transmission
Owner as an applicable entity to give the standard DT maximum flexibility to do their work.
ERCOT
may be a need for pre-defined terms, however we do not agree with the concept
; There
of a rigorous script for communications. It would not be possible to identify every
operational situation.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
Yes No
Comment
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
IRC SRC
are concerned that the scope of "... the protocol shall define a rigorous script for the
; We
Sender and Receiver of information" is too prescriptive yet not exhaustive enough to
cover all situations. We support the notion of defining standard terms to be used in
operation personnel communication, but do not believe predetermined script is required
in every communication situation, nor do we think it is possible to have a set of scripts
that covers all possible cases.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
ITC Transco
SAR scope needs to be clear in that it refers to specific protocols for communication,
; The
and not to "scripted" responses for every situation. Although the SAR discusses the use
of protocols, other context of the remaining passages in the SAR lead one to believe
otherwise.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
KCPL
SAR description suggests establishment of "protocols shall define a rigorous script"
; The
to be followed. It would be impracticle to presume to think through every operating
condition that scripting would require. Although the notion of everyone using the same
terms or phrases sounds good, the development of such an operating "dictionary" is not
practicle. Who will be the final word on terminology the industry must adopt that
changes the way in which operating entities have described their adopted practices and
procedures for decades?
The scope of the SAR should limit itself to the principles of effective communication for
operating entities to follow and not so prescriptive such as pre-definition of terms.
Operating entities are smart enough to be able to use effective communication principles
in a standard to determine and document communication protocols and terminology
between them that provides effective communication. The same should apply between
Reliability Coordinators. Follow the basic standards development: a standard should not
say how something should be done, it should say what the required outcome should be.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
Manitoba Hydro
Yes
No
Comment
The
scope
of
this
SAR
is
much
to
far
reaching.
It appears that the intention is for the this
; Standard to reach into the intra region operation.
This could become a safety issue as
Utility Safety Rule Books could be in conflict with terminalogy being proposed by the
standard writer. Getting this standard accepted by the industry at large will be a major
hurtle to jump.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
The coordination between RC and TOP/BA is addressed in a separate NERC Project 2006-6 entitled Reliability Coordination
and is not part of this SAR.
It is not the intent of the standard to define terms that may conflict with other programs but rather to prescribe essential
elements (not necessarily specific terms) in communications protocols such that information is efficiently conveyed and
mutually understood.
Midwest SCG
;
The recommendation from the blackout report is overly broad and vague. Tightening
does not sound like a complete overhaul but rather tweaking the existing protocols and
documenting them if they are informal. This may not even require a standard across all
functional entities. For instance, establishing a common lexicon makes sense at face
value; however, it may not be needed for communications between neighboring BAs.
BAs and TOPs in a given region have long history of communication and differing terms
are already understood. However, for communications that occur between regional
areas, there may be a need for common terms.
We do not agree with the concept of a rigorous script for communications. This sounds
like it would require the team to identify any operational situation that could ever occur
and then establish a script. If this were possible, it would be great. However, it is not
possible. This is why we have trained (yes there is a training standard) operators to
make decisions when new operational situations occur.
The SAR also proposes that any reliability impacts beyond a Reliability Coordinator's area
must be coordinated and approved by the impacted Reliability Coordinator. This is
certainly a laudable goal but is not reasonable in all cases. If there is an IROL violation
in RC A's area and the action the RC would take would impact the area of RC B, RC A
could not take action until RC B approved the action. Let's assume the impact on RC B is
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
Yes
No
Comment
that a small load would be radialized when RC A opens a circuit to correct the IROL. This
seems like a small risk to subject to RC B since the action will immediately correct the
IROL. After the IROL is corrected, then RC A and RC B could begin determining other
options. With the proposed language in the SAR, RC A would have violated this standard
even though they eliminated that risk of more widespread outages.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
The coordination between RC and TOP/BA is addressed in a separate NERC Project 2006-6 entitled Reliability Coordination
and is not part of this SAR.
MRO Members
;
The scope need not be so expansive , it should start at a high level with no scripted
message.
We do not agree with the concept of a rigorous script for communications. This sounds
like it would require the team to identify any operational situation that could ever occur
and then establish a script. If this were possible, it would be great. However, it is not
possible. This is why we have trained (yes there is a training standard) operators to
make decisions when new operational situations occur.
The Communication Training can be made part of Operator Training Procedures.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
The SAR DT agrees that training is essential.
NYISO
The NYISO is concerned that the scope of "... the protocol shall define a rigorous script
; for
the Sender and Receiver of information" is too prescriptive yet not exhaustive
enough to cover all situations. We support the notion of defining standard terms to be
used in operation personnel communication, but do not believe predetermined script is
required in every communication situation, nor do we think it is possible to have a set of
scripts that covers all possible cases.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #2
Commenter
We Energies
Yes
No
Comment
The
scope
should
be
limited
to
communications
between entities and should not
; prescribe communication protocols for communication
within an organization. Intracompany communications are most appropriately addressed by interal policies and
procedures tailored to an entity's specific needs and characteristics.
Response: The SAR DT agrees that the scope of this standard does not apply to internal non-reliability related company
communications; however it does apply to separate functional entities within a single company.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
3. The proposed standard will be applicable to Transmission Operators, Balancing Authorities, Reliability Coordinators,
Generator Operators and Distribution Providers. Do you agree with the proposed applicability? If “No,” please explain why
Summary Consideration: The majority of the commenters agreed that the proposed requirements should be applicable to
the RC, BA, TOP, GO and DP functional entities.
Question #3
Commenter
Ameren Services
BPA
Constellation
Entergy Services
ERCOT
FirstEnergy
Hydro-Québec
TransÉnergie
IESO
IRC SRC
ISO-NE
ITC Transco
KCPL
Manitoba Hydro
NPCC CP9
NYISO
Yes
No
Comment
;
;
;
;
;
;
;
;
;
;
;
;
;
;
;
;
PSC of South
Carolina
Response:
The SAR DT acknowledges the commenters’ affirmative response to this question and appreciates their submission.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #3
Commenter
Yes No
Comment
Southern Company
However,
there
is
only
one
"real
time"
requirement
that is applicable to the DP. It is
;
Transmission
contained in TOP-001-1, R4.
Response: The SAR DT agrees that the DP comply with direction from TOP. This standard does not conflict with that
requirement but is intended to ensure quick, clear and mutual understanding of any directives from the TOP to the DP.
WECC RCCWG
;
The WECC RCCWG generally agrees, but some questions remain. The standard will
apply to TO, BA, GO, DP; however, the SAR (Applicability Section #2) states that all
those entities "will be required to adopt and employ directives that use pre-defined
terms, and will require entities that receive those directives to respond to the reliability
coordinator using pre-defined terms." Entities that receive those directives should
respond to the entity issuing the directives using pre-defined terms. Additionally, the
WECC RCCWG believes that the SAR drafting committee should consider adopting the
term "directive" for reliability coordinator issue only and adopt another term, such as
"operating instructions" for those actions directed by other than the reliability
coordinator to distinguish between the two terms.
Response: The SAR’s detailed description was revised to delete the sentence that indicated the standard would require
scripts to be used. The SAR DT’s intent is for the standard to require that communications include essential elements or
protocols such that information is efficiently conveyed and mutually understood.
The SAR DT believes that limiting the use of the word directive by RC’s only is not within the scope of this standard. The use
of the word “directive” occurs throughout several NERC standards.
ATC LLC
;
Issue 1:
The recommendation from the blackout report is overly broad and vague. Tightening
does not sound like a complete overhaul but rather tweaking the existing protocols and
documenting them if they are informal. This may not even require a standard across all
functional entities. TOPs and BAs in a given region have long history of communication
and differing terms are already understood. However, for communications that occur
between regional areas, there may be a need for common terms.
ATC does not agree with the concept of a rigorous script for communications. This may
sound like it would require the team to identify any operational situation that could ever
occur and then establish a script. If this were possible, it would be great. However, it is
not possible. This is why we have trained operators to make decisions when new
operational situations occur.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #3
Commenter
Yes
No
Comment
Issue 2:
The SAR needs to include local control center’s system operators. The inclusion of this
group of system operators will not be simple because local control centers are not an
identified entity in NERC’s functional model. Never the less if the SDT is going to create
a common lexicon and procedures it’s important that these system operators are
required to follow the standard. ATC believes that the purpose behind this SAR would be
better address through NERC’s CEH program then through reliability standards.
SAR Scope:
“The scope of the proposed standard or reviewed standards is to establish a common
lexicon of communications protocols and communications paths such that all operators
and users of the North American bulk electric system have the same understanding as to
its meaning, usage and take pre-determined action in response.”
PER FERC Final Rule RM06“1343. Clearly, in a region where an RTO or ISO performs the transmission operator
function, its personnel with primary responsibility for real-time operations must receive
formal training pursuant to PER-002-0. IN addition, personnel who are responsible for
implementing instructions at a local control center also affect the reliability of the Bulk
Power System. These entities may take independent action under certain
circumstances, for example, to protect assets, personnel safety and during system
restorations. Whether the RTO or the local control center is ultimately responsible for
compliance is a separate issue addressed above, but regardless of which entity registers
for that responsibility, these local control center employees must receive formal training
consistent with their roles, responsibilities and tasks. Thus, while we direct the ERO to
develop modifications to PER-002-0 to include formal training for local control center
personnel, that training should be tailored to the needs of the positions.”
“1345. Another organization structure, typically representative of relative smaller
entities, consists of a single control center that implements operating instructions from
its transmission operator, e.g., an RTO, ISO or pooled resources. Similar to the
discussion above, operators at these control centers also may take independent action to
protect assets, safety and system restoration. Such control center personnel must also
receive formal training pursuant to PER-002-0.”
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #3
Commenter
Yes
No
Comment
Because NERC has been order to create training plans for local control center’s system
operator any common lexicon and communications protocols could be dealt with for all
entities most effectively in NERC’s CEH program.
Response: See previous responses to Questions 1 and 2.
Midwest SCG
agree that these functional entities should be considered for applicability; however, it
; We
is possible that the final standard should not apply to all of them. Further examination
of the reason for the recommendation of the from the blackout report would help
determine this.
Response: The SAR DT view is all of the applicable entities, RC, BA, TOP, GO, DP should be guided by communication
protocols to ensure quick, clear and mutual understanding of information between them in real time. The specific reasons
identified in the Blackout report are addressed by this SAR but is not limited by them.
MRO Members
agree that these functional entities should be considered for applicability; and in
; We
addition it should apply to Interchange Coordinator Function.
Response: The SAR DT believes the Interchange Authority function is under the BA function. The IA does ‘receive’ info from
other entities and may, under some circumstances relay that info to others – see FM V3 P32, Real-time #7.
We Energies
should be limited to communication among separate entities/organizations. For
; Scope
example, the standard should not address communication protocols between a Balancing
Authority, Generaotr Operator and a Distribution Provider tha are the same corporate
entity. The requirement to maintain situational awareness within a given entiy is
addressed by other standards.
Response: The SAR DT agrees that the scope of this standard does not apply to internal non-reliability related company
communications protocols, however it does apply to separate functional entities within a single company.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
4. The SAR includes a list of standards that include requirements that involve the issuing or receipt of real-time
communications. If you are aware of additional requirements, beyond those listed on pages 8-9, please identify them here.
Summary Consideration: Based on stakeholder comments, the SAR DT modified the SAR to clarify that EOP-001-0
Attachment 1 should be addressed by the standard drafting team.
Question #4
Commenter
Yes No
Requirement
Southern Company
IRO-016-1,
R1
;
Transmission
Response: The SAR DT would like the Standard DT to
duplication, conflicts and consolidation.
BPA
Hydro-Québec
TransÉnergie
Comment
We do not recommend bringing the requirement over to this SAR. It
is better to leave in the IRO standards.
consider communication-related requirements in other standards for
None identified.
No others.
No others.
If it is the intention of the standard writer to re write these
requirements into scripts than we see problems, especially if it is
intended to push these scripts into the entities' intra region operating
procedures.
Response: The SAR DT does not intend to re-write any requirements into scripts.
ISO-NE
Manitoba Hydro
MRO Members
;
EOP-001-0 Attachment 1
Response: The SAR DT agrees with the commenter.
NPCC CP9
No others.
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
5. Please provide any other comments (that you have not already provided in response to the first four questions on this form)
that you have on the revised SAR.
Summary Consideration: Based on stakeholder comments, the SAR DT modified the SAR to clarify that three-part
communications will be included in the proposed requirements.
Question #5
Commenter
PSC of South
Carolina
Yes
No
Comment
The PSCSC believes the SAR should specifically acknowledge the power and
effectiveness of three-part communications in ensuring common understanding of verbal
exchanges. Three-part communications include the sender giving the information, the
receiver repeating the information back, and the sender acknowledging the correctness
of the repeated information. This form of communication is used in nuclear plant
communications and in other industries where it is critical that everyone involved has a
common understanding of the intended message.
Response: The SAR DT thanks the commenter for this item and has incorporated the use of three-part communications into
the scope of the SAR.
Southern Company
*Under FERC staff's Preliminary Assessment contained on page 7 of the SAR (items i and
Transmission
ii), item ii should not be addressed in this SAR. There are numerous requirements in the
IRO standards already that adequately cover communications to other RCs for situations
in which a reliability impact may go beyond a RC's area of view. In particular, the
IRO-001-1, Req. 7;
following standard requirements address the 2nd part (ii):
IRO-003-2, Req.1; IRO-004-1, Req.2; IRO-014-1, Req.1,2,3; IRO-015-1, Req.1,2;
IRO-016-1, Req.1;
*If the SAR drafting team removes the requirements of the standards referenced in the
"Related Standards" section of this SAR and move them to this SAR, it will become
difficult for a Reliability Coordinator to know where to go for standards applicable to
them. For example, currently most of the requirements related to real time actions taken
by a RC are contained in the IRO standards. If the 4 IRO standard requirements are
removed from the IRO standards and placed into this SAR, the RC system operators will
now have to refer to more standards to find requirements related to their
responsibilities. This same scenario also applies to the other standard drafting teams
who are considering the same actions.
It would be helpful if NERC were to provide on the Standards Homepage a listing of
Page 22 of 24
June 8, 2007
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #5
Commenter
Yes
No
Comment
standards by Function: RC, BA, TOP, etc. Then the RC could review the RC function and
know all standards that are applicable to them in a quick and easy fashion.
Response: The SAR DT would like the Standard DT to consider communication-related requirements in other standards for
duplication, conflicts and consolidation.
There is a link to a document “Version 0 and Version 1 Matrix of Requirements by Function” on the NERC Standards website.
The link may be found on the “BOT Approved Standards” webpage in the center of the page. Many standards include
requirements that are applicable to more than one functional entity.
FirstEnergy
No additional comments.
Manitoba Hydro
We believe that there is a need to clean up the communication protocol in as far as full
name identification of all parties for all communications between entities and three part
comunication: the sender giving the information or direction, the receiver repeating the
information or direction back as to his understanding, and the reciever confirming or
correcting the repeated statement. If there is a correction than the process is repeated.
A glossary of terms for industry standard operating terms is essential. This glossary with
input from the entities should be an integral part of this SAR.
Response: The SAR DT thanks the commenter for the item regarding three part communications and have incorporated it
into the scope of the SAR.
The SAR’s detailed description was revised to delete the sentence that indicated the standard would require scripts to be
used. The SAR DT’s intent is for the standard to require that communications include essential elements or protocols such
that information is efficiently conveyed and mutually understood.
MRO Members
Proof of the pudding is in tightly defining the Requirements and stipulating the Severity
Levels and VRFs accurately so that the penalties are commensurate with the severity
level and the VRF.
Is there a consistent methodology between IRO-014-1 R1.1 footnote 1 and CIP-008-1
R1.2?
Is IRO-001-1 R3 a repeat of IRO-005-2 R3?
There is an overlapping request for requirements for communication facilities for use
during emergencies. These requests are made in this SAR (Operating Personnel
Communications Protocols Project 2007-02) and in the SAR for Project 2006-06
Reliability Coordination-Attachment 1. Perhaps both the associated drafting teams could
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
Question #5
Commenter
Yes
No
Comment
work together so that there are no overlapping requirements among developed
standards. We do not see the purpose behind not including the recommendation
regarding the upgrade to communication system hardware in this SAR. This SAR should
include , if need be, the recommendations to upgrade communication system hardware.
Response: The Standard DT and Compliance Elements DT will work together to ensure the VRF and VSL assignments are
appropriate.
The SAR DT will endeavor to eliminate any duplication and/or contradictions with other reliability standards.
COM-001 addresses hardware requirements and continue to be in effect until it is formally retired. The retirement can occur
all at once or can occur on a requirement by requirement basis.
NPCC CP9
SRP
NPCC participating members agree with the concepts in the SAR.
The SAR is a proposal for protocols to be used over "pre-established communications
paths". This is good as far as it goes. When Operations sits down to write up these
protocols with their peers, I recommend that they have a Communications person from
at least one of the utilities on the panel to initially clearly delineate what the
recommended path(s) are between the subject utilities. This will be based on use of
private systems first with the possibility of widespread unavailability of commercial
services, etc.
Response: Thank you for your comment, the scope of this SAR concerns itself with communication protocols (verbal, written
and visual) and not with telecommunications systems. (See COM-001-1)
Page 24 of 24
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Consideration of Comments — SAR for Operating Personnel Communications Protocols
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard Authorization Request Form
Title of Proposed Standard:
Operating Personnel Communications Protocols
Request Date:
March 1, 2007
Revised Date:
June 8, 2007
SAR Requester Information
SAR Type (Check one box.)
Name:
Lloyd Snyder
Company:
Georgia System Operations Corp.
New Standard
Telephone:
770-270-7418
Revision to Existing Standard
Fax:
770-270-7672
Withdrawal of Existing Standard
E-mail:
[email protected]
Urgent Action
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
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Standards Authorization Request Form
Purpose (Describe the purpose of the proposed standard – what the
standard will achieve in support of reliability.)
Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve
situational awareness and shorten response time. The purpose of this
standard is to:
1.
Provide an adequate level of reliability for the North American
bulk power systems – by ensuring that the standards are complete
and the requirements are set at an appropriate level to ensure
reliability.
2.
Ensure the standard or standards are enforceable as mandatory
reliability standards with financial penalties - the
applicability to bulk power system owners, operators, and users,
are clearly defined; the purpose, requirements, and measures are
results-focused and unambiguous; the consequences of violating
the requirements are clear.
3.
Consider other general improvements described in the standards
development work plan.
4.
Consider stakeholder comments received during the initial
development of the standards and other comments received from
Electric Reliability Organization (ERO) regulatory authorities,
as noted in the attached review sheets.
5.
Satisfy the standards procedure requirement for five-year review
of the standards.
Industry Need (Provide a detailed statement justifying the need for
the proposed standard, along with any supporting documentation.)
The need for improved real-time communications protocols was
identified during the investigation of the August 2003 Blackout.
Blackout Recommendation #26 is: “Tighten communications protocols,
especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate.” (Note that this SAR
does not include the second part of this recommendation regarding the
upgrade to communication system hardware.)
SAR–2
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Standards Authorization Request Form
Brief Description (Describe the proposed standard in sufficient detail
to clearly define the scope in a manner that can be easily understood
by others.)
This standard will require the use of specific communication
protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditions. The standard will
be applicable to transmission operators, transmission owners balancing
authorities, reliability coordinators, generator operators and
distribution providers.
Requirements will ensure that communications include essential elements such
that information is efficiently conveyed and mutually understood for
communicating changes to real-time operating conditions and responding
to operating directives.
The project may involve moving some requirements that address
communications protocols from existing standards into this new
standard and will involve adding new requirements that more fully
address communications protocols under various operating conditions.
SAR–3
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check all applicable boxes.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Coordinator
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads within
a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk Electric
System within its portion of the Planning Coordinator area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market Operator
Interface point for reliability functions with commercial functions.
SAR–4
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Standards Authorization Request Form
Reliability and Market Interface Principles
Applicable Reliability Principles (Check all boxes that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained, and implemented.
5. Facilities for communication, monitoring, and control shall be provided, used, and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement actions.
7. The reliability of the interconnected bulk power systems shall be assessed, monitored,
and maintained on a wide-area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface Principles?
(Select ‘yes’ or ‘no’ from the drop-down box.)
Recognizing that reliability is an essential requirement of a robust North American economy:
1. A reliability standard shall not give any market participant an unfair competitive advantage.Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR–5
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Standards Authorization Request Form
Detailed Description (Provide enough detail so that an independent
entity familiar with the industry could draft a standard based on this
description.)
Scope
The scope of the proposed standard is to establish essential elements
of communications protocols and communications paths such that
operators and users of the North American bulk electric system will
efficiently convey information and ensure mutual understanding. The
August 2003 Blackout Recommendation Number 26 calls for a tightening
of communications protocols. This standard is to ensure that
effective communication is practiced and delivered in clear language
via pre-established communications paths among pre-identified
operating entities. References to communication protocols in other
NERC Standards may be moved to this new standard. The standard
drafting team shall consider incorporating the use of Alert Level
Guidelines and three-part communications in developing this new
standard to achieve high level consistency across regions.
Applicability
Medical, law enforcement, air traffic control and other fields
routinely use mutually defined and understood terminology or codes.
Clear and mutually established communications protocols used during
real time operations under normal and emergency conditions ensure
universal understanding of terms and reduce errors.
Communications protocols shall precisely define terms, codes, phrases,
words, etc. as to their connotation, conditions for use, context of
use and expected responses in reply to these terms, codes, phrases,
words, etc. Effective communications with proper communications
protocols among the operating entities are essential for maintaining
reliable system operations.
The standard will include requirements for the following:
1. Real—time system operators will be required to use specific
communications protocols under normal, abnormal and emergency
conditions to relay critical reliability-related information in a
timely and effective manner.
2. Reliability Coordinators, Balancing Authorities, Generation
Operators, Transmission Operators, Transmission Owners and
Distribution Providers will be required to comply with this
standard.
3. The standard will include requirements for entities that
experience abnormal conditions to use pre-defined terms such as
proposed in the “Alert Level Guideline” (attached) to communicate
the operating condition to other entities that are in a position
to either assist in resolving the operating condition or to
entities that are impacted by the operating condition.
SAR–6
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Standards Authorization Request Form
4. The standard may include other requirements that involve
communications protocols for real-time system operators.
The standard should address directives 1 and 3 of the FERC Order 693
Mandatory Reliability Standards, paragraph 540 which contains
(directive 1 will also be addressed in Project 2006-06; directive 2
will be addressed in Project 2006-06):
“…the Commission identified concerns regarding COM-002-2, the proposed
Reliability Standard serves an important purpose by requiring users, owners and operators to
implement the necessary communications and coordination among entities.
Accordingly, the Commission approves Reliability Standard COM-002-2 as mandatory and
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of
our regulations, the Commission directs the ERO to develop a modification to COM-0022 through the Reliability Standards development process that: (1) expands the
applicability to include distribution providers as applicable entities; (2) includes a new
Requirement for the reliability coordinator to assess and approve actions that have
impacts beyond the area view of a transmission operator or balancing authority and
(3) requires tightened communications protocols, especially for communications during alerts
and emergencies. Alternatively, with respect to this final issue, the ERO may
develop a new Reliability Standard that responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally, we direct the ERO to include APPA’s
suggestions to complete the Measures and Levels of Non-Compliance in its modification of
COM-002-2 through the Reliability Standards development process.”
SAR–7
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Standards Authorization Request Form
Related Standards
Standard No.
COM-001-1
COM-002-2
Explanation – these requirements may need to be modified or moved to the new
standard
R4 is a requirement for the Reliability Coordinator’s, Transmission Operator’s, and
Balancing Authority’s real-time operating personnel to use English when
communicating between entities.
R1.1 is a requirement for the Balancing Authority and Transmission Operator to make
notifications when there is a threat to reliability.
R2 is a requirement for the Reliability Coordinator, Transmission Operator and
Balancing Authority relative to issuing and receiving operating directives.
EOP-001-0
R4.1 includes a requirement for the Transmission Operator and Balancing Authority
to have communications protocols for use during emergencies (and Attachment 1EOP-001-0)
EOP-002-2
R6.5 and R7.2 require the Balancing Authority to ask the Reliability Coordinator to
declare an Energy Emergency or an Energy Emergency Alert under certain
conditions
R8 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R9.1 requires the Load-serving Entity to ask the Reliability Coordinator to declare an
Energy Emergency Alert under certain conditions
EOP-006-1
R4 requires the Reliability Coordinator to disseminate information regarding
restoration to neighboring Reliability Coordinators and Transmission Operators or
Balancing Authorities
R5 requires the Reliability Coordinator to approve, communicate, and coordinate the
re-synchronizing of major system islands or synchronizing points
CIP-001-1
R1 and R2 require operating entities to have procedures for communicating
information relative to sabotage of bulk power system facilities
CIP-008-1
R1.2 requires the responsible entity to have a communication plan for response to a
cyber security incident
IRO-001-1
R3 requires the Reliability Coordinator to direct entities to act and R8 requires entities
to respond to the Reliability Coordinator’s directives
IRO-004-1
R6 requires the Reliability Coordinator to direct entities to act and R7 requires entities
to respond to the Reliability Coordinator’s directives
IRO-005-2
R4 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R3, R5, R8, R11, R15, and R17 require the Reliability Coordinator to direct actions to
alleviate various types of abnormal or emergency situations
IRO-014-1
R1.1 requires Reliability Coordinators to have procedures processes or plans that
address communications and notifications made between Reliability Coordinators
under various operating scenarios
PRC-001-1
R6 requires the Transmission Operator and Balancing Authority to make notifications
when there is a change in the status of a special protection system
TOP-001-1
R3 requires some responsible entities to comply with the Reliability Coordinator’s and
Transmission Operator’s directives
R4 requires some responsible entities to comply with the Transmission Operator’s
directives
R5 requires the Transmission Operator to notify its Reliability Coordinator of certain
emergency situations
SAR–8
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Standards Authorization Request Form
TOP-002-2
R14, R16 and R17 require responsible entities to notify their Reliability Coordinator of
various changes to operating parameters
R18 requires the use of uniform line identifiers when referring to transmission facilities
of an interconnected network
TOP-007-0
R1 requires the Transmission Operator to notify its Reliability Coordinator when it
exceeds an SOL or IROL
R4 requires the Reliability Coordinator to direct entities to take actions to restore the
system to within SOLs or IROLs
TOP-008-1
R3 requires the Transmission Operator to make notifications if it disconnects an
overloaded facility
VAR-001-1
R8 and R12 require the Transmission Operator to direct actions to maintain voltage
within limits and to prevent voltage collapse
VAR-002-1
R2.2 and R5.1 require the Generator Operator to comply with directives
R3 requires the Generator Operator to notify the Transmission Operator of various
status or capability changes
Related SARs
SAR ID
Project 2006-06
Explanation
Reliability Coordination SAR
Project 2007-08
Emergency Operations
Regional Variances
Region
ERCOT
Explanation
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
SAR–9
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2007/05/17
Guideline for Operating State Alert Levels
Background
System operators need common definitions for normal, alert, and emergency conditions to enable them
to act appropriately and predictably as system conditions change. On August 14, 2003, the principal
entities involved in the blackout did not have a shared understanding of whether the grid was in an
emergency condition, nor did they have a common understanding of the functions, responsibilities,
capabilities, and authorities of reliability coordinators and control areas under emergency or nearemergency conditions.
The U.S./Canada Task Force Recommendation 20 recommends the establishment of clear definitions of
normal, alert, and emergency operational system conditions, and to clarify the roles, responsibilities,
and authorities of reliability coordinators and control areas under each condition.
At its May 2006 meeting, the NERC Reliability Coordinator WG approved a motion to implement a
pilot program that defined normal, alert, and emergency operating conditions as they relate to
Transmission Loading and Security. The intent is to align the definitions for Transmission Loading and
Security with the conditions identified in the Emergency Energy Alert states. In an effort to clarify the
application of the definitions being used in the pilot program this guideline has been created. In the
event of a conflict between the pilot program and applicable NERC Standards the Standards should
always be applied first.
Condition Level
Normal
>>>>
Threat Level>>>> Low
Condition/Threat
Green
Color >>>>
EEA 0
No Energy
Generating/capacity Deficiencies
Transmission
Security
TEA 0
Respecting all
IROLs
SEA 0
No cyber threat
identified; No
known threats on
control center or
grid assets (lines,
substations,
generators)
Alert Level 1
Alert Level 2
Alert Level 3
Elevated
High
Severe
Yellow
EEA 1
all available
resources in use
Orange
EEA 2
Load management
procedures in effect
TEA 1
All available
resources
committed to
respecting IROLs
SEA 1
Cyber threat
identified or is
imminent, OR
verified physical
threat against
control center or
grid assets
Draft
Red
EEA 3
Firm load
interruption
imminent or in
progress
TEA 2
TEA 3
Load Mgmt
Firm Load
procedures in effect Curtailments in
to respect IROLs effect to respect
IROLs
SEA 2
SEA 3
Cyber event is
Cyber event has
affecting control
shut down control
center EMS
center EMS
capability, OR
capability, OR
physical attack at physical attack at
single site (control multiple sites
center or grid
(control center or
assets- lines,
grid assets- lines,
substations,
substations,
generators)
generators)
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Transmission Emergency Alert (TEA) Levels
Introduction
This Attachment provides the procedures by which a Transmission Operator or Reliability Coordinator
can advise of actions taken to manage potential or actual Interconnected Reliability Operating Limit
(IROL) violations.
All three operating alert states (EEAs, TEAs and SEAs) are independent of each other and should be
declared independently but they may also be declared concurrently.
A. General Requirements
1. Initiation by Reliability Coordinator. A Transmission Emergency Alert (TEA) may be initiated
only by a Reliability Coordinator at:
1) the Reliability Coordinator’s own request, or
2) upon the request of a Transmission Operator
1.1. Situations for initiating alert. A Transmission Emergency Alert may be initiated for the
following reasons:
•
•
When all the available resources have been committed to respect an IROL in the
pre-contingency state.
When load curtailment procedures have been implemented to respect an IROL.
2. Notification. A Reliability Coordinator who declares a Transmission Emergency Alert shall notify
all Transmission Operators and Balancing Authorities in its Reliability Area. The Reliability
Coordinator shall also notify Reliability Coordinators of the situation via the
Reliability Coordinator Information System (RCIS) using the “System Emergency” category.
Additionally, conference calls between Reliability Coordinators shall be held as necessary to
communicate system conditions. The Reliability Coordinator shall also notify all Transmission
Operators and Balancing Authorities in its Reliability Area and Reliability Coordinators when the alert
has ended.
B. Transmission Emergency Alert Levels
Introduction
To ensure that all Reliability Coordinators clearly understand potential and actual actions taken to
manage IROLs on the Interconnection, NERC has established three levels of Transmission Alerts. The
Reliability Coordinators will use these terms when explaining actions taken to manage IROLs to each
other. A Transmission Emergency Alert is an emergency procedure, not a daily operating practice, and
is not intended as an alternative to compliance with NERC reliability standards.. The Reliability
Coordinator may declare whatever alert level is appropriate, and need not proceed through the alerts
sequentially.
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1. Transmission Emergency Alert 1 (TEA 1) – All available resources committed to respecting
IROLs.
Circumstances:
•
The Reliability Coordinator or Transmission Operator foresees or is experiencing
conditions where all available resources are committed to respect the IROL and is
concerned about its ability to respect the IROL.
2. Transmission Emergency Alert 2 (TEA 2) — Load management procedures in effect to respect
IROLs.
Circumstances:
•
The Reliability Coordinator or Transmission Operator foresees or has implemented
procedures up to, but excluding, interruption of firm load commitments. When time
permits, these procedures may include, but are not limited to:
• Public appeals to reduce demand.
• Voltage reduction.
• Interruption of non-firm end use loads in accordance with applicable contracts
(for emergency purposes, not economic reasons)
• Demand-side management.
• Utility load conservation measures
• TLR 6
Note: TLR 5 would normally be implemented in advance of this alert state. Under some circumstances
TLRs may not be available or effective and would not be called prior to this alert state.
During TEA 2, Reliability Coordinators and Transmission Operators have the following
responsibilities:
2.1 Declaration period. The declaring Reliability Coordinator shall update the RCIS (under
“System Emergency”) at a minimum of every hour until the TEA 2 is terminated.
2.4 Evaluating and mitigating transmission limitations. The Reliability Coordinators shall
review all System Operating Limits (SOLs) and Interconnection Reliability Operating Limits
(IROLs) and transmission loading relief procedures in effect that may be contributing to the
alert level. Where appropriate, the Reliability Coordinators shall inform the Transmission
Operators under their purview of the pending Transmission Emergency Alert and request that
they increase their ATC by actions such as restoring transmission elements that are out of
service, reconfiguring their transmission system, adjusting phase angle regulator tap positions,
implementing emergency operating procedures and redispatching generation.
2.4.1 Notification of ATC adjustments. Resulting increases in ATCs shall be
communicated to the market via posting on the appropriate OASIS websites by the
Transmission Providers.
2.4.2 Availability of generation redispatch options. Available generation redispatch
options shall be immediately communicated to the declaring Reliability Coordinator.
2.4.3 Evaluating impact of current transmission loading relief events. The
Reliability Coordinators shall evaluate the impact of any current transmission loading
relief events on the ability to supply emergency assistance to the declaring entity. This
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evaluation shall include analysis of system reliability and involve close communication
among Reliability Coordinators.
2.4.4 Initiating inquiries on re-evaluating SOLs and IROLs. The Reliability
Coordinators shall consult with the Balancing Authorities and Transmission Providers
in their Reliability Areas about the possibility of re-evaluating and revising SOLs or
IROLs.
2.5 Coordination of emergency responses. The Reliability Coordinator shall communicate
and coordinate the implementation of emergency operating responses.
2.6 Actions Prior to Declaration of TEA 3. Before declaring a TEA 3, all available resources
must be committed. This includes but is not limited to:
2.6.1 All available generation units are on-line. All generation capable of being online in the time frame of the emergency is on-line including quick-start and peaking
units, regardless of cost.
2.6.2 Purchases made regardless of cost. All firm and non-firm purchases have been
made, regardless of cost.
2.6.3 Non-firm sales recalled and contractually interruptible loads and demandside management curtailed. All non-firm sales have been recalled, contractually
interruptible retail loads curtailed, and demand-side management activated within
provisions of the agreements.
2.6.4 Operating Reserves. Operating reserves are being utilized such that the declaring
entity may be carrying reserves below the required minimum or has initiated
emergency assistance through its operating reserve sharing program.
3. Transmission Emergency Alert 3 (TEA 3) — Firm load curtailment in effect to respect IROLs.
Circumstances:
The Reliability Coordinator or Transmission Operator foresees or has implemented firm load
obligation interruption to respect an IROL.
3.1 Continue actions from TEA 2. The Reliability Coordinators and the declaring entity shall
continue to take all actions initiated during TEA 2.
3.2 Declaration Period. The declaring Reliability Coordinator shall update the RCIS under
“System Emergency” at a minimum of every hour until the TEA 3 is terminated.
3.3 Use of Transmission short-time limits. The Reliability Coordinators shall request the
appropriate Transmission Providers within their Reliability Area to utilize available short-time
transmission limits or other emergency operating procedures in order to increase transfer
capabilities.
3.4 Re-evaluating and revising SOLs and IROLs. The Reliability Coordinator of the
declaring entity shall evaluate the risks of revising SOLs and IROLs on the reliability of the
overall transmission system. Re-evaluation of SOLs and IROLs shall be coordinated with other
Reliability Coordinators and only with the agreement of the Transmission Operator whose
equipment would be affected. The resulting increases in transfer capabilities shall only be made
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available to the declaring entity who has requested an TEA 3 condition. SOLs and IROLs shall
only be revised as long as a TEA 3 condition exists or as allowed by the Transmission Operator
whose equipment is at risk. The following are minimum requirements that must be met before
SOLs or IROLs are revised:
3.4.2 Mitigation of cascading failures. The Reliability Coordinator shall use its best
efforts to ensure that revising SOLs or IROLs would not result in any cascading
failures within the Interconnection.
3.5 Returning to pre-emergency SOLs and IROLs. Whenever the transmission systems can
be returned to their pre-emergency SOLs or IROLs, the declaring Entity shall notify its
respective Reliability Coordinator.
3.5.1 Notification of other parties. Upon notification from the declaring entity that an
alert has been downgraded, the Reliability Coordinator shall notify the affected
Reliability Coordinators (via the RCIS), Transmission Operators and Balancing
Authorities that their systems can be returned to their normal limits.
4. Transmission Emergency Alert 0 (TEA 0) - Termination.
When the declaring Entity is able to respect IROL requirements and is no longer concerned with its
ability to respect IROLs, it shall request its Reliability Coordinator to terminate the alert.
4.1. Notification. The Reliability Coordinator shall notify Reliability Coordinators via the
RCIS of the termination. The Reliability Coordinator shall also notify the affected
Transmission Operators and Balancing Authorities. The TEA 0 shall also be posted on the
NERC website if the original alert was so posted.
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Security Emergency Alerts (SEA)
Introduction
This Attachment provides the procedures by which a Reliability Coordinator, Transmission Operator or
Balancing Authority can communicate the physical and cyber security status of their facilities.
All three operating alert states (EEAs, TEAs and SEAs) are independent of each other and should be
declared independently but they may also be declared concurrently.
A. General Requirements
1. Initiation by Reliability Coordinator. A Security Emergency Alert may be initiated
only by a Reliability Coordinator at
1) The Reliability Coordinator’s own request, or
2) Upon the request of a Transmission Operator, or
3) Upon the request of a Balancing Authority
1.1. Situations for initiating alert. A Security Emergency Alert may be initiated
for the following reasons:
•
•
A Cyber threat affecting a control center, grid or generator assets has been
identified or is imminent.
A physical threat affecting a control center, grid or generator assets has been
identified or is imminent.
2. Notification.
A Reliability Coordinator who initiates a Security Emergency Alert
shall notify all Transmission Operators and Balancing Authorities in its Reliability
Area. The Reliability Coordinator shall also notify Reliability Coordinators of the situation via
the Reliability Coordinator Information System (RCIS) using the “CIP” category.
Additionally, conference calls between Reliability Coordinators shall be held as necessary to
communicate system conditions. The Reliability Coordinator shall also notify all Transmission
Operators and Balancing Authorities in its Reliability Area and other Reliability Coordinators
when the alert has ended
B. Security Emergency Alert (SEA) Levels
To ensure that all Reliability Coordinators clearly understand potential and actual Security Emergency
Alerts, NERC has established three levels of Security Emergency Alerts. The Reliability Coordinators
will use these terms when explaining security alerts to each other. A Security Emergency Alert is an
emergency procedure, not a
daily operating practice, and is not intended as an alternative to compliance with NERC
reliability standards. The Reliability Coordinator may declare whatever alert level is necessary, and
need not proceed through the alerts sequentially.
1. Security Emergency Alert 1 (SEA 1) – Cyber or Physical threat is identified or imminent
Circumstances:
Draft
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• The Reliability Co-ordinator, Transmission Operator or Balancing Authority has
identified an actual or imminent cyber or physical threat to one of its facilities including but
not limited to:
• Control Centers
• Generating facilities
• Substations
• Transmission Lines
2. Security Emergency Alert 2 (SEA 2) – Cyber event impacts control center EMS or physical
attack at a single site
Circumstances:
•
•
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified an actual cyber threat event that is affecting control center EMS capability.
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified a physical attack at a single site.
During Security Emergency Alert 2, Reliability Coordinators, Transmission Operators and Balancing
Authorities have the following responsibilities:
2.1 Notifying other Reliability Coordinators, Transmission Operators and Balancing
Authorities
The Reliability Coordinator shall post the declaration of the alert level along with the location
of the affected facility on the RCIS under “CIP”.
2.2 Declaration period.
The declaring Entity shall update its Reliability Coordinator of the situation at a minimum of
every hour until the SEA 2 is terminated. The Reliability Coordinator shall update the RCIS as
changes occur and pass this information on to the affected Reliability Coordinators,
Transmission Operators and Balancing Authorities.
3. Security Emergency Alert 3 (SEA 3) – Cyber event shuts down control center EMS or
physical attack at multiple sites
Circumstances:
Draft
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•
•
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified an actual cyber threat event that has shutdown a control center EMS
capability.
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified a physical attack at a multiple sites
3.1. Notifying other Reliability Coordinators, Balancing Authorities and Transmission
Operators
The Reliability Coordinator shall post the declaration of the alert level along with the
locations of the affect facilities on the RCIS under “CIP”.
3.2. Declaration period
The declaring Entity shall update its Reliability Coordinator of the situation at a minimum
of every hour until the SEA 3 is terminated. The Reliability Coordinator shall update the
RCIS as changes occur and pass this information on to the affected Reliability
Coordinators, Transmission Operators and Balancing Authorities.
4. Security Emergency Alert 0 (SEA 0) – Termination of alert level
When the declaring entity believes it is no longer under threat, it shall request its Reliability
Coordinator to terminate the SEA.
4.1. Notification
The Reliability Coordinator shall notify all other Reliability
Coordinators via the RCIS of the termination. The Reliability Coordinator shall
also notify the affected Transmission Operators and Balancing Authorities
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Example #1
IROL violation on “X”
No Global Adequacy Concerns
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
Zone A
Zone B
Load
1,500 MW
Load
1,000 MW
Gen available
2,800 MW
Gen available
100 MW
Imp
0 MW
Imp
100 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
50 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 2,900 MW
BA Imp Limit
500 MW
Intertie Limit
Imp 300
Exp 200
EEA
1 No
2 No
3 No
TEA
1 Yes
2 Yes
3 Yes
•
•
•
•
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A is in excess of its
load requirements. The available generation in B is less than its
load requirements. Area B will be relying on the full transfer
capability of the interface “X” plus an additional import of 100
MW to the maximum limit on the intertie in Area B. With the
implementation of the interruptible load and V/R the firm load
requirements in B cannot be met without the use of Firm load
shedding.
In this scenario an EEA is not required as the BA is able to meet its global
load/generation requirements.
When this situation is forecast a TEA 1 should be issued to indicate the potential
concerns with the ability to respect the IROL limit “X” without the use of load
management procedures.
When load management procedures are implemented in Real Time to respect the IROL
“X”, a TEA 2 should be issued.
When Firm load is curtailed to respect the limit a TEA 3 should be issued.
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Example #2
Global Adequacy Deficiency
No IROL Violation
IROL “X”
500 MW - A to B
300 MW - B to A
Balancing Authority
“X”
Zone A
Load
Zone B
1,500 MW
Load
1,000 MW
Gen available
900 MW
Gen available
900 MW
Imp
300 MW
Imp
200 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
Intertie Limit
Imp 300
Exp 200
EEA
1 Yes
2 Yes
3 No
TEA
1 No
100 MW
50 MW
Interruptible
Load
V/R
BA Total Load 2,500 MW
BA Total Gen 1,800 MW
BA Imp Limit 500 MW
50 MW
50 MW
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A is less than its load
requirements. The available generation in B is less than its load
requirements. There is a Global Adequacy deficiency after
considering full import capability and utilization of interruptible
load and V/R.
2 No
3 No
•
•
EEA procedures should be followed
There is no need for a TEA to be issued
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Example #3
Global Adequacy Deficiency
IROL Violation
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
A
B
Load
1,500 MW
Load
1,000 MW
Gen available
1,600 MW
Gen available
100 MW
Imp
300 MW
Imp
200 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
100 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 1,700 MW
BA Imp Limit 500 MW
Intertie Limit
Imp 300
Exp 200
EEA
1 Yes
2 Yes
3 No
TEA
1 Yes
2 Yes
3 Yes
•
•
•
•
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A meets its load
requirements. The available generation in B is less than its load
requirements. There is a Global Adequacy deficiency after
considering full import capability. There is also an IROL violation
at “X” in the direction of A to B to meet the load requirements in
B depending on where load management procedures are
implemented.
An EEA 1 and a TEA 1 should be issued to identify the potential issues
When load management procedures are implemented to manage the transfer from A to
B a TEA 2 should be issued (assumes B will be deficient before the global deficiency
occurs).
An EEA 2 should be issued when load management procedures are being implemented
in A to manage global requirements.
TEA 3 should also be issued when Firm load is shed in B to meet the load requirements
in B while respecting the IROL.
Draft
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Example #4
Transaction Curtailments
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
A
B
Load
1,500 MW
Load
Gen available
2,000 MW
Gen available
1,000 MW
500 MW
Imp
200 MW
Imp
0 MW
Exp
0 MW
Exp
100 MW
Interruptible
Load
V/R
100 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 2,500 MW
BA Imp Limit 500 MW
Intertie Limit
Imp 300
Exp 200
EEA
Intertie Limit
Imp 200
Exp 100
1 No
2 No
3 No
In this example there are no global adequacy concerns. There is an
export transaction in B that is causing a limit concern on “X” in
the A to B direction. With the available generation in B plus the
transfer capability there is no concern for violating the IROL limit.
TEA 1 No
The transaction is creating a situation where it will be required
2 No
curtailed at some point to prevent the IROL violation. Assuming
the
TLR procedure would be effective at relieving this constraint
3 No
regardless of the TLR level (at either the TLR 3 or 5 level) no TEA
would be required as there is no concern that the IROL can’t be respected with control actions
that don’t involve load management procedures.
Draft
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Standard Authorization Request Form
Title of Proposed Standard:
Operating Personnel Communications Protocols
Request Date:
March 1, 2007
Revised Date:
June 8, 2007
SAR Requester Information
Name:
Harry Tom - to be replaced
with SAR Drafting Team Chair when SAR
Drafting Team is appointedLloyd
Snyder
SAR Type (Check one box.)
Company:
Corp.
NERCGeorgia System Operations
Telephone:
609-452-8060770-270-7418
Revision to Existing Standard
Fax:
609-452-9550770-270-7672
Withdrawal of Existing Standard
[email protected]@gas
Urgent Action
New Standard
E-mail:
oc.com
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
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Standards Authorization Request Form
Purpose (Describe the purpose of the proposed standard – what the
standard will achieve in support of reliability.)
Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve
situational awareness and shorten response time. The purpose of
revising and expanding the existing requirements that address realtime system operator communicationsthis standard is to:
1.
Provide an adequate level of reliability for the North American
bulk power systems – by ensuring that the standards are complete
and the requirements are set at an appropriate level to ensure
reliability.
2.
Ensure the standard or standards are enforceable as mandatory
reliability standards with financial penalties - the
applicability to bulk power system owners, operators, and users,
are clearly defined; the purpose, requirements, and measures are
results-focused and unambiguous; the consequences of violating
the requirements are clear.
3.
Consider other general improvements described in the standards
development work plan.
4.
Consider stakeholder comments received during the initial
development of the standards and other comments received from
Electric Reliability Organization (ERO) regulatory authorities,
as noted in the attached review sheets.
5.
Satisfy the standards procedure requirement for five-year review
of the standards.
Industry Need (Provide a detailed statement justifying the need for
the proposed standard, along with any supporting documentation.)
The need for improved real-time communications protocols was
identified during the investigation of the August 2003 Blackout.
Blackout Recommendation #26 is: “Tighten communications protocols,
especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate.” (Note that this SAR
does not include the second part of this recommendation regarding the
upgrade to communication system hardware.)
SAR–2
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Brief Description (Describe the proposed standard in sufficient detail
to clearly define the scope in a manner that can be easily understood
by others.)
This standard will require the use of specific communication
protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditionsespecially for
communications during alerts and emergencies. The standard will be
applicable to transmission operators, transmission owners balancing
authorities, reliability coordinators, generator operators and
distribution providers.
Requirements will ensure that communications include essential elements such
that information is efficiently conveyed and mutually understood include
protocols for communicating changes to real-time operating
statesconditions and protocols for issuing and responding to operating
directives.
The project may involve moving some requirements that address
communications protocols from existing standards into this new
standard and will involve adding new requirements that more fully
address communications protocols under various operating
scenariosconditions.
SAR–3
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Standards Authorization Request Form
Reliability Functions
The Standard will Apply to the Following Functions (Check all applicable boxes.)
Reliability
Coordinator
Responsible for the real-time operating reliability of its Reliability Coordinator
Area in coordination with its neighboring Reliability Coordinator’s wide area
view.
Balancing
Authority
Integrates resource plans ahead of time, and maintains load-interchangeresource balance within a Balancing Authority Area and supports
Interconnection frequency in real time.
Interchange
Coordinator
Ensures communication of interchange transactions for reliability evaluation
purposes and coordinates implementation of valid and balanced interchange
schedules between Balancing Authority Areas.
Planning
Coordinator
Assesses the longer-term reliability of its Planning Coordinator Area.
Resource
Planner
Develops a >one year plan for the resource adequacy of its specific loads within
a Planning Coordinator area.
Transmission
Planner
Develops a >one year plan for the reliability of the interconnected Bulk Electric
System within its portion of the Planning Coordinator area.
Transmission
Service Provider
Administers the transmission tariff and provides transmission services under
applicable transmission service agreements (e.g., the pro forma tariff).
Transmission
Owner
Owns and maintains transmission facilities.
Transmission
Operator
Ensures the real-time operating reliability of the transmission assets within a
Transmission Operator Area.
Distribution
Provider
Delivers electrical energy to the End-use customer.
Generator
Owner
Owns and maintains generation facilities.
Generator
Operator
Operates generation unit(s) to provide real and reactive power.
PurchasingSelling Entity
Purchases or sells energy, capacity, and necessary reliability-related services
as required.
Market Operator
Interface point for reliability functions with commercial functions.
SAR–4
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Reliability and Market Interface Principles
Applicable Reliability Principles (Check all boxes that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the NERC
Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained, and implemented.
5. Facilities for communication, monitoring, and control shall be provided, used, and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement actions.
7. The reliability of the interconnected bulk power systems shall be assessed, monitored,
and maintained on a wide-area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface Principles?
(Select ‘yes’ or ‘no’ from the drop-down box.)
Recognizing that reliability is an essential requirement of a robust North American economy:
1. A reliability standard shall not give any market participant an unfair competitive advantage.Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
SAR–5
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Standards Authorization Request Form
Detailed Description (Provide enough detail so that an independent
entity familiar with the industry could draft a standard based on this
description.)
Scope
The scope of the proposed standard or revised standards is to
establish a common lexiconessential elements of communications
protocols and communications paths such that all operators and users
of the North American bulk electric system will have the same
understanding as to its meaning, usage and take pre-determined action
in responseefficiently convey information and ensure mutual
understanding. The August 2003 Blackout Recommendation Number 26
calls for a tightening of communications protocols. This standard is
to ensure that effective communication is practiced and delivered in
clear language via pre-established communications paths among preidentified operating entities. References to communication protocols
in other NERC Standards may be moved to this new standard. The
standard drafting team shall consider incorporating the use of Alert
Level Guidelines and three-part communications in developing this new
standard to achieve high level consistency across regions.
Applicability
Medical, law enforcement, air traffic control and other fields
routinely use mutually defined and understood terminology or codes.
Clear and mutually established communications protocols used during
real time operations under normal and emergency conditions ensure
universal understanding of terms and reduce errors.
Communications protocols shall precisely define terms, codes, phrases,
words, etc. as to their connotation, conditions for use, context of
use and expected responses in reply to these terms, codes, phrases,
words, etc. Furthermore the protocols shall define a rigorous script
for the Sender and Receiver of information. Effective communications
with proper communications protocols among the operating entities are
essential for maintaining reliable system operations.
The standard will include requirements for the following:
1. Real—time system operators will be required to use specific
communications protocols under normal, abnormal and emergency
conditions to quickly relay critical reliability-related
information in a timely and effective manner.
2. Reliability Coordinators, Balancing Authorities, Generation
Operators, Transmission Operators, Transmission Owners and
Distribution Providers will be required to adopt and employcomply
with this standard directives that use pre-defined terms, and
will require entities that receive those directives to respond to
the reliability coordinator using pre-defined terms.
3. The standard will include requirements for entities that
experience abnormal conditions to use pre-defined terms such as
SAR–6
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Standards Authorization Request Form
proposed in the “Alert Level Guideline” (attached) to communicate
the operating conditionsituation to other entities that are in a
position to either assist in resolving the operating situation
condition or to entities that are impacted by the operating
condisituation.
4. The standard may include other requirements that involve
communications protocols for real-time system operators.
The standard should consider address directives 1 and 3 of the FERC
staff’s Preliminary Assessment of NERC Standards (dated May 11, 2006)
in which the FERC staff cited various Blackout Report excerpts
pertaining to ineffective communications as a factor common to the
August 14 blackout and other previous major outages in North America.
The Commission staff interprets Blackout Report recommendation #26
that urges “effective communications” with “tightened communications
protocols” among operating entities to include two key components:
(i) Effective communications that are delivered in clear language via
pre-established communications paths among pre-identified
operating entities, and
(ii)Communications protocols which clearly identify that any operating
actions with reliability impact beyond a local area or beyond a
Reliability Coordinator’s area must be communicated to the
appropriate Reliability Coordinator for assessment and approval
prior to their implementation to ensure reliability of the
interconnected systems.
The communications protocols may be developed and then distributed to
relevant standards and/or may be developed and retained in one or more
specialized standards.Order 693 Mandatory Reliability Standards,
paragraph 540 which contains (directive 1 will also be addressed in
Project 2006-06; directive 2 will be addressed in Project 2006-06):
“…the Commission identified concerns regarding COM-002-2, the proposed
Reliability Standard serves an important purpose by requiring users, owners and operators to
implement the necessary communications and coordination among entities.
Accordingly, the Commission approves Reliability Standard COM-002-2 as mandatory and
enforceable. In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f) of
our regulations, the Commission directs the ERO to develop a modification to COM-0022 through the Reliability Standards development process that: (1) expands the
applicability to include distribution providers as applicable entities; (2) includes a new
Requirement for the reliability coordinator to assess and approve actions that have
impacts beyond the area view of a transmission operator or balancing authority and
(3) requires tightened communications protocols, especially for communications during alerts
and emergencies. Alternatively, with respect to this final issue, the ERO may
develop a new Reliability Standard that responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally, we direct the ERO to include APPA’s
suggestions to complete the Measures and Levels of Non-Compliance in its modification of
COM-002-2 through the Reliability Standards development process.”
SAR–7
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Related Standards
Standard
No.
Explanation – these requirements may need to be modified
or moved to the new standard
COM-001-1
R4 is a requirement for the Reliability Coordinator’s, Transmission Operator’s, and
Balancing Authority’s real-time operating personnel to use English when
communicating between entities.
R1.1 is a requirement for the Balancing Authority and Transmission Operator to make
notifications when there is a threat to reliability.
COM-002-2
R2 is a requirement for the Reliability Coordinator, Transmission Operator and
Balancing Authority relative to issuing and receiving operating directives.
EOP-001-90
R4.1 includes a requirement for the Transmission Operator and Balancing Authority
to have communications protocols for use during emergencies (and Attachment 1EOP-001-0)
EOP-002-2
R6.5 and R7.2 require the Balancing Authority to ask the Reliability Coordinator to
declare an Energy Emergency or an Energy Emergency Alert under certain
conditions
R8 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R9.1 requires the Load-serving Entity to ask the Reliability Coordinator to declare an
Energy Emergency Alert under certain conditions
EOP-006-1
R4 requires the Reliability Coordinator to disseminate information regarding
restoration to neighboring Reliability Coordinators and Transmission Operators or
Balancing Authorities
R5 requires the Reliability Coordinator to approve, communicate, and coordinate the
re-synchronizing of major system islands or synchronizing points
CIP-001-1
R1 and R2 require operating entities to have procedures for communicating
information relative to sabotage of bulk power system facilities
CIP-008-1
R1.2 requires the responsible entity to have a communication plan for response to a
cyber security incident
IRO-001-1
R3 requires the Reliability Coordinator to direct entities to act and R8 requires entities
to respond to the Reliability Coordinator’s directives
IRO-004-1
R6 requires the Reliability Coordinator to direct entities to act and R7 requires entities
to respond to the Reliability Coordinator’s directives
IRO-005-2
R4 requires the Reliability Coordinator to issue an Energy Emergency Alert under
certain conditions
R3, R5, R8, R11, R15, and R17 require the Reliability Coordinator to direct actions to
alleviate various types of abnormal or emergency situations
IRO-014-1
R1.1 requires Reliability Coordinators to have procedures processes or plans that
address communications and notifications made between Reliability Coordinators
under various operating scenarios
PRC-001-1
R6 requires the Transmission Operator and Balancing Authority to make notifications
when there is a change in the status of a special protection system
TOP-001-1
R3 requires some responsible entities to comply with the Reliability Coordinator’s and
Transmission Operator’s directives
R4 requires some responsible entities to comply with the Transmission Operator’s
directives
R5 requires the Transmission Operator to notify its Reliability Coordinator of certain
emergency situations
SAR–9
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Standards Authorization Request Form
TOP-002-2
R14, R16 and R17 require responsible entities to notify their Reliability Coordinator of
various changes to operating parameters
R18 requires the use of uniform line identifiers when referring to transmission facilities
of an interconnected network
TOP-007-0
R1 requires the Transmission Operator to notify its Reliability Coordinator when it
exceeds an SOL or IROL
R4 requires the Reliability Coordinator to direct entities to take actions to restore the
system to within SOLs or IROLs
TOP-008-1
R3 requires the Transmission Operator to make notifications if it disconnects an
overloaded facility
VAR-001-1
R8 and R12 require the Transmission Operator to direct actions to maintain voltage
within limits and to prevent voltage collapse
VAR-002-1
R2.2 and R5.1 require the Generator Operator to comply with directives
R3 requires the Generator Operator to notify the Transmission Operator of various
status or capability changes
Related SARs
SAR ID
Explanation
Project
2006-06
Reliability Coordination SAR
Project
2007-08
Emergency Operations
Regional Variances
Region
Explanation
ERCOT
FRCC
MRO
NPCC
RFC
SERC
SPP
WECC
SAR–10
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2007/05/17
Guideline for Operating State Alert Levels
Background
System operators need common definitions for normal, alert, and emergency conditions to enable them
to act appropriately and predictably as system conditions change. On August 14, 2003, the principal
entities involved in the blackout did not have a shared understanding of whether the grid was in an
emergency condition, nor did they have a common understanding of the functions, responsibilities,
capabilities, and authorities of reliability coordinators and control areas under emergency or nearemergency conditions.
The U.S./Canada Task Force Recommendation 20 recommends the establishment of clear definitions of
normal, alert, and emergency operational system conditions, and to clarify the roles, responsibilities,
and authorities of reliability coordinators and control areas under each condition.
At its May 2006 meeting, the NERC Reliability Coordinator WG approved a motion to implement a
pilot program that defined normal, alert, and emergency operating conditions as they relate to
Transmission Loading and Security. The intent is to align the definitions for Transmission Loading and
Security with the conditions identified in the Emergency Energy Alert states. In an effort to clarify the
application of the definitions being used in the pilot program this guideline has been created. In the
event of a conflict between the pilot program and applicable NERC Standards the Standards should
always be applied first.
Condition Level
Normal
>>>>
Threat Level>>>> Low
Condition/Threat
Green
Color >>>>
EEA 0
No Energy
Generating/capacity Deficiencies
Transmission
Security
TEA 0
Respecting all
IROLs
SEA 0
No cyber threat
identified; No
known threats on
control center or
grid assets (lines,
substations,
generators)
Alert Level 1
Alert Level 2
Alert Level 3
Elevated
High
Severe
Yellow
EEA 1
all available
resources in use
Orange
EEA 2
Load management
procedures in effect
TEA 1
All available
resources
committed to
respecting IROLs
SEA 1
Cyber threat
identified or is
imminent, OR
verified physical
threat against
control center or
grid assets
Draft
Red
EEA 3
Firm load
interruption
imminent or in
progress
TEA 2
TEA 3
Load Mgmt
Firm Load
procedures in effect Curtailments in
to respect IROLs effect to respect
IROLs
SEA 2
SEA 3
Cyber event is
Cyber event has
affecting control
shut down control
center EMS
center EMS
capability, OR
capability, OR
physical attack at physical attack at
single site (control multiple sites
center or grid
(control center or
assets- lines,
grid assets- lines,
substations,
substations,
generators)
generators)
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Transmission Emergency Alert (TEA) Levels
Introduction
This Attachment provides the procedures by which a Transmission Operator or Reliability Coordinator
can advise of actions taken to manage potential or actual Interconnected Reliability Operating Limit
(IROL) violations.
All three operating alert states (EEAs, TEAs and SEAs) are independent of each other and should be
declared independently but they may also be declared concurrently.
A. General Requirements
1. Initiation by Reliability Coordinator. A Transmission Emergency Alert (TEA) may be initiated
only by a Reliability Coordinator at:
1) the Reliability Coordinator’s own request, or
2) upon the request of a Transmission Operator
1.1. Situations for initiating alert. A Transmission Emergency Alert may be initiated for the
following reasons:
•
•
When all the available resources have been committed to respect an IROL in the
pre-contingency state.
When load curtailment procedures have been implemented to respect an IROL.
2. Notification. A Reliability Coordinator who declares a Transmission Emergency Alert shall notify
all Transmission Operators and Balancing Authorities in its Reliability Area. The Reliability
Coordinator shall also notify Reliability Coordinators of the situation via the
Reliability Coordinator Information System (RCIS) using the “System Emergency” category.
Additionally, conference calls between Reliability Coordinators shall be held as necessary to
communicate system conditions. The Reliability Coordinator shall also notify all Transmission
Operators and Balancing Authorities in its Reliability Area and Reliability Coordinators when the alert
has ended.
B. Transmission Emergency Alert Levels
Introduction
To ensure that all Reliability Coordinators clearly understand potential and actual actions taken to
manage IROLs on the Interconnection, NERC has established three levels of Transmission Alerts. The
Reliability Coordinators will use these terms when explaining actions taken to manage IROLs to each
other. A Transmission Emergency Alert is an emergency procedure, not a daily operating practice, and
is not intended as an alternative to compliance with NERC reliability standards.. The Reliability
Coordinator may declare whatever alert level is appropriate, and need not proceed through the alerts
sequentially.
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1. Transmission Emergency Alert 1 (TEA 1) – All available resources committed to respecting
IROLs.
Circumstances:
•
The Reliability Coordinator or Transmission Operator foresees or is experiencing
conditions where all available resources are committed to respect the IROL and is
concerned about its ability to respect the IROL.
2. Transmission Emergency Alert 2 (TEA 2) — Load management procedures in effect to respect
IROLs.
Circumstances:
•
The Reliability Coordinator or Transmission Operator foresees or has implemented
procedures up to, but excluding, interruption of firm load commitments. When time
permits, these procedures may include, but are not limited to:
• Public appeals to reduce demand.
• Voltage reduction.
• Interruption of non-firm end use loads in accordance with applicable contracts
(for emergency purposes, not economic reasons)
• Demand-side management.
• Utility load conservation measures
• TLR 6
Note: TLR 5 would normally be implemented in advance of this alert state. Under some circumstances
TLRs may not be available or effective and would not be called prior to this alert state.
During TEA 2, Reliability Coordinators and Transmission Operators have the following
responsibilities:
2.1 Declaration period. The declaring Reliability Coordinator shall update the RCIS (under
“System Emergency”) at a minimum of every hour until the TEA 2 is terminated.
2.4 Evaluating and mitigating transmission limitations. The Reliability Coordinators shall
review all System Operating Limits (SOLs) and Interconnection Reliability Operating Limits
(IROLs) and transmission loading relief procedures in effect that may be contributing to the
alert level. Where appropriate, the Reliability Coordinators shall inform the Transmission
Operators under their purview of the pending Transmission Emergency Alert and request that
they increase their ATC by actions such as restoring transmission elements that are out of
service, reconfiguring their transmission system, adjusting phase angle regulator tap positions,
implementing emergency operating procedures and redispatching generation.
2.4.1 Notification of ATC adjustments. Resulting increases in ATCs shall be
communicated to the market via posting on the appropriate OASIS websites by the
Transmission Providers.
2.4.2 Availability of generation redispatch options. Available generation redispatch
options shall be immediately communicated to the declaring Reliability Coordinator.
2.4.3 Evaluating impact of current transmission loading relief events. The
Reliability Coordinators shall evaluate the impact of any current transmission loading
relief events on the ability to supply emergency assistance to the declaring entity. This
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evaluation shall include analysis of system reliability and involve close communication
among Reliability Coordinators.
2.4.4 Initiating inquiries on re-evaluating SOLs and IROLs. The Reliability
Coordinators shall consult with the Balancing Authorities and Transmission Providers
in their Reliability Areas about the possibility of re-evaluating and revising SOLs or
IROLs.
2.5 Coordination of emergency responses. The Reliability Coordinator shall communicate
and coordinate the implementation of emergency operating responses.
2.6 Actions Prior to Declaration of TEA 3. Before declaring a TEA 3, all available resources
must be committed. This includes but is not limited to:
2.6.1 All available generation units are on-line. All generation capable of being online in the time frame of the emergency is on-line including quick-start and peaking
units, regardless of cost.
2.6.2 Purchases made regardless of cost. All firm and non-firm purchases have been
made, regardless of cost.
2.6.3 Non-firm sales recalled and contractually interruptible loads and demandside management curtailed. All non-firm sales have been recalled, contractually
interruptible retail loads curtailed, and demand-side management activated within
provisions of the agreements.
2.6.4 Operating Reserves. Operating reserves are being utilized such that the declaring
entity may be carrying reserves below the required minimum or has initiated
emergency assistance through its operating reserve sharing program.
3. Transmission Emergency Alert 3 (TEA 3) — Firm load curtailment in effect to respect IROLs.
Circumstances:
The Reliability Coordinator or Transmission Operator foresees or has implemented firm load
obligation interruption to respect an IROL.
3.1 Continue actions from TEA 2. The Reliability Coordinators and the declaring entity shall
continue to take all actions initiated during TEA 2.
3.2 Declaration Period. The declaring Reliability Coordinator shall update the RCIS under
“System Emergency” at a minimum of every hour until the TEA 3 is terminated.
3.3 Use of Transmission short-time limits. The Reliability Coordinators shall request the
appropriate Transmission Providers within their Reliability Area to utilize available short-time
transmission limits or other emergency operating procedures in order to increase transfer
capabilities.
3.4 Re-evaluating and revising SOLs and IROLs. The Reliability Coordinator of the
declaring entity shall evaluate the risks of revising SOLs and IROLs on the reliability of the
overall transmission system. Re-evaluation of SOLs and IROLs shall be coordinated with other
Reliability Coordinators and only with the agreement of the Transmission Operator whose
equipment would be affected. The resulting increases in transfer capabilities shall only be made
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available to the declaring entity who has requested an TEA 3 condition. SOLs and IROLs shall
only be revised as long as a TEA 3 condition exists or as allowed by the Transmission Operator
whose equipment is at risk. The following are minimum requirements that must be met before
SOLs or IROLs are revised:
3.4.2 Mitigation of cascading failures. The Reliability Coordinator shall use its best
efforts to ensure that revising SOLs or IROLs would not result in any cascading
failures within the Interconnection.
3.5 Returning to pre-emergency SOLs and IROLs. Whenever the transmission systems can
be returned to their pre-emergency SOLs or IROLs, the declaring Entity shall notify its
respective Reliability Coordinator.
3.5.1 Notification of other parties. Upon notification from the declaring entity that an
alert has been downgraded, the Reliability Coordinator shall notify the affected
Reliability Coordinators (via the RCIS), Transmission Operators and Balancing
Authorities that their systems can be returned to their normal limits.
4. Transmission Emergency Alert 0 (TEA 0) - Termination.
When the declaring Entity is able to respect IROL requirements and is no longer concerned with its
ability to respect IROLs, it shall request its Reliability Coordinator to terminate the alert.
4.1. Notification. The Reliability Coordinator shall notify Reliability Coordinators via the
RCIS of the termination. The Reliability Coordinator shall also notify the affected
Transmission Operators and Balancing Authorities. The TEA 0 shall also be posted on the
NERC website if the original alert was so posted.
Draft
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Security Emergency Alerts (SEA)
Introduction
This Attachment provides the procedures by which a Reliability Coordinator, Transmission Operator or
Balancing Authority can communicate the physical and cyber security status of their facilities.
All three operating alert states (EEAs, TEAs and SEAs) are independent of each other and should be
declared independently but they may also be declared concurrently.
A. General Requirements
1. Initiation by Reliability Coordinator. A Security Emergency Alert may be initiated
only by a Reliability Coordinator at
1) The Reliability Coordinator’s own request, or
2) Upon the request of a Transmission Operator, or
3) Upon the request of a Balancing Authority
1.1. Situations for initiating alert. A Security Emergency Alert may be initiated
for the following reasons:
•
•
A Cyber threat affecting a control center, grid or generator assets has been
identified or is imminent.
A physical threat affecting a control center, grid or generator assets has been
identified or is imminent.
2. Notification.
A Reliability Coordinator who initiates a Security Emergency Alert
shall notify all Transmission Operators and Balancing Authorities in its Reliability
Area. The Reliability Coordinator shall also notify Reliability Coordinators of the situation via
the Reliability Coordinator Information System (RCIS) using the “CIP” category.
Additionally, conference calls between Reliability Coordinators shall be held as necessary to
communicate system conditions. The Reliability Coordinator shall also notify all Transmission
Operators and Balancing Authorities in its Reliability Area and other Reliability Coordinators
when the alert has ended
B. Security Emergency Alert (SEA) Levels
To ensure that all Reliability Coordinators clearly understand potential and actual Security Emergency
Alerts, NERC has established three levels of Security Emergency Alerts. The Reliability Coordinators
will use these terms when explaining security alerts to each other. A Security Emergency Alert is an
emergency procedure, not a
daily operating practice, and is not intended as an alternative to compliance with NERC
reliability standards. The Reliability Coordinator may declare whatever alert level is necessary, and
need not proceed through the alerts sequentially.
1. Security Emergency Alert 1 (SEA 1) – Cyber or Physical threat is identified or imminent
Circumstances:
Draft
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• The Reliability Co-ordinator, Transmission Operator or Balancing Authority has
identified an actual or imminent cyber or physical threat to one of its facilities including but
not limited to:
• Control Centers
• Generating facilities
• Substations
• Transmission Lines
2. Security Emergency Alert 2 (SEA 2) – Cyber event impacts control center EMS or physical
attack at a single site
Circumstances:
•
•
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified an actual cyber threat event that is affecting control center EMS capability.
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified a physical attack at a single site.
During Security Emergency Alert 2, Reliability Coordinators, Transmission Operators and Balancing
Authorities have the following responsibilities:
2.1 Notifying other Reliability Coordinators, Transmission Operators and Balancing
Authorities
The Reliability Coordinator shall post the declaration of the alert level along with the location
of the affected facility on the RCIS under “CIP”.
2.2 Declaration period.
The declaring Entity shall update its Reliability Coordinator of the situation at a minimum of
every hour until the SEA 2 is terminated. The Reliability Coordinator shall update the RCIS as
changes occur and pass this information on to the affected Reliability Coordinators,
Transmission Operators and Balancing Authorities.
3. Security Emergency Alert 3 (SEA 3) – Cyber event shuts down control center EMS or
physical attack at multiple sites
Circumstances:
Draft
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•
•
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified an actual cyber threat event that has shutdown a control center EMS
capability.
The Reliability Coordinator, Transmission Operator or Balancing Authority has
identified a physical attack at a multiple sites
3.1. Notifying other Reliability Coordinators, Balancing Authorities and Transmission
Operators
The Reliability Coordinator shall post the declaration of the alert level along with the
locations of the affect facilities on the RCIS under “CIP”.
3.2. Declaration period
The declaring Entity shall update its Reliability Coordinator of the situation at a minimum
of every hour until the SEA 3 is terminated. The Reliability Coordinator shall update the
RCIS as changes occur and pass this information on to the affected Reliability
Coordinators, Transmission Operators and Balancing Authorities.
4. Security Emergency Alert 0 (SEA 0) – Termination of alert level
When the declaring entity believes it is no longer under threat, it shall request its Reliability
Coordinator to terminate the SEA.
4.1. Notification
The Reliability Coordinator shall notify all other Reliability
Coordinators via the RCIS of the termination. The Reliability Coordinator shall
also notify the affected Transmission Operators and Balancing Authorities
Draft
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Example #1
IROL violation on “X”
No Global Adequacy Concerns
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
Zone A
Zone B
Load
1,500 MW
Load
1,000 MW
Gen available
2,800 MW
Gen available
100 MW
Imp
0 MW
Imp
100 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
50 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 2,900 MW
BA Imp Limit
500 MW
Intertie Limit
Imp 300
Exp 200
EEA
1 No
2 No
3 No
TEA
1 Yes
2 Yes
3 Yes
•
•
•
•
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A is in excess of its
load requirements. The available generation in B is less than its
load requirements. Area B will be relying on the full transfer
capability of the interface “X” plus an additional import of 100
MW to the maximum limit on the intertie in Area B. With the
implementation of the interruptible load and V/R the firm load
requirements in B cannot be met without the use of Firm load
shedding.
In this scenario an EEA is not required as the BA is able to meet its global
load/generation requirements.
When this situation is forecast a TEA 1 should be issued to indicate the potential
concerns with the ability to respect the IROL limit “X” without the use of load
management procedures.
When load management procedures are implemented in Real Time to respect the IROL
“X”, a TEA 2 should be issued.
When Firm load is curtailed to respect the limit a TEA 3 should be issued.
Draft
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Example #2
Global Adequacy Deficiency
No IROL Violation
IROL “X”
500 MW - A to B
300 MW - B to A
Balancing Authority
“X”
Zone A
Load
Zone B
1,500 MW
Load
1,000 MW
Gen available
900 MW
Gen available
900 MW
Imp
300 MW
Imp
200 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
Intertie Limit
Imp 300
Exp 200
EEA
1 Yes
2 Yes
3 No
TEA
1 No
100 MW
50 MW
Interruptible
Load
V/R
BA Total Load 2,500 MW
BA Total Gen 1,800 MW
BA Imp Limit 500 MW
50 MW
50 MW
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A is less than its load
requirements. The available generation in B is less than its load
requirements. There is a Global Adequacy deficiency after
considering full import capability and utilization of interruptible
load and V/R.
2 No
3 No
•
•
EEA procedures should be followed
There is no need for a TEA to be issued
Draft
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Example #3
Global Adequacy Deficiency
IROL Violation
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
A
B
Load
1,500 MW
Load
1,000 MW
Gen available
1,600 MW
Gen available
100 MW
Imp
300 MW
Imp
200 MW
Exp
0 MW
Exp
0 MW
Interruptible
Load
V/R
100 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 1,700 MW
BA Imp Limit 500 MW
Intertie Limit
Imp 300
Exp 200
EEA
1 Yes
2 Yes
3 No
TEA
1 Yes
2 Yes
3 Yes
•
•
•
•
Intertie Limit
Imp 200
Exp 100
In this example the available generation in A meets its load
requirements. The available generation in B is less than its load
requirements. There is a Global Adequacy deficiency after
considering full import capability. There is also an IROL violation
at “X” in the direction of A to B to meet the load requirements in
B depending on where load management procedures are
implemented.
An EEA 1 and a TEA 1 should be issued to identify the potential issues
When load management procedures are implemented to manage the transfer from A to
B a TEA 2 should be issued (assumes B will be deficient before the global deficiency
occurs).
An EEA 2 should be issued when load management procedures are being implemented
in A to manage global requirements.
TEA 3 should also be issued when Firm load is shed in B to meet the load requirements
in B while respecting the IROL.
Draft
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Example #4
Transaction Curtailments
IROL “X”
500 MW - A to B
300 MW - B to A
“X”
Balancing Authority
A
B
Load
1,500 MW
Load
Gen available
2,000 MW
Gen available
1,000 MW
500 MW
Imp
200 MW
Imp
0 MW
Exp
0 MW
Exp
100 MW
Interruptible
Load
V/R
100 MW
50 MW
Interruptible
Load
V/R
50 MW
50 MW
BA Total Load 2,500 MW
BA Total Gen 2,500 MW
BA Imp Limit 500 MW
Intertie Limit
Imp 300
Exp 200
EEA
Intertie Limit
Imp 200
Exp 100
1 No
2 No
3 No
In this example there are no global adequacy concerns. There is an
export transaction in B that is causing a limit concern on “X” in
the A to B direction. With the available generation in B plus the
transfer capability there is no concern for violating the IROL limit.
TEA 1 No
The transaction is creating a situation where it will be required
2 No
curtailed at some point to prevent the IROL violation. Assuming
the
TLR procedure would be effective at relieving this constraint
3 No
regardless of the TLR level (at either the TLR 3 or 5 level) no TEA
would be required as there is no concern that the IROL can’t be respected with control actions
that don’t involve load management procedures.
Draft
12
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Maureen E. Long
Standards Process Manager
April 18, 2007
TO:
REGISTERED BALLOT BODY
Ladies and Gentlemen:
Announcement
Nomination Periods Open for Three Drafting Teams
The Standards Committee (SC) announces the following standards actions:
Nominations for Project 2007-09 Generator Verifications SAR Drafting Team (April
18–May 2, 2007)
The Standards Committee is seeking industry experts to serve on the Generator Verification SAR
Drafting Team. This project calls for completing the final four Phase III & IV standards (PRC019, PRC-024, MOD-026, and MOD-027) and for refinement of two standards that were
approved in 2005 (MOD-024 and MOD-025).
PRC-019 — Coordination of Generator Voltage Regulator Controls with Unit
Capabilities and Protection
PRC-024 — Generator Performance During Frequency and Voltage Excursions
MOD-024 — Verification of Generator Gross and Net Real Power Capability
MOD-025 — Verification of Generator Gross and Net Reactive Power Capability
MOD-026 —Verification of Models and Data for Generator Excitation System Functions
MOD-027 — Verification of Generator Unit Frequency Response
The set of six standards all require generator verifications — either to ensure that generators will
not trip off line during specified voltage and frequency excursions or as a result of improper
coordination between generator protective relays and generator voltage regulator controls and
limit functions or to ensure that generator models accurately reflect the generator’s capabilities
and operating characteristics.
If you are interested in serving on this team, please complete this nomination form and return it
to [email protected] with “GEN VER SARDT Nomination” in the subject line, no later than
May 2, 2007.
Nominations for Project 2006-03 System Restoration and Blackstart Standard
Drafting Team (April 18–May 2, 2007)
The Standards Committee is seeking additional industry experts to serve on the System
Restoration and Blackstart Standard Drafting Team. This project calls for the modification of
the following standards:
EOP-005 — System Restoration Plans
EOP-006 — Reliability Coordination — System Restoration
EOP-007 — Establish, Maintain, and Document a Regional Blackstart Capability Plan
EOP-009 — Documentation of Blackstart Generating Unit Test Results
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
REGISTERED BALLOT BODY
April 18, 2007
Page Two
This project involves upgrading the overall quality of the four standards; eliminating some gaps
in the requirements; eliminating some ambiguity; and eliminating some “fill-in-the-blank”
components. The Standards Committee has appointed the initial standard drafting team, but is
seeking additional members, particularly from within the SPP and WECC regions.
If you are interested in serving on this team, please complete this nomination form and return it
to [email protected] with “SRBS SDT Nomination” in the subject line, no later than May 2,
2007.
Nominations for Project 2007-02 Operating Personnel Communications Protocols
SAR Drafting Team (April 18–May 2, 2007)
The Standards Committee is seeking additional industry experts to serve on the Operating
Personnel Communications Protocols SAR Drafting Team. This SAR calls for the development
of communications protocols for use by real-time system operators to improve situational
awareness and shorten response time. The Standards Committee has appointed an initial SAR
Drafting Team but is seeking additional nominations, particularly from the FRCC, NPCC, and
SPP regions, from Canada, and from the generation and load-serving entity segments that will be
affected by the proposed standard.
If you are interested in serving on this team, please complete this nomination form and return it
to [email protected] with “OPS COM SARDT Nomination” in the subject line, no later than
May 2, 2007.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the
standards development process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate. If you
have any questions, please contact me at 813-468-5998 or [email protected].
Sincerely,
Maureen E. Long
cc:
Registered Ballot Body Registered Users
Standards Mailing List
NERC Roster
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
Description of Current Draft:
This is the first draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 45-day comment period.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, posts for 30-day comment period.
March 16 to April 15, 2010
2. Drafting team considers comments, makes conforming
changes, requests SC approval to proceed to pre-ballot
comment period.
May 15, 2010
3. First ballot of standards.
June 2010
4. Recirculation ballot of standards.
July 2010
5. Board adopts standards.
August or November 2010
Draft 1: November 18, 2009
1
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Communications Protocol — A framework of rules that govern how verbal and written
information is exchanged.
Three-part Communication — A Communications Protocol where information is verbally
stated by a party initiating a communication, the information is repeated back correctly to the
party that initiated the communication by the second party that received the communication, and
the same information is verbally confirmed to be correct by the party who initiated the
communication.
Interoperability Communication — Communication between two or more entities to exchange
reliability-related information to be used by the entities to change the state or status of an
element or facility of the Bulk Electric System.
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Introduction
1.
Title:
Operating Personnel Communications Protocols
2.
Number:
COM-003-1
3.
Purpose: To timely convey reliability-related information effectively, accurately,
and consistently in order to ensure mutual understanding by all key parties, especially
during alerts and emergencies.
4.
Applicability:
4.1. Transmission Operator
4.2. Transmission Owner
4.3. Balancing Authority
4.4. Reliability Coordinator
4.5. Generator Operator
4.6. Distribution Provider
4.7. Transmission Service Provider
4.8. Load Serving Entity
5.
(Proposed) Effective Date:
First day of first calendar quarter, one calendar year following applicable regulatory
approval; or, in those jurisdictions where no regulatory approval is required, the first
day of the first calendar quarter a year from the date of Board of Trustee adoption.
Requirements
R1.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall develop a written Communications Protocol Operating
Procedure (CPOP) for Interoperability Communications among personnel responsible for
Real-time generation control and Real-time operation of the interconnected Bulk Electric
System. The CPOP shall include but is not limited to all elements described in
Requirements R2 through R7 to ensure effective Interoperability Communications.
[Violation Risk Factor: Low][Time Horizon: Long Term Planning]
R2.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use pre-defined system condition terminology as defined in
Attachment 1-COM-003-1 for verbal and written Interoperability Communications.
[Violation Risk Factor: High][Time Horizon: Real Time]
R3.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use the English language for verbal and written
Interoperability Communications. Responsible Entities may use an alternate language for
internal communications. [Violation Risk Factor: High][Time Horizon: Real time]
R4.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use Central Standard Time (24 hour format) as the common
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
time zone for verbal and written Interoperability Communications. [Violation Risk
Factor: High][Time Horizon: Real time]
R5.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use Three-part Communications when issuing a directive
during verbal Interoperability Communications. [Violation Risk Factor: High][Time
Horizon: Real time]
R6.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use the North American Treaty Organization (NATO)
phonetic alphabet as identified in Attachment 2-COM-003-1 when issuing directives,
notifications, directions, instructions, orders or other reliability related operating
information that involves alpha-numeric information during verbal Interoperability
Communications. [Violation Risk Factor: High][Time Horizon: Real time]
R7.
Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall use pre-determined, mutually agreed upon line and equipment
identifiers for verbal and written Interoperability Communications. [Violation Risk
Factor: High][Time Horizon: Real time]
Measures
M1. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall have and provide for review, its written CPOP that includes all
elements described in Requirements R2 through R7.
M2. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall have and provide evidence that pre-defined system condition
terminology contained in Attachment 1-COM-003-1 was used for verbal and written
Interoperability Communications. Evidence may include but is not limited to voice
recordings, transcripts, operating logs, or on site observations.
M3. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall have and provide evidence that the English language was used
for verbal and written Interoperability Communications. Responsible Entities may use an
alternate language for internal operations. Evidence may include but is not limited to voice
recordings, transcripts, operating logs, or on site observations.
M4. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall provide evidence that the Central Time Zone was used for
verbal and written Interoperability Communications. Evidence may include but is not
limited to voice recordings, transcripts, operating logs, or on site observation.
M5. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall provide evidence that Three-part Communications was used
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
when issuing directives during verbal Interoperability Communications. Evidence may
include but is not limited to voice recordings, transcripts, operating logs, or on site
observations.
M6. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider provides evidence that the NATO phonetic alphabet was used when
issuing directives, notifications, directions, instructions, orders or other reliability related
operating information that involves alpha-numeric information or for clarification during
verbal Interoperability Communications. Evidence may include but is not limited to voice
recordings, transcripts, operating logs, or on site observations.
M7. Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider provides documented evidence such as a list or a one-line diagram
acknowledged and used by the affected parties that confirms there is mutual agreement on
the names/identifiers of lines and equipment. Evidence of use may include but is not
limited to voice recordings, transcripts, operating logs, or on site observations.
Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Regional Entity
1.2. Compliance Monitoring Period and Reset
Not Applicable
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
Each Transmission Operator, Transmission Owner, Balancing Authority,
Reliability Coordinator, Generator Operator, Transmission Service Provider, Load
Serving Entity and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
o Each Transmission Operator, Transmission Owner, Balancing Authority,
Reliability Coordinator, Generator Operator, Transmission Service Provider,
Load Serving Entity and Distribution Provider shall retain its current, in force
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
document and any documents in force for Requirement 1, Measure 1 since the
last compliance audit.
o Each Transmission Operator, Transmission Owner, Balancing Authority,
Reliability Coordinator, Generator Operator, Transmission Service Provider,
Load Serving Entity and Distribution Provider shall retain for Requirement 2
through 7, Measure 2 through 7, dated operator logs for the most recent 12
months and voice recordings or transcripts of voice recordings for the most
recent 3 months.
If a Transmission Operator, Transmission Owner, Balancing Authority, Reliability
Coordinator, Generator Operator, Transmission Service Provider, Load Serving
Entity or Distribution Provider is found non-compliant, it shall keep information
related to the non-compliance until found compliant.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.5. Additional Compliance Information
None.
Draft 1: November 18, 2009
6
2.
Violation Severity Levels
R#
VRF
Lower
R1
Low
R2
High
The responsible entity failed to use predefined system condition terminology
(Attachment 1-COM-003-1) for verbal and
written Interoperability Communications.
R3
High
The responsible entity failed to use the
English language for verbal and written
Interoperability Communications.
R4
High
The responsible entity failed to use Central
Standard Time (24 hour format) as the
common time zone for verbal and written
Interoperability Communications.
R5
High
The responsible entity failed to use Three-part
Communications when issuing a directive
during verbal Interoperability Communications.
R6
High
The responsible entity failed to use the North
American Treaty Organization (NATO)
phonetic alphabet when issuing notifications,
directions, instructions, orders and other
reliability related operating information that
involves alpha-numeric information or for
clarification during verbal Interoperability
Communications.
R7
High
The responsible entity failed to use predetermined, mutually understood line and
equipment identifiers for verbal and written
Interoperability Communications.
Draft 1: November 18, 2009
Moderate
High
The responsible entity developed a
CPOP but failed to incorporate one
of the elements contained in R2
through R7.
The responsible entity
developed a CPOP but failed
to incorporate two or more
elements contained in R2
through R7.
Severe
The responsible entity failed to develop a
written CPOP.
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Regional Variances
None
Version History
Version
Date
Draft 1: November 18, 2009
Action
Change Tracking
8
Attachment 1 — COM-003-1 — Operating State Alert Levels
This Attachment 1-COM-003-1 defines normal, alert, and emergency operating conditions as they relate to Transmission Loading, Physical and
Cyber Security. These definitions for Transmission Loading, Physical and Cyber Security Alert states align with the Emergency Energy Alert
(EEA) states (as already described in NERC Reliability Standard EOP-002-2.1). The time frame for declaration of these Alert states shall be
consistent with the approach used to declare EEAs and would normally apply to Real Time declarations and not forecast conditions.
Reliability Coordinator Notifications for Physical Security Emergency Alerts
Condition YELLOW:
The Reliability Coordinator is notified of a verified
actual or imminent physical threat affecting any
ONE site within the RC Area:
Control center
Generating facility
Substation
Transmission line
Condition ORANGE:
The Reliability Coordinator is notified of a physical
attack at any ONE site within the RC Area:
Control center
Generating facility
Substation
Transmission line
Condition RED:
The Reliability Coordinator is notified of a physical
attack at multiple sites within the RC Area:
Control center
Generating facility
Substation
Transmission line
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Physical Security Emergency Alert –
PSEA Level One within (identify RC, TOP or BA
area)”
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Physical Security Emergency Alert – PSEA
Level Two within (identify RC, TOP, or BA area)”
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Physical Security Emergency Alert –
PSEA Level Three within (identify RC, TOP, or
BA area)”
Notify all the following functional entities within the Reliability Coordinator Area:
Balancing Authorities
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following functional entities outside the Reliability Coordinator Area:
All Reliability Coordinators using “CIP Free Form” category of RCIS
Notify the following entities:
NERC (ES-ISAC) via the RCIS. Under “External Links” use “ES-ISAC Site”.
Additional Communications:
Post the declaration of the alert level along with the location of the affected facility to other parties as required by internal communication procedure, OE-417
Form, law enforcement, etc.
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Make Final Notifications:
“At (insert time) the Physical Security Emergency
Alert – PSEA Level One (identify RC, BA or
TOP Area) has been curtailed”
Make Final Notifications:
“At (insert time) the Physical Security
Emergency Alert – PSEA Level Two within
(identify RC, TOP or BA Area) has been
curtailed”
Make Final Notifications:
“At (insert time) the Physical Security Emergency Alert –
PSEA Level Three within (identify RC, TOP, or BA Area)”
has been curtailed
Notify all the following within the Reliability Coordinator Area:
Balancing Authorities
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following outside the Reliability Coordinator Area:
All Reliability Coordinators using “CIP Free Form” category of RCIS. Notify ES-ISAC of end of Alert and any other entities initially notified.
Additional Communications:
Remove the declaration of the alert level from the RCIS and other entities initially notified.
Draft 1: November 18, 2009
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Attachment 1 — COM-003-1 — Operating State Alert Levels (continued)
Reliability Coordinator Notifications for Cyber Security Emergency Alerts
Condition YELLOW:
The Reliability Coordinator is notified of a identified
actual or imminent cyber threat affecting any ONE
site within the RC Area:
Control center
Generating facility
Substation
Transmission line
Condition ORANGE:
The Reliability Coordinator is notified of a cyber
attack at any ONE site within the RC Area:
Control center
Generating facility
Substation
Transmission line
Condition RED:
The Reliability Coordinator is notified of a cyber
attack at multiple sites within the RC Area:
Control center
Generating facility
Substation
Transmission line
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Cyber Security Emergency Alert – CEA
Level One within (identify RC, TOP or BA area)”
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Cyber Security Emergency Alert – CEA
Level Two within (identify RC, TOP, or BA area)”
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Cyber Security Emergency Alert – CEA
Level Three within (identify RC, TOP, or BA area)”
Notify all the following functional entities within the Reliability Coordinator Area:
Balancing Authorities
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following functional entities outside the Reliability Coordinator Area:
All Reliability Coordinators and CIP Participants using “CIP Free Form” category of RCIS.
Notify the following entities:
NERC (ES-ISAC) via the RCIS. Under “External Links” use “ES-ISAC Site”.
Additional Communications:
Post the declaration of the alert level along with the location of the affected facility to other parties as required by internal communication procedure, OE-417
Form, law enforcement, etc.
Make Final Notifications:
“At (insert time) the Cyber Security Emergency
Alert – CEA Level One (identify RC, BA or TOP
Area) has been curtailed”
Make Final Notifications:
“At (insert time) the Cyber Security Emergency
Alert – CEA Level Two within (identify RC,
TOP or BA Area) has been curtailed”
Make Final Notifications:
“At (insert time) the Cyber Security Emergency Alert – CEA
Level Three within (identify RC, TOP, or BA Area)” has
been curtailed
Notify all the following within the Reliability Coordinator Area:
Balancing Authorities
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following outside the Reliability Coordinator Area:
All Reliability Coordinators and CIP Participants using “CIP Free Form” category of RCIS. Notify ES-ISAC of end of Alert and any other entities initially notified
Additional Communications:
Remove the declaration of the alert level from the RCIS and any other entities initially notified.
Draft 1: November 18, 2009
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Attachment 1 — COM-003-1 — Operating State Alert Levels (continued)
Reliability Coordinator Notifications for Transmission Emergency Alerts
Condition YELLOW:
Condition ORANGE:
Condition RED:
The Reliability Coordinator or Transmission
Operator foresees or is experiencing conditions
where all available generation resources are
committed to respect the IROL and/or is
concerned about its ability to respect the IROL.
The Reliability Coordinator or Transmission
Operator foresees or has implemented procedures up
to, but excluding, interruption of firm load
commitments.
The Reliability Coordinator or Transmission Operator
foresees or has implemented firm load obligation
interruption to respect an IROL.
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert
time) there is a Transmission Emergency Alert –
TEA Level One affecting the (name of the
interface; monitored and contingency element)”
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Transmission Emergency Alert – TEA
Level Two affecting the (name of the interface;
monitored and contingency elements; amount of MW
relief; type of load management procedures that
have been or expected to be implemented i.e.,
voltage reduction, curtailable load reductions; relief
that has been (or is expected) to be implemented to
respect the limit; any actions that are expected to last
the next (length of time – hours/days).
Make Initial Notifications:
“This is the Reliability Coordinator. At (insert time)
there is a Transmission Emergency Alert – TEA Level
Three affecting the (name of the interface; monitored
and contingency elements; amount of MW relief;
amount of Firm Load curtailments that have been (or
is expected) implemented to respect the limit; any
actions that are expected to last the next (length of
time – hours/days).”
Notify all the following functional entities within the Reliability Coordinator Area:
Balancing Authorities
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following functional entities outside the Reliability Coordinator Area:
All Reliability Coordinators using “Free Form” category of RCIS.
Notify the following entities:
Additional Communications:
Post the declaration of the alert level along with the location of the affected facility to other parties as required by internal communication procedure, etc.
Make Final Notifications:
“At (insert time) the Transmission Emergency
Alert – TEA Level One (identify RC, BA or TOP
Draft 1: November 18, 2009
Make Final Notifications:
“At (insert time) the Transmission Emergency
Alert – TEA Level Two within (identify RC,
Make Final Notifications:
“At (insert time) the Transmission Emergency Alert – TEA
Level Three within (identify RC, TOP, or BA Area)” has
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Area) has been curtailed”
TOP or BA Area) has been curtailed”
been curtailed
Notify all the following within the Reliability Coordinator Area:
Balancing Authorities
Distribution Service Providers
Generator Operators
Transmission Operators
Transmission Owners
Notify the following outside the Reliability Coordinator Area:
All Reliability Coordinators using “Free Form” category of RCIS
Additional Communications:
Remove the declaration of the alert level from the RCIS and any other parties initially notified.
Draft 1: November 18, 2009
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Attachment 2 — COM-003-1
NATO Phonetic Alphabet or International Radiotelephony Spelling Alphabet
Character
Telephony
Pronunciation
A
Alpha
(al-fah)
B
Bravo
(brah-voh)
C
Charlie
(char-lee)
D
Delta
(dell-tah)
E
Echo
(eck-oh)
F
Foxtrot
(foks-trot)
G
Golf
(golf)
H
Hotel
(hoh-tel)
I
India
(in-dee-ah)
J
Juliet
(jew-lee-ett)
K
Kilo
(key-loh)
L
Lima
(lee-mah)
M
Mike
(mike)
N
November
(no-vem-ber)
O
Oscar
(oss-ker)
P
Papa
(pah-pah)
Q
Quebec
(keh-beck)
R
Romeo
(row-me-oh)
S
Sierra
(see-air-rah)
T
Tango
(tang-go)
U
Uniform
(you-nee-form)
V
Victor
(vik-ter)
W
Whiskey
(wiss-key)
X
X-Ray
(ecks-ray)
Y
Yankee
(yang-key)
Z
Zulu
(zoo-loo)
1
One
(wun)
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Standard COM-003-1 — Operating Personnel Communications Protocols Standard
Character
Telephony
Pronunciation
2
Two
(too)
3
Three
(tree)
4
Four
(fow-er)
5
Five
(fife)
6
Six
(six)
7
Seven
(sev-en)
8
Eight
(ait)
9
Nine
(nin-er)
0
Zero
(zee-row)
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Implementation Plan for COM-003-1 — Operating Personnel Communications Protocols
Prerequisite Approvals
None
Conforming Changes to Requirements in Already Approved Standards
Remove R4 from COM-001-1
Move R2 (or subsequent replacements) from COM-002-3 into COM-003-1 and retire
COM-002-3
Standard Summary
The OPCP SDT developed this new standard and is proposing removing requirements R4 from
COM-001-1 and R2 (or subsequent replacements) from COM-002-3 for inclusion in this standard.
This standard addresses part of Blackout Recommendation #26 and issues in FERC Order 693.
Compliance with Standards
Once these standards become effective, the responsible entities identified in the Applicability
section of the standard must comply with the requirements. These include:
Reliability Coordinator
Balancing Authority
Transmission Owner
Transmission Operator
Generator Operator
Distribution Provider
Transmission Service Provider
Load Serving Entity
Effective Date
The proposed effective date for this standard is the first day of the third calendar quarter after
applicable regulatory approvals have been received (or the Reliability Standard otherwise becomes
effective the first day of the third calendar quarter after BOT adoption in those jurisdictions where
regulatory approval is not required).
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Disposition of Requirements Identified in the SAR for Operations Communications Protocols as Possibly Needing either Modification or Movement
Standard
No.
Requirement(s) identified in the SAR as possibly needing to be
modified or moved to the new standard
SDT Disposition/Explanation
COM-001-1
R4 is a requirement for the Reliability Coordinator’s, Transmission
Operator’s, and Balancing Authority’s real-time operating personnel to
use English when communicating between entities.
Requirement R4 from COM-001 has been incorporated as
Requirement R3 of draft COM-003-1.
COM-002-2
R1.1 is a requirement for the Balancing Authority and Transmission
Operator to make notifications when there is a threat to reliability.
Regarding R1.1, the SDT decided to focus on requirements that
specify protocols on “How to” communicate rather than specified
scenarios of “to Whom” or “When to” communicate (albeit COM-003
communication protocols are expected to be used when conveying
real-time, reliability-related information in a high level, generic sense).
The SDT believes this requirement focuses on predetermined
communication paths / communications hardware. It does not appear
to be appropriate to relocate this requirement.
R2 is a requirement for the Reliability Coordinator, Transmission
Operator and Balancing Authority relative to issuing and receiving
operating directives.
Requirement R2 to use Three-part Communication is currently in the
scope of work for Project 2006-06. This Project includes a new
Glossary term Reliability Directive. Upon completion of the Project
2006-06 development, the revisions to COM-002-3 will be moved to
COM-003-1 and COM-002-3 will be retired.
EOP-001-0
R4.1 includes a requirement for the Transmission Operator and
Balancing Authority to have communications protocols for use during
emergencies (and Attachment 1-EOP-001-0)
R4.1and EOP-001 as a whole requires “plans” for mitigating
emergencies. These communication protocols differ from COM-003
protocols in that R4.1 involves actions and tasks for mitigating
operational emergencies and for coordinating activities; not how to
communicate.
EOP-002-2
R6.5 and R7.2 require the Balancing Authority to ask the Reliability
Coordinator to declare an Energy Emergency or an Energy
Emergency Alert under certain conditions
R6.5 and R7.2 prescriptively provide detail in the standard for
remedies to capacity emergencies. These requirements specify the
“when”, “who” and “what” to communicate not “how” to communicate.
Relocating or modifying these requirements is not appropriate.
R8 requires the Reliability Coordinator to issue an Energy Emergency
Alert under certain conditions
R9.1 requires the Load-serving Entity to ask the Reliability Coordinator
November 18, 2009
R8 of EOP-002 likewise specifies the “when” for an RC to declare an
emergency alert; not “how” to communicate.
R9.1 of EOP-002 likewise specifies the “when” for an LSE to request
its RC to declare an emergency alert; not “how” to communicate.
1
Standard
No.
Requirement(s) identified in the SAR as possibly needing to be
modified or moved to the new standard
SDT Disposition/Explanation
to declare an Energy Emergency Alert under certain conditions
EOP-006-1
R4 requires the Reliability Coordinator to disseminate information
regarding restoration to neighboring Reliability Coordinators and
Transmission Operators or Balancing Authorities
R5 requires the Reliability Coordinator to approve, communicate, and
coordinate the re-synchronizing of major system islands or
synchronizing points
The SDT decided to focus on requirements that specify protocols on
“How to” communicate rather than “to Whom” or “When to”
communicate. The SDT believes these requirements involve
information/content and/or timing of certain communications and
therefore these requirements should not be duplicated or relocated to
COM-003-1 Standard because it would reduce the effectiveness of the
existing standard or requirement.
COM-003-1 is complementary to EOP-006-1 and must be complied
with in conjunction with each other during emergencies.
CIP-001-1
R1 and R2 require operating entities to have procedures for
communicating information relative to sabotage of bulk power system
facilities
These requirements require procedures to be followed during
emergency situations such as sabotage/security events. COM-003-1
requires protocols for ensuring understanding and conveying
information in a generic sense regardless of the specific information.
COM-003-1 is complementary to CIP-001-1 and must be complied
with in conjunction with each other during sabotage emergencies.
CIP-008-1
R1.2 requires the responsible entity to have a communication plan for
response to a cyber security incident
This requirement requires a plan, not how to ensure understanding of
reliability-related information.
COM-003-1 is complementary to CIP-008-2 R1.2 and must be
complied with in conjunction with each other during Cyber Security
emergencies.
IRO-001-1
R3 requires the Reliability Coordinator to direct entities to act and R8
requires entities to respond to the Reliability Coordinator’s directives
The purpose of this standard and its requirements is to specifically
ensure IROLs are mitigated within 30 minutes to ensure reliability of
the BES per the direction of the Reliability Coordinator.
The generic communication protocols of COM-003-1 can be used but
removing any of the words from IRO-001-1 would dilute that standard.
The SDT decided to focus on requirements that specify protocols on
“How to” communicate rather than “to Whom” or “When to”
communicate. The SDT believes the requirements R3 and R8 of IRO001-1 involve information/content and/or timing of certain
communications and therefore these requirements should not be
duplicated or relocated to COM-003-1 Standard because it would
November 18, 2009
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Disposition of Requirements Identified in the SAR for Operations Communications Protocols as Possibly Needing either Modification or Movement
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Disposition of Requirements Identified in the SAR for Operations Communications Protocols as Possibly Needing either Modification or Movement
Standard
No.
Requirement(s) identified in the SAR as possibly needing to be
modified or moved to the new standard
SDT Disposition/Explanation
reduce the effectiveness of the existing standard or requirement.
COM-003-1 is complementary to IRO-001-1 R3 and R8; and must be
complied with in conjunction with each other to preserve the integrity
and reliability of the Bulk Electric System.
IRO-004-1
R6 requires the Reliability Coordinator to direct entities to act and R7
requires entities to respond to the Reliability Coordinator’s directives
These requirements provide direction as to actions that should be
taken when the results of next-day system studies reveal potential
IROL and SOL violations within the system and not how to
communicate.
IRO-005-2
R4 requires the Reliability Coordinator to issue an Energy Emergency
Alert under certain conditions
These requirements tell the RC “when” to take certain actions.
R3, R5, R8, R11, R15, and R17 require the Reliability Coordinator to
direct actions to alleviate various types of abnormal or emergency
situations
R4 prescriptively provide detail in the standard for remedies to
operating reserve in order to meet CPS and DCS requirements.
Requirement R4 specify the “when”, “who” and “what” to communicate
not “how” to communicate. Relocating or modifying these
requirements is not appropriate.
R3, R5 R8, R11, R15 and R17 of IRO-005-2 specifies the “what” and
“when” for RCs to mitigate potential IROL violations and CPS/DCS
violations; not “how” to communicate.
IRO-014-1
R1.1 requires Reliability Coordinators to have procedures processes
or plans that address communications and notifications made between
Reliability Coordinators under various operating scenarios
This requirement specifies the contents of plans that are needed to be
pre-established as well as the process to follow but not necessarily the
“how” as prescribed in COM-003.
COM-003-1 is complementary to IRO-0014-1 R1.1; and must be
complied with in conjunction with each other to ensure that each
Reliability Coordinator’s operations are coordinated.
PRC-001-1
R6 requires the Transmission Operator and Balancing Authority to
make notifications when there is a change in the status of a special
protection system
R6 specifies that when a Special Protection System’s status has
changed the BA/TOP shall notify affected BA/TOPs of such a change.
This is a “when” to communicate issue. COM-003-1 is complementary
to PRC-001-1 R6.
TOP-001-1
R3 requires some responsible entities to comply with the Reliability
Coordinator’s and Transmission Operator’s directives
These are “when” to communicate requirements and should not be
relocated.
R4 requires some responsible entities to comply with the
Transmission Operator’s directives
COM-003-1 is complementary to TOP-001-1 and must be complied
with in conjunction with each other to ensure that directives are
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Disposition of Requirements Identified in the SAR for Operations Communications Protocols as Possibly Needing either Modification or Movement
Standard
No.
TOP-002-2
Requirement(s) identified in the SAR as possibly needing to be
modified or moved to the new standard
R5 requires the Transmission Operator to notify its Reliability
Coordinator of certain emergency situations
understood and coordinated.
R14, R16 and R17 require responsible entities to notify their Reliability
Coordinator of various changes to operating parameters
These are “when” to communicate requirements and should not be
relocated.
R18 requires the use of uniform line identifiers when referring to
transmission facilities of an interconnected network
TOP-007-0
TOP-008-1
SDT Disposition/Explanation
COM-003-1 is complementary to TOP-002-2 and must be complied
with in conjunction with each other.
The SDT recommends that TOP-002-2 R18 be retired and to add
applicability to LSE and TSP in the COM-003-1 Standard.
R1 requires the Transmission Operator to notify its Reliability
Coordinator when it exceeds an SOL or IROL
These are “when” to communicate requirements and should not be
relocated.
R4 requires the Reliability Coordinator to direct entities to take actions
to restore the system to within SOLs or IROLs
COM-003-1 is complementary to TOP-007-0 and must be complied
with in conjunction with each other.
R3 requires the Transmission Operator to make notifications if it
disconnects an overloaded facility
This is a “when” and a “what” to communicate requirement and should
not be relocated.
COM-003-1 is complementary to TOP-008-1 and must be complied
with in conjunction with each other.
VAR-001-1
R8 and R12 require the Transmission Operator to direct actions to
maintain voltage within limits and to prevent voltage collapse
This is a “when” and a “what” to communicate requirement and should
not be relocated.
COM-003-1 is complementary to VAR-001-1 and must be complied
with in conjunction with each other.
VAR-002-1
R2.2 and R5.1 require the Generator Operator to comply with
directives
This is a “when” and a “what” to communicate requirement and should
not be relocated.
R3 requires the Generator Operator to notify the Transmission
Operator of various status or capability changes
COM-003-1 is complementary to VAR-002-1 and must be complied
with in conjunction with each other.
November 18, 2009
4
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Unofficial Comment Form for Project 2007-02 Operating Personnel
Communications Protocols — Standard COM-003-1 —Operating Personnel
Communications Protocols
Please DO NOT use this form. Please use the electronic comment form located at the link
below to submit comments on the proposed draft COM-003-1 Operating Personnel
Communications Protocols standard. Comments must be submitted by January 15, 2010.
If you have questions please contact Harry Tom at [email protected] or by telephone at
609-452-8060.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information:
Effective communication is critical for real time operations. Failure to successfully
communicate can lead to negative consequences.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007
and approved by the Standards Committee on June 8, 2007. It established the scope of
work to be done for Project 2007-02 Operating Personnel Communications Protocols (OPCP
SDT). The scope described in the SAR is to establish essential elements of communications
protocols and communications paths such that operators and users of the North American
Bulk Electric System will efficiently convey information and ensure mutual understanding.
The August 2003 Blackout Recommendation Number 26 calls for a tightening of
communications protocols. This proposed standard is to ensure that effective
communication is practiced and delivered in clear language via pre-established
communications paths among pre-identified operating entities.
The SAR indicated that references to communication protocols in other NERC Reliability
Standards may be moved to this new standard. The SAR instructed the standard drafting
team to consider incorporating the use of Alert Level Guidelines and three-part
communications in developing this new standard to achieve high level consistency across
regions.
The upgrade of communication system hardware where appropriate is not included in this
project (it is included in NERC Project 2007-08 Emergency Operations).
The standard will be applicable to Transmission Operators, Transmission Owners, Balancing
Authorities, Reliability Coordinators, Generator Operators, Transmission Service Providers,
Load Serving Entities and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and
mutually understood for communicating changes to real-time operating conditions and
responding to directives, notifications, directions, instructions, orders, or other reliability
related operating information.
The Purpose statement of this standard states: “To ensure that reliability-related
information is conveyed effectively, accurately, consistently, and timely to ensure mutual
understanding by all key parties, especially during alerts and emergencies.”
The team developed a table to show each communications-related requirement identified in
the SAR and the conclusion of the OPCP SDT with respect to whether each of these
requirements should be modified or moved as part of this project. In summary, the OPCP
SDT is recommending that three of the identified requirements be incorporated into the new
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Unofficial Comment Form for Project 2007-02 OPCPSDT — COM-003-1
COM-003-1 Operating Personnel Communications Protocols standard and that the other
requirements remain in their respective standards. Please review the table showing the
disposition of related requirements identified in the SAR to see if you agree with the team.
The OPCP SDT is seeking industry comment on a number a specific issues related to Project
2007-02 Operating Personnel Communications Protocols as identified in the questions
below. The OPCP SDT is seeking industry input on:
•
New NERC Glossary terms: Communications Protocol, Three-part Communication
and Interoperability Communication. These terms are proposed for addition to the
NERC Glossary to establish their meaning and usage within the electricity industry.
•
Addition of Transmission Service Provider and Load Serving Entity as
applicable under this new standard. The SDT believes incorporating Requirement
R18 from TOP-002-2 as Requirement R7 of this draft COM-003-1 is appropriate.
The applicability for R18 includes the Transmission Service Provider and Load
Serving Entity; therefore the OPCP SDT proposes to add them to the Applicability
section of COM-003-1.
•
Communication Protocol Operating Procedure (CPOP): Each Reliability
Coordinator, Balancing Authority, Transmission Owner, Transmission Operator,
Generator Operator, Transmission Service Provider, Load Serving Entity and
Distribution Provider shall develop a written CPOP in order to formally establish a set
of Communication Protocols for use during real-time operations (R2 through R7).
The SDT seeks feedback on whether this requirement is needed.
•
Pre-defined system condition terminology: The Alert Level Guide document is
work that was originally prepared by the Reliability Coordinator Working Group
(RCWG) in accordance with a U.S./Canada Task Force Recommendation.
Recommendation #20 called for the establishment of clear definitions of normal,
alert, and emergency operational system conditions, and to clarify the roles,
responsibilities, and authorities of Reliability Coordinators and other responsible
entities under each condition.
The SDT recognizes the Alert Level Guide as an important tool for the clear and
efficient communication of system condition levels regarding Physical Security,
Cyber Security, Transmission Emergencies and Energy Emergencies. The SDT has
incorporated the Alert Level Guide into Attachment 1-COM-003-1.
The SDT proposes four system condition alerts instead of the initial three in the
RCWG version. The main criterion for splitting the Security Energy Alert (SEA) into
two separate system condition alerts (Cyber and Physical) is based on feedback
from Field Test participants that recommended separation.
Energy Emergency Alert requirements currently exist in NERC Standard EOP-002-2.1.
There is an ongoing Field Test of the Alert Level Guide among Reliability
Coordinators, Balancing Authorities and Transmission Operators. The OPCP SDT is
interested in receiving feedback from participants in the Field Test with respect to
potential improvements to the Alert Level Guide.
•
Common time zone: The SDT believes that Interoperability Communications
would be enhanced with the use of a common time zone. Central Standard Time was
chosen as it is already in use for NERC Time Error Corrections. The Blackout Report
cited the need to tighten communication protocols and the SAR includes
6
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Unofficial Comment Form for Project 2007-02 OPCPSDT — COM-003-1
consideration of a common time zone to minimize mis-matched time signature
issues between control systems especially during an emergency.
•
Three-part Communication: The SDT will move the existing Requirement R2 of
COM-002-2 to this new standard when the RCSDT has completed their development
and the industry has approved the revisions. The COM-003-1 Standard proposes to
require the use of Three-part Communication whenever a directive is issued during
verbal Interoperability Communications. The SDT seeks industry feedback on this
proposal.
•
NATO Phonetic Alphabet: The SDT proposes the standardized use of the NATO
Phonetic Alphabet when issuing directives, notifications, directions, instructions,
orders or other reliability related operating information that involves alpha-numeric
information during verbal Interoperability Communications. During spoken
communications certain sounds become difficult to discern because they are audibly
similar. The use of the NATO Phonetic Alphabet is not intended for all verbal
communications but is required for Interoperability Communications.
•
Pre-determined Line and Equipment Identifiers: COM-003-1 requires the use
of predetermined line and equipment identifiers in Requirement R7 however the
Requirement does not stipulate a single/unique identifier as long as all parties
mutually agree on the identifier for the line or equipment. The mutual agreement
shall be reached in advance of the use of the identifiers as described in the
functional entity’s CPOP.
The SDT is proposing to retire Requirement R4 from COM-001 and incorporate it into
Requirement R2 of this draft COM-003-1. The SDT is proposing to retire COM-002-3
(requiring the use of Three-part Communication) upon the completion of Project 2006-06
Reliability Coordination and incorporate it into Requirement R4 of this draft of COM-003-1.
Since Requirement R4 from COM-001-1 carries over unchanged there is no specific question
related to it in this Comment Form.
The choice of VRFs was made on the basis of the impact on the Bulk Electric System of a
miscommunication especially during an emergency situation. Requirements R2 through R7
are assigned a High Violation Risk Factor due to their potential direct impact on BES
reliability. Requirement R1 is assigned a Low VRF due to its administrative nature.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R2 through R7 must be implemented in real time operations and therefore
were assigned a Time Horizon of Real time. A violation of Requirement R1 can be
addressed before it has a direct effect on the BES over a longer period and as such the SDT
assigned R1 a Time Horizon of Long Term Planning.
The drafting team is posting the standard for industry comment for a 45-day comment
period.
The Operating Personnel Communications Protocols Drafting Team would like to receive
industry comments on this draft standard. Accordingly, we request that you include your
comments on this form by January 15, 2010.
6
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Unofficial Comment Form for Project 2007-02 OPCPSDT — COM-003-1
*Please use the electronic comment form to submit your final comments to NERC.
1. Do you agree with the adoption of the following new terms for inclusion in the
NERC Glossary and their proposed definitions: Communications Protocol,
Three-part Communication, and Interoperability Communication? If not, please
explain in the comment area.
Yes
No
Comments:
2. The SDT incorporated TOP-002-2 Requirement R18 into this new standard
COM-003-1 as Requirement R7. In TOP-002-2, Requirement R18 applies to the
Transmission Service Provider and Load Serving Entity. These entities are now
added to COM-003-1. Do you agree with this proposal? If not, please explain in
the comment area.
Yes
No
Comments:
3. Requirement R1 of the draft COM-003-1 states, “Each Reliability Coordinator,
Balancing Authority, Transmission Owner, Transmission Operator, Generator
Operator, Transmission Service Provider, Load Serving Entity and Distribution
Provider shall develop a written Communications Protocol Operating Procedure
(CPOP) for Interoperability Communications among personnel responsible for
Real-time generation control and Real-time operation of the interconnected
Bulk Electric System. The CPOP shall include but is not limited to all elements
described in Requirements R2 through R7 to ensure effective Interoperability
Communications.” Do you agree with this proposal? If not, please explain in
the comment area.
Yes
No
Comments:
4. Requirement R2 of the draft COM-003-1 states, “Each Responsible Entity shall
use pre-defined system condition terminology as defined in Attachment 1-COM003-1 for all verbal and written Interoperability Communications.” Do you
agree with this proposal? If not, please explain in the comment area.
Yes
No
Comments:
5. Requirement R4 of the draft COM-003-1 states, “Each Responsible Entity shall
use Central Standard Time (24 hour format) as the common time zone for all
6
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Unofficial Comment Form for Project 2007-02 OPCPSDT — COM-003-1
verbal and written Interoperability Communications.” Do you agree with this
proposal? If not, please explain in the comment area.
Yes
No
Comments:
6. Requirement R5 of the draft COM-003-1 states, “Each Responsible Entity shall
use Three-part Communications when issuing a directive during verbal
Interoperability Communications.” Do you agree with this proposal? If not,
please explain in the comment area.
Yes
No
Comments:
7. Requirement R6 of the draft COM-003-1 states, “Each Responsible Entity shall
use the North American Treaty Organization (NATO) phonetic alphabet as
identified in Attachment 2-COM-003-1 when issuing directives, notifications,
directions, instructions, orders or other reliability related operating information
that involves alpha-numeric information during verbal Interoperability
Communications.” Do you agree with this proposal? If not, please explain in
the comment area.
Yes
No
Comments:
8. Requirement R7 of the draft COM-003-1 states, “Each Responsible Entity shall
use pre-determined, mutually agreed upon line and equipment identifiers
during for all verbal and written Interoperability Communications.” Do you
agree with this proposal? If not, please explain in the comment area.
Yes
No
Comments:
9. Attachment 1-COM-003-1 is based upon work performed by the Reliability
Coordinator Working Group (RCWG). Do you have any concerns or suggestions
for improvement of the attachment? If yes, please provide in the comment
area. (If you are involved in the field testing of the Alert Level Guide please
share any comments regarding the use of the guideline as it relates to the field
test.)
Yes
No
Comments:
6
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Unofficial Comment Form for Project 2007-02 OPCPSDT — COM-003-1
10.Are you aware of any regional variances that would be required as a result of
this standard? If yes, please identify the regional variance.
Yes
No
Comments:
11.Are you aware of any conflicts between the proposed standard and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or
agreement? If yes, please identify the conflict.
Yes
No
Comments:
12.Do you have any other comments to improve the draft standard? If yes, please
elaborate in the comment area.
Yes
No
Comments:
6
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Standards Announcement
Comment Period Open
November 30, 2009–January 15, 2010
Now available at: http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Project 2007-02: Operating Personnel Communications Protocols
The Operating Personnel Communications Protocols Standard Drafting Team is seeking comments on the
following documents until 8 p.m. EDT on January 15, 2010:
Standard COM-003-1 — Operating Personnel Communications Protocols
Implementation plan
Disposition of Related Requirements Identified in Standard Authorization Request (SAR)
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page: http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_200702.html
Next Steps
The drafting team will draft and post responses to comments received during this period. The drafting team will
also determine whether to post the standard for an additional comment period or seek approval from the
Standards Committee to proceed to balloting.
Project Background
The purpose of this project is to require that real-time system operators use standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten response time.
In the development of this proposed standard (as requested in the SAR), the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and threepart communications to achieve consistency across regions. The proposed standard is designed to ensure that
reliability-related information is conveyed effectively, accurately, consistently, and timely to ensure mutual
understanding by all key parties, especially during alerts and emergencies.
Applicability of Standards in Project
Transmission Operator
Transmission Owner
Balancing Authority
Reliability Coordinator
Generator Operator
Distribution Provider
Transmission Service Provider
Load Serving Entity
Proposed Glossary of Terms Change (new definitions)
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Communications Protocol
Three-part Communication
Interoperability Communication
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Shaun Streeter at [email protected] or at 609.452.8060.
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Individual or group. (71 Responses)
Name (44 Responses)
Organization (44 Responses)
Group Name (27 Responses)
Lead Contact (27 Responses)
Question 1 (68 Responses)
Question 1 Comments (71 Responses)
Question 2 (67 Responses)
Question 2 Comments (71 Responses)
Question 3 (70 Responses)
Question 3 Comments (71 Responses)
Question 4 (67 Responses)
Question 4 Comments (71 Responses)
Question 5 (68 Responses)
Question 5 Comments (71 Responses)
Question 6 (67 Responses)
Question 6 Comments (71 Responses)
Question 7 (68 Responses)
Question 7 Comments (71 Responses)
Question 8 (66 Responses)
Question 8 Comments (71 Responses)
Question 9 (58 Responses)
Question 9 Comments (71 Responses)
Question 10 (57 Responses)
Question 10 Comments (71 Responses)
Question 11 (57 Responses)
Question 11 Comments (71 Responses)
Question 12 (63 Responses)
Question 12 Comments (71 Responses)
Group
E.ON U.S. LLC
Brent Ingebrigtson
Disagree
For the Communication Protocol definition, please clarify if “written” includes electronic (email.)
Change the definition of “Interoperability” to “Emergency” Entities should not be required to use 3
part communications on a routine basis, only on emergency issues.
Disagree
As the requirement already exists it is redundant to incorporate it into COM-003. The incorporation
not only exposes a responsible entity to double jeopardy, it now exposes Transmission Service
Providers and LSEs to COM-003 requirements that should not apply to these entities. TOP-002
addresses planning ahead of the operating hour whereas COM-003 addresses communication during
real-time operations. In the absence of evidence that the lack of common identifiers is an imminent
and continuing risk to BES reliability, it does not make sense to have operators addressing urgent,
real-time situations bear significant penalty risk should they refer a BES element by something other
than a newly established common identifier. Is it the intent of the requirement that the common
identifiers be the same for all neighboring parties, all of whom must “agree” to the identification? If
not, then an element might be referred to by one identifier with Party A, another with Party B etc.
which might well defeat the purpose of the requirement. If it is required that there be a single
identifier, then all neighbors would have to agree upon the identifier constrained as each may be by,
for example, the formatting limitation of their respective SCADA/EMS systems. Cost to modify
software to accommodate common identifiers could be significant and NERC should weigh these
costs and the aforementioned operational risks against the perceived incremental improvements to
the BES reliability.
Disagree
Requiring production of a document that merely repeats Requirement 2-7 of COM-003 does not
further BES reliability. Requirements R2-R7 set forth all that such a document would contain. Stating
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that the CPOP should include but not be limited to R2-R7 is nonsensical. What additional issues
should the CPOP be required to address and why aren’t those issues the subject of a COM-003
requirement?
Disagree
The attachment adds a whole new lexicon for BES operators. E.ON U.S. suggests integrating
attachment 1 and the relative alert levels into the EOP standards. The purpose of COM-003 indicates
this standard is to ensure understanding of information during emergency alerts and emergency
situations and not to establish the conditions, required notification, or levels of emergency alerts.
While the attachment has been identified as a product of the RCWG it is unclear whether it has been
reviewed and approved through the normal NERC and industry vetting.
Disagree
If it is the intent that the requirements of this standard apply not only to control room operators but
field personnel (line crews, substation crews, etc.) then E ON US is not in favor of using a common
time zone nation-wide. The confusion that this change could create in real-time operations
outweighs the BES reliability benefit E.ON US would also like clarification that this requirement does
not apply to control systems or elements thereof that may log equipment operations. The
background information above suggests this possible interpretation.
Disagree
E ON US believes more specificity is required as to what constitutes a “directive”. Moreover, this
requirement is redundant in light of COM-002 R2 for normal operations. If COM-003 is only
applicable to emergencies, then this R5 would appear reasonable. E.ON U.S. suggests editing R5
and M5 as follows: Each Responsible Entity shall use Three-part Communications when issuing
and/or receiving a directive during verbal Interoperability Communications
Disagree
The entire standard should only apply to emergency operations, not all communications. If it is the
intent that the requirements of this standard apply not only to control room operators but also field
personnel (line crews, substation crews, etc.) then E ON U.S. is not in favor of using the NATO
phonetic alphabet. The confusion that this change could create in real-time operations outweighs the
BES reliability benefit. E ON U.S. suggests that if the objective is to avoid confusion over similarly
pronounced words, use of an ad-hoc phonetic alphabet would more easily address the concern. E ON
U.S. is also concerned that the attention paid to “how” orders are given and acknowledged may well
detract from “what” it is responsible entities are attempting to do. Are responsible entities supposed
to spell out each number and word using the phonetic alphabet? The drafting team should be more
specific as to what is meant by “alpha-numeric information.”
Disagree
In the absence of evidence that the lack of common identifiers is an imminent and continuing risk to
BES reliability, it does not make sense to have operators addressing urgent, real-time situations that
bear significant penalty risk should they refer to a BES element by something other than the
common identifier. The operator focus at such times should be on resolving the situation not
avoiding penalties over nomenclature. Is it the intent of the requirement that the common identifiers
be the same for all neighboring parties, all of whom must “agree” to the identification? If not, then
an element might be referred to by one identifier with Party A, another with Party B, and so on,
which might well defeat the purpose of the requirement. If it is required that there be a single
identifier, then all neighbors would have to agree upon the identifier constrained as each may be by,
for example, the formatting limitation of their respective SCADA/EMS systems. Cost to modify
software to accommodate common identifiers could be significant and NERC should weigh these
costs and the aforementioned operational risks against the perceived incremental improvements to
the BES reliability.
Disagree
E.ON U.S. has many concerns with this proposed attachment. The use of color coding and multiple
types of alerts adds unnecessary levels of complexity. Any proposed alert level should be consistent
throughout the suite of reliability standards, e.g level 1,2,3. Also, as previously noted in our
comment to question 4 above, E.ON U.S. suggests integrating attachment 1 and the relative alert
levels into the EOP standards and focusing the COM standards on the requirements of
communications protocol.
Disagree
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Disagree
If the requisite protocols are intended to be followed by all field personnel, applicability of these
requirements to Distribution Providers could run afoul of FPA Section 215(a) codified in 18CFR39.1.
Disagree
This standard should only apply to alerts and emergencies. E.ON U.S. suggests eliminating “
especially” in the purpose statement of COM-003-1. During emergency situations, operational focus
on the semantics of how communications are to occur does little to enhance the reliability of the
system. High VRFs with Severe VSLs may add stress and distraction to operation personnel during
times of emergency thus potentially harming, not improving reliability.
Individual
James Sharpe
South Carolina Electric and Gas
Agree
Agree
Agree
Agree
We agree with the proposal, however we feel that the color system should be evaluated to better
distinguish the type of attack for example using P-YELLOW for physical vs. C-YELLOW for cyber
instead of just "YELLOW" for both.
Disagree
We feel that time zones should be consistent throughout all standards and regulatory reporting
requirements(eg. TADS)
Disagree
The term "directive" should be changed to "Reliability Directive" as defined in COM-002-3.
Disagree
We believe this should only be required when issuing Reliability Directives.
Agree
Agree
See question 4.
Disagree
Disagree
Agree
The SDT should consider vertically integrated utilities, where communication between functional
entities is internal.
Group
Electric Market Policy
Mike Garton
Disagree
We do not agree with the adaptation of the proposed term “Interoperability Communication”. As
defined, it is limited to the communication of information to be used to change the state or status of
a BES element or facility. That definition is too limiting in that there are many types of reliabilityrelated information that need to be clearly communicated that do not lead to changing the state of a
BES facility. For example; information related to ratings, information related to the results of
studies, information related to data errors or loss of data, etc. If the term “Interoperability
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Communication” is to be retained, we strongly suggest a name change. The word “interoperability”
is widely used to refer to the ability of a system to work with or use the parts or equipment of
another system. For example please see the current standards development efforts identified in the
NIST Framework and Roadmap for Smart Grid Interoperability Standards available at
http://www.nist.gov/public_affairs/releases/smartgrid_interoperability.pdf. Using the term
“interoperability” to refer to reliability-related human communications could be confusing to
regulators, compliance personnel, auditors, and many others who have to deal with a variety of
standards.
Disagree
In our experience, neither the TSP nor the LSE provide or receive information about specific lines or
equipment in real-time. Therefore, requirement R7 should not apply to them absent clear evidence
that a realistic (not hypothetical) threat to reliability would exist if they are omitted. We do not think
that such a threat would exist. Applying R7 to TSPs and LSEs would only cause them grief and
further burden the compliance staffs of the regional entities for no appreciable benefit.
Disagree
We agree that communications procedures are necessary, but we do not agree with several of the
requirements proposed to be addressed in the elements of the CPOP. See our comments on specific
requirements elsewhere in our responses. We do not see the need to create a CPOP that includes
requirements R2 through R7 given that each requirement spells out how and what is to be
communicated. We could agree that a CPOP may be needed for Interoperability Communications
that are not addressed in R2-7.
Disagree
We object due to the following reasons; 1 - There are 3 versions of Attachment 1-COM-003-1 which
is potentially confusing. We suggest separating into 3 attachments, one for each type of notification.
2 – The level(s) identified in the notification text are at odds with the condition (color vs numerical).
It is suggested that the standard either use to Condition (color) or the level (numerical). 3 – None of
the Operating State Alert Levels in Attachment 1 appears to address Energy Emergency Alerts
(EEAs). The note in the “Attachment 1-COM-003-1 defines normal, alert, and emergency operating
conditions as they relate to Transmission Loading, Physical and Cyber Security. These definitions for
Transmission Loading, Physical and Cyber Security Alert states align with the Emergency Energy
Alert (EEA) states (as already described in NERC Reliability Standard EOP-002-2.1). The time frame
for declaration of these Alert states shall be consistent with the approach used to declare EEAs and
would normally apply to Real Time declarations and not forecast conditions.” This seems to limit use
of Interoperability Communications to only events where there exists either a physical or cyber
threat, or where an IROL can’t be mitigated. This emphasizes the confusion as described in item 2
above where the EEA levels in EOP-002-2.1 uses numerical values (i.e. EEA Level 1) without the
colored conditions. We recommend adding a new section to Attachment 1 ‘Operating State Alert
Levels’ as: ‘Reliability Coordinator Notifications for Energy Emergency Alerts.’ 4-Attachment 1
pertains specifically to Operating State Alert Levels and says nothing about the communication of
information to be used to change the state or status of a BES element or facility (which is the SDT’s
proposed definition of Interoperability Communications). Therefore, it is not appropriate to require
that all verbal and written Interoperability Communications use the pre-defined terminology in
Attachment 1. Only those communications concerning Operating State Alert Levels should be
required to use that terminology. By the proposed definition, such communications are not
Interoperability Communications since the information is not used to change the state or status of a
BES element or facility. The SDT needs to revise this requirement to clarify that it pertains only to
communicating the Operating State Alert Levels and nothing more.
Disagree
Any confusion about what time is being verbally communicated should be cleared up by three-part
communications. There should be no confusion about what time is being communicated in writing as
long as the time zone and AM\PM designation are included. Besides, many entities exchange written
information via web-enabled applications that allow the users to configure their interface to show
time in whatever format and time zone they prefer. This eliminates confusion. Operators will
continue to use local time in their communications with field personnel, support staff, and
management, and we see no demonstrable reliability-related need to require every operator in
North America to have to convert their local time to CST in their communications with other
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operators. However, if the SDT feels a standard time must be adopted, it should be GMT as this is
the time that used by all ‘true time’ devices.
Agree
As currently defined, Three-part Communications presumes the second party will repeat the
information back “correctly.” Failure to do so is assigned a High VRF and a Severe VSL. The practical
application of Three-part Communication involves a sender communicating information, a receiver
repeating back the information, and the sender verifying the repeat back is either correct or
incorrect. If the repeat back is incorrect, the process repeats until both parties have the same
understanding of what is being communicated. This iterative process needs to be addressed within
the definition of Three-part Communications.
Disagree
Use of this adds a lot to verbal communication but has little value. Where either the issuing or
receiving party is unsure as to which letter was used, their choice of word to associate with the
alphabet need not be dictated by a specific phonetic alphabet. If I am unclear, whether I ask “did
you say ‘F’ as in Frank or ‘F’ as in Foxtrot, it is my belief that we will both know that I heard the
letter F not the letter S. Using Frank instead of Foxtrot will result in a violation of Requirement R6
which carries a High VRF and a Severe VSL; even though there would be no impact on effective
communication. There is no compelling reason to require every operator in North America to learn
and use the NATO phonetic alphabet. It would be overkill to do so, and it could create some really
bizarre conversations. For example, consider a TOP in the eastern time zone who calls his RC (also
in the eastern time zone) at 10:00 A.M.to confirm that a line that tripped earlier that morning will be
ready to switch back in service at 10:35. Taken to the extreme, a strict interpretation of R6 and R4
(the CST requirement) would say that the TOP operator would have to state the estimated time of
restoration as “niner tree fife, Alpha Mike, Charlie Sierra Tango”. There is no need for that.
Agree
While we agree conceptually, it is our experience that Interoperability Communications concerning
BES elements do not usually specifically identify the element or facility when the BA, RC or TOP is
communicating with the TSP, LSE or GOP. This may have to do with concerns about
Standards/Codes of Conduct or may be because specific identification of the element or facility isn’t
required in order to communicate action(s) that entity is required to take.
Agree
See response to question 4. In addition, there seems to be an inconsistency between the inclusion of
Attachment 1 and what is stated in the document posted with the standard entitled Disposition of
Requirements Identified in the SAR for Operations Communications Protocols as Possibly Needing
either Modification or Movement. The document states that the standard focuses on “how to”
communicate rather than on specified scenarios of “to whom” or “when to” communicate; however,
Attachment 1 does just the opposite.
Agree
Some ISO/RTOs have market rules which allow participants to elect NOT to follow instructions issued
by their market operator (who may also perform BA, TOP and/or RC entity functions) unless an
Emergency exists.
Agree
PJM members are only required to comply during an Emergency.
Agree
The VRFs for R2-R7 are all “High”, and the VSLs are all “Severe”. That is too harsh. Failing to comply
with one of the requirements does not automatically mean that a miscommunication occurred that
caused a reliability problem. There should be a “Moderate” VSL for failure to comply with a
requirement but no miscommunication occurred. There should be a “High” VSL for failure to comply
with a requirement that caused a miscommunication but resulted in no violation of another reliability
standard. The “Severe” VSL should only apply to failures to comply with a requirement that caused a
miscommunication that lead to a violation of another reliability standard. If approved, this standard
will require a number of distracting things be added to each entity’s control center with little value
added. Clock – set to the ‘standard time’ Attachment 1 – COM-003 (all 3 versions) Attachment 2 –
COM-003
Individual
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Martin Bauer
Bureau of Reclamation
Agree
Agree
Agree
Disagree
Reclamation does not agree with the Attachment 1 condition color coding as it will conflict with the
DHS system of notification of change in threat condition. The three color system is unique to the
notifications issued by DHS. Use of that color system is reserved by the DHS. Federal agencies are
required to perform specific tasks when DHS issues alerts or changes the threat condition. Only DHS
can change the threat condition. The concept needs to be revised considerably to avoid the conflict
or create a potential security issue.
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
As indicated in the previous response the standard conflictsd with DHS notifications.
Agree
Group
Midwest ISO Standards Collaborators
Jason L. Marshall
Disagree
The definition of Three-part Communication applies only when the communication is understood by
the listener the first time. Because the definition requires the listener to repeat the information back
correctly, failure of the listener to understand the information the first time could be construed as a
violation or at least not fitting the definition. The definition should rather reflect that three-part
communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows: “A
Communications Protocol where information is verbally stated by a party initiating a communication,
the information is repeated back correctly to the party that initiated the communication by the
second party that received the communication, and the same information is verbally confirmed to be
correct or corrected by the party who initiated the communication. The protocol should be followed
until the party issuing the information is satisfied that a party receiving the information has
understood the communication and confirmed it.” These principles are included in Requirements R2
and R3 in the recently issued draft Standard COM-002-3 in Project 2006-06. We believe the term
“Interoperability Communication” creates confusion within the industry and contradicts the work by
RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part communications
when issuing Reliability Directives (defined in Project 2006-06) that address anticipated and actual
emergency conditions. Additionally, it appears that this definition would encompass all verbal
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communications and, as such, we question the need for such definition. While using three-part
communications during routine operations may be a best operating practice, we do not believe that
it is so critical to reliability that it becomes an enforceable requirement for routine operating
instructions. Rather we believe the enforceable requirement should be limited to require three-part
communications during actual emergency and anticipated emergency conditions only. Both element
and facility are used in the Interoperability Communication definition and are NERC defined terms.
Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized. In addition, the term “entities” is confusing and needs to be defined.
Disagree
The SDT actually expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. In any
event, this Requirement represents a “how” and not a “what”. In general, standards should be
focused on “what” not how. The only real need for a requirement is to establish that each entity
issuing a directive shall use three-part communications and the recipient of a directive shall also
properly participate in the of use three-part communication protocol until the message has been
correctly spoken and comprehended.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Performance-based Reliability Standard Task Force’s recommendations to assess the existing
standards, modify and develop standards that support reliability performance and risk management,
and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to eliminate administrative requirements. This proposal takes the opposite approach
and incorporates a new administrative requirement. We – and the industry as a whole based on the
response to the Task Force – do not support such an approach. We suggest deleting this
Requirement from the Standard.
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Many RC communications are issued to multiple parties using blast
communication systems such as the RCIS. Several of the listed entities such as Distribution
Providers and Generator Operators cannot have access to these systems due FERC standards of
conduct requirements. Attachment 1 and R2 are not consistent with the definition of Interoperability
Communications. By definition, Interoperability Communication pertains to all communications about
how entities change the state of the BES (not just about physical or cyber attacks). Attachment 1 is
only about notifying of what physical and cyber attacks and transmission emergencies have already
happened to the BES.
Disagree
There is no reliability need to use a common time zone for communications. There is already a
requirement to use hour ending for scheduling purposes, inadvertent accounting, CPS and other
standards where needed. There is no additional reliability need to use a common time zone. The
time zone should be identified in the communication. Use of CST will actually cause confusion and
significant, unnecessary costs with no foreseeable reliability benefit. Some of the costs will arise to
change systems such as RCIS, IDC, scheduling and E-Tag systems, etc.
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part
communications is required to communicate routine operating instructions. We believe this
Requirement contradicts the work that has been done and substantially progressed through two
other SDTs and creates confusion within the industry. We believe this Requirement would, in fact, be
adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned
with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT in Project 2006-06 which would define a Reliability
Directive based on the determination of the person giving such an order. We believe it should be left
to the entity that needs the action to be taken to establish the need for three-part communications
by stating in the communication that they are issuing a directive. This would be a clear trigger and
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easily auditable and measureable. R5 is not consistent with the Functional Model. Only the RC, BA,
and TOP can issue directives.
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary
to be used in all verbal Interoperability Communications and is certainly not necessary to be
included as an enforceable Requirement. Imagine the situation in which an operator says “A as in
apple” instead of using the NATO Alpha. Even though the listener should clearly be able to discern
the correct meaning, the speaker’s company could be sanctioned even if the correct actions were
taken as a result of the clear communication. There is no reliability need for this Requirement.
Disagree
This may represent a good utility practice but it is not necessary to be included as a Requirement.
The key question is: “Do the companies’ personnel understand one another?” If I know that my
company refers to a tie-line as Alpha and my neighboring company calls it Beta, I know what he
means when communicating to me. That is all that matters. This is a “how” based Requirement that
should be eliminated.
Disagree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads,
“The time frame for declaration of these Alert states shall be consistent with the approach used to
declare EEAs and would normally apply to Real Time declarations and not forecast conditions.” In
Transmission Emergency Alerts Condition Yellow, Orange and RED: The Reliability Coordinator or
Transmission Operator foresees or is experiencing conditions where all available generation
resources are committed to respect the IROL and/or is concerned about its ability to respect the
IROL. Forsees is a forecast condition. In condition Orange and Red for TEA Level Two/Three, the
initial notification requirements are redundant with IRO-006-East-1 R3.2. Under the Make Final
Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in operations
generally means cuts for schedules/tags. EEA’s use terminated. We recommend using terminated.
Distribution Service Providers should be Distribution Providers to be consistent with the Functional
Model.
Disagree
Disagree
Agree
We believe that the existing standard COM-002 is better than this proposed Standard. This Standard
actually causes more confusion and ambiguity and creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. Additionally, we cannot understand how all
requirements but R1 have been determined to have a HIGH VRF when, many of them are dictating
HOW communications should take place and not when and why or what. COM-002 retirement does
not appear to be consistent with the direction of the RC SDT in Project 2006-06. The RC SDT is
adding requirements. More coordination is certainly required between these two teams. In addition,
as stated earlier, this Standard focuses on “how” certain tasks should be performed and conflicts
with NERC’s position of pursuing performance based and results based Standards. Based on these
considerations, we suggest that work on this Standard be stopped until work on Project 2006-06 has
been completed and approved. This approach is consistent with the August 2003 Blackout
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Recommendation #26 which actually focused on communications during emergencies which is the
scope of Project 2006-06. After Project 2006-06 is completed, a determination can be made if this
Standard is even required.
Individual
Kasia Mihalchuk
Manitoba Hydro
Disagree
Comments: Agree to the adoption, but not the definitions as defined. 1. Communication Protocol Remove “written” from this definition. Create a new standard that defines “written” protocol, i.e.:
express “24 hour format”, common date format, etc. a) Using “written” in this definition and which
is also used in COM-003-1 R2, R3, R4 and R7 clouds both the Definition and the Standard. The
majority of COM-003-1 requirements also focus on the spoken word, such as the use of English,
Phonetics and Three-way Communication. b) “Communications” in the Definition infers verbal
communication especially when examining the COM-003-1 Standard where its purpose is “timely
information in alerts and emergencies”. c) When COM-001-1 R4 “English” and COM-002-2 R2
“Three-way” requirements are amalgamated into COM-003-1, the COM-003-1 standard will now
strengthen the focus on the process of verbal communications. d) COM-003-1 R2 “Uniform Line
Identifiers” This requirement would be used in real time reliability situations, alerts and
emergencies. The “written” communications would be used after the fact and therefore “written”
does not belong in the definition. e) In COM-003-1 R3 “use English” The purpose of this standard is
convey information effectively during alerts and emergencies. “Written” would be used after the fact
and therefore does not belong here. f) In COM-003-1 R4 “24 hour format” “Written” could be
reserved for a new standard, which could which define “24 hour format” along with a common date
format which is also needed. g) In COM-003-1 R5 “Three-part Communication” Focuses entirely on
the spoken word and appears appropriate that “written” is not used here. h) In COM-003-1 R6
“Phonetics” Focus on the spoken word and would never be used to empathize a written word and is
appropriate that is not used here. i) COM-003-1 R7 states “Operating State Levels” All
communications for broadcasting these alerts would typically be verbal. “Written” communications
would be after the fact. 2. Three-part Communication - Use COM-002-2 R2 requirement as an
improved basis for the “Three-part Communication” glossary term and define each part of the three
parts separately. a) This new NERC Glossary term is better defined in the COM-002-2 R2 “Threepart communication” requirement. “Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and definitive manner; shall ensure the
recipient of the directive repeats the information back correctly; and shall acknowledge the response
as correct or repeat the original statement to resolve any misunderstandings.” b) The current
glossary term is overwhelming and confusing with the “back and forth” exchange of responsibilities.
More thought process is consumed trying to break down the definition into usable portions, then
comprehending the definition itself. c) The glossary term should be more clearly defined by
specifying each of the three part communication protocol; i. An initiating party verbally issues
directives in a clear, concise and definitive manner. ii. The receiving party shall replicate the intent
of the directive and iii. The initiating party shall acknowledge to their satisfaction that the receiving
party fully understands and is capable of caring out the directive. 3. Interoperability Communication
- Define further and/or define entities. Expand “interoperability” and add and define “entity” a)
Using “interoperability” and “entities” in same glossary term, clouds the definition especially when
this glossary term is used to help clarify requirements in COM-003-1. There are at least three
possible levels of “Interoperability” from a Control Center point of view; i. Internally, within a utility.
-Communication between the Balancing Authority and Transmission for reliability purposes (within
control center). -Between BA, TO, TOP, GO, TSP, LSE and DP, such as between the sending and
receiving end of an HVDC terminal. ii. Externally, between neighbouring utilities. iii. Externally,
between the Balancing Authority and their Reliability Coordinator. For a Reliability Coordinator two
more levels of “Interoperability” could be added: iv. Communication between Reliability
Organizations. v. Communication between the three major interconnections. b) Though the glossary
definition surely includes all of the above, it does not clarify that and becomes immediately clouded
when interpreting COM-003-1 R1 where “personnel” is used for real time control for effective
Interoperability Communication. 1. Personnel – individual responsible for the operation of the
interconnected bulk electrical system (real time, planning, etc) c) Adding and defining Entity in the
glossary as per suggestions; i. “Entities” are used commonly in the Reliability Standards and
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encompasses a lot of different contexts. ii. “Entity” defined by a dictionary includes a comprehensive
range such as: -body -Unit -Group -Thing -Article iii. Entity in a interoperable power system: - BA,
TO, GO, TSP, LSE, etc - Neighbouring BA, Control Area, Neighbour (Utility) - Reliability Coordinator,
MISO, Reserve sharing Group, etc - NERC, MRO, WECC, NPCC, ERCOT, etc - Western
Interconnection, Eastern Interconnection, ERCOT.
Disagree
Leave TOP-002-2 R18 in its original location. 1)“Mutual line and equipment identifiers” should not be
moved from TOP-002-2 and placed in COM-003-1 R7. TOP-002-2 Standard’s focus is “Planning,
coordination and procedures” whereas: • R1 is “Maintain current Plans” • R2 is “Participate in
planning and design” • R3 is “LSE coordinate with Host” • R4 is “BA coordinate with neighbours” •
R5 is “plan to meet schedules” • R6 is “plan to meet N-1” • R7 is “plan to meet capacity and
reserves” • R8 is “plan to meet VAR limits” • R9 is “plan to meet interchange” • R10 is “plan to meet
IROL, SOL’s” • R11 is “perform studies for SOL’s” and “utilize identical SOL’s for common facilities” •
R12 is “include known SOLs or IROLs” • R13 is “GO shall verify generation capability” • R14 is “GO
shall notify of changes” • R15 is “GO shall provide generation forecast” • R16 is “shall notify RC of
changes” • R17 is “notify RC of R1 to R16” • R18 is “shall use uniform identifiers” • R19 is “maintain
computer models for planning” 2)TOP-002-2 R18 “shall use uniform identifies” appears to be more
strongly related to where it already exists and would have more impact to have it moved between
R2 and R3. 3)Uniform identifiers are determined in the planning stages and are common knowledge
to entities by the time they are in service and not a real time communication issue. a.Having TOP002-2 R18 moved to COM-003-1 R7, takes the purpose of the COM-003 standard outside its context
of “timely convey reliability information . . . especially during alerts and emergencies”. b.COM-0031’s purpose and all its requirements directly relate to real time communication. 4)TOP-002-2 R11
“identical SOL’s for common facilities” complements R18 “shall use uniform identifiers” and again are
both planning requirements. 5)The unofficial comment for “Pre-determined Line and Equipment
Identifiers” indicates that mutual agreement of these identifiers are to be reached in advance, thus
agreeing with above. Leave R18 in TOP-002-2, but possibly move it between R2 and R3, thus R2 in
COM-003-1 would be removed. Regarding adding TSP and LSE, no comment added.
Agree
Yes, with comments 1)In this requirement “Interoperability Communications between personnel
responsible for real time” becomes clouded when compared to the “Interoperability
Communications” definition that states “exchange information between entities”. a.Improving the
“Interoperability Communication” definition as per early suggestion should clarify this. 2)Changing
the order of requirements would make the flow of the standard smoother. a.Since this standard is
mostly designed for real time communication, the requirements should pyramid down. • R1 is fine. •
R2 should be “English” • R3 should be “NATO” • R4 should be “Time” • R5 should be “Three-part
communications” • R6 reserved for “Full name identification” (See below for clarification)
Conclusion: This requirement is acceptable as long as the enclosed comments are considered.
Disagree
Move this new requirement R1.2 in COM-002-2. 1)COM-003-1 R2 “Pre-defined system condition
terminology” are all planned definitions. a.COM-003-1 purpose is to “convey information effectively”
meaning the use of English, NATO, three-part communication, 24 time format are all verbal aspects
to accomplish this purpose and not suited to pre-defined or planned items. 2)COM-003-1 R2 appears
more appropriate and relevant placed in COM-002-2. COM-002-2’s Purpose is “capabilities for
addressing real time emergencies and to ensure communications by personnel are effective”.
a.Placing “Pre-defined system condition terminology” in COM-002-2 after R1.1 as R1.2 appears to
have more of a chronological approach. i.R1.1 states “conditions that could threaten” ii.R1.2 use
“pre defined system conditions” Conclusion: Remove COM-003-1 R2 and replace in COM-002-2 as
R1.2
Disagree
As per below. 1)The 24 hour format will certainly reduce the confusion of AM and PM and at present
seems to be the current best practice for all entities so should not be a major change. 2)Examining
the definition of “Interoperability Communications” means that there is and will be real time
communications with entities in other times zones, thus it is assumed that this being an NERC
standard is enforcing that all other time zones (PST, MST, EST) will be using CST when
communicating with interoperability. a.If this is the case, it appears that the other time zones (PST,
MST and EST) must make effort to modify their local time to synchronize with CST. b.This brings to
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point that when interoperability communication is used, this fact must be mentioned, instead of
13:53, it should be 13:53 CST. 3)Adding CST to verbal time formats will be difficult to implement,
so maybe a statement confirming the time zone should be appropriate each time interoperability
communications is used when required. Conclusion: 24 hour format is fine, further clarify that all
other time zones must use CST.
Move requirement as planned but keep Three-part Communication definition as stated originally in
COM-002-2 R2. 1)Reading the “Disposition/Explanation” it appears that COM-002-2 R2 will
eventually be moved into COM-003 R5. This appears logical as COM-002-2 ensures staffing and
communication capabilities. a.The statement in COM-002 R2 is reasonably descriptive, but loses its
depiction when replaced with statement found in COM-003-0 R5. 2)Regarding COM-002-2 R2,
Manitoba Hydro interprets part 2 (repeat back correctly) of Three-part Communication to mean; that
the party receiving the directive has clearly received it in its full form and understands completely
what is expected of him and to convey this to the sender; i.We delineated “repeating back correctly”
to mean any of the three protocols as acceptable: 1.Actually repeating back the directives correctly.
2.The recipient verifies the issued directive(s) are identical to a copy they have at hand. Example for
clarification: “The steps you have read are identical to what I have here on Order Number 1234,
Revision 5 and I understand I can proceed with steps 3,4 and 5”. 3.The recipient summarizes the
issued directive(s) to a copy they have at hand. Example for clarification: “I will do step 8, open all
115 kV disconnects as read to me and are identical to the order 1234 Revision 5 that I have at
hand”. 4.This all could be resolved by using the term “repeat back the intent of the directive”. This
statement could allow the operator to determine if the recipient fully understands and is capable of
carrying out the directive, by the method of the recipient reply (any literate person can read back a
written statement, but do they understand what they are doing and the consequences). ii.The
purpose of protocols 2 and 3 are to alleviate potential of “lose of attention” due to the tedious
receptiveness of long written directives. Summarizing or verifying these types of written orders will
maintain the interest and attention to the detail. iii.Verbally detailing a directive at least once in any
single conversation by either party should be sufficient to fulfill the first two parts of Three-part
Communications (Clear and concise, repeat back). iv.Part 3 (acknowledge to satisfaction of the
originator) could ensure that the person receiving the directive is capable and competent of carrying
out the directive. v.None written (changes, revisions, real time emergency switching) and radio
communication directives are a must for repeating back and are covered by other local policies. Part
Two “Three Part Identification” 3)This new Standard COM-003-1 should contain a requirement for
“Three Part Identification” or more commonly known as “Full Name Identification”. This is not
addressed fully anywhere in the NERC standards. 4)We have defined “Three Part Identification”
based loosely on common industry best practice into three parts: 1.Location – Company Name,
Control Room Name, etc. 2.Area of responsibility or authority (function) – The operator at the desk
must identity his position such as Balancing Authority or Distribution Operate, etc. 3.Identification –
Unique identifier such as first and last Name.
Disagree
To using NATO full time 1)Being trained or being familiar with NATO Phonetics is a great idea, but
should only be implemented, in bad communication connections, or upon request due to accents,
quiet voice, fast talk, too loud, unusual request, etc. 2)Communication technology for the most part
is exceptionally clear, and the regular use of NATO Phonetics would be difficult to implement and
time consuming to use. The RC and neighbouring entities are familiar with common terminology
between each other.
Disagree
Move this new requirement R1.3 in COM-002-2. This is similar to Question 4 and should be treated
in the same way: (This requirement is moved from TOP-002-2 R18) 1)COM-003-1 R7 “Predetermined, mutually agreed upon line and equipment identifiers” are all planned definitions.
2)COM-003-1 purpose is to “convey information effectively” meaning the use of English, NATO,
three-part communication, 24 time format are all verbal aspects to accomplish this purpose and not
suited to pre-determined or planned items. a.COM-003-1 R7 appears more appropriate and relevant
placed in COM-002-2. COM-002-2’s Purpose is “capabilities for addressing real time emergencies
and to ensure communications by personnel are effective”. 3)Placing “Pre-determined, mutually
agreed upon line and equipment identifiers” in COM-002-2 after R1.1 as R1.3 appears to have more
of a chronological approach. i. R1.1 states “conditions that could threaten” ii. R1.2 use “pre defined
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system conditions” iii. R1.3 use “pre determined equipment identifiers” Conclusion: Remove COM003-1 R7 and replace in COM-002-2 as R1.3
Disagree
1)Attachment 1-COM-003-1 qualifies for all three requirements stated below and would be better
suited in this Standard. a.CIP-001-1 Purpose:“sabotage to be reported to appropriate bodies” and
includes the following requirements; R1. Procedure for recognition R2. Procedure for communication
R3. Response guideline 2)OR COM-003-1 Attachment 1 could also be placed in COM-002-2. COM002-2’s Purpose is “capabilities for addressing real time emergencies and to ensure communications
by personnel are effective”. 3)COM-003-1 purpose is to “convey information effectively” meaning
the use of English, NATO, three-part communication, 24 time format are all verbal aspects to
accomplish this purpose and not suited to pre-defined or planned items. 4)COM-003-1 Attachment 1
also defines Physical Security threats and notifications which fulfills the purpose of COM-002-2 more
thoroughly (then in COM-003-1) and could even be made as an requirement.
Disagree
Disagree
Disagree
Group
Transmission Owner
Silvia Parada-Mitchell
Agree
Disagree
This requirement is already covered by TOP-002. If the TOP-002 standard is deemed deficient
because certain entities have been excluded or language appears to be missing, the changes need
to occur to TOP-002 as opposed to copying and revising the existing requirement elsewhere. This
would ensure that compliance oversight, understanding, and adherence goals are unencumbered by
unnecessary redundancies. Moreover, this would ensure that the industry continues to re-enforce
standards with changes that are within the scope of their original reliability purpose. The latter is in
line with one of the core objectives of the Performance-based Reliability Standards Task Force’s
recommendations to focus on identifying and aggregating duplicated requirements.
Disagree
FPL agrees with the reliability goal of establishing a set of agreed upon communication standards to
ensure consistent communications particularly for actual and anticipated emergency coordination
needs. FPL also believes that existing coordination/communication standards already fulfill this
objective and that it might be of “training” or “reference” value to aggregate those requirements to
a single document or view. However, FPL is not convinced that this requirement, largely
administrative in nature, will result in marked improvement in reliability. Organizations tend to take
the path of least resistance and unless forced out of that path with extensive and granular guidance
on what CPOPs should contain above and beyond existing standards or contract language, CPOPs
would likely become a simple patchwork of requirements constructed out of existing NERC standard
language and contract language. Standards need to be clearly implementable before they are
approved yet important implementation questions do not appear to have been answered. (1) What if
parties cannot reach agreement? (2) Is it enough to have attempted to coordinate? (3) What if
parties already have agreed upon procedures such as NPIRs, or those stated in Interconnection
Agreements – do they take precedent or must they be redesigned/relegated? (4) What if CPOPs
differ greatly across interconnections because of differing parties? (One might conclude that by
formalizing these different practices, as opposed to mandating standard practices, the goal of more
reliable coordination may not have been achieved) (5) What level of evidence constitutes
“agreement” especially in circumstances where entities may be remiss to agree? (6) What if CPOPs
are simply a patchwork of requirements constructed out of existing NERC standard language and
contract language – does that achieve the CPOP goal?
Disagree
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FPL agrees that standard system condition terminology could be beneficial in communications but
this requirement introduces alert level conventions with no clarity on what the corresponding
associated actions for such levels are and as a result, aside from the value derived from have
improvement in terminology during communications, it is unclear what reliability improvements this
will achieve in carrying out instructions since details on what sort of tasks need to be carried out for
each level have not been defined. Also, this requirement should clearly indicate that this alerting
system and any communication conventions be required for emergency conditions.
Disagree
Existing market and reliability communication methods already ensure that time-zone adjustments
occur. It is critical that the feasibility, impact, and logistical aspects of implementing this change be
rigorously reviewing and understood to inform this standard’s development. Any implementation or
transition gaps between the time format and references used by reliability coordinators, their
corresponding systems, and the interfaced systems of market participants would be extremely
detrimental to system stability and ongoing market operations.
Disagree
The term “directive” as of yet has not been explicitly defined. Furthermore, FPL believes that by
associating the “3-part communication” method with “directives” this standard drafting team could
be at risk of unintentionally defining a directive as anything that takes the 3-part communication
form. We would encourage the standard drafting team to continue to use the terms already
employed in the draft standard: “… three-part communication be used when issue instructions
related to “actual or expected emergency conditions.”
Disagree
FPL believes that though aspiring to use a single strict phonetic alphabet is important, it is more
important to ensure that ease of communication takes precedence especially under emergency
conditions. As such, this requirement should be written more as a best practice or guideline. FPL
believes this requirement could be improved by stating that under such emergency conditions, the
NATO phonetic alphabet can be used as a base-line reference but that usage of ad-hoc phonetic
alternatives that achieve the same real-time communication goal can also be used.
Disagree
FPL believes that R7 should be withdrawn as it repeats TOP-002 R18 requirements. Please refer to
comments on Q3.
Disagree
Disagree
Disagree
Agree
In the case of nuclear plant operations, NRC communication requirements and the requirements of
NERC NUC-001 for nuclear facilities more than adequately cover communication requirements. COM003 should not be applicable to Nuclear Generator Operators since doing so will introduce an
additional, unnecessary, and potentially conflicting level of requirements. Measures: FPL suggests
that the SDT clarify the periodicity of providing evidence of compliance and on what constitutes
sufficient evidence of CPOP acceptance. Violation Severity Levels: FPL encourages the SDT to revisit
the violation severity levels. In the case of most of the requirements it is unreasonable to levy
severe penalties in instances where the operator may have deviated from the requirements but the
communication occurred in an unencumbered and successful manner as evidenced by the
use/acknowledgement outcomes of three-part communication.
Individual
Tim Hattaway
PowerSouth Energy
Disagree
Inoperability definition is too broad and not clear.
Agree
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Disagree
It's not clear as to who is being targeted as the "personnel responsihle for real-time generation
control and real-time operation of the BES". Is this just the system operator or is this the generator
unit operator or the field switchman?
Disagree
This requirement is unecessary.
Disagree
This requirement will be too confusing and could lead to compliance violations because someone
stated the wrong time during the conversation.
Disagree
The term interoperability communications is not clear.
Disagree
Completely unnecessary to require each operator to learn and use the NATO alphabet for situations
that may occur on a very limited basis.
Agree
Individual
Joylyn Stover
Consumers Energy
Disagree
Communications Protocol and Three Part Communications have been used in the industry and are
acceptable. There seems to be a better way of stating “informational” communications since
Directives are already discussed.
Disagree
There is no reason to move R18 from TOP-002 to COM-003. There is also no reason to utilize a
shotgun blast method of coverage for this standard. Also, regardless of technical accuracy, TOP002-2 R18 should not be moved to COM-003-1 without a simultaneous and corresponding change to
TOP-002-2, lest an entity be found non-compliant with both standards for a compliance violation.
Disagree
I agree written Communication Protocols should be in place. Since we do not agree with all of the
requirements mentioned we can not agree with this statement. Furthermore, since these protocols
will have to be between Functional Entities and most likely multiple companies, a methodology
needs to be in place to prevent duplication of efforts and double jeopardy in the audit process.
Disagree
The COM Standards should put forth the methodology of communication, not provide communication
for each event. For example, CIP-001 describes the communication to take place for CIP attacks, be
they physical or cyber, EOP-002 describes the process for Generation and Capacity Emergencies.
Utilizing the similar sounding vernacular (EEA,CEA,PSEA,TEA) is not prudent.
Disagree
Common Time Zone has been discussed for decades. There was little or no evidence a common time
zone standard would have prevented any of the system disturbances experienced since 1996 let
alone the blackout of 2003.
Agree
Agree
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Disagree
This requirement is better served under the TOP Standards. The TOP standards already require this
(TOP-002-2 R18), and the requirement should not be duplicated.
None.
None.
None.
Agree
Amplification of the communication process is needed but this draft reaches beyond Communication
to the start of drafting procedures for three separate emergency conditions while it leaves one
alone. Focusing on the communication process is in order.
Group
PacifiCorp
Sandra Shaffer
Agree
Agree
Agree
Agree
Disagree
The sole use of Central Standard time Time would add confusion to thefor Interoperability
communication Communications process that would detract would have the unintended consequence
of creating more confusion, particularly during emergency communications. While PacifiCorp
appreciates the need for minimizing mis-matched time signatures between control systems, it
believes that mandating one time zone for all Interoperability Communications will create more
confusion during an emergency that it will prevent.
Agree
Agree
Agree
Disagree
Disagree
Disagree
Currently, PacifiCorp’s Open asis Access Same-Time Information System (OASIS) allows time to be
showndisplays time in Pacific standard Standard timeTime. Mandating all Interoperability
Communications to be held in Central Standard Time may cause confusion with regard to
transactions and activities conducted on OASIS – which ultimately relate to real-time operations.
Disagree
Group
Northeast Power Coordinating Council
Guy Zito
Disagree
The way the definition of “Three-part Communication” is worded applies only when the
communication is understood by the listener the first time. The RC SDT requirement which includes
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“and shall acknowledge the response as correct or repeat the original statement to resolve any
misunderstandings” is more complete. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could
be construed as a violation or at least not fitting the definition. The definition should reflect that
three-part communication is an iterative process that should be followed until the listener is
confirmed by the speaker to get the information correct. A suggested revision to the definition: A
Real-Time Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the
communication by the second party that received the communication, and the same information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it. These principles are included in
Requirements R2 and R3 in the recently issued draft Standard COM-002-3 in Project 2006-06. An
alternative suggestion to the definition of Three-part Communication: A Real-Time Operating
Communications Protocol where information is verbally stated by a party initiating a communication,
the information is repeated back correctly to the party that initiated the communication by the
second party that received the communication, and the same information is verbally confirmed to be
correct by the party who initiated the communication. A suggestion to the definition of
Communications Protocol: The term “Interoperability Communication” creates confusion within the
industry, and contradicts the work by RTO and RC SDT in Project 2006-06 that limits the
requirement to use three-part communications when issuing Reliability Directives (defined in Project
2006-06) that address anticipated and actual emergency conditions, and do not agree with its
definition. What also must be considered is that the RC SDT has stated that when someone “says”, it
is a directive--operating conditions are not distinguished. This definition unnecessarily and
counterproductively encompasses all verbal communications and, as such, is not needed. It is not so
critical to reliability that it should become an enforceable requirement for routine operating
instructions. The enforceable requirement should be limited to require three-part communications,
and be left to the entity that needs the action to be taken to establish the need for three-part
communications by stating in the communication that they are issuing a directive. This would be a
clear trigger, and be auditable and measurable. Virtually all communications in a control room
environment deal with changing the state or status of an element of facility, as such there is not a
need to define this communication protocol. Both element and facility are used in the
Interoperability Communication definition and are NERC defined terms. Did the drafting team intend
that the NERC definitions should apply? If so, the terms need to be capitalized. The term “entities” is
confusing and needs to be defined.
Disagree
The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. This
Requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and understood. LSEs and TSPs do not own or operate equipment, and as such in a market
environment should not fall under the mandates of this requirement. Neither the TSP nor the LSE
provide or receive information about specific lines or equipment in real-time. Therefore, requirement
R7 should not apply to them absent clear evidence that a realistic (not hypothetical) threat to
reliability would exist if they are omitted. We do not think that such a threat would exist.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Results-based Reliability Standard Task Force’s recommendations to assess the existing standards,
modify and develop standards that support reliability performance and risk management, and work
on an overall plan to transition existing standards to a new set of standards. One goal of this effort
is to eliminate administrative requirements. This proposal takes the opposite approach and
incorporates a new administrative requirement. The industry as a whole, based on the response to
the Task Force, does not support such an approach. This Requirement should be deleted from the
Standard. There is no need to create a CPOP that includes requirements R2 through R7 given that
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each requirement spells out how and what is to be communicated. A CPOP may be needed for
Interoperability Communications that are not addressed in R2-7.
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Just stating the severity and details of the
incident should suffice. Further, the “pre-defined” system conditions and alert levels are too detailed
and overly prescriptive. System operators will need to spend time looking for the right color and
level to communicate the prevailing system condition terminology to avoid violating the standard.
This task does not lend itself to promptly and effectively deal with the emergency situation. The
level(s) identified in the notification text are at odds with the condition (color versus numerical).
Suggest that the standard either use Condition (color) or the level (numerical). Many RC
communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the listed entities such as Distribution Provider and Generator Operator cannot have
access to these systems due FERC standards of conduct requirements. Attachment 1 and R2 are not
consistent with the definition of Interoperability Communications. By definition, Interoperability
Communication pertains to all communications about how entities change the state of the BES (not
just physical or cyber attacks). Attachment 1 is about notifying of what physical and cyber attacks
have already happened to the BES. It is not clear in the context of Interoperability Communications
what the recipient of a specific notification is expected to do when there is a change of state or
status of an element or facility of the Bulk Electric System. Attachment 1 pertains specifically to
Operating State Alert Levels and says nothing about the communication of information to be used to
change the state or status of a BES element or facility (which is the SDT’s proposed definition of
Interoperability Communications). Therefore, it is not appropriate to require that all verbal and
written Interoperability Communications use the pre-defined terminology in Attachment 1. Only
those communications concerning Operating State Alert Levels should be required to use that
terminology. By the proposed definition, such communications are not Interoperability
Communications since the information is not used to change the state or status of a BES element or
facility. The SDT needs to revise this requirement to clarify that it pertains only to communicating
the Operating State Alert Levels and nothing more. None of the examples in either of the
attachments appear to address EEAs (EEA is mentioned in the top paragraph of page 9 that is
included in EOP-002-2.1) or SOLs. This limits the use of Interoperability Communications to only
events where there exists either a physical or cyber threat, or where an IROL can’t be mitigated.
The requirements should focus on what is required, not how. The RC and encompassed entities
should be required to define terms that will be used in communications. This would allow for the use
of terms that are well understood in an area, rather than having to add new terms. The Background
Information in this Comment Form introductory section mentions “The SDT proposes four system
condition alerts instead of initial three in the RCWG version.” However, Attachment 1 only mentions
3 alerts – Physical Security, Cyber Security, and Transmission Emergency Alerts leading to
confusion.
Disagree
There is no reliability need to use a common time zone for communications. There is already a
requirement to use hour ending for scheduling purposes, inadvertent accounting, CPS and other
standards where needed. There is no additional reliability need to use a common time zone. The
time zone should be identified in the communication. Not only does this requirement attempt to
determine HOW entities operate within their various footprints, it would significantly change the way
many markets are structured. To implement this into existing Markets would cost significant time,
money and resources while not enhancing reliability in these areas. When operating across timezones, simply referencing “Central Standard Time” or “Eastern Standard Time” is sufficient for
operating entities to reliably operate. The time zone adopted by the respective Reliability
Coordinator (RC) and their area control center, e.g., NYISO Eastern Standard Time (EST), should be
used. If each entity in the area and the RC are all using EST (or daylight savings), then why would a
time zone be used that is foreign to all parties in the area? This can lead to considerable confusion.
What cannot be ignored is how many entities would have to modify their existing practices,
hardware, software, Control System, billing systems, bidding systems, etc. We are strongly opposed
to this requirement. The requirement should be that those entities which need to communicate and
are in different time zones define which time they will use for communications. Any confusion about
what time is being verbally communicated should be cleared up through three-part communications.
There should be no confusion about what time is being communicated as long as the time zone
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(where applicable), and the 24 hour format designations are included. Besides, many entities
exchange written information via web-enabled applications that allow the users to configure their
interface to show time in whatever format and time zone they prefer. This eliminates confusion.
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part
communications is required to communicate routine operating instructions, or during operational
strategic discussions as well as other “non-action” oriented communications. This Requirement
contradicts the work that has been done and substantially progressed through two other SDTs and
creates confusion within the industry. This Requirement would, in fact, be adverse to reliability
instead of enhancing reliability by reducing the amount of pre-action communications that may
occur prior to taking action because operators may be more concerned with not repeating back
during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person
giving such an order. The entity that needs the action to be taken should establish the need for
three-part communications by stating in the communication that they are issuing a directive. This
would be a clear trigger, auditable, and measureable. R5 is not consistent with the Functional Model.
Only the RC, BA, and TOP can issue directives. Outside of allowing the individual who NEEDS the
action to be taken, this is an auditable or measureable requirement whether it be for 3-part
communications or for the receiving entity to actually take said action. By definition, Three-part
Communications presumes the second party will repeat the information back “correctly.” Failure to
do so is assigned a High VRF and a Severe VSL. The practical application of Three-part
Communication involves a sender communicating information, a receiver repeating back the
information, and the sender verifying the repeat back is either correct or incorrect. If the repeat
back is incorrect, the process repeats until both parties have the same understanding of what is
being communicated.
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary
to be used in all verbal Interoperability Communications, and is certainly not necessary to be
included as an enforceable Requirement. For example, a situation in which an operator says “A as in
apple” instead of using the NATO Alpha. Even though the listener should clearly be able to discern
the correct meaning, the speaker’s company could be sanctioned even if the correct actions were
taken as a result of the clear communication. The objective of good communications is to assure
that the parties understand each other. The statement “… shall use the NATO phonetic alphabet”
doesn’t make sense for North America. If the Real-Time Operator states “breaker 6-North,” under
the NATO phonetic alphabet that would be unacceptable, because the operator did not use the
appropriate NATO term “breaker 6-November,” even thought the “N” on the one line diagram refers
to the “North” breaker and not the “South” breaker. Many organizations may have established
communications protocols which are working well. Making a change may actually hinder reliable
operations by introducing unnecessary confusion and questioning. Not only does this requirement
attempt to determine HOW entities operate with their various footprints, it may change the way
many Markets are structured. What is the difference between using the word “Zebra” instead of
“Zulu” to signify the letter “Z”? And, why would this be enforceable. Perhaps this should be a
guideline document rather than an enforceable Requirement. There is no reliability need for this
Requirement.
Agree
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There do not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information, for example 12 substations have been physically or cyber
attacked. This is more meaningful than issuing a red alert that would only indicate more than one
site has been attacked. Furthermore, we question the value of communicating the physical and
cyber alerts. How does this notification help the BES reliability? Consider the following example. One
BA in Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells
other operators that somewhere in Oklahoma an attack occurred. This notification does not present
any information that could require actions on the operators’ parts, and will only generate phone calls
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for more information. Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001
R2. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2. Also it
has been the experience of several entities during the field test of these Alert Levels that there are
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion
than exists today. Reliability has not been enhanced. Attachment 1 contains a conflict. The last
sentence of the opening paragraph of Attachment 1 reads, “The time frame for declaration of these
Alert states shall be consistent with the approach used to declare EEAs and would normally apply to
Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts Condition
Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL
and/or is concerned about its ability to respect the IROL. Foresees is a forecast condition. There is
an inconsistency between the inclusion of Attachment 1 and what is stated in the document posted
with the standard entitled Disposition of Requirements Identified in the SAR for Operations
Communications Protocols as Possibly Needing either Modification or Movement. The document
states that the standard focuses on “how to” communicate rather than on specified scenarios of “to
whom” or “when to” communicate; however, Attachment 1 does just the opposite. In condition
Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2. Under the Make Final Notifications, is curtailed intended to mean canceled or
terminated? The term Curtailed in operations generally means cuts for schedules/tags. EEA’s use
terminated. Terminated is the preferred term. Distribution Service Providers should be Distribution
Provider to be consistent with the Functional Model. Refer to the response to Question #4.
Agree
Many RC communications are issued to multiple parties using blast communication systems such as
the RCIS. Several of the parties such as Distribution Provider and Generation Operator cannot have
access to these systems due FERC standards of conduct requirements. Requirement 2 and the listing
of functional entities required to be notified within the RC footprint in Attachment 1 creates a de
facto requirement for them to have RCIS access or an unnecessary burden to communicate with all
functional entities listed separately. Having to communicate to all functional entities in that list
verbally and individually would create that unnecessary burden, and distract the RC from actual
system operation. This is a detriment to reliability. Some ISO/RTOs have market rules which allow
participants to elect NOT to follow instructions issued by their market operator (who may also
perform BA, TOP and/or RC entity functions) unless an Emergency exists. In the Province of Québec,
the use of French is mandatory, according to law, for communication within the Province. R3 should
include: Within the Québec Interconnection, the French language shall be used for verbal and
written interoperability communication between entities (RC, BA, TO, TOP, GOP, TSP, LSE and DP).
For their interoperability communication with entities outside of the Québec Interconnection, they
shall use the English language.
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in
the requirements is an unnecessary burden for these areas. The requirement to use CST attempts to
determine HOW entities operate within their various footprints and it would significantly change the
way many Markets are structured. To implement this into existing Markets would cost significant
time, and resources while not enhancing reliability in these areas. When operating across timezones, simply referencing “Central Standard Time” or “Eastern Standard Time” is sufficient for other
operating entities to reliably operate. Many entities would have to modify their existing practices,
hardware, software, Control System, billing systems, bidding systems, etc. We are strongly opposed
to this requirement.
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes
more confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that
add little or no value to reliability. All requirements with the exception of R1 have been determined
to have a HIGH VRF, when many of them are dictating HOW communications should take place and
not when, why, or what. COM-002 retirement does not appear to be consistent with the direction of
the RC SDT in Project 2006-06. The RC SDT is adding requirements. More coordination is required
between the Standard Drafting Teams. Again, we support the work being done by the RC SDT and
RTO SDT and do not believe this adds more necessary requirements. Many of the requirement
proposed in this posting either reiterate the drafts as posted (i.e. English language) or introduce
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confusion when compared to the drafts as posted. The SDTs should limit their scope to R2 and R7,
so as not to duplicate or contradict the on-going work of other SDTs. The SDT appears to have
adopted severe violations for every infraction. There should be some gradations, using increasing
severity based on the number of or severity of any infractions. Definitions: The standard should
define other terms, as well, including the following: • reliability-related information, • “… state or
status of an element or facility of the BES …” The standard should also have provision to include the
boundaries (components) of an “element,” and the meaning of the terms “state or status” in the
written communication protocol. For example, is the gas compressor of a 345kV breaker considered
part of this element, and so would a change in its “state or status” be covered? Similarly, is the heat
trace inside a 345kV breaker control cabinet part of this element or not? The VRFs for R2-R7 are all
“High”, and the VSLs are all “Severe” are too harsh. Failing to comply with one of the requirements
does not automatically mean that a miscommunication occurred that caused a reliability problem.
There should be a “Moderate” VSL for failure to comply with a requirement, but no
miscommunication occurred. There should be a “High” VSL for failure to comply with a requirement
that caused a miscommunication but resulted in no violation of another reliability standard. The
“Severe” VSL should only apply to failures to comply with a requirement that caused a
miscommunication that lead to a violation of another reliability standard, or caused a reliability
problem. In addition, as stated earlier, this Standard focuses on “how” certain tasks should be
performed and conflicts with NERC’s position of pursuing performance based and results based
Standards. Based on these considerations, work on this Standard should be stopped until work on
Project 2006-06 has been completed and approved. This approach is consistent with the August
2003 Blackout Recommendation #26 “failure to identify emergency conditions and communicate
that status to neighboring systems, and upgrade communication system hardware where
appropriate” which actually focused on communications during emergencies, which is the scope of
Project 2006-06. After Project 2006-06 is completed, a determination can be made on the
disposition of this Standard. This Standard should be effective uniformly continent-wide.
Group
SERC OC&SOS Standards Review Group
Margaret Stambach
Disagree
We feel that the definition of Interoperability Communication is much too broad and is inconsistent
with the effort to develop results-based standards. Adherence to such results-based standards would
have a measurable and observable effect on the reliability of the bulk electric system. The definition
of Interoperability Communication, as written, can include virtually any information
exchange/instruction between entities, both routine and emergency. Such communication may or
may not have a measurable and observable effect on bulk system reliability. The concern is that,
since the broad term Interoperability Communication is used in every requirement in COM-003-1,
entities will be required to use the English language, the central time zone, and 3-part
communication in even the most routine exchanges of information. This could create a burden on
operating personnel and a distraction from their reliability duties. This group does not feel the need
for a definition of Interoperability Communication, since the term Reliability Directive has been
defined in draft standard COM-002-3, which is currently posted for review. The Reliability Directive
term is emergency-focused and consistent with the results-based standards process. In addition, the
definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state – repeat - acknowledge) apply to Reliability Directives, while in COM-003-1
the definition of Three-part Communication refers to “information” in general. If, as stated in the
Disposition of Requirements, the revisions to COM-002-3 will be moved to COM-003-1, the definition
of Three-part Communication in this draft standard should be consistent with the requirements of
COM-002-3.
Disagree
TSPs and LSEs are not typically included in real-time communications and should not be included in
COM-003-1. The intent of requirement R18 in TOP-002-2 pertained to communications between
neighboring BAs and TOPs. Adding LSEs and TSPs to the applicability of this standard doesn’t make
sense, and this change should not be made.
Disagree
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This group feels that there should not be a requirement in the standard to have a “procedure”. It is
our understanding that, to be auditably compliant with a standard, the responsible entity must
develop a procedure, train on that procedure, and be able to demonstrate compliance via
documents, data, logs, records, etc. If Requirements R2 – R7 are included in this standard, the
entity will need to develop a procedure to be compliant. Therefore, we feel that requirement R1 is
redundant and should not be included.
Disagree
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliabilityrelated communications. Both the Reliability Directive and Interoperability Communication, as
currently defined, require some emergency action or change of equipment status. Yet the Alert Level
Guides were intended for announcement, not actions. Requiring system operators to use the colorcoded system condition terminology during communication adds a layer of responsibility that will
distract from the operator’s real-time reliability-related tasks. We do not feel that these Alert Level
Guides apply to all the responsible entities identified under Applicability in the draft standard – for
example, TSPs and LSEs are not included in the list of notifications. There is also some redundancy
in the Alert Level Guides – for example, the CIP-001 standard requires notification of sabotage
events – it should not be repeated in this standard.
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should
be that entities operating in different time zones agree on how to best eliminate any confusion
regarding the time difference. Entities that routinely operate in different time zones already have an
effective system for dealing with time differences. There seems to be no incentive to change a
system that already works quite well, and the cost of updating computer systems could prove
prohibitive. For instance, the requirement to use the central time zone for logging the time of an
alert is problematic in that all communication tools, such as the RCIS, will need to be re-vamped.
We question whether there will be a measurable reliability benefit by so doing. This group feels that
mandating a common time zone across all of North America can only lead to confusion and
increased reliability issues.
Disagree
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should
be used in place of Interoperability Communication, since the directive is specific to emergency
operations. The requirement should read: “Each responsible entity shall use Three-part
Communication when issuing a Reliability Directive”. In addition, this requirement should apply only
to BAs, TOPs & RCs. The other entities listed in the draft standard under Applicability do not issue
Reliability Directives.
Disagree
First, please note that “NATO” does not stand for North American Treaty Organization; it stands for
North Atlantic Treaty Organization. Use of the NATO phonetic alphabet should be considered a “best
practice” and should not be included as a requirement in a reliability standard. One failure, such as
saying “Baker” instead of “Bravo”, results in a severe violation without any impact on system
reliability. This group is concerned that operating personnel will be focused on using the correct
word rather than managing the power system.
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original
requirement intended that neighboring Balancing Authorities use uniform line identifiers when
communicating information about their tie lines. This requirement drops that clarification and
introduces the additional requirement to use pre-determined “equipment” identifiers. Having to
mutually agree in advance on identifiers for every switch & transformer is another example of a
prescriptive requirement whose violation will not affect system reliability, yet will expose entities to
large fines.
Agree
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators,
not the industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the
RCIS. If the RCIS is not functioning and the hotline is used instead, is the entity vulnerable to a
violation by virtue of the fact that these alert guides are included in the standard? We believe that
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the color-coded system condition terminology should be defined/required externally to the COM
standards. The use of clear & consistent alert level terminology, while important, does not fit in well
with the reliability-related communication standards, especially at these high violation severity
levels. It is our suggestion that the Alert Level Guides be balloted separately, and include the Energy
Emergency Alerts (EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.1
Disagree
No, we are not aware of any regional variances.
Agree
We do see a potential conflict with the Energy Policy Act of 2005, which set the framework for the
Electric Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of
the Bulk Electric System. This standard seems to cross the line between reliability-related activities
and other types of operating actions. The concern here is that system operators will focus on the
letter of the standard rather than on good operating practice. The fear of a violation among
operators may have a greater impact on reliability than the violation itself.
Agree
This review group has identified several problems with this standard, as noted above. Other
observations include: The effective dates in the draft standard and in the implementation plan do
not seem to match. In the standard, the effective date mentions one calendar year following
regulatory approval, while the implementation plan refers to the third calendar quarter after
regulatory approval. Furthermore, we do not feel that any of the requirements in this standard
warrant Violation Risk Factors or Violation Severity Levels in the high or severe category. In
summary, this review group feels that COM-003-1 is not yet ready to be acted upon and may have
been posted too soon. There does not seem to be sufficient coordination between the drafting teams
of all the COM standards, or any attempt to integrate these standards. One example is the
inconsistency between COM-003-1 and COM-002-3 regarding the meaning of three-part
communication (mentioned in our response to Question 1 above). As noted above, we feel that
many of the requirements prescribe specific “how to” methods for compliance rather than focusing
on the “what” of the requirement. Overall, COM-003-1 is much too prescriptive to be tied to million
dollar-level fines. “The comments expressed herein represent a consensus of the views of the named
members of the SERC OC&SOS Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”
Individual
Jonathan Appelbaum
Long Island Power Authority
Disagree
LIPA disagrees with the definition for Three-Part Communication. LIPA prefers the process offered in
COM-002-03 (draft). In COM-003 the listener must understand the communication the first time.
Failure to understand and repeat back correctly could be a violation of the requirement. The intent
three part communication is to have an iterative process whereby the person issuing the message is
ultimately satisfied that the recipient understands the information and will perform the required
action. It should not be defined as three steps and only three steps. LIPA offers the following
definition: A Real-Time Operating Communications Protocol where information is verbally stated by a
party initiating a communication, the information is repeated back to the party that initiated the
communication by the second party that received the communication, and the information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it. LIPA disagrees with the
definition of Interoperability Communication. LIPA believes the Standard is addressing the
communication of the Operating State of BES equipment and facilities. The proposed definition
utilizes the phrase “change the state … of a BES facility” which can be interpreted as the position,
e.g. open, close, tap position, etc… thereby extending this Standard into routine switching and
operation of the BES. The SAR stated this Standard was “to use specific communications protocols
under normal, abnormal and emergency conditions to relay critical reliability-related information in a
timely and effective manner”. The proposed definition can be interpreted in a manner that extends
this to all reliability related information for every BES operation. The drafting team should also
consider adding a definition for Directive or acknowledge the definition in draft Com-002-03.
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Agree
Disagree
LIPA agrees with the need for CPOP but does not agree that R4 can or should apply to all
interoperability communications between entities. Since the examples in Attachment 1 specifically
state RC and TOP, this standard should not apply to any other entity except for the RC and TOP.
COM-002-03(draft) could require the other entities to utilize three part communication for reliabilityrelated Interoperability communication.
Disagree
LIPA believes the use of “shall” and “all” coupled with the broad applicability of this Standard and
the broad definition of Interoperability Communication will result in entities either not complying
with R2 or making statements regarding the Operating Alert State when unnecessary. Attachment
1-Com-003 is very prescriptive in the use pre-defined terminology, colors and levels, and what to
report on. There is no benefit to specifying the specific terminology. This requirement should require
the RC to define the terms/levels/alert states to include within the CPOP that sufficiently
communicate the increased levels of Alert or Response encountered/required. Many entities have
invested time and training in the existing processes that meet the intent of this requirement. Read
strictly, the only predefined alert conditions are Physical security, Cyber security and Transmission
Security as it applies to the RC and TOP only. LIPA notes that R2 in the draft Standard does not
match R2 in this question. Specifically the word ALL is not in the Standard.
Disagree
This requirement will burden those entities whose operations and communication needs are with
other entities in the same time zone, which represents the overwhelming majority of all
communications performed. It will increase the likelihood of errors for such entities. Further, some
entities are operating both NERC BES elements and non-BES elements from the same control room.
This requirement will significantly impact the efficiency and the safety of workers within those
entities. LIPA notes that R4 in the draft Standard does not match R2 in this question. Specifically the
word ALL is not in the Standard.
Disagree
The SDT should define Directive. Draft Com-002 -3 has a similar requirement to identify a directive
and then utilize three-part communication. Also Com-002-3 Three part communication differs from
the description of Three-part communication in this Standard. LIPA prefers Com-002-3 usage of the
word “intent” in the repeat back. Also see comments to Question 1.
Disagree
While LIPA understands the benefit of utilizing a phonetic alphabet, we question the designation of a
specific phonetic alphabet. This prescriptive requirement may result in absurd non-compliance
reports, such as, using “Dog” for “D” instead of “Delta”. R6 requires the use of the alphabet when
issuing information, but not in the repeat back step. This may be an oversight. Also Does the RC in
its communication utilize the abbreviation for the threat type, e.g PSEA, or does the RC use the
NATO-Alphabet? If NATO, then the example in Attachment 1 should state this need.
Agree
LIPA notes that R7 in the draft Standard does not match R2 in this question. Specifically the word
ALL is not in the Standard.
Agree
In addition to the response to Question 4, LIPA does not understand why there are Levels and color
designations since only the threat level numeral is being communicated. Attachment 1-Com-003 is
very prescriptive in the use pre-defined terminology, colors and levels. There is no benefit to
specifying the specific terminology. Requiring system Operators to state Colors and Levels would
seem to result in slower and more confused communication.
Disagree
Agree
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R1 requires each entity to create a CPOP. There is not a requirement to coordinate CPOP’s amongst
entities beyond the requirements in the Standard. There is no requirement to exchange CPOP’s
between entities with an operating relationship. The SDT should consider adding a requirement
either that allows entities with operating relationships to request and be provided a copy of the
other’s CPOP, or a requirement requiring the exchange of CPOP between entities with operating
relationships. Additionally, we cannot understand how all requirements but R1 have been
determined to have a HIGH VRF when, many of them are dictating HOW communications should
take place and not when and why or what. High Risk Factor requirement (a) is one that, if violated,
could directly cause or contribute to bulk power system instability, separation, or a cascading
sequence of failures, or could place the bulk power system at an unacceptable risk of instability,
separation, or cascading failures. LIPA does not believe that any requirement in this Standard if
violated would have the results specified in the definition of a High VRF, especially since these
requirements are addressing the HOW of communication.
Group
Pacific Northwest Small Utilities Comment Group
Margaret Ryan
Disagree
Communication protocols extend beyond the verbal and written versions. How does the “nonroutable (communication) protocol” of CIP-006 fit into or not fit into these definitions?
Our utilities agree with the move in principle, but are concerned about the transition. How will NERC
ensure that registered entities are not doubly jeopardized during the time when the same
requirement exists in two active standards? The addition of LSE to COM-003 goes way beyond the
obligations in TOP-002-2 R18; LSE’s are now in every requirement of COM-003.
Disagree
DPs and LSEs are in general users, not owners or operators of interconnected BES equipment per
the registry criteria. DPs and LSEs should be removed from this requirement since LSEs typically do
not own or operate the interconnected BES equipment
Disagree
The referenced attachment appears to list alert levels for RCs to use in communicating threats to
BAs, DPs, GOs, TOPs and TOs. This requirement should apply only to RCs.
Disagree
While our utilities agree that understanding the actual time is important, stating the time zone and
summer offset (13:34 PDT) should suffice. As an alternative, UTC might be used since it is clearly
distinguishable from local time in all of NERC. As in R1, LSEs and DPs should be removed from this
Requirement.
Disagree
Per TOP-001 and IRO-001, only TOs and RCs have the authority to issue reliability directives (per
the proposed definition of interoperability communications, such directives would qualify as
reliability directives). All other entity types should be removed from this requirement. As in Q2, the
transition is a concern. Unless the effective date of COM-003-1 is the same as the date of retirement
of COM-002; there will either be a reliability gap where neither active standard requires three-part
communication, or there will be a situation where an entity could be doubly jeopardized for a single
event. Three-part communication is worthless unless the recipient understands what he/she is
parroting and is authorized to take action. For example, many DPs/LSEs do not maintain 24/7
dispatch desks and an afterhours call may go to an answering service. Three-part communication
with the answering service operator will only delay the requested action. The entity issuing the
directive should be required to ensure their employee reaches someone authorized to take action
before delivering the directive via Three-part communication.
Agree
No Comment
Disagree
DPs and LSEs are typically users, not owners or operators of interconnected BES equipment per the
registry criteria. DPs and LSEs should be removed from this requirement.
Disagree
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Agree
(This is a yes or no questions) Yes, The RC in the WECC region has no communication with any
entity other than the sixteen listed in
http://www.bpa.gov/corporate/business/reliability/Docs/2007/PNSC_RE_Data_Letter_2_070723.pdf.
Although the linked document is on PNSC letterhead, WECC as RC continues this policy.
Communication paths involving the RC and any other entity in the west other than the sixteen
should be exempt from all the requirements in this standard. If DPs and LSEs must be included in
this standard, then there should be an agreement in force beforehand between them and their RC,
BA and TOP that they may receive directives, or require the RC, BA and TOP to list those DPs and
LSEs that would not receive directives.
Agree
(This is a Yes or No Questions) Yes, see our comments to Q2.
Agree
(This is a Yes or No Questions) The proposed standard seems to have just thrown everyone into the
pot, and not considered how registered entities interact with the BES or what other standard
requirements apply to them. We can not lose sight of the original objective of, not only ERO
Compliance, but the “purpose” described in regards to the development of this standard (Posted as
background information on Project 2007-02). The stated purpose is, “To ensure that reliabilityrelated information is conveyed effectively, accurately, consistently, and timely to ensure mutual
understanding by all key parties, especially during alerts and emergencies.” With this said, The BA’s,
TOP’s and RC’s are the key registered entities that have the power to take action, they are the key
players in the communication of information which “impacts” the BES. We fail to see the value
added by including DP’s and LSE in most of the requirements of this standard. If anything, we see
the opposite affect taking place by adding DP & LSE’s. This may be an extra tier of unnecessary
communication that would not only slow down this process, but just may contribute to greater
inefficiencies. Please note that many DP & LSE in the WECC region are very small utilities that do
not have 24 by 7 coverage.
Individual
Richard Appel
Sunflower Electric Power Corp.
Disagree
I feel the use of the NATO phonetic alphabet is over kill. You should use a phonetic alphaber that is
in common use in the USA
Agree
Agree
Agree
Agree
Agree
Disagree
I don't feel we should use NATO phonetic alphabet. Use something in common use in the USA
Agree
Use a Phonetic alphabet in common use in the USA
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Individual
Kevin Koloini
American Municipal Power
Agree
Please define "directive" as a term.
Agree
Disagree
A written CPOP will place an unnecessary burden on smaller entities without an increase in reliable
communications. I feel that the other requirements are somewhat self-explanatory and that an
annual review of the phonetics and three-part communications would improve reliability more than
having a written CPOP requirement.
Agree
Eliminating lax communications and improving identifiers is one of the cheapest and easiest ways to
improve reliability.
Disagree
In other large industries one time zone is usually picked, and the time zone that is usually picked is
the EST zone (JP Morgan Chase is an example). I feel that picking a standard time zone is very
important, but I have not seen significantly good arguments to use CST. EST, on the other hand, is
where the majority of the load for the electric industry resides. I suggest changing the standard to
EST but with the 24 hour format.
Agree
I feel that there needs to be a way to verify what has been said. Three-part Communications
accomplish the verification that may be required as a result of the communication medium. If a
better method is developed I propose that it be used.
Agree
The NATO Phonetic alphabet is easy to learn and use. Most people can learn it on their own much
faster than it will take the SDT to read all of the comments for COM-003.
Agree
How many substations have the same name? Unique identifiers easily and inexpensively eliminate
confusion and errors.
Agree
Agree
Agree
Agree
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
Disagree
Clarification must be made to the definition "Interoperability Communication" and to the specific
applicability of the term as it translates into the actions and functions both internal and external to
the local TO.
Agree
Disagree
R4 - Use of the CST time format would present challenges affecting hardware, software, and training
in the ECC and is counter to practices of scheduling, switching execution, and time-stamping of
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activities currently executed by the ECC. A more defined definition of “Interoperability
Communications” needs to be instituted in conjunction with R4 applicability.
Agree
Disagree
Use of the CST time format would present significant challenges as expressed in the comments of
question #3 listed above.
Agree
Disagree
Agree
Disagree
Disagree
Not aware
Disagree
Not aware
Disagree
No additional Comments
Individual
Noman Williams
Sunflower Electric Power Corporation
Agree
Agree
Disagree
We believe that distribution providers (electric cooperatives) should be removed from this standard
unless they control a BES segement
Agree
As defined in Attachment 1 - COM-003-1
Agree
General question will time follow central prevailing time (standard/daylight savings)?
Agree
Agree
Agree
Agree
Disagree
Disagree
Disagree
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Individual
Mark Ringhausen
Old Dominion Electric Cooperative
Disagree
Comments: We believe that it may be important for entities registered as a Reliability Coordinator,
Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission
Service Provider , Load Serving Entity and Distribution Provider to have a formalized
Communications Protocol Operating Procedure (CPOP) for Interoperability Communications, but this
requirement will place an unnecessary burden on the personnel at many of the smaller Load Serving
Entities and Distribution Providers on the NERC Compliance Registry. In most real-time scenarios,
the BES facilities are not operated nor maintained by the Load Serving Entity or Distribution
Provider. As with many standards, entities will be required to demonstrate why the
standard/requirement is applicable. We suggest the drafting team consider modifying the
applicability of this standard as follows similar to the format used in PRC-OO5: 4. Applicability: 4.1.
Transmission Operator 4.2. Transmission Owner 4.3. Balancing Authority 4.4. Reliability Coordinator
4.5. Generator Operator 4.6. Distribution Provider that is responsible for Real-time generation
control and Real-time operation of the interconnected Bulk Electric System 4.7. Transmission
Service Provider 4.8. Load Serving Entity that is responsible for Real-time generation control and
Real-time operation of the interconnected Bulk Electric System
Disagree
Comments: We believe that it may be important for entities registered as a Reliability Coordinator,
Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission
Service Provider , Load Serving Entity and Distribution Provider to have a formalized
Communications Protocol Operating Procedure (CPOP) for Interoperability Communications, but this
requirement will place an unnecessary burden on the personnel at many of the smaller Load Serving
Entities and Distribution Providers on the NERC Compliance Registry. In most real-time scenarios,
the BES facilities are not operated nor maintained by the Load Serving Entity or Distribution
Provider. As with many standards, entities will be required to demonstrate why the
standard/requirement is applicable. We suggest the drafting team consider modifying the
applicability of this standard as follows similar to the format used in PRC-OO5: 4. Applicability: 4.1.
Transmission Operator 4.2. Transmission Owner 4.3. Balancing Authority 4.4. Reliability Coordinator
4.5. Generator Operator 4.6. Distribution Provider that is responsible for Real-time generation
control and Real-time operation of the interconnected Bulk Electric System 4.7. Transmission
Service Provider 4.8. Load Serving Entity that is responsible for Real-time generation control and
Real-time operation of the interconnected Bulk Electric System
Agree
Agree
Agree
Agree
Agree
Individual
Misty Revenew
Westar Energy
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Disagree
Would like to see the Interoperability Communication definition be more specific.
Agree
Disagree
While I agree that a CPOP in necessary and should include the elements of the requirements, I am
not sold on all of the requirements yet as written.
Agree
Agree
Agree
Disagree
One of the more common or ad-hoc phonetic alphabets which are easier to remember could be a
better fit since these communications happen infrequently. Having operators potentially struggle to
remember the NATO phonetic alphabet during communications rather than focus on the
communication itself is in contradiction with the stated purpose of the standard.
Agree
Agree
no suggestions
Agree
not aware
Agree
not aware
Agree
no additional comments
Group
ExxonMobil Research and Engineering
Martin Kaufman
Agree
Agree
Disagree
While recording telephone conversations may be routine for utility companies, many industrial
facilities that fall under the jurisdiction of this standard do not currently have the facilities necessary
to record the conversations and store them for an extended length of time. If a company does not
currently possess the capability to record telephone conversations, is it the intent of this standard to
require them to install such facilities? If so, what is the time frame surrounding the installation of
the facilities necessary to record and store telephone conversations? Currently, we maintain a log of
our communications which includes the question or instruction and our (or in the case of a question
the third party’s) response. Does this satisfy the requirements for evidence as defined in measures
M2 through M7?
Agree
Agree
Agree
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Agree
Agree
Disagree
We have no concerns or suggestions for improvement.
Disagree
We are not aware of any regional variances that would be required as a result of this standard.
Disagree
We are not aware of any conflicts.
Agree
Compliance paragraph 1.4 bullet 2 implies that all entities retain 3 months worth of telephone voice
recordings through its use of the word ‘and’ in the statement “Distribution Provider shall retain for
Requirement 2 through 7, Measure 2 through 7, dated operator logs for the most recent 12 months
and voice recordings or transcripts of voice recordings for the most recent 3 months”. While many
utility companies employ the use of voice recorders, many industrial facilities do not. When a facility
does not currently employ the use of voice recorders, is it the intent of this document to require the
facility to install the infrastructure necessary to record and store telephone conversations? If so,
what is the time line for deploying the infrastructure necessary to record and store telephone
converstations? Currently, we maintain a log of our communications which includes the question or
instruction and our (or in the case of a question the third party’s) response. Does this satisfy the
evidence criteria as defined in measures M2 through M7 of the proposed standard?
Individual
Bob Casey
Georgia Transmission Corp
Disagree
The definition of Interoperability Communication is very broad and has no real benefit.
Agree
Disagree
This is a requirement for an operating procedure which is redundant and would require the entities
to document how they met the requirement.
Disagree
Should only include physical security emergency, cyber security emergency, or transmission
emergency as stated in Attachment 1 instead of Interoperability Communications.
Agree
Disagree
replace “directive during verbal Interoperability Communications” with “Reliability Directive”. replace
"Each Responsible Entity" with "TOPs & RCs". The other entities listed in the draft standard under
Applicability do not issue Reliability Directives.
Disagree
This is an operational burden and could easily cause a violation by using a different common
identifier. If used, it should only apply to Reliability Directives.
Agree
Agree
Disagree
Disagree
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Disagree
Individual
Tracy Sliman - System Operations Compliance
Tri-State Generation & Transmission Assoc.
Disagree
The term directive is not defined therefore it is unclear what constitutes a directive.
Disagree
LSE and TSP are not responsible for the reliability of the Bulk Electric System. That responsibility
resides with the TOP.
Disagree
DP, LSE and TSP are not responsible for the reliability of the Bulk Electric System. Also, attachment
1 explains Operating State Alert Levels that defines colors that are already in use by the Department
of Homeland Security. Re-using these colors presents confusion to the operators of the BES. This
places an unnecessary additional burden on Real Time day-to-day operations with a high risk of
confusion in an emergency.
Disagree
Attachment 1 explains Operating State Alert Levels that defines colors that are already in use by the
Department of Homeland Security. Re-using these colors presents confusion to the operators of the
BES. This places an unnecessary additional burden on Real Time day-to-day operations with a high
risk of confusion in an emergency. Additionally, this is too complicated and requires a complete
retraining of operators in the English language.
Disagree
We have been operating within our individual time zones for many years without incident. Modifying
the time zone to which we operate will pose additional confusion and add unnecessary risk in
operating the BES.
Disagree
Directive is not defined. This would require issuing a directive for each and every verbal
communication between entities, even those that pose no risk to the BES, which is not necessary.
Disagree
Directive is not defined. This poses an undue burden on the operators, which does not improve the
reliability of the BES. NERC should only concern themselves with issues related to maintaining the
reliability of the BES.
Disagree
This is not NERC’s responsibility to define. There are too many lines and too much equipment to
identify each as a NERC definition. Definitions are already agreed upon between operating entities.
Agree
The Operating State Alert Levels can be confused with DHS security levels. DSPs should not be
included because they are not subject to BES standards because they do not operate the BES, that
responsibility resides with the TOP. The title Distribution Service Providers should be changed to
Distribution Provider to correlate with the NERC functional model. Under Additional Communication
the posting of the alert level should be determined by each entities internal procedure and not
included in this standard. This attachment is too invasive and restrictive.
Disagree
Disagree
Agree
This standard should not apply to DPs, LSEs or TSPs as they do not have control over the BES. That
responsibility resides entirely with the TOP. Additionally, it is concerning that the term “directive” is
not defined. The proposed definition for Interoperability Communication could be interpreted to
include all communication between entities. This is too restrictive.
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Individual
Joe O'Brien
NIPSCO
Agree
When COM-002-3 is fully incorporated, more definitions such as Reliability Directive will need to be
added.
Agree
Agree
Disagree
This may not be necessary.
Agree
I believe we call this "system time" in our area
Disagree
It's not clear whether this is limited to emergency situations. In the Purpose section of this standard
the line "especially during alerts and emergencies" seems rather vague. When does this standard
exactly apply?
Disagree
This should not be a requirement, but could be a suggested option. If one were recorded using the
wrong phonetic would that be a compliance violation? This doesn't seem reasonable.
Disagree
This question includes a mis-statement in quotes. This is not what the requirement says.
Furthermore, the word "Neighboring" was removed from the TOP-002 R18 which changes the
meaning and intent of the requirement. Why not bring in R18 verbatim?
Disagree
No comment
Disagree
none
Disagree
none
Disagree
This standard is based on COM-002-3 however that standard has not been voted-in or NERC
approved yet. I think this COM-003 effort should be put on hold until the 2006-06 project is
complete. At that time the term "directive" should be replaced by "Operational Directive" and
"Reliability Directive" based on context and all of these terms should be defined in the NERC
Glossary of Terms.
Individual
Joe Knight
Great River Energy
Disagree
GRE believes the proposed definition for the term Interoperability Communication is too broad and
ambiguous. We recommend the following instead: Communication between two or more Functional
Entities to exchange reliability-related information to be used by the entities to change the state or
status of Facilities of the Bulk Electric System. The inclusion of the terms Functional Entities and
Facilities removes the ambiguity which we believe is contained in the proposed definition. (Both of
these terms are defined in NERC’s Glossary) The way the definition of Three-part Communication is
worded applies only when the communication is understood by the listener the first time. Because
the definition requires the listener to repeat the information back correctly, failure of the listener to
understand the information the first time could be construed as a violation or at least not fitting the
definition. The definition should rather reflect that three-part communication is an iterative process
that should be followed until the listener is confirmed by the speaker to get the information correct.
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We suggest the definition be revised as follows: A Communications Protocol where information is
verbally stated by a party initiating a communication, the information is repeated back correctly to
the party that initiated the communication by the second party that received the communication,
and the same information is verbally confirmed to be correct or corrected by the party who initiated
the communication. The protocol should be followed until the party issuing the information is
satisfied that a party receiving the information has understood the communication and confirmed it.
GRE believes there should be a definition added for Reliability Directive to ensure consistency across
the defined projects for standards development. The Drafting Team working on Project 2006-06 has
defined Reliability Directive as: A communication initiated by a Reliability Coordinator, Transmission
Operator or Balancing Authority where action by the recipient is necessary to address an actual or
expected Emergency. GRE recommends use of this definition and the term Reliability Directive as
opposed to Directive.
Disagree
TOP-002_R18 is fundamentally different from the new proposed requirement in COM-003-1_R7.
TOP-002 R18 states that the BA, TOP, GOP TSP and LSE shall use uniform line identifiers when
referring to transmission facilities of an interconnected network. COM-003-1_R7 states that each RC,
BA, TO, TOP, GOP, TSP, LSE and DP shall use PRE-DETERMINED, MUTUALLY AGREED UPON line and
equipment identifiers for verbal and written Interoperability Communications. GRE believes the TOP002_R18 could be included in COM-003-1 but included as stated verbatim in TOP-002.
Disagree
The NERC BOT has approved pursuing the Performance-based Reliability Standard Task Force’s
recommendations to assess the existing standards, modify and develop standards that support
reliability performance and risk management, and work on an overall plan to transition existing
standards to a new set of standards. One goal of this effort is to eliminate administrative
requirements. This proposal takes the opposite approach and incorporates a new administrative
requirement. GRE does not support such an approach. GRE suggests deleting this Requirement from
the Standard.
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Many RC communications are issued to multiple parties using blast
communication systems such as the RCIS. Several of the listed entities such as Distribution
Providers and Generator Operators cannot have access to these systems due FERC standards of
conduct requirements. Attachment 1 and R2 are not consistent with the definition of Interoperability
Communications. By definition, Interoperability Communication pertains to all communications about
how entities change the state of the BES (not just about physical or cyber attacks). Attachment 1 is
only about notifying of what physical and cyber attacks and transmission emergencies have already
happened to the BES.
Disagree
There is no reliability need to use a common time zone for communications. The prevailing time
zone should be used to avoid confusion between operating staff and field personnel. Use of CST will
actually cause confusion with no foreseeable reliability benefit.
Disagree
Without defining directive the SDT is leaving the industry in the same situation we are currently in.
As discussed in the response to Question #1 above, it is GRE’s opinion that the definition of
Reliability Directive must be developed and included in the discussion of this standard. The term
directive should be as defined in Project 2006-06: A communication initiated by a Reliability
Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.. GRE believes it should be left to the entity
that needs the action to be taken to establish the need for three-part communications by stating in
the communication that they are issuing a directive. This would be a clear trigger and easily
auditable and measureable.
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so
necessary to be enforceable through enforceable requirements. The NATO phonetic alphabet does
not allow for the use of numbers ten and beyond. An entity WOULD be found non compliant for
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saying OPEN SWITCH FOURTEEN BRAVO. GRE does not believe this is reasonable as it adds nothing
to the reliability of the BES. It is too prescriptive and all encompassing and could potentially confuse
or slow down the communication process especially in an emergency situation.
Disagree
See comments for Question 2
Disagree
Disagree
Agree
GRE believes that the existing standard COM-002 is actually better than this standard. This standard
actually causes more confusion and ambiguity and creates unnecessary or overly cumbersome
requirements that add little or no value to reliability.
Individual
Fred Meyer
The Empire District Electric Company
Disagree
Replace the proposed COM-003-1 definition of "Thee-part Communication with what is used here:
Three Part Communication: A communications protocol to be used when a Reliability Directive is
initiated verbally, whereby the action to be takein is identified as a Reliability Directive; the recipient
repeat the details of the Reliability Directive back to the issuer of the Reliability Directive; and the
issuer acknowledges the response from the recipient of the Reliability Directive as correct, or reissues the Reliability Directive to resolve any misunderstanding.
Disagree
A more efficient method of designation common pre-determined line and equipment identifiers
would be through the Reliability Coordinator. Having the Reliability Coordinator establish this would
create a single methodology as opposed to several different methodologies that would have to be
agreed upon between entities and a significant amount of work for all entities.
Disagree
What benefit to the BES would this provide? Rather I see more confusion by having entities develop
different CPOPs. How will this benefit real time operations? This seems to be a requirement by NERC
to assist NERC in anaylysis "after the fact" of an event, but in reality it can hinder daily operations.
Disagree
This attachment is not needed. It is a duplicate of the NERC Alert process that is already established
as well as CIP-001 Sabotage reporting requirement R2 along with requirements of EOP-001 R5 and
EOP-004 R2 dealing with disturbance reporting. The last thing the industry needs is more paperwork
requirements that are redundant when an emergency event happens on the system.
Disagree
In dealing in real time, what possible benefit can be had by this requirement? I see this requirement
benefitting NERC analysis after the fact and can lead to more operating mistakes in real time than it
benefits. If a situation is occuring in real time and two entities are in communication with each
other, the requirement of a common time zone holds no benefit.
Disagree
When and why would a GO, TSP or LSE ever issue a directive? Directives are given by RC's. Use the
definition of Third Party Communications provided earlier in this comment form.
Disagree
The NATO phonetic alphabet is too descriptive as a requirement. A common phonetic alphabet
where both parties understand the communication should be a better requirement and left up to the
parties in communication with each other as common across the USA.
Disagree
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I would suggest a more efficient method of desinating common pre-determined line and equipment
indetifiers through the Reliability Coordinator. As similar to the response earlier. A definition of
"Equipment" is needed as well.
Disagree
Again this attachment is redundant to the NERC Alert process.
Agree
NO
Disagree
Disagree
This proposed standard seems to be a redundant standard to many other already approved NERC
standards such as CIP-001, EOP-001, EOP-004, as well as the NERC alert process. I see little to no
benefit from this standard as proposed.
Individual
Ed Davis
Entergy Services
Disagree
The definition for Three-part communication is deficient when compared with the requirements of
the recently posted COM-002-3 which describes an interative process in which the communicating
party corrects the recipient in the situation where the repeated message contains inconsistencies.
The party receiving the message will not always get the message right the first time. Also, Entergy
does not believe that the introduction of the term Interoperability Communications is necessary. In
the questions below, we identify specific ways that the requirements could be improved by including
the term Reliability Directive as included in the recently posted COM-002-3. The term
Interoperability Communications is very broad, covering both normal and emergency
communications, creates a new category of communications without providing any real benefit to
the industry.
Disagree
TSP and LSE are not typically included in real-time communications and should not be included in
this requirement. The intent this requirement in TOP-002-2 pertained to communications between
neighboring BAs and TOPs. Adding LSE and TSP to this requirement doesn’t make sense, and this
change should not be made.
Disagree
Interoperability communications should be removed as recommended in our response to question 1.
Creating requirements for the communications protocol will by necessity require entities to
document how they meet the requirements. A requirement for an operating procedure is redundant.
The requirement to have an operating procedure in effect makes this a “how” requirement. An entity
could choose to have more than one procedure that described their communications protocol. This
requirement as written could force an entity to put all of their communications procedures into one
CPOP, which doesn’t improve reliability. Therefore the requirement is not needed and should not be
included in the standard.
Disagree
Term Interoperability Communications should be removed from the standard. As written, the actions
that fall into interoperability communications are much broader than the set of conditions described
in the table in attachment 1. To the extent that the communications are outside of the ones in the
table, entities will be non-compliant because their communications are not pre-defined. Recommend
that this requirement be changed to indicate that “Any Reliability Coordinator or Transmission
Operator experiencing a physical security emergency, cyber security emergency, or transmission
emergency will communicate their status using the conditions and processes in Attachment 1.”
Disagree
This is also a “how” requirement and not a “what” requirement. If the industry believes that
confusion exists pertaining to what time zone different entities are referring to in written and verbal
communications, the requirement should be focused on ensuring clear communication of time zone
information is included in verbal and written communication. Forcing entities to change to any one
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time zone will impose significant effort and expense without a measurable improvement in reliability.
However, Entergy is not aware that reliability issues have occurred as a result of entities
communicating in written or verbal format in different time zones. Entergy proposes that this
requirement be removed from the standard.
Disagree
Should be rewritten to say that “Each Responsible Entity shall use Three-part Communications when
issuing a Reliability Directive.” This should use the definition of Reliability Directive as proposed in
project 2006-06. Entergy recommends not including the definition of Interoperability
Communications in this standard or in the R5 Requirement. Also, the list of responsible entities
listed in the requirement R5 are not all able to issue Reliability Directives. So this requirement
should be limited to Reliability Coordinators, Balancing Authorities and Transmission Operators, who
can issue Reliability Directives.
Disagree
Entergy has 2 concerns with this requirement as written. First, the use of the NATO phonetic
alphabet is overly prescriptive to convey alpha-numeric information. For instance, if I use the word
“baker” instead of “bravo” in my communications, I would have still successfully communicated the
letter “B” to the person receiving my communication. My communication may have supported
reliable interconnected operations. However, according to this requirement, I would still have
violated the standard. Second, the requirement as written is very broad, applying not just to
directives, but also to “notifications, directions, instructions, orders and other reliability related
operating information”. These terms are not defined, so I would assume that this covers Reliability
Directives, and everything else. If the industry supports using a phonetic alphabet, it should be
limited just to directives containing alpha-numeric information. Again, the requirement to use the
NATO phonetic alphabet imposes a significant operational burden, creates a human error trap for
operating personnel, and does not improve reliability. It should not be included in the new standard.
Disagree
The requirement as it was written in TOP-002-2 pertained to communication between neighbors for
shared lines and facilities. That intent has been lost in this version of the requirement. Also a term
“equipment identifiers” has been added, but it is not clear what additional equipment is covered by
this requirement, or what reliability concern is being addressed by these changes. Entergy
recommends that this requirement be changed to be similar to the language that exists in TOP-0022 R18 “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use pre-determined mutually agreed
upon line identifiers when referring to transmission facilities of an interconnected network.”
Agree
As written, the actions that fall into interoperability communications in requirement 2 are much
broader than the set of conditions described in the table in attachment 1. To the extent that the
communications are outside of the ones in the table, entities will be non-compliant because their
communications are not pre-defined. Recommend that requirement 2 be changed to indicate that
“Any Reliability Coordinator or Transmission Operator experiencing a physical security emergency,
cyber security emergency, or transmission emergency will communicate their status using the
conditions and processes in Attachment 1.”
Disagree
Disagree
Disagree
Group
NRECA RTF Members
Patti Metro
Disagree
Comments: We agree with the new terms for inclusion in the NERC Glossary. We are somewhat
concerned that in this version of the draft standard there was no definition for “directive” included.
We do understand that the term “directive” is no longer capitalized in this version of the standard,
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
therefore, not required to be included in the NERC Glossary. Since several requirements of this draft
standard require certain actions when a “directive” is issued, the term should be defined. It is
necessary to define the term “directive” to ensure that just normal conversations between entities
are not later “interpreted” to be a “directive”.
Agree
Yes, we believe that the use of pre-determined, mutually agreed upon line and equipment identifiers
for verbal and written Interoperability Communications enhances the reliable operation of the BES.
Disagree
We believe that it may be important for entities registered as a Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service
Provider , Load Serving Entity and Distribution Provider to have a formalized Communications
Protocol Operating Procedure (CPOP) for Interoperability Communications, but this requirement will
place an unnecessary burden on the personnel at many of the smaller Load Serving Entities and
Distribution Providers on the NERC Compliance Registry. In most real-time scenarios, the BES
facilities are not operated nor maintained by the Load Serving Entity or Distribution Provider. As with
many standards, entities will be required to demonstrate why the standard/requirement is
applicable. We suggest the drafting team consider modifying the applicability of this standard as
follows similar to the format used in PRC-OO5: 4. Applicability: 4.1. Transmission Operator 4.2.
Transmission Owner 4.3. Balancing Authority 4.4. Reliability Coordinator 4.5. Generator Operator
4.6. Distribution Provider that is responsible for Real-time generation control and Real-time
operation of the interconnected Bulk Electric System 4.7. Transmission Service Provider 4.8. Load
Serving Entity that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
Agree
We believe there is a need to use pre-defined system condition terminology and the ones provided
in the attachment are easy to understand.
Disagree
We believe that adding the Central Time zone requirement for all verbal and written Interoperability
Communications is unnecessary. For these type of activities there should already be accurate time
stamps from equipment such as RTUs, EMS systems etc… for record keeping and documentation
activities. In the future, with the implementation of Smart Grid technologies, time stamping will be
included in the developed platforms for such technology, therefore, reducing the much of the time
stamping errors. Because many of the actions required for Interoperability Communications, are
completed by field personnel this requirement is onerous. It could potentially impact reliability since
the field personnel might be more focused on documenting the correct time zone, for compliance to
the requirement and the potential impact for non-compliance, than completing the required task
safely and accurately. If time-stamping is an issue in event analysis, it might be more appropriate
that Central Standard Time be utilized by recording devices such as RTUs, EMS systems etc… not for
the actual verbal and written communications. In addition, how will daylight savings time be
addressed in the proposed requirement of this standard?
Disagree
We agree that Three-part communication is a more accurate form of communication for issuing and
responding to a Directive during verbal Interoperability Communications and should remain as a
requirement of this standard. However since the term “directive” has not been defined it is unclear
when Three-part communication is required.
Disagree
We agree that using the NATO phonetic alphabet is a more accurate form of communication for
issuing and responding to a directive during verbal Interoperability Communications. However, other
forms of phonetic alphabet communications could be utilized to achieve the same results and
entities should not be forced to use only the NATO phonetic alphabet. As stated in question 6 we are
concerned about the undefined term “directive”. In addition to the NATO alphabet, did the drafting
team consider including the 10-Code system many utilities use for verbal communication (ex: 104)? If not, why not and if so, why not included?
Agree
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We agree using pre-determined, mutually agreed upon line and equipment identifiers during for all
verbal and written Interoperability Communications is a more accurate form of communication and
should remain as a requirement of this standard.
Agree
POSSIBLE FRCC VARIENCE - FRCC appears to have developed a communication protocol in which
“any or all conversations on the phone is considered a directive. If this case, we suggest that the
drafting team review the FRCC approach and determine if a regional variance should be included in
this standard or consider utilizing the FRCC approach for clearly defining the term “directive” for
inclusion in the NERC Glossary.
We recommend replacing the term “Distribution Service Providers” in Attachment 1 with the term
“Distribution Provider” as stated in the Applicability of this standard. In addition, please see our
response to Question 3 regarding a modification to the Applicability portion of the standard to
address concerns about the inclusion of Distribution Providers and Load Serving Entities. We are
concerned with the onerous communication requirements for Load Serving Entities and Distribution
Providers with field personnel that have rare or possibly no opportunities to communicate with
personnel working at an entity registered as a Transmission Operator, Transmission Owner,
Balancing Authority, Reliability Coordinator, Generator Operator or Transmission Service Provider.
Individual
Gordon Rawlings
British Columbia Transmission Corporation
Agree
Agree
Disagree
BCTC agrees with R1, R2, R3, R5 and R7 but strongly objects to R4 and R6. As a majority of the
Interoperability Communications is within our time zone the is no advantage in using Central
Standard Time as this will only make the communications more difficult as both parties are required
to change time, R4 is unreasonable. R6 requiring the use of North American Treaty Organization
(NATO) phonetic alphabet adds no value and will only cause confusion presently an instruction would
be issued as: “At Kelly Lake open 5CB4” R6 it will now become “At Kelly Lake open Fife Charlie
Bravo Fow-er”
Agree
Disagree
BCTC's position: as a majority of the Interoperability Communications is within our time zone there
is no advantage in using Central Standard Time as this will only make the communications more
difficult as both parties are required to change time, R4 is unreasonable.
Agree
Disagree
BCTC's position: R6 requiring the use of North American Treaty Organization (NATO) phonetic
alphabet adds no value and will only cause confusion. Presently an instruction would be issued
as:“At Kelly Lake open 5CB4” R6 it will now become: “At Kelly Lake open Fife Charlie Bravo Fow-er"
Agree
Agree
Should a move to a standard time be required then the move should be to Universal Time
Disagree
Disagree
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Disagree
Group
PJM
Mike Bryson
Disagree
We feel that the definition of Interoperability Communication is much too broad and is inconsistent
with the effort to develop results-based standards which would have a measurable and observable
effect on the reliability of the bulk electric system. The definition of Interoperability Communication,
as written, can include virtually any information exchange/instruction between entities, both routine
and emergency. Such communication may or may not have a measurable and observable effect on
bulk system reliability. Since the broad term Interoperability Communication is used in every
requirement in COM-003-1, entities will be required to use the English language, the central time
zone, and 3-part communication in even the most routine exchanges of information. This could
create a burden on operating personnel and a distraction from their reliability duties. This group
does not feel the need for a definition of Interoperability Communication, since the term Reliability
Directive has been defined in draft standard COM-002-3, which is currently posted for review. The
Reliability Directive term is emergency-focused and consistent with the results-based standards
process. In addition, the definition of Three-part Communication in this standard does not match the
three-part communication requirements stated in COM-002-3. In COM-002-3, the requirements for
three-part communication (state – repeat - acknowledge) apply to Reliability Directives, while in
COM-003-1 the definition of Three-part Communication refers to “information” in general. If, as
stated in the Disposition of Requirements, the revisions to COM-002-3 will be moved to COM-003-1,
the definition of Three-part Communication in this draft standard should be consistent with the
requirements of COM-002-3. The way the definition of Three-part Communication is worded applies
only when the communication is understood by the listener the first time. Because the definition
requires the listener to repeat the information back correctly, failure of the listener to understand
the information the first time could be construed as a violation or at least not fitting the definition.
The definition should rather reflect that three-part communication is an iterative process that should
be followed until the listener is confirmed by the speaker to get the information correct. We suggest
the definition be revised as follows: “A Communications Protocol where information is verbally stated
by a party initiating a communication, the information is repeated back correctly to the party that
initiated the communication by the second party that received the communication, and the same
information is verbally confirmed to be correct or corrected by the party who initiated the
communication. The protocol should be followed until the party issuing the information is satisfied
that a party receiving the information has understood the communication and confirmed it.” Both
element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to
be capitalized.
Disagree
Requirement R7, regarding the use of pre-determined line & equipment identifiers, applies to TSPs &
LSEs. However, the other requirements of this standard do not seem to apply to these entities. For
instance, most of the reliability-related alerts are communicated through the Reliability Coordinator
Information System (RCIS). TSPs do not have access to this real-time communication tool, so the
TSP should not be included in the applicability for the entire standard. Furthermore, Requirement
R18 in TOP-002-2 mandated that neighboring Balancing Authorities use the uniform line identifiers.
In COM-003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring
BAs. This requirement represents a “how” and not a “what”. In general, standards should be focused
on “what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and comprehended.
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
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actual and anticipated emergency conditions. We feel that there should not be a requirement in the
standard to have a “procedure”. It is our understanding that, to be auditably compliant with a
standard, the responsible entity must develop a procedure, train on that procedure, and be able to
demonstrate compliance via documents, data, logs, records, etc. If Requirements R2 – R7 are
included in this standard, the entity will need to develop a procedure to be compliant. In other
words, the procedure itself will become the focus rather than the actual communications protocol.
Therefore, we feel that requirement R1 is redundant and should not be included. The NERC BOT has
approved pursuing the Performance-based Reliability Standard Task Force’s recommendations to
assess the existing standards, modify and develop standards that support reliability performance
and risk management, and work on an overall plan to transition existing standards to a new set of
standards. One goal of this effort is to delineate actionable reliability requirements from
record/documentation requirements. This proposal takes the opposite approach and incorporates a
new administrative requirement. We – and the industry as a whole based on the response to the
Task Force – do not support such an approach. We suggest deleting this Requirement from the
Standard. Futhermore, the establishment of R2-R7 as elements of the CPOP required in R1 appears
to contradict the recent shift in direction that NERC has taken regarding defining criteria as bullets
under a requirement. See NERC’s August 10th informational filing regarding assignment of violation
risk factors and violation severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9000, and RR07-10-000 Furthermore, R2 appears to define Interoperability Communications for
attachment 1 communications only. Is this the intent of the drafting team?
Disagree
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliabilityrelated communications. Both the Reliability Directive and Interoperability Communication, as
currently defined, require some emergency action or change of equipment status. Yet the Alert Level
Guides were intended for announcement, not actions. Further, the “pre-defined” system conditions
and alert levels are too detailed and overly prescriptive. System operators need to spend time
looking for the right color and level to communicate the prevailing system condition terminology to
avoid violating the standard. This task does not lend itself to promptly and effectively deal with the
emergency situation. We also do not feel that these Alert Level Guides apply to all the responsible
entities identified under Applicability in the draft standard – for example, TSPs and LSEs are not
included in the list of notifications. The requirement to use the central time zone for logging the time
of an alert is problematic in that all communication tools, such as the RCIS, will need to be revamped. We question whether there will be a measurable reliability benefit by doing so. There is
also some redundancy in the Alert Level Guides – for example, the CIP-001 standard requires
notification of sabotage events – it should not be repeated in this standard. This also needs to be
reconciled with EOP-004 and CIP-001 and the SAR formed to address those redundancies. It is not
clear what value there is in identifying alert levels. There does not appear to be any differentiation in
actions taken based on the alert levels. Why not just state the number of substations attacked, etc?
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the
state of the BES and Attachment 1 is about notifying of what already happened to the BES.
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should
be that entities operating in different time zones agree on how to best eliminate any confusion
regarding the time difference. Entities that routinely operate in different time zones already have an
effective system for dealing with time differences. There seems to be no incentive to change a
system that already works quite well, and the cost of updating computer systems could prove
prohibitive. This group feels that mandating a common time zone across all of North America can
only lead to confusion and increased reliability issues.
Disagree
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should
be used in place of Interoperability Communication, since the directive is specific to emergency
operations. The requirement should read: “Each responsible entity shall use Three-part
Communication when issuing a Reliability Directive”. In addition, this requirement should apply only
to entities which issue reliability directives - BAs, TOPs & RCs. The other entities listed in the draft
standard under Applicability do not issue Reliability Directives.
Disagree
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Use of the NATO phonetic alphabet should be considered a “best practice” and should not be
included as a requirement in a reliability standard. One failure, such as saying “Baker” instead of
“Bravo”, results in a severe violation without any impact on system reliability. This group is
concerned that operating personnel will be focused on using the correct word rather than managing
the power system. Also, many organizations may have established communications protocols which
are functioning properly and making a change may actually hinder reliable operations by introducing
unnecessary confusion.
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original
requirement intended that neighboring Balancing Authorities use uniform line identifiers when
communicating information about their tie lines. This requirement drops that clarification and
introduces the additional requirement to use pre-determined “equipment” identifiers. Having to
mutually agree in advance on identifiers for every switch & transformer is another example of a
prescriptive requirement whose violation will not affect system reliability, yet will expose entities to
large fines. The key question is: “Do the companies’ personnel understand one another?”
Agree
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators,
not the industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the
RCIS. If the RCIS is not functioning and the hotline is used instead, is the entity vulnerable to a
violation by virtue of the fact that these alert guides are included in the standard? We believe that
the color-coded system condition terminology should be defined/required externally to the COM
standards. The use of clear & consistent alert level terminology, while important, does not fit in well
with the reliability-related communication standards, especially at these high violation severity
levels. It is our suggestion that the Alert Level Guides be balloted separately, and include the Energy
Emergency Alerts (EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.1 It
is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads,
“The time frame for declaration of these Alert states shall be consistent with the approach used to
declare EEAs and would normally apply to Real Time declarations and not forecast conditions.” In
Transmission Emergency Alerts Condition Yellow, Orange and RED: The Reliability Coordinator or
Transmission Operator foresees or is experiencing conditions where all available generation
resources are committed to respect the IROL and/or is concerned about its ability to respect the
IROL. Forsees is a forecast condition. In condition Orange and Red for TEA Level Two/Three, the
initial notification requirements are redundant with IRO-006-East-1 R3.2. Under the Make Final
Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in operations
generally means cuts for schedules/tags. EEA’s use terminated. We recommend using terminated.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional
Model.
Disagree
Many RC communications are issued to multiple parties using blast communication systems such as
the RCIS. Several of the parties such as Distribution Provider and Generation Operator cannot have
access to these systems due FERC standards of conduct requirements. Requirement 2 and the listing
of functional entities required to be notified within the RC footprint in attachment 1 create a de facto
requirement for them to have RCIS access or an unnecessary burden to communicate with all
functional entities listed separately. Having to communicate to all functional entities in that list
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
verbally and individually would create an unnecessary burden that distracts the RC from actual
system operation and represents a detriment to reliability.
Agree
We do see a potential conflict with the Energy Policy Act 2005, which set the framework for the
Electric Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of
the Bulk Electric System. This standard seems to cross the line between reliability-related activities
and other types of operating actions which may be better suited for NAESB action. The concern here
is that system operators will focus on the letter of the standard rather than on good operating
practice. The fear of a violation among operators may have a greater impact on reliability than the
violation itself. In some market structures, TSPs and LSE do not own or operate equipment. Thus,
including them in the requirements is an unnecessary burden for these areas. The requirement to
use CST attempts to determine HOW entities operate within their various footprints and it would
significantly change the way many Markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We
believe that, when operating across time-zones, simply referencing “Central Standard Time” or
“Eastern Standard Time” is sufficient for other operating entities to reliably operate; also, let’s not
lose sight of HOW MANY entities would have to modify their existing practices, hardware, software,
Control System, billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Agree
We have identified several problems with this standard, as noted above. Other observations include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In
the standard, the effective date mentions one calendar year following regulatory approval, while the
implementation plan refers to the third calendar quarter after regulatory approval. Furthermore, we
do not feel that any of the requirements in this standard warrant Violation Risk Factors or Violation
Severity Levels in the high or severe category. In summary, this review group feels that COM-003-1
is not yet ready to be acted upon and may have been posted too soon. There does not seem to be
sufficient coordination between the drafting teams of all the COM standards, or any attempt to
integrate these standards. One example is the inconsistency between COM-003-1 and COM-002-3
regarding the meaning of three-part communication (mentioned in our response to Question 1
above). Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for
extending three-part communications. We believe the title of Recommendation 26 is misleading and
when reviewed separately from the supporting text of the recommendation and direct and
contributing factors in the report results in an incorrect interpretation. “Failure to identify emergency
conditions and communicate that status to neighboring systems” is one of the contributing factors
and the supporting text of the recommendation clearly refer to shoring up communications during
emergency and anticipated emergency conditions and establishing an emergency broadcast
communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some
have incorrectly inferred the initial clause of Recommendation 26, “Tighten communication
protocols”, means the recommendation applies to all routine communications. As noted above, we
feel that many of the requirements prescribe specific “how to” methods for compliance rather than
focusing on the “what” of the requirement. Overall, COM-003-1 is much too prescriptive to be tied to
million dollar-level fines.
Group
PJM SOS Comments
Mike Bryson
Disagree
We feel that the definition of Interoperability Communication is much too broad and is inconsistent
with the effort to develop results-based standards which would have a measurable and observable
effect on the reliability of the bulk electric system. The definition of Interoperability Communication,
as written, can include virtually any information exchange/instruction between entities, both routine
and emergency. Such communication may or may not have a measurable and observable effect on
bulk system reliability. Since the broad term Interoperability Communication is used in every
requirement in COM-003-1, entities will be required to use the English language, the central time
zone, and 3-part communication in even the most routine exchanges of information. This could
create a burden on operating personnel and a distraction from their reliability duties. This group
does not feel the need for a definition of Interoperability Communication, since the term Reliability
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Directive has been defined in draft standard COM-002-3, which is currently posted for review. The
Reliability Directive term is emergency-focused and consistent with the results-based standards
process. In addition, the definition of Three-part Communication in this standard does not match the
three-part communication requirements stated in COM-002-3. In COM-002-3, the requirements for
three-part communication (state – repeat - acknowledge) apply to Reliability Directives, while in
COM-003-1 the definition of Three-part Communication refers to “information” in general. If, as
stated in the Disposition of Requirements, the revisions to COM-002-3 will be moved to COM-003-1,
the definition of Three-part Communication in this draft standard should be consistent with the
requirements of COM-002-3. The way the definition of Three-part Communication is worded applies
only when the communication is understood by the listener the first time. Because the definition
requires the listener to repeat the information back correctly, failure of the listener to understand
the information the first time could be construed as a violation or at least not fitting the definition.
The definition should rather reflect that three-part communication is an iterative process that should
be followed until the listener is confirmed by the speaker to get the information correct. We suggest
the definition be revised as follows: “A Communications Protocol where information is verbally stated
by a party initiating a communication, the information is repeated back to the party that initiated the
communication by the second party that received the communication, and the information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it.” Both element and facility are
used in the Interoperability Communication definition and are NERC defined terms. Did the drafting
team intend that the NERC definitions should apply? Then the terms need to be capitalized.
Disagree
Requirement R7, regarding the use of pre-determined line & equipment identifiers, applies to TSPs &
LSEs. However, the other requirements of this standard do not seem to apply to these entities. For
instance, most of the reliability-related alerts are communicated through the Reliability Coordinator
Information System (RCIS). TSPs do not have access to this real-time communication tool, so the
TSP should not be included in the applicability for the entire standard. Furthermore, Requirement
R18 in TOP-002-2 mandated that neighboring Balancing Authorities use the uniform line identifiers.
In COM-003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring
BAs. This requirement represents a “how” and not a “what”. In general, standards should be focused
on “what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and comprehended.
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
actual and anticipated emergency conditions. We feel that there should not be a requirement in the
standard to have a “procedure”. It is our understanding that, to be auditably compliant with a
standard, the responsible entity must develop a procedure, train on that procedure, and be able to
demonstrate compliance via documents, data, logs, records, etc. If Requirements R2 – R7 are
included in this standard, the entity will need to develop a procedure to be compliant. In other
words, the procedure itself will become the focus rather than the actual communications protocol.
Therefore, we feel that requirement R1 is redundant and should not be included. The NERC BOT has
approved pursuing the Performance-based Reliability Standard Task Force’s recommendations to
assess the existing standards, modify and develop standards that support reliability performance
and risk management, and work on an overall plan to transition existing standards to a new set of
standards. One goal of this effort is to delineate actionable reliability requirements from
record/documentation requirements. This proposal takes the opposite approach and incorporates a
new administrative requirement. We – and the industry as a whole based on the response to the
Task Force – do not support such an approach. We suggest deleting this Requirement from the
Standard. Futhermore, the establishment of R2-R7 as elements of the CPOP required in R1 appears
to contradict the recent shift in direction that NERC has taken regarding defining criteria as bullets
under a requirement. See NERC’s August 10th informational filing regarding assignment of violation
risk factors and violation severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9000, and RR07-10-000 Furthermore, R2 appears to define Interoperability Communications for
attachment 1 communications only. Is this the intent of the drafting team?
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Disagree
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliabilityrelated communications. Both the Reliability Directive and Interoperability Communication, as
currently defined, require some emergency action or change of equipment status. Yet the Alert Level
Guides were intended for announcement, not actions. Further, the “pre-defined” system conditions
and alert levels are too detailed and overly prescriptive. System operators need to spend time
looking for the right color and level to communicate the prevailing system condition terminology to
avoid violating the standard. This task does not lend itself to promptly and effectively deal with the
emergency situation. We also do not feel that these Alert Level Guides apply to all the responsible
entities identified under Applicability in the draft standard – for example, TSPs and LSEs are not
included in the list of notifications. The requirement to use the central time zone for logging the time
of an alert is problematic in that all communication tools, such as the RCIS, will need to be revamped. We question whether there will be a measurable reliability benefit by doing so. There is
also some redundancy in the Alert Level Guides – for example, the CIP-001 standard requires
notification of sabotage events – it should not be repeated in this standard. This also needs to be
reconciled with EOP-004 and CIP-001 and the SAR formed to address those redundancies. It is not
clear what value there is in identifying alert levels. There does not appear to be any differentiation in
actions taken based on the alert levels. Why not just state the number of substations attacked, etc?
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the
state of the BES and Attachment 1 is about notifying of what already happened to the BES.
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should
be that entities operating in different time zones agree on how to best eliminate any confusion
regarding the time difference. Entities that routinely operate in different time zones already have an
effective system for dealing with time differences. There seems to be no incentive to change a
system that already works quite well, and the cost of updating computer systems could prove
prohibitive. This group feels that mandating a common time zone across all of North America can
only lead to confusion and increased reliability issues.
Disagree
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should
be used in place of Interoperability Communication, since the directive is specific to emergency
operations. The requirement should read: “Each responsible entity shall use Three-part
Communication when issuing a Reliability Directive”. In addition, this requirement should apply only
to entities which issue reliability directives - BAs, TOPs & RCs. The other entities listed in the draft
standard under Applicability do not issue Reliability Directives.
Disagree
Use of the NATO phonetic alphabet should be considered a “best practice” and should not be
included as a requirement in a reliability standard. One failure, such as saying “Baker” instead of
“Bravo”, results in a severe violation without any impact on system reliability. This group is
concerned that operating personnel will be focused on using the correct word rather than managing
the power system. Also, many organizations may have established communications protocols which
are functioning properly and making a change may actually hinder reliable operations by introducing
unnecessary confusion.
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original
requirement intended that neighboring Balancing Authorities use uniform line identifiers when
communicating information about their tie lines. This requirement drops that clarification and
introduces the additional requirement to use pre-determined “equipment” identifiers. Having to
mutually agree in advance on identifiers for every switch & transformer is another example of a
prescriptive requirement whose violation will not affect system reliability, yet will expose entities to
large fines. The key question is: “Do the companies’ personnel understand one another?”
Agree
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators,
not the industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
RCIS. If the RCIS is not functioning and the hotline is used instead, is the entity vulnerable to a
violation by virtue of the fact that these alert guides are included in the standard? We believe that
the color-coded system condition terminology should be defined/required externally to the COM
standards. The use of clear & consistent alert level terminology, while important, does not fit in well
with the reliability-related communication standards, especially at these high violation severity
levels. It is our suggestion that the Alert Level Guides be balloted separately, and include the Energy
Emergency Alerts (EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.1 It
is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads,
“The time frame for declaration of these Alert states shall be consistent with the approach used to
declare EEAs and would normally apply to Real Time declarations and not forecast conditions.” In
Transmission Emergency Alerts Condition Yellow, Orange and RED: The Reliability Coordinator or
Transmission Operator foresees or is experiencing conditions where all available generation
resources are committed to respect the IROL and/or is concerned about its ability to respect the
IROL. Forsees is a forecast condition. In condition Orange and Red for TEA Level Two/Three, the
initial notification requirements are redundant with IRO-006-East-1 R3.2. Under the Make Final
Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in operations
generally means cuts for schedules/tags. EEA’s use terminated. We recommend using terminated.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional
Model.
Agree
Many RC communications are issued to multiple parties using blast communication systems such as
the RCIS. Several of the parties such as Distribution Provider and Generation Operator cannot have
access to these systems due FERC standards of conduct requirements. Requirement 2 and the listing
of functional entities required to be notified within the RC footprint in attachment 1 create a de facto
requirement for them to have RCIS access or an unnecessary burden to communicate with all
functional entities listed separately. Having to communicate to all functional entities in that list
verbally and individually would create an unnecessary burden that distracts the RC from actual
system operation and represents a detriment to reliability.
Agree
We do see a potential conflict with the Energy Policy Act 2005, which set the framework for the
Electric Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of
the Bulk Electric System. This standard seems to cross the line between reliability-related activities
and other types of operating actions which may be better suited for NAESB action. The concern here
is that system operators will focus on the letter of the standard rather than on good operating
practice. The fear of a violation among operators may have a greater impact on reliability than the
violation itself. In some market structures, TSPs and LSE do not own or operate equipment. Thus,
including them in the requirements is an unnecessary burden for these areas. The requirement to
use CST attempts to determine HOW entities operate within their various footprints and it would
significantly change the way many Markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We
believe that, when operating across time-zones, simply referencing “Central Standard Time” or
“Eastern Standard Time” is sufficient for other operating entities to reliably operate; also, let’s not
lose sight of HOW MANY entities would have to modify their existing practices, hardware, software,
Control System, billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Agree
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
We have identified several problems with this standard, as noted above. Other observations include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In
the standard, the effective date mentions one calendar year following regulatory approval, while the
implementation plan refers to the third calendar quarter after regulatory approval. Furthermore, we
do not feel that any of the requirements in this standard warrant Violation Risk Factors or Violation
Severity Levels in the high or severe category. In summary, this review group feels that COM-003-1
is not yet ready to be acted upon and may have been posted too soon. There does not seem to be
sufficient coordination between the drafting teams of all the COM standards, or any attempt to
integrate these standards. One example is the inconsistency between COM-003-1 and COM-002-3
regarding the meaning of three-part communication (mentioned in our response to Question 1
above). Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for
extending three-part communications. We believe the title of Recommendation 26 is misleading and
when reviewed separately from the supporting text of the recommendation and direct and
contributing factors in the report results in an incorrect interpretation. “Failure to identify emergency
conditions and communicate that status to neighboring systems” is one of the contributing factors
and the supporting text of the recommendation clearly refer to shoring up communications during
emergency and anticipated emergency conditions and establishing an emergency broadcast
communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some
have incorrectly inferred the initial clause of Recommendation 26, “Tighten communication
protocols”, means the recommendation applies to all routine communications. As noted above, we
feel that many of the requirements prescribe specific “how to” methods for compliance rather than
focusing on the “what” of the requirement. Overall, COM-003-1 is much too prescriptive to be tied to
million dollar-level fines.
Group
New York State Reliability Council
Robert Ganley
Disagree
Comments: NYSRC agrees with the definitions for Communication Protocol. NYSRC disagrees with
the definition for Three-Part Communication. NYSRC prefers the process offered in COM-002-03
(draft). In COM-003 the listener must understand the communication the first time. Failure to
understand and repeat back correctly could be a violation of the requirement. The intent three part
communication is to have an iterative process whereby the person issuing the message is ultimately
satisfied that the recipient understands the information and will perform the required action. It
should not be defined as three steps and only three steps. NYSRC offers the following definition: A
Real-Time Operating Communications Protocol where information is verbally stated by a party
initiating a communication, the information is repeated back to the party that initiated the
communication by the second party that received the communication, and the information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it. NYSRC disagrees with the
definition of Interoperability Communication. NYSRC believes the Standard is addressing the
communication of the Operating State of BES equipment and facilities. The proposed definition
utilizes the phrase “change the state … of a BES facility” which can be interpreted as the position,
e.g. open, close, tap position, etc… thereby extending this Standard into routine switching and
operation of the BES. The SAR stated this Standard was “to use specific communications protocols
under normal, abnormal and emergency conditions to relay critical reliability-related information in a
timely and effective manner”. The proposed definition can be interpreted in a manner that extends
this to all reliability related information for every BES operation. The drafting team should also
consider adding a definition for Directive or acknowledge the definition in draft Com-002-03.
Agree
Disagree
Comments: NYSRC agrees with the need for CPOP but does not agree that R4 can or should apply to
all interoperability communications between entities. Since the examples in Attachment 1 specifically
state RC and TOP, this standard should not apply to any other entity except for the RC and TOP.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COM-002-03(draft) could require the other entities to utilize three part communication for reliabilityrelated Interoperability communication.
Disagree
Comments: NYSRC believes the use of “shall” and “all” coupled with the broad applicability of this
Standard and the broad definition of Interoperability Communication will result in entities either not
complying with R2 or making statements regarding the Operating Alert State when unnecessary.
Attachment 1-Com-003 is very prescriptive in the use pre-defined terminology, colors and levels,
and what to report on. There is no benefit to specifying the specific terminology. This requirement
should require the RC to define the terms/levels/alert states to include within the CPOP that
sufficiently communicate the increased levels of Alert or Response encountered/required. Many
entities have invested time and training in the existing processes that meet the intent of this
requirement. Read strictly, the only predefined alert conditions are Physical security, Cyber security
and Transmission Security as it applies to the RC and TOP only. NYSRC notes that R2 in the draft
Standard does not match R2 in this question. Specifically the word ALL is not in the Standard.
Disagree
Comments: This requirement will burden those entities whose operations and communication needs
are with other entities in the same time zone, which represents the overwhelming majority of all
communications performed. It will increase the likelihood of errors for such entities. Further, some
entities are operating both NERC BES elements and non-BES elements from the same control room.
This requirement will significantly impact the efficiency and the safety of workers within those
entities. NYSRC notes that R4 in the draft Standard does not match R2 in this question. Specifically
the word ALL is not in the Standard.
Disagree
Comments: The SDT should define Directive. Draft Com-002 -3 has a similar requirement to identify
a directive and then utilize three-part communication. Also Com-002-3 Three part communication
differs from the description of Three-part communication in this Standard. NYSRC prefers Com-0023 usage of the word “intent” in the repeat back. Also see comments to Question 1.
Disagree
Comments: While NYSRC understands the benefit of utilizing a phonetic alphabet, we question the
designation of a specific phonetic alphabet. This prescriptive requirement may result in absurd noncompliance reports, such as, using “Dog” for “D” instead of “Delta”. R6 requires the use of the
alphabet when issuing information, but not in the repeat back step. This may be an oversight. Also
Does the RC in its communication utilize the abbreviation for the threat type, e.g PSEA, or does the
RC use the NATO-Alphabet? If NATO, then the example in Attachment 1 should state this need.
Agree
Comments: NYSRC notes that R7 in the draft Standard does not match R2 in this question.
Specifically the word ALL is not in the Standard.
Agree
Comments: In addition to the response to Question 4, NYSRC does not understand why there are
Levels and color designations since only the threat level numeral is being communicated.
Attachment 1-Com-003 is very prescriptive in the use pre-defined terminology, colors and levels.
There is no benefit to specifying the specific terminology. Requiring system Operators to state Colors
and Levels would seem to result in slower and more confused communication.
Disagree
Agree
Comments: R1 requires each entity to create a CPOP. There is not a requirement to coordinate
CPOP’s amongst entities beyond the requirements in the Standard. There is no requirement to
exchange CPOP’s between entities with an operating relationship. The SDT should consider adding a
requirement either that allows entities with operating relationships to request and be provided a
copy of the other’s CPOP, or a requirement requiring the exchange of CPOP between entities with
operating relationships. Additionally, we cannot understand how all requirements but R1 have been
determined to have a HIGH VRF when, many of them are dictating HOW communications should
take place and not when and why or what. High Risk Factor requirement (a) is one that, if violated,
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could directly cause or contribute to bulk power system instability, separation, or a cascading
sequence of failures, or could place the bulk power system at an unacceptable risk of instability,
separation, or cascading failures. NYSRC does not believe that any requirement in this Standard if
violated would have the results specified in the definition of a High VRF, especially since these
requirements are addressing the HOW of communication.
Individual
Greg Rowland
Duke Energy
Disagree
When viewed in the context of its use in R5 and R6, the definition of Interoperability Communication
is excessively broad and unclear. R5 refers to the issuing of a “directive” during verbal
Interoperability Communications. The term “directive” is undefined. R6 requires the use of the NATO
phonetic alphabet during verbal Interoperability communications such as directives, notifications,
directions, instructions, orders or other reliability related operating information. This could
conceivably encompass all communications. Also, the definition refers to communications between
two or more “entities”. Does “entities” refer to functional entities or registered entities?
Disagree
We disagree with moving R18 into COM-003-1 and broadening it to include every line and piece of
equipment. This would create an enormous amount of effort to implement, and would substantially
increase compliance risk, without any increase in reliability. Furthermore, if R18 is moved into COM003-1, when would it be removed from TOP-002-2? Until R18 is actually removed from TOP-002-2,
entities would be subject to compliance double jeopardy.
Disagree
There is no need to have a CPOP to describe how an entity will comply with R2 through R7. A CPOP
would just be a restatement of the requirements. If an entity complies with R2 through R7, there’s
no reliability related benefit to having a CPOP.
Disagree
Attachment 1 is limited to notifications from the RC to other entities regarding Alerts for Physical
Security Emergency, Cyber Security Emergency or Transmission Emergency. Also, these types of
notifications wouldn’t meet the definition of “Interoperability Communications”, because they
wouldn’t necessarily be used to effect a change in the state or status of an element or facility of the
Bulk Electric System.
Disagree
We don’t agree with this requirement because it would introduce confusion into communications,
especially in all communications other than RC to RC. RC’s already have protocols in place to deal
with time zone differences, and changing that and applying it to all entities would create reliability
errors. We think that this is “a solution in search of a problem”.
Disagree
We believe that the term “directive” should be defined. This SDT should work with the COM-002 SDT
to come up with common phraseology and definition for the term “Directive”. Work on COM-003-1
should have begun by defining “directive”, and limiting the requirement to use 3-part
communications to “directives”, and not requiring it for general day-to-day communications. The
entity issuing a “directive” should inform the receiving entity that it is a directive and therefore
requires the use of 3-part communications.
Disagree
We believe that R6 should be deleted, because it is focused on the details of the “how” rather than
the “what” in communications. The key is accurate 3-part communications for “directives”, as
required by R5. R6 is far too broad in the communications that would be included. Also, we believe
that there is no reasonable way to implement, self-certify or audit compliance with this requirement.
Disagree
Delete this requirement. See our response to Question #2 above.
Agree
We support the development of this attachment, but question whether it belongs in this standard,
especially since it is under field trial. We think it belongs in the EOP standards. We note the
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Attachment 1 is only associated with notifications by the RC, so we question whether these are
Interoperability Communications as that term is defined. Also, the introduction on Attachment is
very confusing. Attachment 1 states that definitions for Transmission Loading, Physical and Cyber
Security Alert states align with the Emergency Energy Alert (EEA) states as already described in
Standard EOP-002-2.1. EOP-002-2.1 and associated EEA Levels provides guidance on Energy and
Capacity Emergencies rather than Transmission or Physical/Cyber Alerts. Energy Emergency is
defined as a condition when a LSE has exhausted all other options and can no longer provide its
customers’ expected energy requirements. This is a totally different classification of Emergency
Alert. We suggest deleting the 2nd and 3rd sentences of the introduction to Attachment 1. In
addition, Attachment 1 does not contain four system condition alerts, as the SDT has proposed.
Disagree
Disagree
Agree
As a general comment, all the requirements other than R1 are High VRFS with only Severe VSLs. As
this standard is written to apply broadly to routine as well as emergency communications between
entities, we believe that failure to meet these requirements would rarely impact the reliability of the
Bulk Electric System. For example if in routine switching an operator says “Baker” instead of
“Bravo”, the entity is subject to FERC’s most severe penalty. Clearly the basis for this standard
needs to be reassessed. If we use the test that if a requirement or a standard supports/encourages
reliability and security, then entities should invest the time and effort to track performance to
ensure auditable compliance. For example – Does DCS compliance support/encourage
reliability/security? The industry would generally say yes – so the tracking and determination of
auditable compliance is justified. But would auditable compliance to this draft of COM-003-1
support/encourage reliability/security? We don’t think so, given the vague and general nature of this
draft. It certainly would not justify the amount of work and effort it would take to ensure auditable
compliance with this COM-003-1 draft, given the amount of effort it would take to monitor all
recorded communications that fit within this vague draft standard. Bottom line is that we think COM003 is not needed. As proposed, it is a “how” and not a “what” based standard that will create more
distraction from reliability/security than any value it might add.
Individual
Frank Cumpton
Transmission System Operations
Disagree
The definition of “Interoperability Communication” is not clear. What does the term “reliabilityrelated” information entail? Does “Interoperability Communication” include instructions from a
control room to a generator to adjust vars, from the control room to field personnel to direct the
changing of transformer taps, from the control room to field personnel to implement switching
instructions, etc? What is the definition of “entity”? Does this mean if switching instructions are
given from a control room of one company to personnel in its own company (i.e., the same entity),
that the interaction would not be classified as “Interoperability Communication”?
Agree
Disagree
We believe the phrase, “but is not limited to” should be deleted. The elements required to be in the
CPOP should be well-defined.
Agree
Disagree
We believe that the use of Central Standard Time in non-CST areas would create confusion between
the Reliability Coordinator, Transmission Operator, Transmission Owner, Generator Operators, and
field personnel.
Disagree
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As stated in Question #1, the definition of “Interoperability Communication” needs further
clarification. Also, further clarification is needed as to when “Interoperability Communications” is
required to be used.
Disagree
As stated in Question #1, the definition of “Interoperability Communication” needs further
clarification. Directives, notifications, directions, instructions, orders, and other reliability operating
information needs to be clearly defined, including what it consists of and when it is to be utilized.
Agree
Agree
It should be made clear that Attachment 1 applies to the RC’s. It is not specifically stated in R2 that
it is the RC’s responsibility to make notifications. In Attachment 1, we believe the wording under
“Initial Notifications” should be changed. For example, on the 2nd row and 1st column of the matrix,
it states that the RC makes initial notification and states that “…there is a Physical Emergency Alert,
PSEA Level One within….” Nowhere is it ever mentioned that there is a “Condition Yellow”. Since it is
never mentioned by the RC in the notification that the Condition is “Yellow”, what is the use or
benefit of having the conditions? It should also be made clear that when the RC states, for example,
that “There is a Physical Security Emergency Alert-PSEA Level One within…” that this refers to
specific definitions given in Attachment 1 of EOP-002-2.1. This fact is mentioned at the top of the
matrix, but the wording of this explanation is not consistent with the wording used in the body of
the matrix.
Agree
Refer to Question #5; we do not agree with using Central Standard Time.
Disagree
Agree
We think the SDT should coordinate their work closely with the team of the Reliability Coordination
Project 2006-06, especially regarding new definitions related to communications and reliability
directives.
Group
We Energies
Howard Rulf
Disagree
Communications Protocol: This defined term appears only in the Three-part Communication
definition and in titles. Titles are expected to be capitalized and are not necessarily the defined term.
The COM-003-1 Standard title is “Operating Personnel Communications Protocols”, but the purpose
is not restricted to verbal and written information, so “Communications Protocol” does not seem to
refer to the defined term in this title. Similarly, it is not necessarily the defined term in CPOP. It is
not clear where this definition is being utilized in the standard. Three-Part Communication: Should
be required for “Reliability Directives” only. It seems that this is currently being addressed, and
could remain, in an updated version of COM-002-003. This should be coordinated between standards
and duplication should be avoided. Interoperability Communication: This definition is excessively
broad, and the terminology “reliability related information” is ambiguous and vague. Communication
is used elsewhere within the NERC Standards to include voice, data, email, memos, NERCnet, etc.
Since communication of any type may be used to change the “state or status” of the Bulk Electric
System, this definition seems to pertain to every communication in every form, which could be
interpreted to include market information which is continuously used to drive changes to the “state
or status”. By extension, a CPOP would need to include every communication of any type (voice,
data, email, memos, etc.), which is over-reaching and open to conflict with the CPOP’s developed
independently by other entities. Interoperability Communications should apply only to situations
covered in Attachment 1, and definitions should better reflect applicability to communications
between separate, distinct entities (not communications within the same organization).
Disagree
Because applicability to a TSP and LSE of this standard stems solely from TOP-002-2 R18, R7 should
be the only requirement that applies to a TSP or LSE.
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Disagree
It is not clear what the purpose of the CPOP is, or how having it would improve reliability of the Bulk
Electric System. This standard, (or alternatively COM-002-003) should focus on requiring Three-Part
Communication during Reliability Directives. In addition, the vague and broad nature of the existing
definition of Interoperability Communication makes creating CPOP’s problematic and open to conflict
with the CPOP’s developed independently by other entities. As noted in question 2, R1 should not
apply to a TSP or LSE.
Disagree
Attempting to mold all possible circumstantial situations into the pre-defined terminologies is overly
restrictive and may result in reduced accuracy, unnecessary confusion and misinterpretation. R2
should have the word “all” included (as is stated in this question) in order to restrict the applicability
of Interoperability Communications to only those situations defined in Attachment 1. As noted in
question 2, R2 should not apply to a TSP or LSE.
Disagree
If requiring one standard time zone, it would seem prudent to specify Greenwich Mean Time (GMT)
as a universal standard. That being said, solely utilizing Central Standard Time (CST), or even GMT,
as the common time zone may cause undue confusion given that MISO and PJM already operate
with established processes and systems that are inconsistent with this, and are based on their own
market timing. In addition, many plant personnel and procedures already have a long and engrained
history of successful operation under existing timing directions, which are not aligned with market
timing. Forcing every plant across multiple time zones to establish a new standard ignores the need
for cases of special consideration and historical circumstances. The potential confusion due to the
forced timing standard across many entities within a given area is too high a price to pay for the
possible clarity by a limited few due to the switch to CST. A preferred alternative would include
focusing the standard on requiring very clear communication of the time zone being specified for a
given Reliability Directive. Thus, compliance enforcement would only pertain to Reliability Directives.
Disagree
The term ”directive” should be replaced with the term “Reliability Directive” as defined by the
Drafting Team working on Project 2006-06 which states it as: “A communication initiated by a
Reliability Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency”. Three-part Communication should be
required (with regard to compliance) during emergency situations in which Reliability Directives are
being issued. This requirement should not apply to normal or non-emergency situations, and should
be enforceable between Functional Entities (distinct entities, not within a given organization). As
noted in question 2, R5 should not apply to a TSP or LSE.
Disagree
While R6 could be recommended as a good utility practice when communicating Reliability
Directives, it is not appropriate to enforce it as a requirement for all communications. The focus of
the standard should be on the achievement of clear communications, with individual organizations
retaining some freedom to implement practices appropriate for their own unique situations. If
Violation Severity Levels will be “high” as indicated in Attachment 1-COM-003-1, then the standard
must be much more specific as to what constitutes “directives, notifications, directions, instructions,
orders or other reliability operating information”. Assigning a high Violation Severity Level to the
failure to use a specific phonetic alphabet (NATO) instead of to a failure to use any phonetic
alphabet seems unreasonable and is likely to cause as much confusion as failing to use any sort of
phonetic pronunciation. If attachment 2 is utilized, it should only be required for situations where
Attachment 1 applies. As noted in question 2, R6 should not apply to a TSP or LSE.
Disagree
TOP-002-2 R18 requires uniform line identifiers. The wording of R7 and the statement by the SDT
that “the Requirement does not stipulate a single/unique identifier as long as all parties mutually
agree” is in conflict with TOP-002-2 R18. Allowing multiple line and equipment identifiers to be used
does not improve reliability or improve communications in an emergency. TOP-002-2 applies to
Transmission Facilities of an Interconnected Network…R7 should do the same for clarity. Having the
term ”mutually agreed upon” in a standard is unworkable, since it allows a non-cooperative party to
disrupt the genuine efforts of others and to exploit unfair leverage in discussions or negotiations. A
better approach is having the Transmission Owners develop identifiers for transmission, and
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Generation Operators develop identifiers for generation. The process should be defined such that
comments are solicited and input within a pre-specified convention, and then a specific entity is
given the ability to make the final determination. Again, R7 is more appropriate as a best practices
recommendation, rather than a requirement.
Agree
Attachment 1 is written for an RC. Usage of Attachment 1 by entities other than an RC should be
clarified.
Disagree
Agree
In general, establishing CST as a uniform time zone may conflict with individual Tariffs regarding
references to wholesale electric market commercial activities and could cause additional confusion if
commercial market time zone references are independent of reliability time zone references.
Agree
Remove “timely” from the Purpose section, since a time period is not part of any requirement.
According to the NERC Reliability Standards Development Procedure, Compliance Monitoring Period
and Reset are required elements, and should be included. M1 through M7 should indicate which
requirement they pertain to. Compliance enforcement should be focused on Reliability Directives
only. Rather than proving 100% compliance, it is more practical if each party is obligated to report
instances of unclear communication to the other party/parties involved in the Reliability Directive(s).
Defining a remediation plan could be part of the requirement, with a measure being whether or not
the remediation was implemented. An overall observation is that the intended communication
updates could be implemented through modification of existing COM-001 & COM-002 standards
without the need for another overlapping standard. Additional industry focus regarding
communication protocols could be further emphasized through NERC System Operation Certification
Program requirements and training.
Individual
Greg Mason
Dynegy
Disagree
The way the definition of “Three-part Communication” is worded applies only when the
communication is understood by the listener the first time. Because the definition requires the
listener to repeat the information back correctly, failure of the listener to understand the information
the first time could be construed as a violation or at least not fitting the definition. The definition
should rather reflect that three-part communication is an iterative process that should be followed
until the listener is confirmed by the speaker to get the information correct. We suggest the
definition be revised as follows: “A Communications Protocol where information is verbally stated by
a party initiating a communication, the information is repeated back correctly to the party that
initiated the communication by the second party that received the communication, and the same
information is verbally confirmed to be correct or corrected by the party who initiated the
communication. The protocol should be followed until the party issuing the information is satisfied
that a party receiving the information has understood the communication and confirmed it.” It
should also be noted that these principles are included in Requirements R2 and R3 in the recently
issued draft Standard COM-002-3 in Project 2006-06. This definition in this Standard is not needed.
We believe the term “Interoperability Communication” creates confusion within the industry and
contradicts the work by RTO and RC SDT in Project 2006-06 that limits the requirement to use
three-part communications when issuing Reliability Directives (defined in Project 2006-06) that
address anticipated and actual emergency conditions. Additionally, it appears that this definition
would encompass all verbal communications and, as such, would be a distraction to Operators.
Therefore, there is no reliability need for this definition. While using three-part communications
during routine operations may be a best operating practice, we do not believe that it is so critical to
reliability that it needs to become an enforceable requirement for routine operating instructions.
Rather we believe the enforceable requirement should be limited to require three-part
communications during actual emergency and anticipated emergency conditions only. Both element
and facility are used in the Interoperability Communication definition and are NERC defined terms.
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Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized. In addition, the term “entities” is confusing and needs to be defined.
Disagree
The SDT actually expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. In any
event, this Requirement represents a “how” and not a “what”. In general, standards should be
focused on “what” not how. The only real need for a requirement is to establish that each entity
issuing a directive shall use three-part communications and the recipient of a directive shall also
properly participate in the use of the three-part communication protocol until the message has been
correctly spoken and comprehended.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Performance-based Reliability Standard Task Force’s recommendations to assess the existing
standards, modify and develop standards that support reliability performance and risk management,
and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to eliminate administrative requirements. This proposed Requirement takes the
opposite approach and incorporates a new administrative requirement. We – and the industry as a
whole based on the response to the Task Force – do not support such an approach. We suggest
deleting this Requirement from the Standard.
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Many RC communications are issued to multiple parties using blast
communication systems such as the RCIS. Several of the listed entities such as Distribution Provider
and Generator Operator cannot have access to these systems due FERC standards of conduct
requirements. Attachment 1 and R2 are not consistent with the definition of Interoperability
Communications. By definition, Interoperability Communication pertains to all communications about
how entities change the state of the BES (not just about physical or cyber attacks). Attachment 1 is
only about notifying of what physical and cyber attacks have already happened to the BES .
Disagree
There is no reliability need to use a common time zone for communications. There is already a
requirement to use hour ending for scheduling purposes, inadvertent accounting, CPS and other
standards where needed. The time zone should be identified in the communication. Use of CST in all
time zones will actually cause confusion and significant and unnecessary costs with no foreseeable
reliability benefit. Some of the costs will arise to change systems such as RCIS, IDC, scheduling and
E-Tag systems, etc.
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part
communications is required to communicate routine operating instructions. We believe this
Requirement contradicts the work that has been done and substantially progressed through two
other SDTs and creates confusion within the industry. We believe this Requirement would, in fact, be
adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned
with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT in Project 2006-06 which would define a Reliability
Directive based on the determination of the person giving such an order. We believe, it should be
left to the entity that needs the action to be taken to establish the need for three-part
communications by stating in the communication that they are issuing a directive. This would be a
clear trigger and auditable and measureable. R5 is not consistent with the Functional Model. Only
the RC, BA, and TOP can issue directives.
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary
to be used in all verbal Interoperability Communications and is certainly not necessary to be
included as an enforceable Requirement. Imagine the situation in which an operator says “A as in
apple” instead of using the NATO Alpha. Even though the listener should clearly be able to discern
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the correct meaning, the speaker’s company could be sanctioned even if the correct actions were
taken as a result of the clear communication. There is no reliability need for this Requirement.
Disagree
This may represent a good utility practice but it is not necessary to be included as a Requirement.
The key question is: “Do the companies’ personnel understand one another?” If I know that my
company refers to a tie-line as Alpha and my neighboring company calls it Beta, I know what he
means when communicating to me. That is all that matters. This is a “how” based Requirement that
should be eliminated.
Disagree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional
Model.
Disagree
Disagree
Agree
We believe that the existing standard COM-002 is better than this proposed Standard. This Standard
actually causes more confusion and ambiguity and creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. Additionally, we cannot understand how all
requirements but R1 have been determined to have a HIGH VRF when, many of them are dictating
HOW communications should take place and not when and why or what. The stated retirement of
COM-002 does not appear to be consistent with the direction of the RC SDT in Project 2006-06. The
RC SDT is adding requirements. More coordination is certainly required between these two teams. In
addition, as stated earlier, this Standard focuses on “how” certain tasks should be performed and
conflicts with NERC’s position of pursuing performance based and results based Standards.
Individual
Dustin Smith
Washington City Light & Power
Disagree
Disagree
Disagree
We believe that it may be important for entities registered as a Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service
Provider , Load Serving Entity and Distribution Provider to have a formalized Communications
Protocol Operating Procedure (CPOP) for Interoperability Communications, but this requirement will
place an unnecessary burden on the personnel at many of the smaller Load Serving Entities and
Distribution Providers on the NERC Compliance Registry. In most real-time scenarios, the BES
facilities are not operated nor maintained by the Load Serving Entity or Distribution Provider. As with
many standards, entities will be required to demonstrate why the standard/requirement is
applicable.
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Individual
Kirit Shah
Ameren
Disagree
The definition for three part implies the exact message must be repeated back. What should be said
is the content must be repeated back in original or modified forms such that the originator is sure
the recipient understands and can execute the action. As far as Interoperability, what is state or
status? Is the dispatch instruction to change from 500 MW to 505 MW such a communication?
(which changed, state or status?)
Agree
Disagree
This is a near fill-in-the-blank requirement. The mere inclusion, or recitation, of the R2-7 elements
does not assure a meaningful plan. It is easy to say “Our plans includes R3”. That does not assure
reliable communications. This requirement should describe a functional CPOP.
Disagree
This is an ambiguous reference in all of NERC standards for all but the RC. How would an LSE
interpret this in communication between them and a DP. Would there ever be a red condition for
issues that affect them? And as it relates to operating, it looks like this is exclusive of EEA type
events, i.e. BA type emergencies seem to not be represented. It would seem that the pre-defined
conditions should be established for each interaction that each entity might have, e.g. a predefined
set for a BA to a TOP, a BA to an LSE, et al. While each entity can certainly address the 3 scenarios
in Attachment 1 (RC to entity) those are not the only conditions where communication affects BES
reliability.
Disagree
We agree that all inter-entity operability communication should be on common time zone but if said
communication includes routine dispatch instructions several RTOs use EST time for market
operations, would they then need to change to CST? And while CST seems to have some value
because it is used for time error, wouldn’t it make more sense to use UTC? It is a world standard
and has the benefit of not being associated with daylight savings times as Central time does (may
be confusion at some times between CST and CDT)
Agree
Disagree
Requirement should be revised to say that Attachment 2 needs to be used when single alphabetic
characters, or when needed for clarity, are needed in communications. If we have a Bee Hollow-51
circuit, that is alpha-numeric information. But we wouldn’t support that Bee Hollow needs to be
spelled out as Bravo-Echo-Echo-space-Hotel…….
Agree
But how does CMEP process check this “mutually agreed”. Much more work needs to be done with
this requirement and measures to address this.
Agree
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As stated earlier, this is an excellent document for RC interactions. But it is wholly unclear how this
impacts other entity-to-entity relationships in pre-defining states. And as mentioned having only
Attachment 1 seems to ignore the energy balance alerts/emergencies
We understand the binary function of VSL that forces Severe for most requirements. However, the
standard itself seems to offer some hope with the definition to address the VSL issue better. The
definition has at the end, “especially during alerts and emergencies” Given that this implies
stratification, couldn’t Severe VSL be assigned to violations during emergencies, High be assigned to
alerts, and moderate to all other system conditions. When emergency conditions exist, entities
should have their “A” game on, and failure to communicate during these times is a more severe
violation of the communication protocols than during the thousands of daily interactions that are
note likely to affect BES, (alternatively, the VRF could be adjusted for the situation)
Individual
Kathleen Goodman
ISO New England Inc.
Disagree
The way the definition of Three-part Communication is worded applies only when the communication
is understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could
be construed as a violation or at least not fitting the definition. The definition should rather reflect
that three-part communication is an iterative process that should be followed until the listener is
confirmed by the speaker to get the information correct. We suggest the definition be revised as
follows: A Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the
communication by the second party that received the communication, and the same information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it. We believe the term
“Interoperability Communication” contradicts the work by the RTO and RC SDT that limits the
requirement to use three-part communications to only those communications that explicitly state
that the communication is a Reliability Directive and creates confusion within the industry.
Additionally, it appears that this definition would encompass all verbal communications and, as such,
we question the need for such definition. While we support using three-part communications during
routine operations as a best operating practice, we do not believe that it is so critical to reliability
that it becomes an enforceable requirement for routine operating instructions. Rather we believe the
enforceable requirement should be left to the entity that needs the action to be taken to establish
the need for three-part communications by stating in the communication that they are issuing a
directive. This would be a clear trigger and auditable and measureable.
Disagree
This requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and comprehended.
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Performance-based Reliability Standard Task Force’s recommendations to assess the existing
standards, modify and develop standards that support reliability performance and risk management,
and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to delineate actionable reliability requirements from record/documentation
requirements. This proposal takes the opposite approach and incorporates a new administrative
requirement. We – and the industry as a whole based on the response to the Task Force – do not
support such an approach. We suggest deleting this Requirement from the Standard. Furthermore,
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the establishment of R2-R7 as elements of the CPOP required in R1 appears to contradict the recent
shift in direction that NERC has taken regarding defining criteria as bullets under a requirement. See
NERC’s August 10th informational filing regarding assignment of violation risk factors and violation
severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10-000.
COM-003 R2 states: “shall use pre-defined system condition terminology as defined in Attachment
1-COM-003-1 for verbal and written Interoperability Communications.” Why does R1 establish the
requirement for a procedure, when the procedure is essentially defined by R2-R7. If there is such a
reliability need to establish these requirements, one could conclude nothing else is so important that
it needs to be included because it is not identified in the standard. Furthermore, R2 appears to
define Interoperability Communications for attachment 1 communications only. Is this the intent of
the drafting team?
Disagree
It is not clear what value there is in identifying alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Further, the “pre-defined” system conditions and alert levels are too
detailed and overly prescriptive. System operators need to spend time looking for the right color and
level to communicate the prevailing system condition terminology to avoid violating the standard.
This task does not lend itself to promptly and effectively deal with the emergency situation. Many RC
communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to
these systems due FERC standards of conduct requirements. Attachment 1 and R2 do not appear to
be in synch primarily due to the definition of Interoperability Communications. By definition,
Interoperability Communication is about how entities change the state of the BES and Attachment 1
is about notifying of what already happened to the BES.
Disagree
There is no need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where
needed. There is no demonstrated benefit to reliability to use a common time zone. The time zone
should be identified in the communication. Use of CST will cause significant and unnecessary costs
and the resulting reliability benefit is not clear. Some of the costs will arise to change systems such
as RCIS, IDC, scheduling and E-Tag systems, etc. Not only does this requirement attempt to
determine HOW entities operate within their various footprints, it would significantly change the way
many markets are structured. To implement this into existing Markets would cost significant time,
money and resources while not enhancing reliability in these areas. We believe that, when operating
across time-zones, simply referencing “Central Standard Time” or “Eastern Standard Time” is
sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing
systems, bidding systems, etc. We, and our members, are strongly opposed to this requirement.
Disagree
Based on the definition of Interoperability Communications, R5 could imply that three-part
communications is required to communicate routine operating instructions. We believe this
Requirement contradicts the work that has been done and substantially progressed through two
other SDTs and creates confusion within the industry. We believe this Requirement would, in fact, be
adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned
with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT which would define a directive based on the
determination of the person giving such an order. We believe, it should be left to the entity that
needs the action to be taken to establish the need for three-part communications by stating in the
communication that they are issuing a directive. This would be a clear trigger and auditable and
measureable.
Disagree
Not only does this requirement attempt to determine HOW entities operate with their various
footprints, it may change the way many Markets are structured. What is the difference between
using the word “Zebra” instead of “Zulu” to signify the letter “Z”? And, why would this be
enforceable? Perhaps this would be better served as a guideline document rather than and
enforceable Requirement. Also, many organizations may have established communications protocols
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which are functioning properly and making a change may actually hinder reliable operations by
introducing unnecessary confusion.
Agree
We agree that the stipulation of a single/unique identifier is unnecessary as long as all parties
mutually agree on the identifier for the line or equipment, and therefore, support this change to the
existing Requirement in TOP-002.
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2. Also,
several entities have observed confusion during the field-test of these Alert Levels because there are
inconsistencies in the implementation of various stages of Alerts. It certainly has not enhanced
Reliability. Attachment 1 contains a conflict. The last sentence of the opening paragraph of
Attachment 1 reads, “The time frame for declaration of these Alert states shall be consistent with
the approach used to declare EEAs and would normally apply to Real Time declarations and not
forecast conditions.” In Transmission Emergency Alerts Condition Yellow, Orange and RED: The
Reliability Coordinator or Transmission Operator foresees or is experiencing conditions where all
available generation resources are committed to respect the IROL and/or is concerned about its
ability to respect the IROL. “Forsees” is a forecast condition. In condition Orange and Red for TEA
Level Two/Three, the initial notification requirements are redundant with IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term
Curtailed in operations generally means cuts for schedules/tags. EEA’s use terminated. We
recommend using terminated. Distribution Service Providers should be Distribution Provider to be
consistent with the Functional Model.
Agree
Many RC communications are issued to multiple parties using blast communication systems such as
the RCIS. Several of the parties such as Distribution Provider and Generation Operator cannot have
access to these systems due FERC standards of conduct requirements. Requirement 2 and the listing
of functional entities required to be notified within the RC footprint in attachment 1 create a de facto
requirement for them to have RCIS access or an unnecessary burden to communicate with all
functional entities listed separately. Having to communicate to all functional entities in that list
verbally and individually would create an unnecessary burden that distracts the RC from actual
system operation and represents a detriment to reliability.
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in
the requirements is an unnecessary burden for these areas. The requirement to use CST attempts to
determine HOW entities operate within their various footprints and it would significantly change the
way many Markets are structured. To implement this into existing Markets would cost significant
time, money and resources while not enhancing reliability in these areas. We believe that, when
operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW
MANY entities would have to modify their existing practices, hardware, software, Control System,
billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Agree
We believe that the existing standard COM-002 is actually better than this standard. This standard
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements
that add little or no value to reliability. Additionally, we cannot understand how all requirements but
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R1 have been determined to have a HIGH VRF when, many of them are dictating HOW
communications should take place and not when and why or what. COM-002 retirement does not
appear to be consistent with the direction of the RC SDT. The RC SDT appears to be adding
requirements. More coordination is requirement between these two teams. Recommendation 26 of
the August 14, 2003 blackout report is cited as a driver for extending three-part communications.
We believe the title of Recommendation 26 is misleading and when reviewed separately from the
supporting text of the recommendation and direct and contributing factors in the report results in an
incorrect interpretation. “Failure to identify emergency conditions and communicate that status to
neighboring systems” is one of the contributing factors and the supporting text of the
recommendation clearly refer to shoring up communications during emergency and anticipated
emergency conditions and establishing an emergency broadcast communication system to alert
regulatory, state and local officials. The supporting text of Recommendation 26 only mentions
addressing alerts, emergencies or other critical situations. Some have incorrectly inferred the initial
clause of Recommendation 26, “Tighten communication protocols”, means the recommendation
applies to all routine communications. Lastly, this on-line submittal asks many questions that are
YES/NO in nature (i.e. "do you have any concerns with...", or "if, yes, please explain...") but the
radial selections are "agree/disagree" which may be taken out of context. We suggest changing the
on-line submittal back to YES/NO.
Group
ATC and ITC
Jason Shaver
Disagree
ATC believes that the proposed definition for the term “Interoperability Communication” is too broad
and ambiguous. We recommend the following: “Communication between two or more Functional
Entities (not within the same organization) to exchange reliability-related information to be used by
the entities to change the state or status of Facilities of the Bulk Electric System.” The inclusion of
the terms “Functional Entities” and “Facilities” removes the ambiguity which we believe is contained
in the proposed definition. (Both of these terms are defined in NERC’s Glossary) In addition, the
inclusion of the phrase “not within the same organization” clarifies that the focus of definition is to
address communication between different Functional Entities. ATC understands that this Drafting
Team is working closely with the Drafting Team working on Project 2006-06 and believes that this
team needs to use the term “Reliability Directive” as a replacement for the term “directive” which is
currently being used. The Drafting Team working on Project 2006-06 has defined Reliability Directive
as: “A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing
Authority where action by the recipient is necessary to address an actual or expected Emergency.”
Disagree
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring
to transmission facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO,
TOP, GOP, TSP, LSE and DP shall use pre-determined, mutually agreed upon line and equipment
identifiers for verbal and written Interoperability Communications. TOP-002 allowed the TOP to
communicate what the line identifiers were via a list and use during communications. The new
requirement implies that the parties must agree upon the line identifiers and that agreement must
be documented. ATC believes that the requirement should state that “mutual agreement” allows for
multiple identifiers. We believe that this is needed in order to avoid the following issues. 1) This
clarification will avoid any need for arbitration or formal dispute resolution steps. 2) If the standard
does not allow for this provision entities will be forced to deviate from their own line naming
convention and will result in entities to modify their drawings, field signs, and SCADA systems.
Disagree
: Based upon the concerns that we have with R2-R7 we would not support this requirement. We
would support the requirement if it stopped after the first sentence and then merely listed the
minimum requirements that should be included in the Procedure such as; (1) time zone, (2)
language spoken, (3) when phonetic alphabet will be used, etc.. This will allow the Entities to draft
their own CPOP per the intent of the requirement and avoid the concerns that we have documented
for the remainder of the requirements.
Disagree
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The Attachment pertains to requirements of the RC, not all entities. Either the attachment should be
changed or the requirement should be changed for accurate accountabilities.
Disagree
ATC is in the Central Standard Time zone, and would not be directly impacted by this requirement.
With that being said we are concerned that forcing an organization to refer to a time zone that is not
local may result in an increase of errors and a decrease in reliability. See comments for question #3.
Disagree
ATC believes that the term “directive” should be replaced with the term “Reliability Directive” which
is being developed under Project 2006-06. It is important for BES reliability that NERC use clearly
defined term which will identify the circumstances under which this requirement is enforceable. We
provide the definition for “Reliability Directive”, as it appears in the latest posting for Project 200606, in our response to question 1. It is our understanding and interpretation that the intent of this
requirement is to require entities to use Three-Part Communication during emergency situations in
which “Reliability Directives” are being issued. In other words this requirement as proposed does not
apply to normal (non-emergency) day-to-day switching. The replacement of the term “directive”
with “Reliability Directive” provides the additional clarity around an entity’s compliance obligation.
Disagree
The use of the phonetic alphabet should be documented in the Entities CPOP per our comments to
question #3. We do not agree that it needs to be included in Requirement 5 because it is too
prescriptive and all encompassing and could potentially confuse or slow down the communication
process. As we recommended in question 6 the term “directive” should be replaced with “Reliability
Directive”.
Disagree
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring
to transmission facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO,
TOP, GOP, TSP, LSE and DP shall use pre-determined, mutually agreed upon line and equipment
identifiers for verbal and written Interoperability Communications. TOP-002 allowed the TOP to
communicate what the line identifiers were via a list and use during communications. The new
requirement implies that the parties must agree upon the line identifiers and that agreement must
be documented. ATC believes that the requirement should state that “mutual agreement” allows for
multiple identifiers. We believe that this is needed in order to avoid the following issues. 1) This
clarification will avoid any need for arbitration or formal dispute resolution steps. 2) If the standard
does not allow for this provision entities will be forced to deviate from their own line naming
convention and will result in entities to modify their drawings, field signs, and SCADA systems.
Disagree
See question #4.
Disagree
Disagree
Disagree
Group
FirstEnergy
Sam Ciccone
Disagree
Three-part Communication � The phrase "the information is repeated back correctly" may pose
compliance problems if the second party does not repeat the information back correctly the first
time. We suggest the definition be revised as follows: "A Communications Protocol where
information is verbally stated by one person to a second person whereby communication is initiated,
the second person repeats the information back to the first person as means to verify the
communication. The initiating party either confirms the response as correct or repeats the original
statement and resolves any misunderstandings." Interoperability Communication � We recommend
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this definition be removed and be incorporated into the RCSDT's proposed definition of Reliability
Directive. Please see our comments in Question 6 for a complete explanation.
Agree
Disagree
We feel that procedures are beneficial for entities to have as far as internal training of new
personnel and as a reference guide for all personnel, but we do not agree that it should be a
requirement of a reliability standard. It is not appropriate to subject an entity to monetary fines for
not having a procedure even if that entity has fully complied with all the other requirements (R2
through R7) of this standard that the procedure is referencing. Although this requirement may fall
into the category of best practices and administrative requirements, it certainly does not rise to the
level of performance-based, risk-based, or competency-based requirements. The real evidence of an
entity implementing R2 through R7 is by evaluating the measures of those requirements and a
variety of information could be used by an entity such as training records, procedures, voice
recordings etc. Having a procedure does not need to be a stand alone requirement.
Disagree
We do not support R2 and its referenced attachment and feel that they should be removed. The
requirement and attachment are too convoluted, create confusion among system operators, and not
necessary with regard to the goal of this standard. This standard mandates proper three-part
communication in all reliability-related communication (including alert level situations). Other
standards should define and mandate rules associated with the specifics surrounding urgent action
situations (i.e. CIP, TOP, EOP standards). Together these standards will arrive at proper
communication between entities during alerts.
Disagree
Using a specific time zone that is subject to adjustments for daylight savings introduces additional
complexity for an operator and has potential to introduce additional reliability issues. A significant
portion of the Eastern Interconnection transmission operators have dealings with entities that do not
span multiple time zones and are solely within the Eastern Time Zone. We do not feel that it is
appropriate for this standard to mandate how time is communicated during three-part
communication. Operating communication can deal with several different subjects and data during a
conversation, and it would be inappropriate to mandate all the possible subjects and data through
standard requirements. As a best practice, and not as a mandated requirement, it would be
appropriate for operators to state the time zone they are in if necessary for the situation or if
requested by an entity.
Disagree
Although we agree that proper communication should be used during actions that affect the
reliability of the BES, we do not agree with this requirement as written. The following contains our
rationale and suggestions: 1. The lower case term "directive" is ambiguous, not defined, and
confusing. This is especially true in light of the proposal of the RCSDT to modify COM-002-3 to
include a definition of "Reliability Directive" and their plan to use this defined term to invoke 3-part
communication. Since the plan of this OPCPSDT is to eventually incorporate the COM-002-3
requirements into this new COM-003-1 standard, we feel the definition of Reliability Directive should
be moved to this standard now (instead of later) and the term should be broadened to include any
actions that affect the BES reliability. Essentially then, the current proposed R1 of COM-002-3 can
be moved to this COM-003-1 standard. 2. Our proposal for the term Reliability Directive in item 1
above incorporates the verbiage of the proposed Interoperability Communication definition.
Therefore, the proposed term Interoperability Communication is no longer required and can be
eliminated. 3. Once the term Reliability Directive and proposed R1 from COM-002-3 are moved to
this COM-003-1 standard, the current R5 of COM-003-1 requiring the use of Three-Part
Communication could then be revised to require three-part when a Reliability Directive is issued and
continue until the operating condition that invoked the Reliability Directive is resolved, mitigated, or
ended. 4. With respect to the proposed R2 and R3 of COM-002-3 which essentially discuss threepart communication, these requirements could be eliminated and would be covered by COM-003-1.
As a result, the COM-002-3 requirements being proposed by the RCSDT can be eliminated in their
entirety since we have now incorporated all of them into this new COM-003-1. 5. Since COM-002-3
included the Purchasing-Selling Entity as an applicable entity, since they could be the recipient of a
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Reliability Related Directive and since, with our proposed changes, COM-002-3 can be retired; the
Purchasing-Selling Entity can be added to the applicability section of and incorporated into this new
COM-003-1 standard as recommended below. In conclusion, we suggest the following
changes/additions to COM-003-1: A. Move a revised version of the term "Reliability Directive" from
COM-002-3 to this new COM-003-1 standard and define it as follows: "A communication initiated by
a Reliability Coordinator, Transmission Operator, or Balancing Authority where the recipient is
directed to change the state or report the status of an Element or Facility of the Bulk Electric
System." B. Delete proposed definition "Interoperability Communication". C. Delete R2 and R3 of
COM-002-3 as suggested in item 4 above. D. Insert a New Requirement R4, renumbered as R2, into
new standard COM-003-1 taken from COM-002-3 R1: "When a Reliability Coordinator, Transmission
Operator or Balancing Authority issues a Reliability Directive, the Reliability Coordinator,
Transmission Operator or Balancing Authority shall identify the action as a Reliability Directive to the
recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]" E. Revise Requirement R5 and
renumber as R3: "Each Reliability Coordinator, Balancing Authority, Transmission Owner,
Transmission Operator, Generator Operator, Transmission Service Provider, Load Serving Entity,
Distribution Provider, and Purchasing-Selling Entity shall use Three-part Communication for all
communications concerning a Reliability Directive that was issued per Requirement R1 and
continuing until the actions or status reporting identified in the Reliability Directive has been
completed. [Violation Risk Factor: High][Time Horizon: Real time]" F. Add the Purchasing-Selling
Entity as an applicable entity to COM-003-1.
Disagree
While we agree that using the NATO phonetic alphabet may be a best practice, we feel that it is not
practical to regulate its use. This requirement is too prescriptive. The focus should be on the correct
understanding of verbal communication which will be accomplished via Three-party Communication,
whether an entity uses NATO or "A as in Apple, B as in Boy", this should not be codified within the
standard. Substantiating compliance with this requirement is not reasonable to expect, practical to
prove, nor does it produce an improvement in reliability.
Disagree
Although we agree with moving this current TOP-002 R18 requirement to this standard, we question
the use of the phrase "mutually agreed upon". It is not clear how the line and equipment identifiers
will be mutually agreed upon and how this will be measured. We suggest using similar wording from
the current TOP-002 R18 and reword COM-003-1 R7 as follows: "Each Reliability Coordinator,
Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission
Service Provider, Load Serving Entity and Distribution Provider shall use uniform line and equipment
identifiers for verbal and written communications."
Disagree
We do not support Att. 1 and feel that it should be removed. This attachment is too convoluted,
creates confusion among system operators, and not necessary with regard to the goal of this
standard. This standard mandates proper three-part communication in all reliability-related
communication. Other standards should define and mandate rules associated with the specifics
surrounding urgent action situations (i.e. CIP, TOP, EOP standards). Together these standards will
arrive at proper communication between entities during alert level situations.
Not aware of any
Not aware of any
Agree
Coordination of SDT Efforts – We feel that the NERC Standards Committee should direct the
Reliability Coordination SDT to hand over COM-002 to this OPCPSDT since those requirements will
eventually be moved to COM-003-1. It is difficult to coordinate all these changes on a separate basis
and moving the development to one SDT would help better coordinate these efforts. The current
path forward is inefficient and causes confusion, not only for industry but also for the two drafting
teams. Purpose Statement – We feel the phrase "especially during alerts and emergencies" implies
that using proper communications protocol during normal operating situations is not as important as
during emergencies. It is not appropriate to include this phrase in the purpose statement of a
standard, and we suggest it be removed. Also, we suggest removing the word "timely" since this
standard does not mandate time limits on communications. Compliance Section 1.4 Data Retention
– We do not agree with the following statement for data retention "If a Transmission Operator,
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Transmission Owner, Balancing Authority, Reliability Coordinator, Generator Operator, Transmission
Service Provider, Load Serving Entity or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until found compliant." We feel that this is not
appropriate in a reliability standard since it is already mandated through Compliance Violation
Investigations (CVI). Also, we feel that it is more applicable to NERC’s Rules of Procedure.
Therefore, we suggest it be removed from the standard.
Group
Pepco Holdings, Inc. - Affiliates
Richard Kafka
Disagree
PHI believes the proposed definition for the term Interoperability Communication is too broad and
ambiguous.It is inconsistent with the effort to develop results based standards which would have an
effect in the reliability of bulf electric system. Additionally, PHI does not see the need of a definition
of Interoperability Communication now that the term Reliability Directive has been defined in draft
standard COM-002-3 which is currently posted for review.
Agree
Disagree
PHI agrees that communications procedures are necessary. We do not see the need to create a
CPOP that includes requirements R2 through R7 given that each requirement defines how and what
is to be communicated. This requirement as written could force entities to incorporate all of their
communication procedures into a CPOP which will not improve reliability.
Disagree
Requiring system operators to use the color-coded system condition terminology during
communication adds a layer of responsibility that will distract from the operator’s real-time
reliability-related tasks.
Disagree
PHI believes that mandating one time zone for all Interoperability Communications will create more
confusion during an emergency that it will prevent and may contribute to increased reliability issues.
Disagree
: As mentioned in Question 1 above, the term Reliability Directive has been defined in the draft
standard COM-002-3 and should be considered in place of Interoperability Communication since the
directive is specific to emergency operations. PHI recommends that the requirement changed to
read “Each responsible entity shall use Three Part Communication when issuing or receiving a
Reliability Directive”.
Disagree
Having system operators potentially struggle to remember the NATO phonetic alphabet during
communications rather than focus on the communication and managing the bulk electric system
itself is in contradiction with the purpose of the standard. Use of the NATO phonetic alphabet should
be considered a “best practice” and should not be included as a requirement in a reliability standard.
One failure, such as saying “Baker” instead of “Bravo”, results in a severe violation without any
impact on system reliability.
Disagree
This requirement came from TOP-002 R18 and is fundamentally different from the new proposed
requirement in COM-003-1 R7. TOP-002 R18 states that the BA, TOP, GO, LSE and TSP shall use
uniform line identifiers when referring to transmission facilities of an interconnected network. The
requirement in COM-003-1 R7 introduces an additional requirement to use pre-determined
“equipment” identifiers is another example of a prescriptive requirement that will not impact bulk
electric system reliability and will expose entities to large fines. PHI believes the TOP-002 R18 could
be included in COM-003-1 but included as defined in TOP-002 R18.
Agree
As noted in our comments to Question 4, Attachment 1 has examples for Reliability Coordinators
only. It is not a good guide for other Interoperability Communications. Additionally, Attachment 1
identifies the Level 1, Level 2 and Level 3 communications by color codes that are not referenced in
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the sample messages. PHI finds the addition of color codes to not be helpful and possibly confused
with national security Alert Levels. The color coding should be eliminated and examples for entities
in addition to the Reliability Coordinator should be included.
Agree
PHI asserts that WECC would say NO to Central Standard Time.
Disagree
Disagree
Individual
Henry Masti
NYSEG
Disagree
The definition for Interoperability Communication needs to be further explained. The current
definition would appear to include not only communication between two control centers, but also
between a control center and field personnel for all normal and routine switching, which we do not
believe is the intent of the Standard. Communication Protocol as a separate definition does not
appear to be necessary. The provided definition describes the term in a simple and generic way and
is not specific enough to provide anymore guidance than is already provided in a general
understanding of the word “communication” or “protocol”. Three-part communication should be
revised as follows: An iterative process where verbal communication from a sender to receiver is
repeated back to the sender by the receiver to eventually ensure correct and accurate transmission
of the entire message. We believe this definition is more consistent with COM-002 R2, which is
proposed to be retired once COM-003-1 is approved and Three-part Communication is adopted.
Agree
Disagree
It is not clear when the Interoperability Communication is required to be used. Is it only for
communications between registered entities (inter) or internal to a registered entity (intra)? And is it
required for all communications or used only in certain circumstances (i.e. emergency (if
emergency, it needs to be defined what constitutes an emergency))?
Disagree
R2 indicates the need to use pre-defined system condition terminology for all verbal and written
Interoperability Communications yet Attachment 1 only defines transmission loading and physical
and cyber security threats. Either need to rewrite the Requirement to include only these
circumstances, or define every possible system condition used in Interoperability Communications.
Additionally, there does not appear to be any benefit in attempting to pre-define transmission
loading, and physical and cyber alert system conditions since the actions associated with each are
similar, if not the same, for almost all conditions.
Disagree
Unless the communication is across time zones, there is no benefit to using Central Standard Time,
nor is it sensible. Entire system infrastructures and business processes are driven by current, local
standard time and it is far more safe, reliable, and practical to use the established current time for
system operations. If there is a compelling need for definitive time notation across time zones then
the requirement should dictate the addition of the time zone when referring to a specific clock time
(i.e, 1400 CST, 1400 EST, 1400 ED[aylight]T, etc.).
Disagree
The definition of Three-part Communications and Interoperability Communications needs to be
revised as explained above.
Disagree
While it is perhaps a good practice to include the use of phonetics to avoid miscommunications, it
should be left up to each entity to determine the appropriateness of adopting such a practice (e.g.,
field switching, internal instructions, etc.) and should not be included in the Requirement, especially
if Interoperability is not further clarified/defined.
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Agree
COM-003-1 R7 is more clearly defined than TOP-002 RI8 in that R7 and associated M7 speak only to
written and verbal Interoperability Communication, where TOP-002 R18 and M10 dictate a more
extensive use of the identifier. The adoption of a more narrow purpose is preferred.
Agree
There does not appear to be any compelling practical or reliability reason to adopt the Attachment.
Disagree
Disagree
Disagree
Individual
Jose Medina
NextEra Energy Resources, LLC
Agree
Disagree
This requirement is already covered by TOP-002. If the TOP-002 standard is deemed deficient
because certain entities have been excluded or language appears to be missing, the changes need
to occur to TOP-002 as opposed to copying and revising the existing requirement elsewhere. This
would ensure that compliance oversight, understanding, and adherence goals are unencumbered by
unnecessary redundancies. Moreover, this would ensure that the industry continues to re-enforce
standards with changes that are within the scope of their original reliability purpose. The latter is in
line with one of the core objectives of the Performance-based Reliability Standards Task Force’s
recommendations to focus on identifying and minimizing duplicated requirements.
Disagree
NextEra agrees with the reliability goal of establishing a set of agreed upon communication
standards to ensure consistent communications particularly for actual and anticipated emergency
coordination needs. NextEra believes that existing coordination/communication standards already
fulfill this objective and that it might be of “training” or “reference” value to aggregate those
requirements to a single document or view. However, NextEra is not convinced that this
requirement, largely administrative in nature, will result in marked improvement in reliability.
Organizations tend to take the path of least resistance and unless forced out of that path with
extensive and granular guidance on what CPOPs should contain above and beyond existing
standards or contract language, CPOPs would likely become a simple patchwork of requirements
constructed out of existing NERC standard language and contract language. Standards need to be
clearly implementable before they are approved yet important implementation questions do not
appear to have been answered. (1) What if parties cannot reach agreement? (2) Is it enough to
have attempted to coordinate? (3) What if parties already have agreed upon procedures such as
NPIRs, or those stated in Interconnection Agreements – do they take precedent or must they be
redesigned/relegated? (4) What if CPOPs differ greatly across interconnections because of differing
parties? (One might conclude that by formalizing these different practices, as opposed to mandating
standard practices, the goal of more reliable coordination may not have been achieved) (5) What
level of evidence constitutes “agreement” especially in circumstances where entities may be remiss
to agree? (6) What if CPOPs are simply a patchwork of requirements constructed out of existing
NERC standard language and contract language – does that achieve the CPOP goal?
Disagree
NextEra agrees that standard system condition terminology could be beneficial in communications
but this requirement introduces alert level conventions with no clarity on what the corresponding
associated actions for such levels are and as a result, aside from the value derived from having
improvement in terminology during communications, it is unclear what reliability improvements this
will achieve in carrying out instructions.
Disagree
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Existing market and reliability communication methods already ensure that time-zone adjustments
occur. It is critical that the feasibility, impact, and logistical aspects of implementing this change be
rigorously reviewed and understood to inform this standard’s development. Conceivably, the result
of that analysis could expose significant risks outweighing the purported benefits of implementing a
single time-zone policy. Any implementation or transition gaps between the time format and
references used by reliability coordinators, their corresponding systems, and the interfaced systems
of market participants would be extremely detrimental to system stability and ongoing market
operations.
Disagree
NextEra believes that by associating the “3-part communication” method with “directives” this
standard drafting team could be at risk of unintentionally defining a directive as anything that takes
the 3-part communication form. We would encourage the standard drafting team to continue to use
the terms already employed in the draft standard: “… three-part communication be used when
issuing instructions related to actual or expected emergency conditions.”
Disagree
NextEra believes that though aspiring to use a single strict phonetic alphabet may be beneficial it is
more important to ensure that ease of communication takes precedent especially under emergency
conditions. The requirement for 3-part communication already ensures that understanding between
two parties occurs. Moreover, it is overly burdensome to require that the phonetic alphabet be used
in all communications which would include communications related to mundane interactions between
interconnected parties and that might broadly fit the mold of the “interoperability” definition but not
truly require the formality or rigor commanded by a phonetic approach.
Disagree
NextEra believes that R7 should be withdrawn as it repeats TOP-002 R18 requirements. Please refer
to comments on Q3.
Disagree
None at this time.
Disagree
None at this time.
Disagree
None at this time.
Agree
In the case of nuclear plant operations, NRC communication requirements and the requirements of
NERC NUC-001 for nuclear facilities more than adequately cover communication requirements. COM003 should not be applicable to Nuclear Generator Operators since doing so will introduce an
additional, unnecessary, and potentially conflicting level of requirements. Measures: NextEra
suggests that the SDT clarify the periodicity of providing evidence of compliance and on what
constitutes sufficient evidence of CPOP acceptance. Violation Severity Levels: NextEra encourages
the SDT to revisit the violation severity levels. In the case of most of the requirements it is
unreasonable to levy Severe penalties in instances where the operator may have deviated from the
requirements but the communication occurred in an unencumbered and successful manner as
evidenced by the use/acknowledgement outcomes of three-part communication.
Individual
Dan Rochester
Independent Electricity System Operator
Disagree
The way the definition of Three-part Communication is worded seems to only apply when the
communication is understood by the listener the first time. Because the definition requires the
listener to repeat the information back correctly, failure of the listener to understand the information
the first time could be construed as a violation. The definition should, rather, reflect that three-part
communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows: A
Communications Protocol where information is verbally stated by a party initiating a communication,
the information is repeated back to the party that initiated the communication by a second party
that received the communication, and the information is verbally confirmed to be correct or
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corrected by the party who initiated the communication. The protocol should be followed until the
party issuing the information is satisfied that a party receiving the information has understood the
communication and confirmed it.
Disagree
This requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also use threepart communication protocol until the message’s correct understanding is confirmed.
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
actual and anticipated emergency conditions without inclusion of the elements to be communicated
as they cover a wide range of conditions which can vary among the communicating parties.
Disagree
It is not clear what value there is in identifying alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Further, the “pre-defined” system conditions and alert levels are too
detailed and overly prescriptive. System operators need to spend time looking for the right color and
level to communicate the prevailing system condition terminology to avoid violating the standard.
This task, in and of itself, does not ensure nor improve reliability and does not lend itself to promptly
and effectively deal with the emergency situation.
Agree
Disagree
3-part communication should be used for communicating a directive that must be complied with.
The “must be complied with” is needed to distinguish between an “instruction type” of directive and
a “need to perform type” of directive. We believe it is the latter that should require 3-part
communication.
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so
necessary to be enforceable through sanctionable requirements. Similar to R2, having to use the
NATO phonetic alphabet is overly prescriptive and forces system operators to learn and remember
“languages” in addition to the power system language. System operators should not be penalized for
using some means other than the NATO phonetic alphabet to communicate equally effectively. We
see no short coming in operations that would require these additional requirements and that the
added complexity and additional training requirements may deteriorate reliability.
Disagree
This may represent a good utility practice but it is not necessary to be a requirement. The key is
whether or not operation personnel understand one another. Similar comments as in Q4 and Q7 also
apply here.
Agree
It is not clear what value is realized by declaring an alert status particularly with cyber and physical
attacks. There does not appear to be any differing actions taken based on the alert status. Given
that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as the number of substations that have been physically or
cyber attacked, etc. This is more meaningful than issuing a red alert that would only indicate more
than one site has been attacked. Also, please see our comments under Q4.
Disagree
Disagree
Agree
We believe that the existing standard COM-002 can be simply modified to cover the 3-part
communication requirement. This COM-003 standard actually causes more confusion and ambiguity,
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
and creates unnecessary or overly cumbersome requirements that add little or no value to reliability.
This standard is not needed.
Individual
Daryl Curtis
Oncor Electric Delivery
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Agree
Disagree
Disagree
Disagree
Disagree
Individual
Brady Baker
City Of Greenfield
Disagree
Listed as an LSE & DP, we are a small municipal utility that does not own nor operate any
generation or transmission equipment. Therefore this standard is not applicable to our facility. Keep
in mind, not all LSE's & DP's operate generation or transmission equipment.There are several small
utilities that this standard would not be applicable to. LSE's & DP's should be put into class sizes
depending on the size of the company or utility. Example: Class #1 LSE & DP : Companies that own
& operate generation & transmission Class #2 LSE & DP : Companies that do not own or operate
generation & transmission.(municipals,co-ops,etc)
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Group
Southern Company Transmission
JT Wood
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: We feel that the
definition of Interoperability Communication is much too broad and is inconsistent with the effort to
develop results-based standards. Adherence to such results-based standards would have a
measurable and observable effect on the reliability of the bulk electric system. The definition of
Interoperability Communication, as written, can include virtually any information
exchange/instruction between entities, both routine and emergency. Such communication may or
may not have a measurable and observable effect on bulk system reliability. The concern is that,
since the broad term Interoperability Communication is used in every requirement in COM-003-1,
entities will be required to use the English language, the central time zone, and 3-part
communication in even the most routine exchanges of information. This could create a burden on
operating personnel and a distraction from their reliability duties. This group does not feel the need
for a definition of Interoperability Communication, since the term Reliability Directive has been
defined in draft standard COM-002-3, which is currently posted for review. The Reliability Directive
term is emergency-focused and consistent with the results-based standards process. In addition, the
definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state – repeat - acknowledge) apply to Reliability Directives, while in COM-003-1
the definition of Three-part Communication refers to “information” in general. If, as stated in the
Disposition of Requirements, the revisions to COM-002-3 will be moved to COM-003-1, the definition
of Three-part Communication in this draft standard should be consistent with the requirements of
COM-002-3. Southern Company comments: Interoperability Communication — Communication
between two or more entities to exchange reliability-related information regarding the Bulk Electric
System. Why is a change in state or status required to make a communication between two entities
an Interoperability Communication? What term should be used when a conference call is made to all
of the RCs in an Interconnection to discuss low frequency?
Disagree
Southern Company supports SERC SOS comments. SERC SOS comments: Requirement R7,
regarding the use of pre-determined line & equipment identifiers, applies to TSPs & LSEs. However,
the other requirements of this standard do not seem to apply to these entities. For instance, most of
the reliability-related alerts are communicated through the Reliability Coordinator Information
System (RCIS). TSPs do not have access to this real-time communication tool, so the TSP should
not be included in the applicability for the entire standard. Furthermore, Requirement R18 in TOP002-2 mandated that neighboring Balancing Authorities use the uniform line identifiers. In COM003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring BAs.
Southern Company comments: No proposed revision to remove R18 from TOP-002-2 has been
provided in this SDT proposal. If this standard is adopted and TOP-002-2 is not revised at the same
time the same requirement will be in two reliability standards.
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: This group feels that
there should not be a requirement in the standard to have a “procedure”. It is our understanding
that, to be auditably compliant with a standard, the responsible entity must develop a procedure,
train on that procedure, and be able to demonstrate compliance via documents, data, logs, records,
etc. If Requirements R2 – R7 are included in this standard, the entity will need to develop a
procedure to be compliant. Therefore, we feel that requirement R1 is redundant and should not be
included. Southern company comments: The VSF for not having a written procedure is Severe. If an
entity does not have a written procedure but complies with the other requirements in this standard
has the reliability of the Bulk Electric System been affected? If the reliability of the Bulk Electric
System is not affected by not having a written procedure why is this requirement in a Reliability
Standard?
Disagree
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Southern Company supports the SERC SOS comments. SERC SOS comments: The Alert Level
Guides in Attachment 1 are not consistent with the proposed definitions of reliability-related
communications. Both the Reliability Directive and Interoperability Communication, as currently
defined, require some emergency action or change of equipment status. Yet the Alert Level Guides
were intended for announcement, not actions. Requiring system operators to use the color-coded
system condition terminology during communication adds a layer of responsibility that will distract
from the operator’s real-time reliability-related tasks. We also do not feel that these Alert Level
Guides apply to all the responsible entities identified under Applicability in the draft standard – for
example, TSPs and LSEs are not included in the list of notifications. The requirement to use the
central time zone for logging the time of an alert is problematic in that all communication tools, such
as the RCIS, will need to be re-vamped. We question whether there will be a measurable reliability
benefit by so doing. There is also some redundancy in the Alert Level Guides – for example, the CIP001 standard requires notification of sabotage events – it should not be repeated in this standard.
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: We feel that this
requirement of a common time zone is overly prescriptive. The requirement should be that entities
operating in different time zones agree on how to best eliminate any confusion regarding the time
difference. Entities that routinely operate in different time zones already have an effective system
for dealing with time differences. There seems to be no incentive to change a system that already
works quite well, and the cost of updating computer systems could prove prohibitive. This group
feels that mandating a common time zone across all of North America can only lead to confusion and
increased reliability issues.
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: As suggested in
Question 1 above, the term Reliability Directive (as defined in COM-002-3) should be used in place
of Interoperability Communication, since the directive is specific to emergency operations. The
requirement should read: “Each responsible entity shall use Three-part Communication when issuing
a Reliability Directive”. In addition, this requirement should apply only to BAs, TOPs & RCs. The
other entities listed in the draft standard under Applicability do not issue Reliability Directives.
Southern Company comments: conditional on if the definition of directive is not routine operational
instruction.
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: Use of the NATO
phonetic alphabet should be considered a “best practice” and should not be included as a
requirement in a reliability standard. One failure, such as saying “Baker” instead of “Bravo”, results
in a severe violation without any impact on system reliability. This group is concerned that operating
personnel will be focused on using the correct word rather than managing the power system.
Southern Company comments: This requirement should be removed from the standard.
Requirement 5 requires understanding by both parties during communication. Requirement 6
requires common identifiers which will enhance the chances of both parties understanding
communications. Although using the phonetic alphabet may be necessary some times in order to
gain understanding between two parties it should not be required. If both parties understand A as
well as they do Alpha the reliability of the system has not been affected. No entity should be found
in non-compliance of a Reliability Standard if reliability was not affected.
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: Requirement R7 in
draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended that
neighboring Balancing Authorities use uniform line identifiers when communicating information
about their tie lines. This requirement drops that clarification and introduces the additional
requirement to use pre-determined “equipment” identifiers. Having to mutually agree in advance on
identifiers for every switch & transformer is another example of a prescriptive requirement whose
violation will not affect system reliability, yet will expose entities to large fines.
Agree
Southern Company supports the SERC SOS comments. SERC SOS comments: Our concern is that
the Alert Level Guides of Attachment 1 were written for Reliability Coordinators, not the industry as
a whole, and now they are being incorporated into an industry-wide standard. This attachment is
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very prescriptive as to how the notifications take place, such as through the RCIS. If the RCIS is not
functioning and the hotline is used instead, is the entity vulnerable to a violation by virtue of the fact
that these alert guides are included in the standard? We believe that the color-coded system
condition terminology should be defined/required externally to the COM standards. The use of clear
& consistent alert level terminology, while important, does not fit in well with the reliability-related
communication standards, especially at these high violation severity levels. It is our suggestion that
the Alert Level Guides be balloted separately, and include the Energy Emergency Alerts (EEA) as
well. EEA requirements currently exist in NERC Standard EOP-002-2.1
Disagree
Agree
Southern Company supports the SERC SOS comments. SERC SOS comments: We do see a potential
conflict with the Energy Policy Act 2005, which set the framework for the Electric Reliability
Organization (ERO). The ERO’s mission is to oversee and protect the reliability of the Bulk Electric
System. This standard seems to cross the line between reliability-related activities and other types
of operating actions. The concern here is that system operators will focus on the letter of the
standard rather than on good operating practice. The fear of a violation among operators may have
a greater impact on reliability than the violation itself.
Agree
Southern Company supports SERC SOS comments. SERC SOS comments: This review group has
identified several problems with this standard, as noted above. Other observations include: The
effective dates in the draft standard and in the implementation plan do not seem to match. In the
standard, the effective date mentions one calendar year following regulatory approval, while the
implementation plan refers to the third calendar quarter after regulatory approval. Furthermore, we
do not feel that any of the requirements in this standard warrant Violation Risk Factors or Violation
Severity Levels in the high or severe category. In summary, this review group feels that COM-003-1
is not yet ready to be acted upon and may have been posted too soon. There does not seem to be
sufficient coordination between the drafting teams of all the COM standards, or any attempt to
integrate these standards. One example is the inconsistency between COM-003-1 and COM-002-3
regarding the meaning of three-part communication (mentioned in our response to Question 1
above). As noted above, we feel that many of the requirements prescribe specific “how to” methods
for compliance rather than focusing on the “what” of the requirement. Overall, COM-003-1 is much
too prescriptive to be tied to million dollar-level fines. Southern Company comments: There are
possible inconsistencies with the references to the term “CIP Free Form” and a more generic term
“Free Form” in the tables described in Attachment 1 – COM-003-1 – Operating State Alert Levels.
Reference the fields where functional entities “outside” the Reliability Coordinator Area are identified
for both the initial alert notification and the end of alert notification. For Physical Security, the field
mentions only RC’s using the “CIP Free Form.” For Cyber Security, the field mentions RC’s and CIP
Participants using the “CIP Free Form.” For Transmission Emergency Alerts, the field mentions only
RC’s using the generic “Free Form.” Is there a distinction between the two forms? Is it consistent to
reference CIP Participants only for Cyber Security alerts and not for Physical or Transmission?
Although this standard is well intentioned it is not ready for presentation to the ballot body. When
this standard is applicable is in question just by the way the Title and Purpose are written. The
Purpose needs to make it absolutely clear to all parties, complying entities as well as compliance
enforcement, when the standard is applicable. For example, the Purpose of the standard is subject
to interpretation. Does this standard apply all of the time or just during Alerts and Emergencies? Or
does the word especially mean that a non-compliance during an emergency is more severe? Is the
phonetic alphabet required when an alert is declared or just after the alert is declared?
Group
PSEG Companies
Kenneth D. Brown
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Agree
Yes. The PSEG Companies agree with the concerns and suggestions expressed in the comments filed
by the PJM System Operations Subcommittee (SOS) Group.
Disagree
No regional variances would be required to the best of PSEG's knowledge.
Agree
Yes. The PSEG Companies agree with the concerns expressed in the comments filed by the PJM
System Operations Subcommittee (SOS) Group.
Agree
Yes. The PSEG Companies agree with the concerns expressed in the comments filed by the PJM
System Operations Subcommittee (SOS) Group.
Individual
James H. Sorrels, Jr.
American Electric Power
Disagree
Given that Three-part Communications is required when using a directive, a “directive” must be
clearly defined. Without this determination, the definitions are incomplete. There are undefined
conditions, such as conference calls with multiple parties. Does each participant repeat back in
three-part? Also, the definitions do not address communication of directives that are made in a nonoral format. This is an important area to address in this standard. Lastly, please expand “entities” in
the Interoperability Communication definition to be “NERC registered functional entities.” We are
concerned that the definition is much too broad and may expand the scope of required
communication beyond alerts and emergencies.
Disagree
Based on definitions provided in the functional model, the inclusion of the TSP and LSE in this
standard is inappropriate. These entities manage the relationship with the end-use customer and are
not responsible for the operation or maintenance of BES facilities.
Disagree
While having a procedure is important and the responsible entities should have a procedure to be
compliant, there is not necessary to establish this requirement to have a procedure. We need to stay
focused on what the purpose of the standard is to be and not dilute its effectiveness by focusing on
documented procedures. Furthermore, if the extent of communication concerns warrants the
extensive effort to establish pre-defined line and equipment identifiers, then this should be
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established in a uniform manner and not left to result in multitudes of approaches. There will likely
need to be system modifications to address character limitations with respect to line and equipment
identifiers.
Disagree
AEP suggests that RCIS be expanded to include the additional parties necessary to support
Interoperability Communications. Without such an expansion, the communication requirements for
the RC are burdensome and the effectiveness may be compromised by the volume of parties that
will need to be included. Is it practical for RFC to communicate across some 60 parties or should this
be limited to only those that need to know? Attachment 1 does not seem consistent with the stated
purpose of this standard as Attachment seems to focus on defining the operating condition, not
communication during alerts and emergencies. The SDT should consider if the scope of the standard
is appropriate to resolve this discrepancy. To the extent that it gets mandated, Attachment 1 could
be administered through the addition of “check boxes” on the expanded RCIS.
Disagree
AEP believes that the significant efforts and significant system changes necessary to support a
common time zone does not provide a significant enough reliability benefit. In fact, the focus on a
common time may divert attention away from more pressing operational reliability needs.
Disagree
Is a “directive” from the RC a “directive” all the way through the communication process, including
down to the plant orders? Again, based on definitions provided in the functional model, the inclusion
of the TSP and LSE in this standard is inappropriate. These entities manage the relationship with the
end-use customer and are not responsible for the operation or maintenance of BES facilities.
Consequently, when would such entities be responsible for issuing “directives?”
Disagree
AEP does not believe that this should be a requirement. It is understood that three-part
communications represent best practices, but it is not necessary to mandate the NATO phonetic
alphabet. We are not aware of an instance where the use of “Ed” rather than “Echo” has resulted in
a reliability compliance breakdown.
Disagree
AEP does not believe it is appropriate for the standard to have been edited to remove the
clarification that neighboring BAs use uniform line identifiers when communicating information about
their lines and to add the addition requirement of using pre-determined “equipment” identifiers.
Agree
“Transmission Loading” should be replaced with “IROLs.” The attachment is very prescriptive as to
the notifications are to take place, but not on conveyance of information to be communicated during
alerts and emergencies. The attachment is not a good fit in this standard.
Disagree
Disagree
Agree
Unfortunately, the standard seems to be losing its value as the emphasis overly focusing on
procedures while missing the intent. The SDT should reconsider the standard in the context of
“what” rather than “how.” Lastly, we do not believe that this standard is ready to advance and
needs significant re-working before the revised draft is posted. The SDT should attempt to better
coordinate with the necessary other drafting teams as these standards are integrated.
Individual
Alice Murdock
Xcel Energy
Agree
Agree
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Disagree
We agree with the structure of the standard, however we have issues with several of the CPOP
elements being proposed. (See detail comments in following questions.)
Disagree
The use of Yellow, Orange and Red, as related to the various alert levels, may conflict with existing
color requirements that entities already have in use. We recommend instead only refer to the PSEA,
CEA and TEA levels. Additionally, it is unclear how R2 applies to anyone other than the RC.
Attachment 1 seems to only apply to the RC. If this is correct, then why would the other entities
listed in R2 have to incorporate that terminology into their CPOP? If this is not correct, please clarify
the requirement so that the other entities can clearly understand what is expected.
Disagree
Do not agree with the requirement to use CST. By requiring the use of CST it may actually introduce
an element of error for those who do not routinely operate in that time zone and must make mental
corrections for the time zone they are in. Additionally, some agreements already exist that stipulate
what time zone is to be used.
Disagree
The way the standard is written, the term "directive" is still open to interpretation and could be
inconsistently applied. The term "directive" should be defined.
Disagree
Use of the NATO phonetic alphabet should be a best practice not a reliability requirement. We are
not convinced that there is any threat to reliability if someone were to use a different phonetic than
what is indicated. Additionally, we do not feel that it is necessary to use the phonetic alphabet
unless there is an indication that the initial communication has been misunderstood. If the drafting
team feels this requirement should remain in the standard, we feel it should be modified to address:
1) there should be an exception for approved acronyms, such as NERC, FERC, etc., 2) it should only
be required upon repeat-back, when the first communication was misunderstood, and 3) any
phonetic alphabet should be acceptable for use, such as military or police, not just NATO's.
Disagree
We feel this requirement needs clarification, particularly regarding how granular an entity would
have to go into the various pieces of equipment/lines. We would also recommend that R7 be
modified to not require mutual agreement. We feel the owner (or majority owner) of the line or
equipment should be the one setting the identifiers. For example, R7 could instead read like this:
“Owner-determined line and equipment identifiers shall be used for all verbal and written
Interoperability Communications.”
Agree
Please see our response to question 4.
Disagree
Disagree
Agree
1) Recommend removal of the references to measures in the data retention section of the standard.
It is only necessary to refer to the requirements, which is already included. 2) The data retention
section should also be modified to refer generically to evidence, instead of "dated operator logs…
and voice recordings or transcripts of voice recordings…". This is because the measures specifically
allow for other types of evidence, as stated: "Evidence of use may include but is not limited to voice
recordings, transcripts, operating logs, or on site observations."
Individual
Laura Zotter
ERCOT ISO
Disagree
The purpose of the standard is for timely communication of reliability-related information “especially
during alerts and emergencies”. The definition and use of Interoperability Communication in this
standard expands the intended scope of the standard beyond alerts and emergencies. Guidance
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should be provided for verbal communications with respect to hot-line calls (one party to many) and
how three-part communication should be handled. This definition assumes a one on one
communication.
Agree
Disagree
This approach of an administrative type requirement is in conflict with the NERC BOT approval of
pursuing the development of standards to support reliability performance and eliminate
administrative requirements. It is not necessary to have a separate CPOP document to insure
operating personnel communicate effectively.
Disagree
This is an administrative task and prescribes how something should be done. Written
Interoperability Communications are typically done through automated systems, in which time zone
conversion should not be an issue. Verbal communication should be thorough enough to confirm the
conversion. If the industry is in favor of this requirement, then perhaps consideration should be to
use Central Prevailing Time to alleviate potential confusion with changes with Daylight Savings Time.
Disagree
The requirement, based on the definitions of the terms, introduces ambiguity or even conflict. Three
part communication should be required for emergency situations and with the issuance of Reliability
Directives (term not yet formally defined – in the works by the Reliability Coordination SDT).
Interoperability communications refer to any communications in which a status of a facility or
element is to be changed, which means not specifically related to emergencies.
Disagree
ERCOT ISO does not agree with this approach, which seems to be overly prescriptive (“directives,
notifications, directions, instructions, orders, or other reliability related information”), which goes
beyond the purpose of “during alerts and emergencies”. This is an administrative requirement that
would increase communication timing and possibly negatively affect reliability. If using a common
language and three part communication for directives is effective this is not required.
Disagree
Does the phrase ‘mutually agreed upon line and equipment identifiers’ mean that identifiers do not
have to be identical, but that all parties understand the equipment discussed? If this is the general
understanding, then no further comment, otherwise, please clarify. Although the related bullet item
in the Background Information section describes that they do not have to be identical, many
auditors many only look at the requirement language.
Agree
The intent is for a simple way to look and know the high-level status of an area. This goes way too
far into HOW to do it instead of stating what must be done.
Disagree
Disagree
Agree
Individual
Leland McMillan
NorthWestern Energy
Agree
Disagree
COM-001 and COM-002 standards, along with Operator Training, adequately address this issue.
Therefore there is no need for this additional requirement.
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Disagree
Attachment 1 seems too overly complicated for emergency Operating circumstances and provides an
additional burden for Real Time personnel who are stressed with difficult decisions already.
Disagree
NorthWestern appreciates the opportunity to comment. We believe the requirement to use Central
Standard Time will cause unnecessary confusion (translating to a different time zone and possibly to
a different time reckoning – standard or daylight) at a time when the need for clarity is critical.
NorthWestern suggests that each entity use their local time zone when issuing switching orders.
Each entity should state the time zone they are using when giving any time reference (e.g., 15:20
Mountain Daylight Time) if necessary.
Agree
Disagree
NorthWestern appreciates the opportunity to comment. The requirement, as drafted, appears to
open the possibility of sanctions for incorrect use of the NATO phonetic alphabet during any verbal
communication between entities. The use of the NATO phonetic alphabet would be difficult when
performing local switching orders to field personnel. NorthWestern suggests that the requirement be
reworded to state that entities “shall use a phonetic code (e.g., the NATO phonetic alphabet) when
necessary, to verify accurate reception of alpha-numeric information.”
Disagree
Agree
NorthWestern feels that the current communication standards are sufficient for reliable BES
Operations.
Individual
Saurabh Saksena
National Grid
Disagree
Interoperability Communication: Virtually all communications in a control room environment deal
with changing the state or status of an element of facility, as such there is not a need to define this
communication protocol. However, addition of “real time communication” in the definition will to an
extent address the issue. The definition should be revised as follows: Real Time Communication
between two or more entities to exchange reliability-related information to be used by the entities to
change the state or status of an element or facility of the Bulk Electric System. Three-part
Communication: The way the definition of Three-part Communication is worded applies only when
the communication is understood by the listener the first time. Because the definition requires the
listener to repeat the information back correctly, failure of the listener to understand the information
the first time could be construed as a violation or at least not fitting the definition. The definition
should rather reflect that three-part communication is an iterative process that should be followed
until the listener is confirmed by the speaker to get the information correct. We suggest the
definition be revised as follows: A Real-Time Operating Communications Protocol where information
is verbally stated by a party initiating a communication, the information is repeated back correctly to
the party that initiated the communication by the second party that received the communication,
and the same information is verbally confirmed to be correct or corrected by the party who initiated
the communication. The protocol should be followed until the party issuing the information is
satisfied that a party receiving the information has understood the communication and confirmed it.
National Grid has no specific stand either ways. However, please refer to response to Question 8 for
issues pertaining to the language of the requirement.
Disagree
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It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
actual and anticipated emergency conditions.
Disagree
Defining specific wording per Attachment 1 is overly prescriptive. The requirements should focus on
what is required not how. The RC and incompassing entities should be required to define terms that
will be used in communications. This would allow for the use of terms that are well understood in an
area rather than adding new terms. Also, System operators need to spend time looking for the right
color and level to communicate the prevailing system condition terminology to avoid violating the
standard. This task does not lend itself to promptly and effectively deal with the emergency
situation. There is still plenty of grey area in Attachment 1 and there does not appear to be any
differentiation in actions taken based on the alert levels. Finally, the section Background Information
in the Comments form mentions “The SDT proposes four system condition alerts instead of initial
three in the RCWG version.” However, Attachment 1 only mentions 3 alerts – Physical Security,
Cyber Security, and Transmission Emergency Alerts leading to confusion.
Disagree
The use of central time is unnecessary and may cause more confusion when converting times. The
requirement should be that those entities which need to communicate and are in different time
zones, define which time they will use for communications.
Disagree
Based on the definition of Interoperability Communications, this would require 3- part
communication to be used during virtually all control room communications. The definition of
Interoperability Communications should be revised as proposed in response to Question 1.
Disagree
Using the NATO phonetic alphabet is useful, but to what extent? Does it apply to facility
identifications, key words, or every letter of every word? Is it upto the judgment of the operators? If
so how will compliance be monitored? If during a communication, personnel used a term different
than that in the NATO alphabet i.e. D as in Dog rather than Delta however, the listener understood
the message and the correct action was taken would there still be the possibility of a compliance
violation?
Disagree
The way this and TOP-002 R18 requirements are written they could be interpreted to mean that the
line identifiers have to be unique. The requirement should be written similar to the bullet on page 7
of the comment form also listed below. “TOP-002 R18. Neighboring Balancing Authorities,
Transmission Operators, Generator Operators, Transmission Service Providers and Load Serving
Entities shall use uniform line identifiers when referring to transmission facilities of an
interconnected network.” “Pre-determined Line and Equipment Identifiers: COM-003-1 requires the
use of predetermined line and equipment identifiers in Requirement R7 however the Requirement
does not stipulate a single/unique identifier as long as all parties mutually agree on the identifier for
the line or equipment. The mutual agreement shall be reached in advance of the use of the
identifiers as described in the functional entity’s CPOP”
Disagree
Please see response to Question 4.
Disagree
None
Disagree
None
Agree
We believe that the existing standard COM-002 is actually better than this standard. This standard
actually causes more confusion and ambiguity and creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. Additionally, we cannot understand how all
requirements but R1 have been determined to have a HIGH VRF when, many of them are dictating
HOW communications should take place and not when and why or what. COM-002 retirement does
not appear to be consistent with the direction of the RC SDT. The RC SDT appears to be adding
requirements. More coordination is required between these two teams.
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Group
NERC Staff
Howard Gugel
Disagree
NERC staff recommends that the term “Communications Protocol” be removed from the definition
section because the term is only used in the title and in another definition. In addition, the definition
adds no additional clarity than can be provided by a commonly used definition of the terms.
Similarly, the term “Three-part Communication” can be removed since it is used in only one
requirement, and the definition can be incorporated in the requirement. Furthermore, Three-part
Communication refers to a process or procedure, not a term. NERC staff recommends that the term
“Interoperability Communication” be modified to “Operating Communication” with the definition of
“communication with the intent to change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System.” This captures all communication that affects BES
reliability, not just communication between function entities.
Disagree
NERC staff agrees with the proposal, but would offer the following modification in order to add
clarity. We recommend that the phrase “when issuing directives, notifications, directions,
instructions, orders or other reliability related operating information that involves alpha-numeric
information during verbal Interoperability Communications” be replaced with “when verbal Operating
Communications with alpha-numeric information is involved.” This would utilize the definition of
Operating Communications offered in the response to Question 1. This will hopefully eliminate the
need to further define what communication is or is not included in the phrase “directives,
notifications, directions, instructions, orders or other reliability related operating information.”
Disagree
NERC staff recommends that Requirement R1 be deleted because it is strictly an administrative
requirement that is not necessary. It is not results-based, and is redundant given the imbedded
reference to Requirements R2 to R7. If an entity can demonstrate compliance with the other
requirements, Requirement R1 performs no additional reliability enhancement. A Requirement
should state a performance outcome or a risk to be mitigated. If there is a need to document
something, the appropriate location for that is in the Measures section of the standard. A distinction
should be made here that producing a document containing specific content necessary for reliability,
such as a system restoration procedure, can be an effective requirement used to minimize risk.
However, documentation that does not stand on its own as a result necessary for reliability should
not be made into a requirement. Such documentation requirements should either be eliminated or
moved to an administrative, informational section of the standards. An example of a weak
requirement is “the Responsible Entity shall document the implementation of security patches”. The
requirement that directly contributes to a risk reduction outcome is to implement applicable cyber
security patches. Documentation of the implementation is simply a vehicle for demonstrating
compliance. The NERC staff does not find that the CPOP satisfies the criterion of reducing risk.
Disagree
NERC staff agrees with the principle behind Requirement R2. However, it appears that two separate
communication actions are being performed, the action to notify the Reliability Coordinator, and the
action by the Reliability Coordinator to communicate the alert level to affected functional entities.
Therefore, we recommend that that Requirement R2 be split into two requirements and offer the
following wording: A Balancing Authority, Transmission Owner, Transmission Operator, Generator
Operator, Transmission Service Provider, Load Serving Entity and Distribution Provider shall notify
its Reliability Coordinator when it becomes aware that there is a situation involving the facilities
under its control that meets the criteria for an alert, as specified in Attachment 1 – Operating State
Alert Levels, to keep the Reliability Coordinator informed on the initial and subsequent status of the
situation. When a Reliability Coordinator is notified (or becomes aware) that there is a situation
within its Reliability Coordinator Area that meets conditions specified in Attachment 1 – Operating
State Alert Levels, the Reliability Coordinator shall use the phraseology when making the
notifications specified in Attachment 1 to keep others informed on the initial and subsequent status
of the situation. The NERC staff recommends that the SDT review the content of the Attachment for
consistency, clarity and omissions (such as found in the table on page 14 of the draft – the cell,
“Notify the following entities:” is blank).
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Disagree
In the “Background Information” section of this Comment Form, you state, “The SDT believes that
Interoperability Communications would be enhanced with the use of a common time zone. Central
Standard Time was chosen as it is already in use for NERC Time Error Corrections. The Blackout
Report cited the need to tighten communication protocols and the SAR includes consideration of a
common time zone to minimize mis-matched time signature issues between control systems
especially during an emergency.” NERC staff would like to see more detailed justification on how
reliability would be enhanced with this requirement. This appears to solve issues for communications
between time zones, but may add additional confusion for all additional communications that exist
within a common time zone.
Disagree
NERC staff agrees with the principle behind Requirement R5. We recommended in Question 1 that
the term “Three-part Communication” be removed since it is only used in this requirement. We feel
that this requirement should be split into two requirements so that the sender and receiver each
have responsibility in the communication. Therefore, we offer the following as suggested
replacement language for Requirement R5: Each Reliability Coordinator, Balancing Authority,
Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider,
Load Serving Entity and Distribution Provider that receives a verbal Operating Communication shall
repeat the communication to the initiator. Each Reliability Coordinator, Balancing Authority,
Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider,
Load Serving Entity and Distribution Provider that initiates a verbal Operating Communication shall
ensure that the receiving party has repeated the communication, and shall verbally confirm the
communication to be correct or reinitiate the communication.
Disagree
As stated in response to Question 2, NERC staff agrees with the proposal, but would offer the
following modification in order to add clarity. We recommend that the phrase “when issuing
directives, notifications, directions, instructions, orders or other reliability related operating
information that involves alpha-numeric information during verbal Interoperability Communications”
be replaced with “when verbal Operating Communications with alpha-numeric information is
involved.” This would require using the definition of Operating Communications offered in the
response to Question 1. This will hopefully eliminate the need to further define what communication
is or is not included in the phrase “directives, notifications, directions, instructions, orders or other
reliability related operating information.”
Disagree
NERC staff is unaware of any instance where not having a mutually agreed upon nomenclature has
led to an adverse reliability event. Rather than requiring a national database for all line and
equipment identifiers, it appears that restricting the list to jointly-owned facilities and tie-line would
accomplish the team’s goal. We recommend that the phrase “Interoperability Communications” be
replaced with “Operating Communications involving jointly-owned Facilities and tie lines.”
Agree
NERC staff recommends that a line be added to each table that provides the expectation for entities
communicating events to the Reliability Coordinator. Using the existing tables, all expectations and
requirements rest solely on the Reliability Coordinator. We also recommend eliminating the color
designations of yellow, orange, red and the Alerts be changed to Level One, Two and Three for
consistency. The use of colors does not appear to add anything to the clarity or effectiveness in
conveying the content of an Alert and may be inconsistent with the Department of Homeland
Security’s threat level system. Additionally, the team should update Attachment 1 to include the
criteria and notifications for Energy Emergency Alerts.
Agree
Although no questions were asked about Requirement R3, NERC staff is aware that some areas in
North America require a language other than English for official communication. In addition, it may
be hard to define what “internal communications” are. NERC staff recommends that the phrase
“Interoperability Communications. Responsible Entities may use an alternate language for internal
communications” be replaced with “Operating Communications between functional entities, unless
prohibited by law.” In addition, regions that exist solely in one time zone may ask for a variance
from the requirement to use CST for communication.
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Agree
Although no questions were asked about Requirement R3, NERC staff is aware that some areas in
North America require a language other than English for official communication. In addition, it may
be hard to define what “internal communications” are. NERC staff recommends that the phrase
“Interoperability Communications. Responsible Entities may use an alternate language for internal
communications” be replaced with “Operating Communications between functional entities, unless
prohibited by law.”
Agree
NERC staff questions whether this standard applies to the Transmission Service Provider and the
Transmission Owner. It is unclear from the functional model where they would be involved in realtime operations communications. It is also unclear why the Violation Risk Factor for every
requirement is High, and the Violation Severity Level for all but the first requirement is Severe. This
automatically elevates any violation of any of these requirements to the highest penalty level that is
imposed. The NERC staff recommends that the SDT review the latest guidelines for assignment of
VSLs and consider alternatives that could expand/gradate the VSLs to account for varying severity
of non-compliances.
Individual
Roger Champagne
Hydro-Québec TransÉnergie
Disagree
The way the definition of “Three-part Communication” is worded applies only when the
communication is understood by the listener the first time. The RC SDT requirement which includes
“and shall acknowledge the response as correct or repeat the original statement to resolve any
misunderstandings” is more complete. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could
be construed as a violation or at least not fitting the definition. The definition should reflect that
three-part communication is an iterative process that should be followed until the listener is
confirmed by the speaker to get the information correct. A suggested revision to the definition: A
Real-Time Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back to the party that initiated the communication by
the second party that received the communication, and the information is verbally confirmed to be
correct or corrected by the party who initiated the communication. The protocol should be followed
until the party issuing the information is satisfied that a party receiving the information has
understood the communication and confirmed it. These principles are included in Requirements R2
and R3 in the recently issued draft Standard COM-002-3 in Project 2006-06. An alternative
suggestion to the definition of Three-part Communication: A Real-Time Operating Communications
Protocol where information is verbally stated by a party initiating a communication, the information
is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the information is verbally confirmed to be correct by the party
who initiated the communication. In the definition of Communications Protocol, the term
“Interoperability Communication” creates confusion within the industry, and contradicts the work by
RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part communications
when issuing Reliability Directives (defined in Project 2006-06) that address anticipated and actual
emergency conditions, and do not agree with its definition. What also must be considered is that the
RC SDT has stated that when someone “says”, it is a directive--operating conditions are not
distinguished. This definition unnecessarily and counterproductively encompasses all verbal
communications and, as such, is not needed. It is not so critical to reliability that it should become
an enforceable requirement for routine operating instructions. The enforceable requirement should
be limited to require three-part communications, and be left to the entity that needs the action to be
taken to establish the need for three-part communications by stating in the communication that they
are issuing a directive. This would be a clear trigger, and be auditable and measurable. Virtually all
communications in a control room environment deal with changing the state or status of an element
of facility, as such there is not a need to define this communication protocol. Both element and
facility are used in the Interoperability Communication definition and are NERC defined terms. Did
the drafting team intend that the NERC definitions should apply? If so, the terms need to be
capitalized. The term “entities” is confusing and needs to be defined.
Disagree
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The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. This
Requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and understood. LSEs and TSPs do not own or operate equipment, and as such should not
fall under the mandates of this requirement. Neither the TSP nor the LSE provide or receive
information about specific lines or equipment in real-time. Therefore, requirement R7 should not
apply to them absent clear evidence that a realistic (not hypothetical) threat to reliability would exist
if they are omitted. We do not think that such a threat would exist.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions for all entities involved in real time operations.
The NERC BOT has approved pursuing the Results-based Reliability Standard Task Force’s
recommendations to assess the existing standards, modify and develop standards that support
reliability performance and risk management, and work on an overall plan to transition existing
standards to a new set of standards. One goal of this effort is to eliminate administrative
requirements. This proposal takes the opposite approach and incorporates a new administrative
requirement. The industry as a whole, based on the response to the Task Force, does not support
such an approach. This Requirement should be deleted from the Standard. There is no need to
create a CPOP that includes requirements R2 through R7 given that each requirement spells out how
and what is to be communicated. A CPOP may be needed for Interoperability Communications that
are not addressed in R2-7.
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Just stating the severity and details of the
incident should suffice. Further, the “pre-defined” system conditions and alert levels are too detailed
and overly prescriptive. System operators will need to spend time looking for the right color and
level to communicate the prevailing system condition terminology to avoid violating the standard.
This task does not lend itself to promptly and effectively deal with the emergency situation. The
level(s) identified in the notification text are at odds with the condition (color versus numerical).
Suggest that the standard either use Condition (color) or the level (numerical). Many RC
communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the listed entities such as Distribution Provider and Generator Operator cannot have
access to these systems due FERC standards of conduct requirements. Attachment 1 and R2 are not
consistent with the definition of Interoperability Communications. By definition, Interoperability
Communication pertains to all communications about how entities change the state of the BES (not
just physical or cyber attacks). Attachment 1 is about notifying of what physical and cyber attacks
have already happened to the BES. It is not clear in the context of Interoperability Communications
what the recipient of a specific notification is expected to do when there is a change of state or
status of an element or facility of the Bulk Electric System. Attachment 1 pertains specifically to
Operating State Alert Levels and says nothing about the communication of information to be used to
change the state or status of a BES element or facility (which is the SDT’s proposed definition of
Interoperability Communications). Therefore, it is not appropriate to require that all verbal and
written Interoperability Communications use the pre-defined terminology in Attachment 1. Only
those communications concerning Operating State Alert Levels should be required to use that
terminology. By the proposed definition, such communications are not Interoperability
Communications since the information is not used to change the state or status of a BES element or
facility. The SDT needs to revise this requirement to clarify that it pertains only to communicating
the Operating State Alert Levels and nothing more. None of the examples in either of the
attachments appear to address EEAs (EEA is mentioned in the top paragraph of page 9 that is
included in EOP-002-2.1) or SOLs. This limits the use of Interoperability Communications to only
events where there exists either a physical or cyber threat, or where an IROL can’t be mitigated.
The requirements should focus on what is required, not how. The RC and encompassed entities
should be required to define terms that will be used in communications. This would allow for the use
of terms that are well understood in an area, rather than having to add new terms. The Background
Information in this Comment Form introductory section mentions “The SDT proposes four system
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condition alerts instead of initial three in the RCWG version.” However, Attachment 1 only mentions
3 alerts – Physical Security, Cyber Security, and Transmission Emergency Alerts leading to
confusion. Finally, Attachment should only be used as a guide.
Disagree
HQT agrees with using 24 hour format. However, there is no reliability need to use a common time
zone for communications. There is already a requirement to use hour ending for scheduling
purposes, inadvertent accounting, CPS and other standards where needed. There is no additional
reliability need to use a common time zone. The time zone should be identified in the
communication. Not only does this requirement attempt to determine HOW entities operate within
their various footprints, it would significantly change the way many markets are structured. To
implement this into existing Markets would cost significant time, money and resources while not
enhancing reliability in these areas. When operating across time-zones, simply referencing “Central
Standard Time” or “Eastern Standard Time” is sufficient for operating entities to reliably operate.
The time zone adopted by the respective Reliability Coordinator (RC) and their area control center,
e.g., NYISO Eastern Standard Time (EST), should be used. If each entity in the area and the RC are
all using EST (or daylight savings), then why would a time zone be used that is foreign to all parties
in the area? This can lead to considerable confusion. What cannot be ignored is how many entities
would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We are strongly opposed to this requirement. The requirement should be that
those entities which need to communicate and are in different time zones define which time they will
use for communications. Any confusion about what time is being verbally communicated should be
cleared up through three-part communications. There should be no confusion about what time is
being communicated as long as the time zone (where applicable), and the 24 hour format
designations are included. Besides, many entities exchange written information via web-enabled
applications that allow the users to configure their interface to show time in whatever format and
time zone they prefer. This eliminates confusion.
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part
communications is required to communicate routine operating instructions, or during operational
strategic discussions as well as other “non-action” oriented communications. This Requirement
contradicts the work that has been done and substantially progressed through two other SDTs and
creates confusion within the industry. This Requirement would, in fact, be adverse to reliability
instead of enhancing reliability by reducing the amount of pre-action communications that may
occur prior to taking action because operators may be more concerned with not repeating back
during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person
giving such an order. The entity that needs the action to be taken should establish the need for
three-part communications by stating in the communication that they are issuing a directive. This
would be a clear trigger, auditable, and measureable. R5 is not consistent with the Functional Model.
Only the RC, BA, and TOP can issue directives. Outside of allowing the individual who NEEDS the
action to be taken, this is an auditable or measureable requirement whether it be for 3-part
communications or for the receiving entity to actually take said action. By definition, Three-part
Communications presumes the second party will repeat the information back “correctly.” Failure to
do so is assigned a High VRF and a Severe VSL. The practical application of Three-part
Communication involves a sender communicating information, a receiver repeating back the
information, and the sender verifying the repeat back is either correct or incorrect. If the repeat
back is incorrect, the process repeats until both parties have the same understanding of what is
being communicated.
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary
to be used in all verbal Interoperability Communications, and is certainly not necessary to be
included as an enforceable Requirement. For example, a situation in which an operator says “A as in
apple” instead of using the NATO Alpha. Even though the listener should clearly be able to discern
the correct meaning, the speaker’s company could be sanctioned even if the correct actions were
taken as a result of the clear communication. The objective of good communications is to assure
that the parties understand each other. The statement “… shall use the NATO phonetic alphabet”
doesn’t make sense for North America. If the Real-Time Operator states “breaker 6-North,” under
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the NATO phonetic alphabet that would be unacceptable, because the operator did not use the
appropriate NATO term “breaker 6-November,” even thought the “N” on the one line diagram refers
to the “North” breaker and not the “South” breaker. Many organizations may have established
communications protocols which are working well. Making a change may actually hinder reliable
operations by introducing unnecessary confusion and questioning. Not only does this requirement
attempt to determine HOW entities operate with their various footprints, it may change the way
many Markets are structured. What is the difference between using the word “Zebra” instead of
“Zulu” to signify the letter “Z”? And, why would this be enforceable. Perhaps this should be a
guideline document rather than an enforceable Requirement. There is no reliability need for this
Requirement. Furthermore, the use of three part communication eliminate the need for a mandatory
use of NATO phonetic alphabet.
Agree
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There do not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information, for example 12 substations have been physically or cyber
attacked. This is more meaningful than issuing a red alert that would only indicate more than one
site has been attacked. Furthermore, we question the value of communicating the physical and
cyber alerts. How does this notification help the BES reliability? Consider the following example. One
BA in Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells
other operators that somewhere in Oklahoma an attack occurred. This notification does not present
any information that could require actions on the operators’ parts, and will only generate phone calls
for more information. Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001
R2. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2. Also it
has been the experience of several entities during the field test of these Alert Levels that there are
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion
than exists today. Reliability has not been enhanced. Attachment 1 contains a conflict. The last
sentence of the opening paragraph of Attachment 1 reads, “The time frame for declaration of these
Alert states shall be consistent with the approach used to declare EEAs and would normally apply to
Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts Condition
Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL
and/or is concerned about its ability to respect the IROL. Foresees is a forecast condition. There is
an inconsistency between the inclusion of Attachment 1 and what is stated in the document posted
with the standard entitled Disposition of Requirements Identified in the SAR for Operations
Communications Protocols as Possibly Needing either Modification or Movement. The document
states that the standard focuses on “how to” communicate rather than on specified scenarios of “to
whom” or “when to” communicate; however, Attachment 1 does just the opposite. In condition
Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2. Under the Make Final Notifications, is curtailed intended to mean canceled or
terminated? The term Curtailed in operations generally means cuts for schedules/tags. EEA’s use
terminated. Terminated is the preferred term. Distribution Service Providers should be Distribution
Provider to be consistent with the Functional Model. Refer to the response to Question #4.
Agree
In the Province of Québec, the use of French is mandatory, according to law, for communication
within the Province. R3 should include: Within the Québec Interconnection, the French language
shall be used for verbal and written interoperability communication between entities (RC, BA, TO,
TOP, GOP, TSP, LSE and DP). For their interoperability communication with entities outside of the
Québec Interconnection, they shall use the English language.
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in
the requirements is an unnecessary burden for these areas. The requirement to use CST attempts to
determine HOW entities operate within their various footprints and it would significantly change the
way many Markets are structured. To implement this into existing Markets would cost significant
time, and resources while not enhancing reliability in these areas. When operating across time-
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zones, simply referencing “Central Standard Time” or “Eastern Standard Time” is sufficient for other
operating entities to reliably operate. Many entities would have to modify their existing practices,
hardware, software, Control System, billing systems, bidding systems, etc. We are strongly opposed
to this requirement.
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes
more confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that
add little or no value to reliability. All requirements with the exception of R1 have been determined
to have a HIGH VRF, when many of them are dictating HOW communications should take place and
not when, why, or what. COM-002 retirement does not appear to be consistent with the direction of
the RC SDT in Project 2006-06. The RC SDT is adding requirements. More coordination is required
between the Standard Drafting Teams. Again, we support the work being done by the RC SDT and
RTO SDT and do not believe this adds more necessary requirements. Many of the requirement
proposed in this posting either reiterate the drafts as posted (i.e. English language) or introduce
confusion when compared to the drafts as posted. The SDTs should limit their scope to R2 and R7,
so as not to duplicate or contradict the on-going work of other SDTs. The SDT appears to have
adopted severe violations for every infraction. There should be some gradations, using increasing
severity based on the number of or severity of any infractions. Definitions: The standard should
define other terms, as well, including the following: • reliability-related information, • “… state or
status of an element or facility of the BES …” The standard should also have provision to include the
boundaries (components) of an “element,” and the meaning of the terms “state or status” in the
written communication protocol. For example, is the gas compressor of a 345kV breaker considered
part of this element, and so would a change in its “state or status” be covered? The VRFs for R2-R7
are all “High”, and the VSLs are all “Severe” are too harsh. Failing to comply with one of the
requirements does not automatically mean that a miscommunication occurred that caused a
reliability problem. There should be a “Moderate” VSL for failure to comply with a requirement, but
no miscommunication occurred. There should be a “High” VSL for failure to comply with a
requirement that caused a miscommunication but resulted in no violation of another reliability
standard. The “Severe” VSL should only apply to failures to comply with a requirement that caused a
miscommunication that lead to a violation of another reliability standard, or caused a reliability
problem. In addition, as stated earlier, this Standard focuses on “how” certain tasks should be
performed and conflicts with NERC’s position of pursuing performance based and results based
Standards. Based on these considerations, work on this Standard should be stopped until work on
Project 2006-06 has been completed and approved. This approach is consistent with the August
2003 Blackout Recommendation #26 “failure to identify emergency conditions and communicate
that status to neighboring systems, and upgrade communication system hardware where
appropriate” which actually focused on communications during emergencies, which is the scope of
Project 2006-06. After Project 2006-06 is completed, a determination can be made on the
disposition of this Standard. This Standard should be effective uniformly continent-wide.
Group
Santee Cooper
Terry L. Blackwell
Disagree
The definition of Interoperability Communication needs to be clarified. What is the intent of the word
“entities” in this definition? This definition may no longer be needed with the recent definition of a
Reliability Directive. Three-part Communication should be required when issuing and receiving a
Reliability Directive. This term has recently been defined by a SDT.
Disagree
A TSP and LSE should not be subjected to other requirements within the COM003 Standard such as
Three-part Communications. In addition, R18 of TOP002-2 required the use of uniform line
identifiers among neighboring BAs. As this requirement (R7) is now written in COM003 it is not clear
that this is when the use of uniform line identifiers is required. As currently written, it could be
interpreted that the use of uniform line identifiers is required for all communication which is more
restricting.
Disagree
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We believe that a company’s documentation demonstrating compliance for R2 through R7 would
eliminate the need for a CPOP document.
Disagree
Utilization of a color-coded system for all verbal and written Interoperability Communications adds a
layer of complexity to the System Operator that is not necessary.
Disagree
A common time zone is not necessary and is overly prescriptive. Companies should not have to
worry about self-reporting or receiving a compliance violation if someone states the wrong time
during a conversation.
Disagree
The SDT should consider using the now defined term Reliability Directive in place of Interoperability
Communications. Typically, only BAs, TOPs, or RCs issue Reliability Directives so this requirement
should only be applicable to those entities.
Disagree
Use of the NATO phonetic alphabet should not be a requirement of this standard. This also adds a
layer of complexity to the system operator position that is not necessary.
Disagree
See previous comment on Question 2. In addition the use of the words “equipment identifiers” could
be interpreted to include all pieces of equipment within a line.
Disagree
Disagree
Agree
A lot of the requirements in this standard could be considered a “best practice” for the industry
rather than reliability related.
Agree
The SDT has put a lot of work into this standard and we appreciate their effort. The SDT of COM-002
and COM-003 may need to integrate the reliability related requirements of these two standards into
one standard that the industry can approve. This standard as written could lead to some extremely
high dollar fines when in reality the reliability of the bulk electric system has not been affected at all.
Group
Bonneville Power Administration
Denise Koehn
Disagree
BPA does not agree with the aspects of Interoperability Communications. We do not need a common
time standard. Why use the NATO Standard. This could add a lot of time to a directive that needs to
be given immediately. The 3 part communication is already used by BPA.
Disagree
BPA Would like further clarification about what is meant by “pre-determined, mutually agreed upon
line and equipment identifiers”. Is it a specified format no matter which part of the system is being
used, or is it only for 115 kV and above as it apllies to LSE’s and TSP’s. If it only refers to
Transmission equipment above 115 kV, then BPA would likely agree.
Disagree
BPA does not agree with the one time zone or the NATO Standard. We believe the protocols are
unnecessary and in fact will add more confusion to the process. We also do not agree, if this
requires creating a brand new documented procedure just to address this standard, when elements
are already covered in a different standard (common language in TOP).
Agree
In Attachment #1 - Operating State Alert Levels, for the Transmission Emergency Alert (TEA) Level
2 definition, a “why” needs to be incorporated into the definition. It appears that the reason we're
going to TEA 2 is to avoid violation of an SOL but it needs to be called out.
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Disagree
This creates a communication barrier between the utility and it's customers and the local population.
Do not go ahead with this provision. The very last thing that we want to do is to create confusion
and this approach, given that the country itself is using different time zones, will do just that. With
3-part communications with specified time zones in Interoperability Communications as required and
a common English language, the matter is covered.
Agree
Suggest that each entity is also required to use the full station name in verbal communications.
Disagree
Disagree
BPA Would like further clarification about what is meant by “pre-determined, mutually agreed upon
line and equipment identifiers”. Is it a specified format no matter which part of the system is being
used, or is it only for 115 kV and above as it apllies to LSE’s and TSP’s. If it only refers to
Transmission equipment above 115 kV, then BPA would likely agree.
Agree
In Attachment #1 - Operating State Alert Levels, for the Transmission Emergency Alert (TEA) Level
2 definition, a “why” needs to be incorporated into the definition. It appears that the reason we're
going to TEA 2 is to avoid violation of an SOL but it needs to be called out. The color scheme may be
confusing with (DHS) Homeland Security's terrorist alert levels. (The RC makes the notifications to
all based upon the Operator’s reported conditions per the scheme.). Suggest only using the
Emergency Energy Alert numerical levels versus the color scheme, to avoid confusion with
Homeland Security alerts. An example: A red alert is a breakup like 2003 and 1996, not shedding of
load to prevent it, The color scheme does not work for this. Agree with Notifications for Physical
Security and Cyber Security. Disagree with Notifications for Transmission Emergency Alerts. This
appears to be only IROL related, but could progress to SOL. May have too many of these issued.
Suggest the following: Yellow – approaching IROL limit; Orange – procedures implemented to
correct IROL; RED – shedding firm to respect an IROL.
Disagree
Disagree
Agree
R3 creates a special need for multi language operators. US and US-involved entities need to use
English in all instances, not only for reliability purposes, but for internal communication purposes
and to be able to hire replacements without competing for an artificially small set of operators and
to be auditable by NERC.
Group
IRC Standards Review Committee
Ben Li
Disagree
The way the definition of Three-part Communication is worded applies only when the communication
is understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could
be construed as a violation or at least not fitting the definition. The definition should rather reflect
that three-part communication is an iterative process that should be followed until the listener is
confirmed by the speaker to get the information correct. We suggest the definition be revised as
follows: A Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the
communication by the second party that received the communication, and the same information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The
protocol should be followed until the party issuing the information is satisfied that a party receiving
the information has understood the communication and confirmed it. We believe the term
“Interoperability Communication” contradicts the work by the RTO and RC SDT that limits the
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requirement to use three-part communications to only those communications that explicitly state
that the communication is a Reliability Directive and creates confusion within the industry.
Additionally, it appears that this definition would encompass all verbal communications and, as such,
we question the need for such definition. While we support using three-part communications during
routine operations as a best operating practice, we do not believe that it is so critical to reliability
that it becomes an enforceable requirement for routine operating instructions. Rather we believe the
enforceable requirement should be left to the entity that needs the action to be taken to establish
the need for three-part communications by stating in the communication that they are issuing a
directive. This would be a clear trigger and auditable and measureable. Both element and facility are
used in the Interoperability Communication definition and are NERC defined terms. Did the drafting
team intend that the NERC definitions should apply? Then the terms need to be capitalized.
Disagree
This requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and comprehended.
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in
the protocol. This standard only needs to focus on requiring three-part communications during
actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Performance-based Reliability Standard Task Force’s recommendations to assess the existing
standards, modify and develop standards that support reliability performance and risk management,
and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to delineate actionable reliability requirements from record/documentation
requirements. This proposal takes the opposite approach and incorporates a new administrative
requirement. We – and the industry as a whole based on the response to the Task Force – do not
support such an approach. We suggest deleting this Requirement from the Standard. Furthermore,
the establishment of R2-R7 as elements of the CPOP required in R1 appears to contradict the recent
shift in direction that NERC has taken regarding defining criteria as bullets under a requirement. See
NERC’s August 10th informational filing regarding assignment of violation risk factors and violation
severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10-000.
COM-003 R2 states: “shall use pre-defined system condition terminology as defined in Attachment
1-COM-003-1 for verbal and written Interoperability Communications.” Why does R1 establish the
requirement for a procedure, when the procedure is essentially defined by R2-R7. If there is such a
reliability need to establish these requirements, one could conclude nothing else is so important that
it needs to be included because it is not identified in the standard. Furthermore, R2 appears to
define Interoperability Communications for attachment 1 communications only. Is this the intent of
the drafting team?
Disagree
It is not clear what value there is in identifying alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Why not just state the number of
substations attacked, etc? Further, the “pre-defined” system conditions and alert levels are too
detailed and overly prescriptive. System operators need to spend time looking for the right color and
level to communicate the prevailing system condition terminology to avoid violating the standard.
This task does not lend itself to promptly and effectively deal with the emergency situation. Many RC
communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to
these systems due FERC standards of conduct requirements. Attachment 1 and R2 do not appear to
be in synch primarily due to the definition of Interoperability Communications. By definition,
Interoperability Communication is about how entities change the state of the BES and Attachment 1
is about notifying of what already happened to the BES.
Disagree
There is no need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where
needed. There is no demonstrated benefit to reliability to use a common time zone. The time zone
should be identified in the communication. Use of CST will cause significant and unnecessary costs
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and the resulting reliability benefit is not clear. Some of the costs will arise to change systems such
as RCIS, IDC, scheduling and E-Tag systems, etc. Not only does this requirement attempt to
determine HOW entities operate within their various footprints, it would significantly change the way
many markets are structured. To implement this into existing Markets would cost significant time,
money and resources while not enhancing reliability in these areas. We believe that, when operating
across time-zones, simply referencing “Central Standard Time” or “Eastern Standard Time” is
sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing
systems, bidding systems, etc. We are strongly opposed to this requirement.
Disagree
Based on the definition of Interoperability Communications, R5 could imply that three-part
communications is required to communicate routine operating instructions. We believe this
Requirement contradicts the work that has been done and substantially progressed through two
other SDTs and creates confusion within the industry. We believe this Requirement would, in fact, be
adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned
with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT which would define a directive based on the
determination of the person giving such an order. We believe, it should be left to the entity that
needs the action to be taken to establish the need for three-part communications by stating in the
communication that they are issuing a directive. This would be a clear trigger and auditable and
measureable. R5 is not consistent with the Functional Model. Only the RC, BA, and TOP issue
directives. Thus, the term “….when issuing a directive….” should be “….when communicating
directives….” , so both the issuer and receiver are included in the requirement.
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so
necessary to be enforceable through enforceable requirements. Imagine the situation in which an
operator says “A as in apple” instead of using the NATO Alpha. Even though the listener should
clearly be able to discern the correct meaning, the speaker’s company could be sanctioned even if
the correct actions were taken as a result of the clear communication. Also, many organizations may
have established communications protocols which are functioning properly and making a change
may actually hinder reliable operations by introducing unnecessary confusion.
Disagree
Please confirm our understanding of this requirement. We believe that the SDT intends for the
requirement to compel all companies to use the same name for all facilities. If this is the intention,
we disagree with the requirement. This may represent a good utility practice but it is not necessary
to be a requirement. The key question is: “Do the companies’ personnel understand one another?” If
I know that my company refers to a tie-line as Alpha and my neighboring company calls it Beta, I
know what he means when communicating to me. That is all that matters.
Disagree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and
physical attacks. There does not appear to be any differing actions taken based on the alert status.
Given that no differing actions are taken for cyber and physical attacks, it seems it would be more
beneficial to use specific information such as 12 substations have been physically or cyber attacked.
This is more meaningful than issuing a red alert that would only indicate more than one site has
been attacked. Furthermore, we question the value of communicating the physical and cyber alerts.
How does this notification help the BES reliability? Consider the following example. One BA in
Oklahoma is 34,323 sq miles. Communicating that an attack occurred in the BA and RC tells other
operators that somewhere in Oklahoma an attack occurred. This notification does not present any
information that could require actions on the operators’ parts and will only generate phone calls for
more information. Furthermore, PSE and CSE is a type of sabotage which is reported in CIP-001 R2
already. TEA Alerts are already covered in IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2. Also,
several entities have observed confusion during the field-test of these Alert Levels because there are
inconsistencies in the implementation of various stages of Alerts. It certainly has not enhanced
Reliability. Attachment 1 contains a conflict. The last sentence of the opening paragraph of
Attachment 1 reads, “The time frame for declaration of these Alert states shall be consistent with
the approach used to declare EEAs and would normally apply to Real Time declarations and not
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forecast conditions.” In Transmission Emergency Alerts Condition Yellow, Orange and RED: The
Reliability Coordinator or Transmission Operator foresees or is experiencing conditions where all
available generation resources are committed to respect the IROL and/or is concerned about its
ability to respect the IROL. “Forsees” is a forecast condition. In condition Orange and Red for TEA
Level Two/Three, the initial notification requirements are redundant with IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term
Curtailed in operations generally means cuts for schedules/tags. EEA’s use terminated. We
recommend using terminated. Distribution Service Providers should be Distribution Provider to be
consistent with the Functional Model.
Agree
Many RC communications are issued to multiple parties using blast communication systems such as
the RCIS. Several of the parties such as Distribution Provider and Generation Operator cannot have
access to these systems due FERC standards of conduct requirements. Requirement 2 and the listing
of functional entities required to be notified within the RC footprint in attachment 1 create a de facto
requirement for them to have RCIS access or an unnecessary burden to communicate with all
functional entities listed separately. Having to communicate to all functional entities in that list
verbally and individually would create an unnecessary burden that distracts the RC from actual
system operation and represents a detriment to reliability.
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in
the requirements is an unnecessary burden for these areas. The requirement to use CST attempts to
determine HOW entities operate within their various footprints and it would significantly change the
way many Markets are structured. To implement this into existing Markets would cost significant
time, money and resources while not enhancing reliability in these areas. We believe that, when
operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW
MANY entities would have to modify their existing practices, hardware, software, Control System,
billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Agree
We believe that the existing standard COM-002 is actually better than this standard. This standard
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements
that add little or no value to reliability. Additionally, we cannot understand how all requirements but
R1 have been determined to have a HIGH VRF when, many of them are dictating HOW
communications should take place and not when and why or what. COM-002 retirement does not
appear to be consistent with the direction of the RC SDT. The RC SDT appears to be adding
requirements. More coordination is requirement between these two teams. Recommendation 26 of
the August 14, 2003 blackout report is cited as a driver for extending three-part communications.
We believe the title of Recommendation 26 is misleading and when reviewed separately from the
supporting text of the recommendation and direct and contributing factors in the report results in an
incorrect interpretation. “Failure to identify emergency conditions and communicate that status to
neighboring systems” is one of the contributing factors and the supporting text of the
recommendation clearly refer to shoring up communications during emergency and anticipated
emergency conditions and establishing an emergency broadcast communication system to alert
regulatory, state and local officials. The supporting text of Recommendation 26 only mentions
addressing alerts, emergencies or other critical situations. Some have incorrectly inferred the initial
clause of Recommendation 26, “Tighten communication protocols”, means the recommendation
applies to all routine communications. The first paragraph in Attachment 1 of COM-003-1 an EEA is
stated as being an Emergency Energy Alert rather than an Energy Emergency Alert. This should be
corrected for consistency with other standards and to avoid confusion. Also in this paragraph, the
term "states" should be replaced with "levels" in order to maintain consistency with the tables in the
Attachment as well as EOP-002-2.1 to which this Attachment refers.
Individual
Brett Koelsch
Progress Energy Carolina, Inc
Disagree
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The definition for Interoperability Communication needs more clarification/an interpretation since
the type of communications is not defined, the term "reliability-related information" undefined, and
it may be so diluting as to de-emphasize true reliability directives.
Disagree
The word "Neighboring" is used in TOP-002 R18. Excluding this word in the proposed COM-003-1
means that each entity would have to coordinate the uniform identifiers with an undefined number
of entities in the entire Interconnection.
Disagree
A requirement to create a CPOP and mandating absolute adherence to that CPOP is overly
prescriptive, may not improve reliability of BES operations, and may serve to delay communications
and therefore delay actions necessary to respond to threats to the reliability of the BES.
Disagree
The link between COM-003-1 R2 and Attachment 1 for entities other than the Reliability Coordinator
is unclear. R2 links with Attachment 1 and is applicable to a host of entities while Attachment 1
seems to only provide pre-defined system condition terminology for use during notifications by the
RC to other entities.
Disagree
Mandating that all “Interoperability Communications” be based on Central Standard Time could
generate an error precursor- (i.e. some entity communicating a reliability directive in a location
using EST to a different entity in a location using EST having to convert the time stamp to CST
introduces possibilities of errors and/or delays.) A better approach for those entities that
communicate across time zones is for those entities to agree/coordinate on a time standard
reference.
Disagree
PEC supports creating a definition of Reliability Directives. PEC may then agree that each entity shall
use 3-part communications when issuing Reliability Directives during “Interoperability
Communications.” Alternatively, simplify and change to use Three Part Communications when using
Interoperability Communications.
Disagree
NATO stands for North Atlantic Treaty Organization. This proposed requirement is a best practice
and does not serve to increase the reliability of the BES.
Disagree
Agree
R2 which links with Attachment 1 is applicable to a host of entities while the Attachment seems to
only provide pre-defined system condition terminology for use during notifications by the RC to
other entities. PEC feels that unscripted specific language used by RCs now on RCIS and in verbal
communications currently provides the necessary awareness and information to entities without
personnel having to refer to a procedure or remember color codes to decipher the meaning. This
attachment does not serve to increase the reliability of the BES.
no
Agree
This proposed revision, if implemented, may introduce unnecessary complications into
communications between entities which may lead to delays and misunderstandings, potentially
decreasing the reliability of the BES.
Group
PEF
Dania Colon
Disagree
PEF does not agree with the adoptation of the proposed term “Interoperability Communication”. The
term “Reliability Communication” should be used instead. The proposed term “Interoperability
Communication” is defined such that it applies to a state or status change of an element or facility of
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the BES – but there are many reliability-related communications which do not necessarily apply to a
state or status change.
Agree
Agree
Disagree
PEF recommends that the color coding and definitions that are used by Homeland Security also be
used for the notification of physical and cyber emergency alerts reported to the RC. This would
follow the ES-ISAC standard already adopted by the electric industry. If the attachment is adopted
as is, PEF recommends adding the EEA levels to provide “pre-defined system condition terminology.”
Disagree
PEF feels that the use of CST will create too much confusion within the different entities, particularly
during emergency communications. We recommend the use of GMT instead.
Agree
Agree
Agree
Agree
PEF recommends that the color coding and definitions that are used by Homeland Security also be
used for the notification of physical and cyber emergency alerts reported to the RC. This would
follow the ES-ISAC standard already adopted by the electric industry. If the attachment is adopted
as is, PEF recommends adding the EEA levels to provide “pre-defined system condition terminology.”
Disagree
Agree
PEF recommends that the color coding and definitions that are used by Homeland Security also be
used for the notification of physical and cyber emergency alerts reported to the RC. This would
follow the ES-ISAC standard already adopted by the electric industry.
Agree
PEF believes additional NERC defined entities (such as Generators Owners) should be made
applicable to this standard. Specifically, PEF believes that the Interchange Authority should be added
due to the communications required between the Reliability Coordinator and the Interchange
Authority. PEF also believes that the adoption of R4 would have major implications on the tagging
process. PEF believes that all tagging would be required to be done using CST due to schedule
check-out between BAs, TSPs, LSEs and RCs. Therefore, PSEs should be made applicable as well for
R3 and R4.
Group
PPL
Annette Bannon
Disagree
Three-part Communication is too prescriptive. How will “all call/blast” communications be handled?
Also, it is unclear what communications are included in Interoperability Communication.
Disagree
It is not clear what real time communications take place with a TSP and/or a LSE that would put the
BES in jeopardy and thus necessitate them to be included as an applicable entity.
Disagree
Will the CPOPs be developed regionally, by RCs, by TOPs, by BAs? Will some entities have to adhere
to various CPOPs since they may operate in various areas? Too many unanswered questions to
support this concept.
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Disagree
This requirement should be applicable to a RC only. Some registered entities may not even receive
these types of communications. Since the responses are the same for all levels noted in attachment
1, there is questionable value to defining this level of additional administrative detail.
Disagree
This requirement is overly prescriptive and the benefit to reliability by switching everyone to CST is
unclear.
Disagree
Only RCs, TOPs, & Bas issue directives. The other entities should be removed from this requirement.
Disagree
The way this could be interpreted is that every type of communication between every applicable
entity would have to use the NATO phonetic alphabet. This would be impractical since many of the
current communications do not require this level of specificity.
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original
requirement intended that neighboring Balancing Authorities use uniform line identifiers when
communicating information about their tie lines. This requirement drops that clarification and
introduces the additional requirement to use pre-determined “equipment” identifiers. Having to
mutually agree in advance on identifiers for every switch & transformer is another example of a
prescriptive requirement whose violation will not affect system reliability, yet will expose entities to
large fines.
No comments either way since this applies specifically to RCs.
Disagree
Disagree
Agree
If this draft standard would be approved as it is currently proposed, the implementation plan is way
too short considering all the process and system changes that are needed to comply with the
numerous additional requirements.
Individual
Scott Berry
Indiana Municipal Power Agency
Disagree
It is not clear in the definition of Interoperability Communication if this is communication between
two outside entities (two different companies) or could apply to communication between two entities
within the same company. For example, communication between a company's generation plant and
the same company's dispatcher.
Disagree
The OPCP SDT does not give a real justified reason on making this requirement move from TOP002-2 to COM-003-1, except saying that the team believes it is appropriate. Unless there is a very
sound or technical justification for moving it, the requirement should be left in the current standard
(TOP-002-2) to reduce the extra work and confusion this may cause among the industry. In
addition, since Inoperability Communication is not clearly defined, if two LSE entities are
communicating, do they have to follow the cummunication protocal required in COM-003?
Disagree
What reliability purpose is served by restating requirements two through seven in a Communications
Protocol Operating Procedure (CPOP)? Since these requirements are the only required items in the
CPOP, entities will just be restating these requirements in their CPOP. In addition, this is an
administrative requirement which does not fit into the new performance-based standard principle
that should be used by SDT's.
Disagree
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No. Does attachment 1 cover all possible communication scenarios and terminology? Using predefined condition terminology does not allow flexiability in communications and for near changes in
communications that might be needed depending on the situation.
Disagree
There is no need to use a common time zone. The time zone should be identified in the
communication, if needed. The reliability benefit is not clear for using one time zone, and the cost
associated with using one time zone will be significant and unnecessary. The use of just CST will
cause confusion, because one ISO has all its systems in EST and another ISO systems has its
systems in EPT. If an entity is required to use CST when verbally communicating to one or both of
these two ISOs, then many mistakes and confusion will result because their portals continue to be in
their respective times.
Disagree
The definition of Interoperability Communications is not clear and this requirement could require
Three-part Communications to communicate routine, internal instructions within an entity. In
addition, the definition of a directive is being worked on by a NERC SDT, and this definition might
help clear up any confusion in this requirement, along with a better definition of Interoperability
Communications.
Disagree
An entity should not be required to use a specific phonetic alphabet. If a letter needs to be clarified,
then boy, bob or beta should be allowed to convey the letter "B". In an emergency, an entity wants
its coordinators to be concentrating on the situation and not worrying about using the proper
phonetic alphabet word for the letter "B".
Agree
This standard is not needed because requirement two in COM-002 takes into account the use of
Three-part Communication which is the main reliability requirement from COM-003. The use of a
procedure (R1), the English language (R3), a standard time zone (R4), the NATO phonetic alphabet
(R6), and a pre-defined system condition terminology (R2) are administrative requirements (not
performance based requirements) and if not used, all of them definitely do not have a high VRF. If
an entity does not use a procedure, but ensures they follow requirement 2 of COM-002 and both
parties have a clear understanding of the directive what other reliability requirement is necessary.
One recommendation might be for the COM-002 Standard Drafting Team or another SDT to come up
with a definition for a directive.
Individual
Michael R. Lombardi
Northeast Utilities
Disagree
The term “Interoperability Communication” creates confusion within the industry and contradicts the
work by RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part
communications when issuing Reliability Directives (defined in Project 2006-06) that address
anticipated and actual emergency conditions. Additionally, it appears that this definition would
encompass all verbal communications and, as such, we question the need for such definition. The
definition of “three-part communication” may be viewed as accurate and consistent with the work
that has been done and substantially progressed through two other SDTs, we believe the RC SDT
requirement, which includes “and shall acknowledge the response as correct or repeat the original
statement to resolve any misunderstandings”, is more complete. Again, we believe the term
“Interoperability Communication” contradicts this work and creates confusion within the industry. It
appears to mandate 3-part communication during operational strategic discussions, as well as other
“non-action” oriented communications. We believe this Requirement would, in fact, be adverse to
reliability instead of enhancing reliability by reducing the amount of pre-action communications that
may occur prior to taking action because operators may be more concerned with not repeating back
during such pre-action, strategic calls and/or discussion.
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Disagree
The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. This
Requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a
directive shall use three-part communications and the recipient of a directive shall also properly
participate in the of use three-part communication protocol until the message has been correctly
spoken and understood. LSEs and TSPs do not own or operate equipment, and as such in a market
environment should not fall under the mandates of this requirement. Neither the TSP nor the LSE
provide or receive information about specific lines or equipment in real-time. Therefore, requirement
R7 should not apply to them absent clear evidence that a realistic (not hypothetical) threat to
reliability would exist if they are omitted. We do not think that such a threat would exist.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions. The NERC BOT has approved pursuing the
Results-based Reliability Standard Ad Hoc Working Group recommendations to assess the existing
standards, modify and develop standards that support reliability performance and risk management,
and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to eliminate administrative requirements. This proposal takes the opposite approach
and incorporates a new administrative requirement. The industry as a whole, based on the response
to the Task Force, does not support such an approach. This Requirement should be deleted from the
Standard.
Disagree
It is not clear what value there is in identifying alert levels since there does not appear to be any
differentiation in actions taken based on the alert levels. Additionally, it has been our experience of
during the field-test of these Alert Levels, that there are inconsistencies in when to implement
various stages of Alerts and, we believe, this introduces more confusion than exists today.
Disagree
There is no reliability need to use Central Standard Time (CST) a common time zone for
communications. Eastern Standard Time (EST) is used in New England and within the NPCC region.
Converting to a different time zone will be confusing to the operators and the field personnel. The
time zone that will be used should be agreed between each operating entity. This should only impact
those entities that cross two time zones. If NERC or a Region were to perform an investigation that
involves entities across the eastern interconnection, it would be appropriate for the investigation
team to request data using a specific time zone.
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part
communications is required to communicate routine operating instructions, or during operational
strategic discussions as well as other “non-action” oriented communications. This Requirement
contradicts the work that has been done and substantially progressed through two other SDTs and
creates confusion within the industry. This Requirement would, in fact, be adverse to reliability
instead of enhancing reliability by reducing the amount of pre-action communications that may
occur prior to taking action because operators may be more concerned with not repeating back
during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person
giving such an order. The entity that needs the action to be taken should establish the need for
three-part communications by stating in the communication that they are issuing a directive. This
would be a clear trigger, auditable, and measurable.
Disagree
Not only does this requirement attempt to determine HOW entities operate with their various
footprints, it may change the way many Markets are structured. What is the difference between
using the word “Zebra” instead of “Zulu” to signify the letter “Z”? And, why would this be
enforceable. Perhaps this should be a guideline document rather than an enforceable Requirement.
There is no reliability need for this Requirement.
Agree
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Disagree
No concerns or suggestions (Disagree = No)
Disagree
(Disagree = No)
Disagree
(Disagree = No)
Agree
Many of the requirement proposed in this posting either reiterate the drafts as posted (i.e. English
language) or introduce confusion when compared to the drafts as posted. The scope should be
limited to R2 and R7, so as not to duplicate or contradict the on-going work of other SDTs. (Agree =
Yes)
Individual
Eric Olson
Transmission Agency of Northern California
Disagree
There is no additional reliability benefit to the proposed applicability of COM-003-1 Requirement R7
to Transmission Service Providers (TSP) and Load Serving Entities (LSE), since TSP and LSE must
already comply with effectively the same terms in TOP-002-2 Requirement R18. Furthermore, TSP
and LSE exposure to penalties and sanctions associated with non-compliance of TOP-002-2
Requirement R18 would effectively be doubled if they were required to also comply with COM-003-1
Requirement R7.
Agree
The requirements of this standard as drafted should not be applicable to Transmission Owners (TO).
This standard pertains to real-time operations, whereas the TO function does not have real-time
operational responsibilities according to the currently effective and proposed NERC Reliability
Functional Model, Versions 4 and 5, respectively.
Group
Florida Municipal Power Agency (FMPA) and some members
Frank Gaffney
Disagree
The definition of Communications Protocol can be improved as: Policies and procedures that govern
how verbal and written communication is exchanged. The definition of Three-part Communication
could be improved by simplifying the language as: A Communications Protocol where information is
verbally stated by a party initiating a communication, the information is repeated back correctly by
the party receiving the communication to the initiating party, and the same information is verbally
confirmed to be correct by the initiating party. The definition of Interoperability Communication can
be improved by using NERC Glossary of Terms definitions, e.g., Element and Facility ought to be
capitalized in the definition, and the use of both Element and Facility is redundant and only the term
Facility needs to be used since a Facility is essentially defined as a BES Element.
Agree
The implementation plan does not specify that TOP 002 2, R18 will be retired. The disposition of the
SAR explains this, but, it should be clear in the implementation plan.
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Disagree
If one of the goals is consistent communications, why would the standard require each Entity to
develop a separate CPOP? For consistency, shouldn’t the Reliability Coordinator develop the CPOP
(with input from the other Entities) and all other Entities within the RC’s area adopt it?
Agree
Disagree
We believe that any time zone can be used as long as the parties come to a common understanding
of time through communication. Also, if an Entity mistakenly starts off a conversation using a time
other than Central Standard Time, but corrects themselves during the 3-part communication
process, is that a violation? We believe not, that as long as the communicating entities come to a
common understanding of time, there is no violation. More clarity on this is desired. We assume
such opportunity to correct mistakes is present throughout the standard and the language of the
standard ought to reflect that. A high VRF is not appropriate, especially if the parties involved in the
communication have a common understanding of the time, who cares what time zone?
Agree
The word “directive” is ambiguous. The standard should either require the Reliability Coordinator to
define a “directive” or the standard should make this a defined term so that there is clarity between
what is and what is not a directive. In fact, the “disposition” does state that “Reliability Directive”
definition is in the scope of the SDT’s effort. We do not think that this merits an increase from a
“Medium” VRF in COM-002-2 R2 to a “High” VRF in this standard, especially if the actual action
taken was in accordance with the direction given.
Disagree
How strict are the NATO pronunciations? E.g., “Uniform” is designated as pronouncing the “i” as a
long “ee”, most people I know do not do that. Similarly, there are multiple pronunciations of
“Quebec”, “Sierra”, “Victor”, “Three”, “Four”, “Five”, and “Nine” to name a few, yet one
pronunciation is specified. We presume that if the wrong pronunciation is used in the current draft of
the standard, there would be a violation, currently at a high risk factor and high severity level, which
seems rather severe. FMPA suggests that the SDT revisit this with an eye towards at least not
penalizing someone for saying “five” instead of “fife”, and possibly with an eye towards saying “’f’ as
in ‘frank’” is OK, rather than being strict with NATO nomenclature.
Agree
For clarity, a NERC Glossary defined term is more appropriate than “line or equipment” identifiers,
such as “Facility” or “Element” identifiers. A VRF of “High” is not appropriate. Note that TOP-002-2,
R18, which this requirement retires, was “Medium”.
Agree
(FMPA assumes that commenting "agree" means "yes, we have suggestions for improvement") It
seems that the first two tables on Physical and Cyber Emergency Alerts are nearly identical. Why not
combine them? On the third table on IROLs, are IROLs the only emergencies, e.g., how about a
capacity / energy emergency? Shouldn’t that be in a table as well?
Disagree
(FMPA assumes "disagree" means that we are not aware of any regional variances)
Disagree
(FMPA assumes that "Disagree" means that we are not aware of any conflicts)
Agree
(FMPA assumes that "Agree" means "Yes, we do have other comments) The Violation Risk Factor for
R2 should be “Low”, not “High”. It is administrative in nature. The Measures make the types of
evidence an “or” statement, e.g., “(e)vidence may include … voice recording, transcripts, operating
logs, OR on site observations” (emphasis added). The Data Retention section seems to make
evidence an “and” statement, e.g., “Each … (Responsible Entity) shall retain … dated operator logs
for the most recent 12 months AND voice recordings or transcripts … for … 3 months” (emphasis
added). These statements are inconsistent with each other and both ought to be “or” statements.
Due to the variability of the length of a month, data retention ought to be expressed in days rather
than months, e.g., 90 days instead of 3 months. Why is the Transmission Owner included in the
applicability of the standard? What “Interoperability Communications” are they involved with? If the
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Transmission Owner is included, why isn’t the Generation Owner? Explain the inconsistent treatment
of Transmission Owners and Generator Owners. R3 – what if an entity starts to communicate in a
language other than English, but, as part of the 3 part communication process changes to English
and completes all steps of 3-part communication in English, is that entity non-compliant or
compliant? How should EOP-001-0, R4.1 coordinate with COM-003-1? Should EOP-001-0, R4.1 focus
on internal Entity communications?
Individual
Darcy O'Connell
California Independent System Operator
Disagree
Three-Part Communications: There is no leeway given if the “intent” of the information is repeated
back correctly. If the initiating party mispronounces a word and the receiver does not, is it a
violation? Also there is a possibility of delaying actions due to multiple repeat backs while attempting
to repeat back verbatim. The air traffic control /pilot communications could be held up as the current
best practice standard in critical communications, and utilizing three-part techniques… and they do
NOT use verbatim word-for-word repeat. Rather the messages are often truncated, but still indicate
an understanding of the message. Interoperability Communication: The proposed definition does not
distinguish between internal and external entities. A more specific term than entity is needed here
for clarity. With no more guidance than provided, a Generation Dispatcher may be considered a
separate entity than the Transmission Dispatcher in the same room. As proposed the definition
opens the doors for wildly different interpretations. We think this term, in this usage, applies to
communication between companies, but we are not sure. Interoperability Communication is a bit of
an unconventional use of the word interoperability. The standard strives to ensure communication
protocols ensure interoperability. Communication Interoperability normally in usage, refers to the
ability of dissimilar systems to exchange data. Its use here is unnecessarily confusing. It’s a rather
messy way of saying, inter-company communication.
Agree
Disagree
CAISO Comment; The requirement does not distinguish between intra and inter communications.
Even though the proposed definition of “Interoperability Communications” is between two “entities”,
how will an auditor interpret it? Will this be taken to the extreme and be required to address
communications between two different functions within one organization? For example, between the
generation desk and the scheduling desk? How important is this plan? This requirement has a low
Violation Risk Factor while the individual requirements that makeup the plan have High Violation
Risk Factors. Furthermore, the Violation Security Levels do not address failure to follow the protocol
in the plan. Based on the VFR and VSL, it is easy to conclude this plan does little in supporting an
adequate level of reliability.
Disagree
CAISO Comments; Regarding CEA; CIP-002 requires responsible entities to identify their cyber
assets and critical cyber assets. This requirement does not address any identification and requires
responsible entities to declare emergency conditions for non-critical assets. How does this provide
an adequate level of reliability? What technical justification did the SDT use in determining an actual
or imminent cyber or physical threat to any BES generating facility, substation, or transmission line
constitute an emergency declaration? Regarding PSEA and CEA; This requirement does not provide
an adequate level of reliability. As a general statement, receiving notification from the RC stating
XXXX BA has identified (actual or imminent) physical or cyber threats affecting 1 or 999 control
center(s), generating facility(ies), substation(s), or transmission line(s) close to your jurisdiction
would provide an adequate level of reliability compared to XXXX BA has declared a PSEA or CEA
condition ORANGE. Why is the SDT promoting requirements that reduce reliability and dumb-down
communications? Is this the correct standard to add a requirement such as this? Physical and Cyber
threats are addressed in the CIP standards and emergencies are addressed in the EOP standards.
Both require notification so why include it in a COM standard? Is there a possibility of double
jeopardy between this requirement and CIP requirements? If this requirement must be included, Per
attachment 1 – COM-003-1 (PSEA and CEA section) the Reliability Coordinator is the only
responsible entity with any defined actions. It is suggested the SDT remove the BA, TO, TOP, GO,
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TSP, LSE, and DP due to lack of applicability. The same entities should be removed from the
measure (M2) also. Until “soft words” such as “threat” and “sabotage” are defined or clarity is
provided the industry should not be proposing standards based upon them. Regarding TEA; What
technical justification did the SDT use in determining that notifying all BA, DP, GOP, TOP, and TO in
the RC area of a possible IROL violation provides an adequate level of reliability? There are no
associated actions for the BA, DP, GOP, TO, and TOP to perform upon notification so what is the
purpose of this requirement? The Alert Level Guide is still in the test phase; does not the Alert Level
Guide need to be approved prior to any standard which references the guide be approved?
Comments: Per attachment 1 – COM-003-1 the Reliability Coordinator is the only responsible entity
with any actions. Suggest removing BA, TO, TOP, GO, TSP, LSE, and DP. Or assign them actions.
The same entities should be removed from the measure (M2) also.
Disagree
CAISO Comments; Any standardization of time zones, in order to enhance reliability or reduce costs
would use GMT as the reference zone in our opinion. The use of Central Standard Time is
problematic because some months of the year other time zones would be at the same time as CST
(Eastern Daylight Savings Time) and others not. Adopting systems that require system operators to
sometimes operate in a time zone that is not their own local time and sometimes to operate in a
time zone that is equivalent to their own local time is standardization that is not actually standard.
How does using Central Standard Time for all verbal and written communication improve or support
reliability? The SDT needs to explain how this requirement provides an adequate level of reliability
for real-time operations for any entity operating outside the Central Standard Time Zone.
Disagree
CAISO Comments: Until “directive” is a defined term the industry should not accept requirements
governing actions regarding directives. Directive is currently being defined in an interpretation.
Subsequent interpretations may subvert the standards drafting process. Terms should be formally
defined before inclusion in other standards to prevent future interpretation issues, including the
changing of a standard outside of the accepted Standard Development process.
Disagree
This requirement is a best practice. Maybe the standardized alpha-numeric communication is
something that companies should be required to train their personnel on, maybe it could even be a
requirement of their CharliePapaOscarPapa. As this requirement is literally written a system operator
who used the word ‘cat’ instead of the word ‘charlie’ when giving a directive would violate a
sanctionable standard with a VRF of ‘High’ and a VSL of ‘Severe’.
Disagree
CAISO Comments; This Requirement is problematic as it doesn’t actually steer towards
standardization. It mandates that companies have potentially scores of agreements agreeing on
terms with each party it interacts with, all of which may be different. It ensures the system operator
will spend more time ensuring terminology is correct for a given inter-company communication and
once again, less time actually reliably operating the system. Standardization can only occur in a
meaningful manner at very minimum, the interconnection level. Also the language in the VSL
section uses “mutually understood”, which the CAISO supports as opposed to the requirement and
measure use “mutually agreed upon”. Mutually agreed upon is overly prescriptive.
CAISO Comments; Information regarding the Alert Level Guide field test has not been widely
circulated and unproductive as of late. Does not the Alert Level Guide need to be approved prior to
any standard which references the guide be approved? What was the outcome of the field testing?
Was reliability enhanced? Attachment 1 describes ‘normal, alert, and emergency operating
conditions’, then goes on to never use those terms again in any meaningful manner. To further
confuse it then mixes color coding of steps with levels. Which is it, Condition Red or Level 3? The
attachment directs Reliability Coordinators to make vague notifications to the functional entities in
its footprint. It directs Reliability Coordinators to make these vague notifications to entities that do
not use, in our case the WECCNet. Is it really anticipated that the Reliability Coordinator calling on
the telephone every DSP in its footprint with a vague notification will be an enhancement to
reliability?
Agree
CAISO Comments; The proposed requirement R7 will cause regions operating in any time zone other
than Central to draft regional standards to avoid this non-reliability supporting requirement.
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Disagree
Agree
The Drafting team should take a hard look at the VRFs and VSLs established in this standard and
contrast them against VRFs and VSLs for other adopted standards. We do not feel, as an example,
that the use of Spanish in a normal communication between two companies, while improper, should
carry a VRF of ‘high’ with a VSL of ‘severe’. The draft standard focuses too much attention on
prescriptive remedy than ensuring understanding.
Individual
Brandy A. Dunn
Western Area Power Administration
Agree
Agree
Agree
Disagree
It’s very confusing to refer to each condition using a color and/or a level number. In other areas, we
are accustomed to using Alert Levels (ie. EEA states). The color designation seems to throw in an
unnecessary element that doesn’t add any value.
Disagree
This could be a potential problem since Operators will need to communicate with field personnel and
local utilities in their local applicable time zone. It could be confusing to communicate by referring to
a different time zone in other instances. It seems like it would make more sense to require that the
time zone being used in a communication must be specifically and clearly referred to and identified.
It doesn’t matter so much WHICH time zone is used, it just matters that everyone understands
which one is being used.
Agree
Disagree
Not everyone is familiar with the NATO phonetic alphabet, so it would be another thing for operators
to have to memorize, or to always have in front of them to refer to.
Agree
Agree
Disagree
Disagree
Disagree
Individual
Catherine Koch
Puget Sound Energy
Agree
Disagree
PSE agrees in the consolidation of communication type activities into one standards, however the
blanket addition of the TSP and LSE across all requirements doesn't seem appropriate. Additional
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thought should be given in the potential for these two entities to participate in the communication
activities contemplated by each requirement, rather than incorporating them wholesale. For
example, a quick search on the term “directive” in the current set of standards indicated that neither
Transmission Service Providers or Load Serving Entities (or even some of the other entities covered
by the proposed standard) are likely to issue directives under the requirements of those standards,
so is it appropriate to subject them to the requirements of Requirement 5?
Disagree
As discussed in Question 2, further consideration should be given to whether it is appropriate to
include all the listed entities in this requirement. Additionally, the phrase “is not limited to” should
be removed from the last sentence of the proposed requirement. The standard should specifically
spell out what should be included in the CPOP. This phrase would lead to confusion about what an
entity must include in the CPOP and is likely to result in inconsistent enforcement of the
requirement. Also R1 appears to require a CPOP that will be used by personnel responsible for Realtime generation control and Real-time operation of the interconnected Bulk Electric System. It is
unclear if this specifity in who has to follow this extends to R2-R7 as well(while as noted the CPOP
has to include elements of R2-R7). Without that clarity, the aspects of R2-R7 could seeming extend
to communication between non-critical personnel regarding non-critical information. In addition, it
appears that each of these entities must develop their own CPOP with clarity how the protocol gets
vetted so that it is effectively employeed across the entities. Finally, when reviewing the Functional
Model document and it's discussion of tasks and relationships to other entities, it is unclear why the
TO is included in the applicability as they perform no real-time functions and provide no real time
information.
Disagree
This requirement, along with the associated M2, will be almost impossible to substantiate for audit
purposes. For example, would an entity be required to present, and an auditor be required to listen
to, voice recorder records for the data retention time? It is difficult to image another way to prove
an entity complied with this requirement. Further the statement "as defined in Attachment 1"
implies a set of definitions can be found and yet Attachment 1 is not structured in such that way. Is
the system condition terminology just the terms "condition yellow", "condition orange", and
"condition red". The procedural and time aspects described in this attachment creates confusion as
to whether compliance is required under this standard or a different one. Suggest, more simplified
presentation of definitions or glossary for clarity. Finally the inclusion of "written" communications
creates a question relative to real-time information or whether this is extending beyond that
timeframe. Most real time information sharing is verbal due to the urgency of it. Suggest removal of
written.
Disagree
The requirement for common time zone should be at the descretion of the Reliability Coordinator in
the respective region to determine. The conversion to CST has no apparent value. It would be much
more reasonable to require communications related to time to include the time zone used in that
communication. If common time zone across the nation is required it should only be imposed on the
RCs as they would communicate with each other more readily than entities to other national entities.
If an entity does not operate within the CST, the need to convert during periods of stress may
increase the potential for error and reduce reliability.
Disagree
The requirement should use the NERC defined term “Reliability Directive,” instead of the general
term “directive.”
Disagree
This requirement is too burdensome when compared to its benefits. The proposed requirement
covers many different types of verbal communication and converts a useful communication protocol
into mandatory requirement, which carries with it large potential penalties. Under this requirement,
an operator’s use of the phrase “M as in Mary” instead of “M as in Mike” would be violation of NERC
reliability standards. The requirement for Three-Part Communications covers most of this ground in
a much more useful fashion and ensures parties understand the information. The use of this protocol
is a matter that should be left for entities to consider for inclusion in their CPOPs, but should not be
a mandatory requirement to use the protocol. Further it is again assumed that based on R1, this
information is related to real time. As well further examples of what a real time issuing of a
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"notification" is and what "other realibiltiy relatied operation information would be needs to be
specified.
Disagree
As discussed in Question 2, Requirement 18 should be removed from TOP-002-2 (or any successor
standard) upon adoption of this standard if this requirement is included in this standard. Further the
term mutually agreed implies that a discussion has occurred prior to the need to verbalize or write
these types of communications. The additional specificity of "pre-determined" is duplicative or leads
one to think there is formal guidance as to what the "identifier" should be. Remove "predetermined". It also begs the question of timeframe which could bring interpretation issues during
an audit.
Disagree
See discussion in Question 4. Also the attachment applies to Reliability Coordinators only, yet the
requirement referencing the attachment applies to additional entities. Those entities should be
removed from Requirement 2 or the attachment and Requirement 2 should be clarified to address
what those additional entities’ responsibilities are under the attachment.
I might suggest one for R4 by each region that is not in the Central Standard Time zone.
Group
NERC Standards Review Subcommittee
Carol Gerou
Disagree
Concerning Three Part Communications: Please clarify by answering the following. Does the word
“correctly” mean repeating back word for word or would paraphrasing the intent of the message
received prove that the receiving party understands the intent and specific action of what they are
required to accomplish? Please verify that Three Part Communications will be required when issuing
directives related to emergency situations, and not every time communications is required between
two parties. We believe the proposed definition for the term “Interoperability Communication” is too
broad and ambiguous. We recommend the following instead: “Communication between two or more
Functional Entities (not within the same organization) to exchange reliability-related information to
be used by the entities to change the state or status of Facilities of the Bulk Electric System.” The
inclusion of the terms “Functional Entities” and “Facilities” removes the ambiguity which we believe
is contained in the proposed definition. (Both of these terms are defined in NERC’s Glossary) In
addition, the inclusion of the phrase “not within the same organization” clarifies that the focus of
definition is to address communication between different Functional Entities. The way the definition
of Three-part Communication is worded applies only when the communication is understood by the
listener the first time. Because the definition requires the listener to repeat the information back
correctly, failure of the listener to understand the information the first time could be construed as a
violation or at least not fitting the definition. The definition should rather reflect that three-part
communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows: A
Communications Protocol where information is verbally stated by a party initiating a communication,
the information is repeated back to the party that initiated the communication by the second party
that received the communication, and the same information is verbally confirmed to be correct or
corrected by the party who initiated the communication. The protocol should be followed until the
party issuing the information is satisfied that a party receiving the information has understood the
communication and confirmed it. We believe there should be a definition added for “Directive” as
orders given in an emergency situation. Directive, as currently used in the industry, is understood to
mean an emergency situation and the party issuing the “Directive” states as such, so everyone
knows it is an emergency situation. In the “Disposition of Requirements identified in the SAR for
Operations Communications Protocols as Possibly Needing either Modification or Movement”
document included with the proposed standard, it is stated that COM-002-2, R2 is being modified in
Project 2006-06 to include a new definition for “Reliability Directive” and that it is to be included in
the NERC Glossary. It also states that when it is completed, it will be moved into COM-003-1 and
COM-002-3 will be deleted. It is our opinion that the definition of Reliability Directive must be
included in the review and approval of COM-003-1, as it is central to many of the actions to be
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taken. We understand that the SDT is working closely with the Drafting Team working on Project
2006-06 and believe that this team needs to use the term “Reliability Directive” as a replacement for
the term “directive” which is in the current version of COM-003-1. The Drafting Team working on
Project 2006-06 has defined Reliability Directive as: “A communication initiated by a Reliability
Coordinator, Transmission Operator or Balancing Authority where action by the recipient is
necessary to address an actual or expected Emergency.” The NSRS recommends use of this
definition and the term “Reliability Directive” as opposed to “directive”.
Disagree
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring
to transmission facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO,
TOP, GOP, TSP, LSE and DP shall use pre-determined, mutually agreed upon line and equipment
identifiers for verbal and written Interoperability Communications. TOP-002 allowed the TOP to
communicate what the line identifiers were via a list and use during communications. The new
requirement implies that the parties must agree upon the line identifiers and that agreement must
be documented. We believe the requirement should require the exchange of line identifies but not
impose that they be mutually agreed upon. This requirement represents a “how” and not a “what”.
In general, standards should be focused on “what” not how.
Disagree
We request that R1 be rewritten for real time operation of elements and facilities connected to the
BES. Based upon the concerns that we have with Requirements R2-R7 we would not support this
requirement. We would support requirement R1 if it stopped after the first sentence and then merely
listed the minimum requirements that should be included in the Procedure such as; (1) time zone,
(2) language spoken, (3) when phonetic alphabet will be used, etc.. This will allow the Entities to
draft their own CPOP per the intent of the requirement and avoid the concerns that we have
documented for the remainder of the requirements. Reliability Standards are supposed to describe
“What” is required, not “How” compliance would be achieved. We believe this proposed Reliability
Standard describes more the the “How”, and is contrary to the Results Based Standards Initiative
being implemented by NERC. The NERC BOT has approved pursuing the Performance-based
Reliability Standard Task Force’s recommendations to assess the existing standards, modify and
develop standards that support reliability performance and risk management, and work on an
overall plan to transition existing standards to a new set of standards. One goal of this effort is to
eliminate administrative requirements. This proposal takes the opposite approach and incorporates a
new administrative requirement. We – and the industry as a whole based on the response to the
Task Force – do not support such an approach. We suggest deleting this Requirement from the
Standard. The CPOP should only apply to verbal communications. It could be implied that written
communications (switching order affecting the BES) must have a CPOP, which would essentially be a
writing guide procedure for how to write a procedure. The CPOP would need to be developed for
each entity on how to write a CPOP and all the requirements contained in this draft standard. Every
entity has unique switching instruction templates that have been developed over time in
negotiations with unions, third-parties, etc, which have detailed procedures for their use. Requiring
the use of a CPOP on top of that is adding additional complexity that adds nothing to the reliability
of the BES.
Disagree
The attachment only applies to the RC. We recommend R2 state that the RC shall use predetermined system condition terminology and the BA, DP, GOP, TOP, and TO shall follow orders and
directives unless such acts violate safety, etc. Either the attachment should be changed or the
requirement should be changed for accurate accountabilities.
Disagree
We believe that requiring the use of Central Standard Time (CST) in the Operating Arena (RealTime) would reduce the level of reliability on a real-time basis. We understand that one of the
primary reasons for going to one time zone is to aid in Event Analysis. It is our belief that during the
analysis of an event, there is adequate time to make the necessary adjustments for time zones. The
Group performing the analysis could require all data being submitted be in one time zone as the
basis. Requiring the use of CST is an added burden to the Operations Staff in real-time that does not
help them.
Disagree
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Without defining “directive” the SDT is leaving the industry in the same situation we are currently in.
As discussed in the response to Question #1 above, it is our opinion that the definition of Reliability
Directive must be developed and included in the discussion of this standard (COM-003-1), and
should be as defined in Project 2006-06: “A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is necessary to address
an actual or expected Emergency.”. Based on the definition of Interoperability Communications, R5
could imply that three-part communications is required to communicate routine operating
instructions. We believe this Requirement contradicts the work that has been done and substantially
progressed through two other SDTs and creates confusion within the industry. We believe this
Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing the
amount of pre-action communications that may occur prior to taking action because operators may
be more concerned with not repeating back during such pre-action, strategic calls and/or discussion.
We support the work being done by the RC SDT and RTO SDT which would define a directive based
on the determination of the person giving such an order. We believe, it should be left to the entity
that needs the action to be taken to establish the need for three-part communications by stating in
the communication that they are issuing a directive. This would be a clear trigger and auditable and
measureable.
Disagree
The required use of the phonetic alphabet should be documented in the Entities CPOP per our
comments to question #3. While this requirement may represent a good utility practice or even a
best practice, it is not so necessary to be enforceable through enforceable requirements. All
information passed by a NERC Certified System operator falls under the scope of Requirement 6:
“directives, notifications, directions, instructions, orders or other reliability related operating
information”. Based on that definition, all communication would fall under this Requirement. The
NATO phonetic alphabet does not allow for the use of numbers ten and beyond. An entity WOULD be
found non compliant for saying “open switch fourteen bravo”. We do not believe this is reasonable
as it adds nothing to the reliability of the BES is too prescriptive and all encompassing and could
potentially confuse or slow down the communication process. We recommend that use of the NATO
phonetic alphabet be included in the NERC operator certification training program and removed from
this standard. As we recommended above, the term “directive” should be replaced with “Reliability
Directive”.
Disagree
Field personnel may not have access to the predetermined agreed to line and equipment identifiers.
Requiring universal use of these identifiers could lead to confusion with field personnel within and
between companies. This could lead to a decrease in the reliability and safety of the BES. As written
R7 is expanding the requirement for agreed upon identifiers. We believe it is not necessary or
required to have agreed upon equipment identifiers between companies as long as the line
identifiers have been agreed upon. TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use
uniform line identifiers when referring to transmission facilities of an interconnected network. COM003-1, R7 states that each RC, BA, TO, TOP, GOP, TSP, LSE and DP shall use pre-determined,
mutually agreed upon line and equipment identifiers for verbal and written Interoperability
Communications. TOP-002 allowed the TOP to communicate what the line identifiers were via a list
and use during communications. The new requirement implies that the parties must agree upon the
line identifiers and that agreement must be documented. We believe the requirement should require
the exchange of line identifiers but not impose that they be mutually agreed upon.
Agree
As Attachment 1 is written it only applies to the RC and is a one-way communications path. The BA,
DP, GOP, TOP, and TO are to be notified by the RC but the attachment doesn’t state what they are
to do with the information. COM-003-1, R1 states that the RC, BA, TO, TOP, GOP, TSP, LSE and DP
are to have a CPOP with the elements in R2 through R7, which refer to Attachment 1. If Attachment
1 is applicable only to the RC, as we recommend, there is no reason to have the other Functions
listed for Attachment 1. Requirement R2 and Measure M2 need to be revised to be applicable to the
RC only. Attachment 1 makes reference to “Distribution Service Providers”. There is no definition of
a Distribution Service Provider in the NERC Functional Model, and we believe this should either be
revised to Distribution Provider, or deleted entirely from the list.
Agree
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If the Central Standard time zone is required as noted in R4, we believe there should be a regional
variance to allow the WECC to select the time zone to use as a standard.
Agree
Attachment 1, Physical Security is a basis for the SAR for Project 2009-02, Disturbance and
Sabotage reporting SDT.
Agree
Without “Directive” being defined, this proposed standard still leaves a huge area that will cause
problems and issues within the industry. We believe the SDT should replace “directive” with
“Reliability Directive” and use the definition developed in Project 20006-06: “A communication
initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where action by
the recipient is necessary to address an actual or expected Emergency.” We believe Reliability
Standard COM-003-1 is entirely too prescriptive, and is in actuality a procedure and not a standard.
The Standard needs to focus on the “What” and not the “How”. If the industry is going to truly
embrace the Results Based Standards Initiative, this standard must be significantly revised to reflect
that philosophy. We believe that the existing standard COM-002 is actually better than this
standard. This standard actually causes more confusion and ambiguity and creates unnecessary or
overly cumbersome requirements that add little or no value to reliability.
Individual
Michael Gammon
Kansas City Power & Light
Disagree
The definition of Three-part Communication applies only when the communication is understood by
the listener the first time. Because the definition requires the listener to repeat the information back
correctly, failure of the listener to understand the information the first time could be construed as a
violation or at least not fitting the definition. The definition should rather reflect that three-part
communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows: “A
Communications Protocol where information is verbally stated by a party initiating a communication,
the information is repeated back correctly to the party that initiated the communication by the
second party that received the communication, and the same information is verbally confirmed to be
correct or corrected by the party who initiated the communication. The protocol should be followed
until the party issuing the information is satisfied that a party receiving the information has
understood the communication and confirmed it.” The definition for Interoperability Communication
is too broad. Currently, this could mean any communication of information. This should be confined
to emergency or unusual operating conditions.
Disagree
Including “equipment” is too broad. This could mean anything and should be limited to transmission
devices that could affect the reliable operation of the bulk electric system.
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be
included in this Standard. This standard only needs to focus on requiring three-part communications
during actual and anticipated emergency conditions and using agreed upon terminology for
switching equipment for bulk electric system.
Disagree
Attachment 1 should be removed from this standard. This is a duplication of the alerts by the NERC
Alerts system and the EISAC. In addition, these are reliability standards and should deal with realtime and expected future reliability issues. Alerts are an inappropriate for this standard.
Disagree
There is no reliability need to use a common time zone for communications. There is already a
requirement to use hour ending for scheduling purposes, inadvertent accounting, CPS and other
standards where needed. There is no additional reliability need to use a common time zone. The
time zone should be identified in the communication. Use of CST will actually cause confusion and
significant, unnecessary costs with no foreseeable reliability benefit. Some of the costs will arise to
change systems such as RCIS, IDC, scheduling and E-Tag systems, etc.
Agree
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Agree
Disagree
Including “equipment” is too broad. This could mean anything and should be limited to transmission
devices that could affect the reliable operation of the bulk electric system.
Disagree
The attachment is inappropriate for this standard and should be removed. See response to question
#4.
Disagree
Disagree
Disagree
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Consideration of Comments on OPCP SDT — Project 2007-02
Consideration of Comments on Project 2007-02 Operating Personnel
Communications Protocols — Standard COM-003-1
The Operating Personnel Communications Protocols Standard Drafting Team (OPCP SDT) thanks all
commenters who submitted comments on the proposed draft COM-003-1 Operating Personnel
Communications Protocols Reliability Standard. This standard was posted for a 45-day public comment
period from November 30, 2009 through January 15, 2010. Stakeholders were asked to provide
feedback on the standard through a special electronic comment form. There were 71 sets of comments
submitted, including comments from more than 280 different people from over 100 companies
representing 9 of the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404 446 2563 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process. 1
Summary Consideration:
The majority of commenters expressed disagreement with the standard.
Definitions:
Most commenters found the proposed definitions confusing. The SDT has removed all three
definitions (Communications Protocol, Three-part Communication and Interoperability
Communication).
•
The term “Three-Part Communications” was subsumed into Requirements R2 and R3 in
the revised standard.
•
The OPCP SDT changed “Interoperability Communications” to become “Operating
Communications,” which is now defined as: “Communication of instruction to change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric
System.”
The OPCP SDT also addressed complaints stating it was unclear if “Interoperability
Communication” included internal communication (communication between functional
entities of the same organization), external communication (communication between
two or more Functional Entities not within the same organization), or both.
“Operating Communication”, the proposed definition to replace “Interoperability
Communication,” addresses changes in state, status, output, or input of any Element or
Facility, capturing all communication that affects BES reliability. The term “Operating
Communication” includes any communication that is requesting a change to the BES,
regardless of whether the communicators are internal or external.
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_Rev%201_20110825.pdf.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Requirements:
Requirement R1 (required entities to have a Communications Protocol Operating Procedure):
•
The majority of the comments stated a Communications Protocol Operating Procedure
(CPOP) would be administrative in nature and would not satisfy the criterion of
enhancing the reliable operation of the BES. The SDT has removed it from the revised
standard.
Requirement R2 (required entities to use pre-defined system condition terminology for verbal
and written Interoperability Communications as defined in an Attachment)
•
Many commenters indicated Requirement R2 should not have been applicable to TSPs
and LSEs. The SDT removed TSPs and LSEs from the standard to be consistent with the
approved SAR.
•
Many commenters indicated that the scope (involving all Interoperability
Communications) of the requirement was too broad.
•
Several commenters indicated that the focus of this requirement was confusing and
mixed guidance with requirements.
•
Several commenters proposed expanding the table of alerts to include the alerts from
EOP-002 – Capacity and Energy Emergencies.
•
Several commenters indicated that this requirement is calling for entities to make
notifications, and take actions under specific conditions, and belongs in other standards.
•
The SDT determined that the notifications in the proposed requirement are not
“communications protocols” and do not belong in COM-003 and removed the
requirement from the revised standard.
Requirement R3 (required entities to use English language for all Interoperability
Communications)
•
Some commenters indicated that there are some places where there are legal
requirements to use a language other than English. The SDT modified the standard
(now Requirement R1, Part 1.1.1) to clarify that this requirement is not applicable where
another language is mandated by law or regulation:
1.1.1 Use the English language when communicating between functional entities,
unless another language is mandated by law or regulation.
Requirement R4 (required entities to use Central Standard Time (24 hour format) for all
Interoperability Communications)
•
The majority of commenters stated Requirement R4 would add confusion for the
operators and decrease reliability. Some recommend the use of another time in place of
Central Standard Time. The SDT modified the standard to require use of the 24 hour
format (new 1.1.2) in all Operating Communications and the inclusion of a time zone
reference (new 1.1.3) only when Operating Communications occur between different
time zones.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
1.1.2. Use the 24-hour clock format when referring to clock times.
1.1.3. When the communication is between entities in different time zones, include
the time, time zone and indicate whether time is daylight saving time or
standard time.
Requirement R5 (required entities to use Three-part Communications when issuing a directive
during verbal Interoperability Communications)
•
Many commenters offered differing recommendations on R5 regarding the application
and Definition of “Reliability Directive.” The proposed term “Reliability Directive” is
being developed by the RC SDT for Project 2006-06. The SDT avoided use of the terms,
“directive” and “Reliability Directive” in the second draft of COM-003.
•
Many commenters recommended splitting proposed Requirement R5 to recognize the
two distinct parties (sending and receiving) in the three part communication process.
The OPCP SDT has done so by separating what had been Requirement R5 into R2 (for
the sender) and Requirement R3 (for the receiver). Together these two requirements.
fully assign the responsibility to accomplish three-part communication.
•
Some commenters expressed concerns regarding potential audit citations if a repeatback was not word-for-word or verbatim. The OPCP SDT added the phrase “not
necessarily verbatim” to address the concern. In other words as long as the
communication is clear and accurately conveys the Operating Communication and its
substantive components, it is acceptable.
R2.
Each Reliability Coordinator, Transmission Operator and Balancing Authority
that issues an oral, two party, person-to-person Operating Communication;
excluding Reliability Directives shall: [Violation Risk Factor: Medium][Time
Horizon: Real-Time]
2.1. Issue the Operating Communication and wait for a response from the
receiver.
2.2. After a response is received , or if no response is received, do one of the
following:
R3.
May 2, 2012
•
Confirm the receiver’s response, if the repeated information is
correct (not necessarily verbatim).
•
Reissue the Operating Communication if the repeated information
is incorrect, or the issuer does not receive a response.
•
Reissue the Operating Communication if requested by the receiver.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator and Distribution Provider that receives an oral two
party, person-to-person Operating Communication excluding Reliability
Directives , shall take one of the following actions:
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Consideration of Comments on OPCP SDT — Project 2007-02
•
Repeat the Operating Communication, (not necessarily verbatim)
and wait for confirmation from the issuer that the repetition was
correct.
•
Request that the issuer reissue the Operating Communication.
Requirement R6 (required entities to use the NATO alphabet during verbal Interoperability
Communications)
•
Many commenters indicated the use of a phonetic alphabet is not necessary and should
not be required, as it will not improve reliability of the BES and that there are no
instances where the absence of its use has resulting in reliability problems. The SDT
disagrees with this comment and believes that enhanced clarity around verbally
conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
•
Commenters stated that requiring strict adherence to and precise pronunciation of the
NATO phonetic alphabet is overly prescriptive, and the proposed standard should allow
for other phonetic clarifiers where clarity on alpha-numeric information is necessary.
The SDT agrees, and modified the Requirement to allow for use of the any correct alpha
numeric clarifier. The revised language was moved into Requirement R1, as Part 1.2.
1.2
When participating in oral Operating Communications and using alphanumeric identifiers, use accurate alpha-numeric clarifiers. 2
Requirement R7 (required entities to use pre-determined, mutually agreed upon line and
equipment identifiers for all Interoperability Communications)
•
Many commenters indicated Requirement R7 should not have been applicable to TSPs
and LSEs. The SDT agrees, and has removed TSPs and LSEs from the standard to be
consistent with the approved SAR.
•
Additional commenters indicated the word “equipment” as used in Requirement R7 was
too broad. The SDT modified the standard to use the defined terms “Element” and
“Facility” instead of “equipment”.
•
Other commenters indicated Requirement R7 addressed a planning function already
included in TOP-002, and should not be included in COM-003. The drafting team
believes communications between entities would be improved when use of predetermined identifiers is required for interface Elements and Facilities. The SDT retained
the concept of R7 and transferred it into Requirement R1, Part 1.1.4.
•
There were additional comments that uniform and mutually agreed line and equipment
identifiers should not be mandated so long as the identifiers are pre-determined. The
SDT agrees documentation of mutual agreement is not necessary, so long as the
identifiers are pre-determined, understood and used during Operating Communications.
The standard has been modified to reflect this change.
2
The North Atlantic Treaty Organization (NATO) Phonetic Alphabet or International Radiotelephony Spelling
Alphabet is one example of a widely utilized set of alpha- numeric clarifiers.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
•
Commenters indicated a general consensus for the mandatory use of line and
equipment identifiers applying only to interface Elements, not Elements or Facilities
internal to the footprint of the entity. The SDT modified the standard to apply only to
interface Elements and Facilities.
1.1.4 When referring to a Transmission interface Element or a Transmission interface
Facility, use the name specified by the owner(s) for that Transmission Element or
Transmission Facility.
Outstanding Minority Issues
Several stakeholders identified potential conflicts between COM-003 and work underway in
Project 2006-06 – Reliability Coordination where another drafting team is also addressing the
use of three-part communications. In Project 2006-06 the proposed requirements focus on the
use of three part communication when issuing and receiving “Reliability Directives.” As
proposed, a Reliability Directive is a directive issued to address an Emergency or an Adverse
Reliability Impact. The OPCP SDT proposes use of three-part communication for all Operating
Communications, which would include Reliability Directives. To prevent double jeopardy, the
second draft of the Implementation Plan for COM-003 proposes retiring COM-002 when COM003 becomes effective.
Some additional comments were received indicating the previously posted standard was too
prescriptive in specifying “how” to communicate, instead of “what.” The SDT proposes that the
second draft of the standard is more focused on “what” protocols to use in specific situations.
Commenters also indicated the proposed standard was unnecessary and would distract
operators from reliably controlling the system. The SDT disagreed based on Blackout Task Force
Report recommendation 26, which calls for tightening communication to improve reliability.
Addendum: As a result of the April 2012 Quality Review, the SDT adopted many changes that
would impact many of the responses in this document. The SDT believes the QR
recommendations provide clarity for the requirements and add discernible reliability value.
•
A significant QR change is the addition of language excluding “Reliability Directives”
from the scope of Operating Communications addressed in R2 and R3. The purpose of
the exclusion is to prevent a potential overlap by requiring the use of three part
communications in two different standards (COM 003-1 and COM 002-3). Thus, several
of the responses in this report indicate that the term, “Reliability Directive” is not used
in COM-003-2 and that is no longer true. Based on the need to distinguish between
Reliability Directives (Operating Communications issued relative to an Emergency) and
Operating Communications (Operating Communications issued anytime there is a need
to communicate about maintenance or a change to an Element or Facility on the BES),
Requirements R2 and R3 now include phrases to indicate they do not apply to
“Reliability Directives”. Retention of the requirements for three-part communication in
COM-002-3, recognizes that failure to effectively communicate during an Emergency
has greater potential risk to reliability than a similar failure during other operating
conditions. Thus noncompliance with three-part communication in COM-002-3 has a
High VRF while as proposed, noncompliance with three part communications for
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Operating Communications during other than Emergencies as proposed in COM-003-1
has a Medium VRF.
•
The SDT believes the proposed definition: Reliability Directive is a subset of Operating
Communication when the Reliability Directive is an instruction to change or maintain
the state, status, output, or input of an Element or Facility of the Bulk Electric System.
While Reliability Directives are excluded from COM 003-01, Requirements R2 and R3,
Reliability Directives are subject to the protocols in Requirement R1.
•
The SDT modified the implementation plan to omit the reference to retirement of COM002-3.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Index to Questions, Comments, and Responses
1.
Do you agree with the adoption of the following new terms for inclusion in the NERC
Glossary and their proposed definitions: Communications Protocol, Three-part
Communication, and Interoperability Communication? If not, please explain in the
comment area. ...................................................................................................................... 22
2.
The SDT incorporated TOP-002-2 Requirement R18 into this new standard COM-003-1 as
Requirement R7. In TOP-002-2, Requirement R18 applies to the Transmission Service
Provider and Load Serving Entity. These entities are now added to COM-003-1. Do you
agree with this proposal? If not, please explain in the comment area. ............................... 74
3.
Requirement R1 of the draft COM-003-1 states, “Each Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission
Service Provider, Load Serving Entity and Distribution Provider shall develop a written
Communications Protocol Operating Procedure (CPOP) for Interoperability
Communications among personnel responsible for Real-time generation control and Realtime operation of the interconnected Bulk Electric System. The CPOP shall include but is
not limited to all elements described in Requirements R2 through R7 to ensure effective
Interoperability Communications.” Do you agree with this proposal? If not, please explain
in the comment area............................................................................................................. 97
4.
Requirement R2 of the draft COM-003-1 states, “Each Responsible Entity shall use predefined system condition terminology as defined in Attachment 1-COM-003-1 for all verbal
and written Interoperability Communications.” Do you agree with this proposal? If not,
please explain in the comment area................................................................................... 121
5.
Requirement R4 of the draft COM-003-1 states, “Each Responsible Entity shall use Central
Standard Time (24 hour format) as the common time zone for all verbal and written
Interoperability Communications.” Do you agree with this proposal? If not, please explain
in the comment area........................................................................................................... 145
6.
Requirement R5 of the draft COM-003-1 states, “Each Responsible Entity shall use Threepart Communications when issuing a directive during verbal Interoperability
Communications.” Do you agree with this proposal? If not, please explain in the comment
area. .................................................................................................................................... 169
7.
Requirement R6 of the draft COM-003-1 states, “Each Responsible Entity shall use the
North American Treaty Organization (NATO) phonetic alphabet as identified in Attachment
2-COM-003-1 when issuing directives, notifications, directions, instructions, orders or
other reliability related operating information that involves alpha-numeric information
during verbal Interoperability Communications.” Do you agree with this proposal? If not,
please explain in the comment area................................................................................... 199
8.
Requirement R7 of the draft COM-003-1 states, “Each Responsible Entity shall use predetermined, mutually agreed upon line and equipment identifiers during for all verbal and
written Interoperability Communications.” Do you agree with this proposal? If not, please
explain in the comment area. ............................................................................................. 226
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
9.
Attachment 1-COM-003-1 is based upon work performed by the Reliability Coordinator
Working Group (RCWG). Do you have any concerns or suggestions for improvement of the
attachment? If yes, please provide in the comment area. (If you are involved in the field
testing of the Alert Level Guide please share any comments regarding the use of the
guideline as it relates to the field test.) .............................................................................. 246
10. Are you aware of any regional variances that would be required as a result of this
standard? If yes, please identify the regional variance. .................................................... 269
11. Are you aware of any conflicts between the proposed standard and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement? If yes,
please identify the conflict. ................................................................................................ 279
12. Do you have any other comments to improve the draft standard? If yes, please elaborate
in the comment area........................................................................................................... 292
May 2, 2012
8
Consideration of Comments on OPCP SDT — Project 2007-02
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Commenter
Organization
Industry Segment
1
1.
Group
Mike Garton
Electric Market Policy
2
X
3
X
4
5
6
X
X
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Bill Thompson
Dominion Resources, Inc. SERC
1
2. Jalal Babik
Dominion Resources, Inc. SERC
1
3. Louis Slade
Dominion Resources, Inc. RFC
6
4. Jack Kerr
Dominion Resources, Inc. SERC
1
2.
Group
Jason L. Marshall
Additional Member
Midwest ISO Standards Collaborators
Additional Organization
Region Segment Selection
1. Jim Cyrulewski
JDRJC Associates, LLC
RFC
8
2. Kirit Shah
Ameren
SERC
1
3. Bill Hutchison
Southern Illinois Power Cooperative SERC
1
4. Greg Mason
Dynegy
NPCC 5
5. Joe Knight
Great River Energy
MRO
1, 3, 5, 6
6. Kenneth A. Goldsmith P.E. Alliant Energy
MRO
4
7. Barb Kedrowski
We Energies
RFC
3, 4, 5
8. Rick Koch
NPPD
MRO
1, 3, 5
9. Alisha Anker
Prairie Power, Inc.
SERC
3
May 2, 2012
X
9
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
10. Larry Larson
Otter Tail Power
MRO
1
11. Randi Woodward
Minnesota Power
MRO
1, 3, 5, 6
12. Ben Porath
Dairyland Power Cooperative
MRO
1, 3, 5
3.
Group
Guy Zito
Additional Member
Additional Organization
4
5
6
7
8
9
NPCC 10
2. Gregory Campoli
New York Independent System Operator
NPCC 2
3. Roger Champagne
Hydro-Quebec TransEnergie
NPCC 2
4. Kurtis Chong
Idnependent Electricity System Operator
NPCC 2
5. Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
6. Chris de Graffenried
Consolidated Edison Co. of New York, Inc. NPCC 1
7. Brian D. Evans-Mongeon Utility Services
NPCC 8
8. Mike Garton
Dominion Resources Services, Inc.
NPCC 5
9. Brian L. Gooder
Ontario Power Generation Incorporated
NPCC 5
10. Kathleen Goodman
ISO - New England
NPCC 2
11. David Kiguel
Hydro One Networks Inc.
NPCC 1
12. Michael R. Lombardi
Northeast Utilities
NPCC 1
13. Randy MacDonald
New Brunswick System Operator
NPCC 2
14. Greg Mason
Dynegy Generation
NPCC 5
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Chris Orzel
FPL Energy/NextEra Energy
NPCC 6
17. Robert Pellegrini
The United Illuminating Company
NPCC 1
18. Saurabh Saksena
National Grid
NPCC 1
19. Michael Schiavone
National Grid
NPCC 1
20. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
21. Gerry Dunbar
Northeast Power Coordinating Council
NPCC NA
22. Lee Pedowicz
Northeast Power Coordinating Council
NPCC NA
Margaret Stambach
X
SERC OC&SOS Standards Review Group
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
May 2, 2012
10
Region Segment Selection
New York State Reliability Council, LLC
Group
3
Northeast Power Coordinating Council
1. Alan Adamson
4.
2
10
X
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
1. Ray Phillips
AMEA
SERC
3, 4
2. Alan Jones
Alcoa
SERC
1, 5
3. Fred Krebs
Calpine
SERC
5
4. Jack Kerr
Dominion VP
SERC
1, 3
5. Louis Slade
Dominion VP
SERC
1, 3
6. Greg Rowland
Duke Energy
SERC
1, 3, 5
7. Laura Lee
Duke Energy
SERC
1, 3, 5
8. Sam Holeman
Duke Energy
SERC
1, 3, 5
9. Scott Watts
Duke Energy
SERC
1, 3, 5
10. Greg Mason
Dynegy
SERC
5, 6
11. Chad Randall
E.ON.US
SERC
1, 3, 5
12. Keith Steinmetz
E.ON.US
SERC
1, 3, 5
13. Jim Case
Entergy Transmission
SERC
1, 3
14. Melinda Montgomery Entergy Transmission
SERC
1, 3
15. Wayne Mitchell
Entergy Transmission
SERC
1, 3
16. Bob Thomas
IMEA
SERC
3, 4, 9
17. Nick Lamotte
LA Generating
SERC
1, 3, 5
18. Timmy LeJeune
LA Generating
SERC
1, 3, 5
19. Jason Marshall
Midwest ISO
SERC
2
20. Randy Castello
Mississippi Power
SERC
1, 3, 5
21. Scott McGough
OPC (Oglethorpe Power) SERC
5
22. Mike Bryson
PJM
SERC
2
23. Bill Thigpen
PowerSouth
SERC
1, 3, 5, 9
24. Tim Hattaway
PowerSouth
SERC
1, 3, 5, 9
25. Glenn Stephens
Santee Cooper
SERC
1, 3, 5, 9
26. Kristi Boland
Santee Cooper
SERC
1,3,5,9
27. Rene' Free
Santee Cooper
SERC
1,3,5,9
28. Tom Abrams
Santee Cooper
SERC
1,3,5,9
29. Gene Delk
SCE&G
SERC
1,3,5
30. John Troha
SERC Reliability Corp.
SERC
10
31. Alvis Lanton
SIPC
SERC
1,3,5
May 2, 2012
2
3
4
5
6
7
8
9
11
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
32. John Rembold
SIPC
SERC
1,3,5
33. Gwen Frazier
Southern Co.
SERC
1,3,5
34. Jim Griffith
Southern Co.
SERC
1,3,5
35. Mike Hardy
Southern Co.
SERC
1,3,5
36. Rocky Williamson
Southern Co.
SERC
1,3,5
37. Annette L. Moore
TVA
SERC
1,3,5,9
38. Bob Pizarro
TVA
SERC
1,3,5,9
39. Ed Rudder
TVA
SERC
1,3,5,9
40. Edd Forsythe
TVA
SERC
1,3,5,9
41. Joel Wise
TVA
SERC
1,3,5,9
42. John Kell
TVA
SERC
1,3,5,9
43. Larry Akens
TVA
SERC
1,3,5,9
44. Sam Austin
TVA
SERC
1,3,5,9
5.
Group
Margaret Ryan
Additional Member
Pacific Northwest Small Utilities Comment Group
3
4
X
X
5
6
7
8
9
Additional Organization Region Segment Selection
1. Central Lincoln PUD
WECC 3
2. Cowlitz PUD
WECC 3
3. Blachly-Lane Electric Cooperative
WECC 3
4. Central Electric Cooperative, Inc.
WECC 3
5. Coos-Curry Electric Cooperative
WECC 3
6. Douglas Electric Cooperative
WECC 3
7. Fall River Electric Cooperative, Inc.
WECC 3
8. Lane Electric Cooperative,Inc.
WECC 3
9. Lincoln Electric Cooperative, Inc.
WECC 3
10. Lost River Electric Cooperative
WECC 3
11. Northern Lights, Inc.
WECC 3
12. Okanogan Country Electric Cooperative, Inc.
WECC 3
13. Raft River Electric Cooperative,Inc.
WECC 3
14. Salmon River Electric Cooperative, Inc.
WECC 3
15. Umatilla Electric Cooperative
WECC 3
May 2, 2012
2
12
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
16. West Oregon Electric Cooperative, Inc.
WECC 3
17. Consumers Power Inc.
WECC 3
18. Clearwater Power Company
WECC 3
19. Pacific Northwest Generating Cooperative
WECC 4
6.
Group
Martin Kaufman
Additional Member
ExxonMobil Research and Engineering
Additional Organization
ExxonMobil Corp - Baton Rouge
SERC
NA
2. Joe Gourley
ExxonMobil Oil Corporation Beaumont Refinery SERC
NA
3. Brock Pearson
ExxonMobil Refining and Supply Company
Group
Patti Metro
Additional Member
NRECA RTF Members
Additional Organization
5
6
7
8
9
X
X
X
X
Region Segment Selection
Old Dominion Electric Cooperative
SERC
4
South Mississippi Electric Power Association SERC
5
3. John Alberts
Wolverine Power Cooperative
RFC
1
4. Noman Williams
Sunflower Electric Power Corporation
SPP
1
5. Bob Solomon
Hoosier Energy
RFC
1
6. Chris Bolick
Associated Electric Cooperative
SERC
1, 3
7. John Bussman
Associated Electric Cooperative
SERC
1, 3
8. Mike Avant
Garkane Energy
WECC NA
Mike Bryson
X
X
2. Steve McElhaney
Group
4
ERCOT NA
1. Mark Ringhausen
8.
3
Region Segment Selection
1. David Cheshire
7.
2
PJM
X
Additional Member Additional Organization Region Segment Selection
1. Patrick Brown
PJM
RFC
2
2. Albert DiCaprio
PJM
RFC
2
3. William Harm
PJM
RFC
2
4. Tom Bowe
PJM
RFC
2
9.
Group
Mike Bryson
Additional Member
1. Jeff Boltz
May 2, 2012
PJM SOS Comments
Additional Organization
First Energy
X
Region Segment Selection
RFC
1
13
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
2. Stephen Alexander PEPCO
RFC
1, 3
3. Bill Keagle
Baltimore Gas & Electric
RFC
1, 3
4. Carl J. Eng
Dominion Virginia Power
SERC
1, 3
5. Ron Warton
PSE&G
RFC
1, 3
6. Doug Myers
PPLEU
RFC
1, 3
7. Tom Bowe
PJM Interconnection
RFC
2
8. Raj Rana
AEP
RFC
1, 3
9. Bob Fannin
Dayton Power and Light
RFC
1, 3
10. David Mahler
Duquesne Light
RFC
1, 3
11. Kenneth Keilholtz
RRI Energy
RFC
5
12. Stephen Kimish
PSEG Energy Resources and Trade RFC
1, 3
13. Stephen C. Knapp
Constellation Energy
1, 3
10.
Group
Howard Rulf
RFC
We Energies
2
3
4
5
X
X
X
X
X
X
6
7
8
9
Additional Member Additional Organization Region Segment Selection
1. Tom Hawley
2. Rob Martin
11.
Group
Jason Shaver
ATC and ITC
X
Additional Member Additional Organization Region Segment Selection
1. Michael Ayotte
12.
Group
ITC
Sam Ciccone
MRO
1
FirstEnergy
X
X
Additional Member Additional Organization Region Segment Selection
1. Dave Folk
FirstEnergy
RFC
1, 3, 4, 5, 6
2. Doug Hohlbaugh
FirstEnergy
RFC
1, 3, 4, 5, 6
3. Steve Megay
FirstEnergy
RFC
1
4. John Martinez
FirstEnergy
RFC
1
5. Andy Hunter
FirstEnergy
RFC
1
6. John Reed
FirstEnergy
RFC
1
7. Jim Eckels
FirstEnergy
RFC
1
8. John Wilson
FirstEnergy
RFC
1
May 2, 2012
14
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
9. John TeSelle
FirstEnergy
RFC
3
10. Larry Herman
FirstEnergy
RFC
3
11. Kevin Querry
FirstEnergy
RFC
6
12. Brian Orians
FirstEnergy
RFC
5
13. Bill Duge
FirstEnergy
RFC
5
13.
Group
Richard Kafka
Additional Member
Pepco Holdings, Inc. - Affiliates
Additional Organization
Potomac Electric Power Company RFC
1
2. Steve Alexander
Potomac Electric Power Company RFC
1
3. JB Rogers
Delmarva Power & Light
RFC
1
4. Vic Davis
Delmarva Power & Light
RFC
1
5. John Keller
Atlantic City Electric
RFC
1
6. Paul Wassil
Conectiv Energy Supply, Inc
RFC
5
7. Kara Dundas
Conectiv Energy Supply, Inc
RFC
5
Group
JT Wood
3
X
X
X
X
X
X
4
5
6
X
X
X
X
7
8
9
Region Segment Selection
1. Dave Thorne
14.
2
Southern Company Transmission
Additional Member Additional Organization Region Segment Selection
1. SERC SOS
15.
Group
SERC
Kenneth D. Brown
Additional Member
SERC
PSEG Companies
Additional Organization
Region Segment Selection
1. Ron Wharton
PSE&G ESOC
2. Steve Kimmish
PSEG Energy Resources & Trade RFC
6
3. Dave Murray
PSEG Power LLC
RFC
5
4. Dom DiBari
Odessa Power Partners
ERCOT 5
5. Clint Bogan
PSEG Power Connecticut
NPCC
5
6. Jim Hebson
PSEG ER&T
NPCC
6
16.
Group
Howard Gugel
RFC
1, 3
NERC Staff
Additional Member Additional Organization Region Segment Selection
May 2, 2012
15
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
2
3
4
5
6
X
X
7
8
9
1. Laurel Heacock
2. Bob Cummings
3. Larry Kezele
4. Ed Ruck
5. Todd Thompson
6. Mark Vastano
7. Roman Carter
8. Jule Tate
9. David Taylor
10. Maureen Long
11. Andy Rodriquez
12. Stephanie Monzon
13. Steve Crutchfield
14. Harry Tom
15. Edd Dobrowolski
16. Al McMeekin
17.
Group
Terry L. Blackwell
Santee Cooper
X
Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams
Santee Cooper
SERC
1
2. Glenn Stephens
Santee Cooper
SERC
1
3. Jim Peterson
Santee Cooper
SERC
1
4. Rene' Free
Santee Cooper
SERC
1
5. Vicky Budreau
Santee Cooper
SERC
1
6. Wayne Ahl
Santee Cooper
SERC
1
18.
Group
Denise Koehn
Additional Member
Bonneville Power Administration
Additional Organization
X
Region Segment Selection
1. Tedd Snodgrass
Transmission Dispatch
WECC 1
2. Tim Loepker
Transmission Dispatch
WECC 1
3. Jim Burns
Transmission Technical Operations WECC 1
May 2, 2012
X
16
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
19.
Group
Ben Li
Additional Member
IRC Standards Review Committee
Midwest ISO
MRO
2
2. Al Dicaprio
PJM
RFC
2
3. Mark Thompson
AESO
WECC 2
4. Charles Yeung
SPP
SPP
5. Steve Myers
ERCOT
ERCOT 2
6. Matt Goldberg
4
5
6
X
X
X
X
7
8
9
10
X
ISO-NE
NPCC
2
2
7. Lourdes Estrada-Salinero CAISO
WECC 2
8. Jim Castle
NPCC
Group
3
Additional Organization Region Segment Selection
1. Bill Phillips
20.
2
NYISO
Annette Bannon
2
PPL
X
Additional Member Additional Organization Region Segment Selection
1. Gary Bast
PPL Electic Utilities
RFC
2. Jon Williamson
PPL EnergyPlus
WECC 6
3. Mark Heimbach
PPL EnergyPlus
MRO
4. Mark Heimbach
PPL EnergyPlus
NPCC 6
5. Mark Heimbach
PPL EnergyPlus
RFC
6
6. Mark Heimbach
PPL EnergyPlus
SERC
6
7. Mark Heimbach
PPL EnergyPlus
SPP
6
8. Annette Bannon
PPL Generation
RFC
5
9. Annette Bannon
PPL Generation
NPCC 5
10. Annette Bannon
PPL Generation
WECC 5
21.
Group
Frank Gaffney
Additional Member
Additional Organization
Lakeland Electric
2. Cairo Venegas
Fort Pierce Utilitiiese Authority
Group
Carol Gerou
May 2, 2012
6
Florida Municipal Power Agency (FMPA) and some
members
1. Jim Howard
22.
1
X
X
X
Region Segment Selection
FRCC
1, 3, 5
1, 3, 4, 5
MRO NERC Standards Review Subcommittee
X
17
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
Additional Member
Additional Organization
3
4
5
6
X
X
X
X
X
X
X
X
7
8
9
10
Region Segment Selection
1. Chuck Lawrence
American Transmission Company
MRO
1
2. Tom Webb
WPS Corporation
MRO
3, 4, 5, 6
3. Terry Bilke
Midwest ISO Inc.
MRO
2
4. Jodi Jenson
Western Area Power Administration MRO
1, 6
5. Ken Goldsmith
Alliant Energy
MRO
4
6. Alice Murdock
Xcel Energy
MRO
1, 3, 5, 6
7. Dave Rudolph
Basin Electric Power Cooperative
MRO
1, 3, 5, 6
8. Eric Ruskamp
Lincoln Electric System
MRO
1, 3, 5, 6
9. Joseph Knight
Great River Energy
MRO
1, 3, 5, 6
10. Joe DePoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
11. Scott Nickels
Rochester Public Utilties
MRO
4
12. Terry Harbour
MidAmerican Energy Company
MRO
6, 1, 3, 5
23.
Individual
Brent Ingebrigtson
E.ON U.S. LLC
X
24.
Individual
Silvia Parada-Mitchell
Transmission Owner
X
25.
Individual
Sandra Shaffer
PacifiCorp
X
26.
Individual
Robert Ganley
New York State Reliability Council
27.
Individual
Dania Colon
PEF
X
28.
Individual
James Sharpe
South Carolina Electric and Gas
X
29.
Individual
Martin Bauer
Bureau of Reclamation
30.
Individual
Kasia Mihalchuk
Manitoba Hydro
31.
Individual
Tim Hattaway
PowerSouth Energy
32.
Individual
Joylyn Stover
Consumers Energy
May 2, 2012
2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
18
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
33.
Individual
Jonathan Appelbaum
Long Island Power Authority
X
34.
Individual
Richard Appel
Sunflower Electric Power Corp.
X
35.
Individual
Kevin Koloini
American Municipal Power
36.
Individual
Edward Bedder
Orange and Rockland Utilities, Inc.
X
37.
Individual
Noman Williams
Sunflower Electric Power Corporation
X
38.
Individual
Mark Ringhausen
Old Dominion Electric Cooperative
39.
Individual
Misty Revenew
Westar Energy
X
40.
Individual
Bob Casey
Georgia Transmission Corp
X
41.
Individual
Tracy Sliman - System
Operations Compliance
Tri-State Generation & Transmission Assoc.
X
42.
Individual
Joe O'Brien
NIPSCO
43.
Individual
Joe Knight
44.
Individual
45.
2
3
4
X
5
6
8
9
X
X
X
X
X
X
X
X
X
X
X
X
Great River Energy
X
X
X
X
Fred Meyer
The Empire District Electric Company
X
X
X
Individual
Ed Davis
Entergy Services
X
X
X
X
46.
Individual
Gordon Rawlings
British Columbia Transmission Corporation
X
47.
Individual
Greg Rowland
Duke Energy
X
X
X
X
48.
Individual
Frank Cumpton
Transmission System Operations
X
49.
Individual
Greg Mason
Dynegy
May 2, 2012
7
X
19
10
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
2
3
4
5
6
X
X
50.
Individual
Dustin Smith
Washington City Light & Power
51.
Individual
Kirit Shah
Ameren
52.
Individual
Kathleen Goodman
ISO New England Inc.
53.
Individual
Henry Masti
NYSEG
54.
Individual
Jose Medina
NextEra Energy Resources, LLC
55.
Individual
Dan Rochester
Independent Electricity System Operator
56.
Individual
Daryl Curtis
Oncor Electric Delivery
57.
Individual
Brady Baker
City Of Greenfield
58.
Individual
James H. Sorrels, Jr.
American Electric Power
X
X
X
X
59.
Individual
Alice Murdock
Xcel Energy
X
X
X
X
60.
Individual
Laura Zotter
ERCOT ISO
61.
Individual
Leland McMillan
NorthWestern Energy
X
X
62.
Individual
Saurabh Saksena
National Grid
X
X
63.
Individual
Roger Champagne
Hydro-Québec TransEnergie
X
64.
Individual
Brett Koelsch
Progress Energy Carolina, Inc
X
65.
Individual
Scott Berry
Indiana Municipal Power Agency
66.
Individual
Michael R. Lombardi
Northeast Utilities
X
67.
Individual
Eric Olson
Transmission Agency of Northern California
X
May 2, 2012
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
20
Consideration of Comments on OPCP SDT — Project 2007-02
Commenter
Organization
Industry Segment
1
68.
Individual
Darcy O'Connell
California Independent System Operator
69.
Individual
Brandy A. Dunn
Western Area Power Administration
X
70.
Individual
Catherine Koch
Puget Sound Energy
X
71.
Individual
Michael Gammon
Kansas City Power & Light
X
May 2, 2012
2
3
4
5
6
7
8
9
X
X
X
X
X
21
10
Consideration of Comments on OPCP SDT — Project 2007-02
1. Do you agree with the adoption of the following new terms for inclusion in the NERC Glossary and their
proposed definitions: Communications Protocol, Three-part Communication, and Interoperability
Communication? If not, please explain in the comment area.
Summary Consideration:
Most commenters who responded to this question indicated all three of the proposed definitions were confusing and had little
bearing on improving communication clarity. The SDT has removed all 3 definitions.
Based on these comments, the SDT deleted the term “Three-Part Communications” but will be covered in the requirements (R2 and
R3) of second draft of the standard.
The OPCP SDT deleted “Interoperability Communications” and replaced it with “Operating Communications,” which is defined as:
“Communication of instruction to change or maintain the state, status, output, or input of an Element or Facility of the Bulk
Electric System.”
The OPCP SDT also responded to comments that the definition of “Interoperability Communication” did not clearly indicate if it
included internal communication (communication between functional entities of the same organization), external communication
(communication between two or more functional entities not within the same organization), or both. The proposed definition of the
new term “Operating Communication” includes communications that change or maintain the state, status, output, or input of any
Element or Facility. As such, the term “Operating Communication” includes any communication that is requesting a change to the
BES, regardless of whether the communicators are internal or external and regardless of whether the communications are oral or
written.
Some commenters indicated concerned that the terms “facilities” and “elements,” were not capitalized in the proposed definition of
Interoperability Communications. The defined terms “Facility” and “Element” are capitalized in the new proposed definition of
Operating Communication.
The term “Communication Protocol” was never specifically mentioned in the standard so the SDT has eliminated it from the second
draft of the standard.
Organization
Yes or No
British Columbia
Transmission
Agree
May 2, 2012
Question 1 Comment
22
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Corporation
Bureau of
Reclamation
Agree
ExxonMobil Research
and Engineering
Agree
NextEra Energy
Resources, LLC
Agree
NorthWestern
Energy
Agree
Oncor Electric
Delivery
Agree
PacifiCorp
Agree
Puget Sound Energy
Agree
South Carolina
Electric and Gas
Agree
Sunflower Electric
Power Corporation
Agree
Transmission Owner
Agree
Western Area Power
Administration
Agree
Xcel Energy
Agree
Washington City
Light & Power
Disagree
ATC and ITC
Disagree
May 2, 2012
ATC believes that the proposed definition for the term “Interoperability Communication” is too broad and
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
ambiguous. We recommend the following: “Communication between two or more Functional Entities (not
within the same organization) to exchange reliability-related information to be used by the entities to change
the state or status of Facilities of the Bulk Electric System.” The inclusion of the terms “Functional Entities”
and “Facilities” removes the ambiguity which we believe is contained in the proposed definition. (Both of
these terms are defined in NERC’s Glossary) In addition, the inclusion of the phrase “not within the same
organization” clarifies that the focus of definition is to address communication between different Functional
Entities.
Response: We agree with most of your comments. The SDT is eliminating the term “Interoperability
Communications” because of comments citing ambiguity. We have revised the draft standard by defining
the new term “Operating Communications.” With this new definition including all communications that
change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System,
the SDT believes it has removed any ambiguity over the utilization of communication protocols between
or among Functional Entities in the same or in other organizations.
ATC understands that this Drafting Team is working closely with the Drafting Team working on Project 200606 and believes that this team needs to use the term “Reliability Directive” as a replacement for the term
“directive” which is currently being used. The Drafting Team working on Project 2006-06 has defined
Reliability Directive as:”A communication initiated by a Reliability Coordinator, Transmission Operator or
Balancing Authority where action by the recipient is necessary to address an actual or expected Emergency.”
Response: The current draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
Response: The SDT thanks you for your comments. Please see our responses above.
Bonneville Power
Administration
May 2, 2012
Disagree
BPA does not agree with the aspects of Interoperability Communications.
We do not need a common time standard.
Why use the NATO Standard. This could add a lot of time to a directive that needs to be given
immediately.
The 3 part communication is already used by BPA.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comments.
1. The SDT has eliminated the term Interoperability Communications.
2 The SDT is proposing an alternative to a single time zone that should address your concern. In the second draft of the standard references to
time zones are only required when those involved in the communication are in different time zones.
3. The SDT is proposing the use of a correct alpha-numeric clarifier instead of explicitly requiring the use of the NATO phonetic alphabet, and
does not agree that it would add an inordinate amount of time to communications.
4 The SDT acknowledges BPA’s use of three-part communications.
Orange and Rockland
Utilities, Inc.
Disagree
Clarification must be made to the definition "Interoperability Communication" and to the specific
applicability of the term as it translates into the actions and functions both internal and external to the local
TO.
Response: The SDT thanks you for your comments.
The SDT is eliminating the term Interoperability Communications because of comments citing ambiguity. We have revised the draft standard by
defining the new term “Operating Communications.” With this new definition including all communications that change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System, the SDT believes it has removed any ambiguity over the utilization
of communication protocols between or among Functional Entities in the same or in other organizations.
Manitoba Hydro
May 2, 2012
Disagree
Comments:
Agree to the adoption, but not the definitions as defined.
1. Communication Protocol - Remove “written” from this definition. Create a new standard that defines
“written” protocol, i.e.: express “24 hour format”, common date format, etc.
Response: “Communication Protocol” has been removed as a defined term. The SDT believes references
to written protocols in some elements of the requirements are justified and these have been retained in
the revised standard.
a) Using “written” in this definition and which is also used in COM-003-1 R2, R3, R4 and R7 clouds both the
Definition and the Standard. The majority of COM-003-1 requirements also focus on the spoken word, such
as the use of English, Phonetics and Three-way Communication.
Response: The SDT believes “written” is appropriate in some cases, and has chosen to retain it. Operating
Communications can be “written” in some cases, and use of these protocols in those cases will add clarity.
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Consideration of Comments on OPCP SDT — Project 2007-02
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Yes or No
Question 1 Comment
b) “Communications” in the Definition infers verbal communication especially when examining the COM003-1 Standard where its purpose is “timely information in alerts and emergencies”.
Response: The SDT respectfully disagrees that “Communications” in the definition applies solely to verbal
communication. The SDT has removed the proposed definition “Interoperability Communications” and
proposes a new definition, “Operating Communication.” The requirements in the draft standard specify
when protocols are required for written, oral or both types of communication.
c) When COM-001-1 R4 “English” and COM-002-2 R2 “Three-way” requirements are amalgamated into COM003-1, the COM-003-1 standard will now strengthen the focus on the process of verbal communications.
Response: The SDT agrees with your comments.
d) COM-003-1 R2 “Uniform Line Identifiers” This requirement would be used in real time reliability situations,
alerts and emergencies. The “written” communications would be used after the fact and therefore “written”
does not belong in the definition.
Response: The SDT questions if you meant R7 instead of R2 as written. Nonetheless, the SDT believes
utilizing uniform line identifiers for interface Elements/Facilities for both oral and written communications
adds clarity and contributes to the accuracy of operating instructions.
e) In COM-003-1 R3 “use English” The purpose of this standard is convey information effectively during alerts
and emergencies. “Written” would be used after the fact and therefore does not belong here.
Response: The SDT does not agree the purpose of this standard is to only convey information effectively
during alerts and emergencies, and also does not agree that written communication is necessarily “after
the fact” communication“. The revised standard requires English in both written and oral “Operating
Communications” when communicating between functional entities, unless another language is mandated
by law or regulation.
f) In COM-003-1 R4 “24 hour format” “Written” could be reserved for a new standard, which could which
define “24 hour format” along with a common date format which is also needed.
Response: The SDT believes the requirement for use of 24 hour format should apply to both oral and
written communication, and sees no need to create a separate standard. The term 24 hour format is
commonly understood and does not require definition. With real-time communications, the SDT does not
believe it is necessary to include a common date format.
g) In COM-003-1 R5 “Three-part Communication” Focuses entirely on the spoken word and appears
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
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Yes or No
Question 1 Comment
appropriate that “written” is not used here.
Response: The SDT agrees with the comment, and the revised draft standard clarifies that three part
communication is only required for oral communication.
h) In COM-003-1 R6 “Phonetics” Focus on the spoken word and would never be used to empathize a written
word and is appropriate that is not used here.
Response: The SDT agrees with your comment and has modified the standard to clearly indicate phonetic
clarifiers are only required for oral communications.
i) COM-003-1 R7 states “Operating State Levels” All communications for broadcasting these alerts would
typically be verbal. “Written” communications would be after the fact.
Response: The SDT believes that Operating State levels could be written or oral. Note, however, that
based on stakeholder comments, the SDT has removed Requirement R2 from the second draft of the
standard. In addition, written communication is not always after the fact.
2. Three-part Communication - Use COM-002-2 R2 requirement as an improved basis for the “Three-part
Communication” glossary term and define each part of the three parts separately.
a) This new NERC Glossary term is better defined in the COM-002-2 R2 “Three-part communication”
requirement.” Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall issue
directives in a clear, concise, and definitive manner; shall ensure the recipient of the directive repeats the
information back correctly; and shall acknowledge the response as correct or repeat the original statement
to resolve any misunderstandings.”
b) The current glossary term is overwhelming and confusing with the “back and forth” exchange of
responsibilities. More thought process is consumed trying to break down the definition into usable portions,
then comprehending the definition itself.
c) The glossary term should be more clearly defined by specifying each of the three part communication
protocol;
i. An initiating party verbally issues directives in a clear, concise and definitive manner.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
ii. The receiving party shall replicate the intent of the directive and
iii. The initiating party shall acknowledge to their satisfaction that the receiving party fully understands and is
c.
capable of caring out the directive.
Response: The SDT has removed the definition for “Three-part Communication” from the second draft of
the standard and has instead included the details of implementing three-part communication in
Requirements R2 and R3 in the second draft of COM-003-1.
3. Interoperability Communication - Define further and/or define entities. Expand “interoperability” and add
and define “entity”
a) Using “interoperability” and “entities” in same glossary term, clouds the definition especially when this
glossary term is used to help clarify requirements in COM-003-1.There are at least three possible levels of
“Interoperability” from a Control Center point of view;
i. Internally, within a utility.-Communication between the Balancing Authority and Transmission for reliability
purposes (within control center).-Between BA, TO, TOP, GO, TSP, LSE and DP, such as between the sending
and receiving end of an HVDC terminal.
ii. Externally, between neighbouring utilities.
iii. Externally, between the Balancing Authority and their Reliability Coordinator. For a Reliability Coordinator
two more levels of “Interoperability” could be added:
iv. Communication between Reliability Organizations.
v. Communication between the three major interconnections.
b) Though the glossary definition surely includes all of the above, it does not clarify that and becomes
immediately clouded when interpreting COM-003-1 R1 where “personnel” is used for real time control for
effective Interoperability Communication.1. Personnel - individual responsible for the operation of the
interconnected bulk electrical system (real time, planning, etc)c) Adding and defining Entity in the glossary as
per suggestions;
i. “Entities” are used commonly in the Reliability Standards and encompasses a lot of different contexts.
ii. “Entity” defined by a dictionary includes a comprehensive range such as:-body-Unit-Group-Thing-Article
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
iii. Entity in a interoperable power system:- BA, TO, GO, TSP, LSE, etc- Neighbouring BA, Control Area,
Neighbour (Utility)- Reliability Coordinator, MISO, Reserve sharing Group, etc- NERC, MRO, WECC, NPCC,
ERCOT, etc- Western Interconnection, Eastern Interconnection, ERCOT.
Response: The SDT has eliminated the term “Interoperability Communications” because of comments
citing ambiguity. We have revised the draft standard by defining the new term “Operating
Communications.” With this new definition including all communications that change or maintain the
state, status, output, or input of an Element or Facility of the Bulk Electric System, the SDT believes it has
removed any ambiguity over the utilization of communication protocols between or among Functional
Entities in the same or in other organizations.
Response: The SDT thanks you for your comments. Please see our responses above.
New York State
Reliability Council
Disagree
Comments:
NYSRC agrees with the definitions for Communication Protocol.
Response: “Communication Protocol” has been removed as a definition as it was not used except in the
title of the standard.
NYSRC disagrees with the definition for Three-Part Communication. NYSRC prefers the process offered in
COM-002-03 (draft). In COM-003 the listener must understand the communication the first time. Failure to
understand and repeat back correctly could be a violation of the requirement. The intent three part
communication is to have an iterative process whereby the person issuing the message is ultimately satisfied
that the recipient understands the information and will perform the required action. It should not be
defined as three steps and only three steps.
NYSRC offers the following definition: A Real-Time Operating Communications Protocol where information is
verbally stated by a party initiating a communication, the information is repeated back to the party that
initiated the communication by the second party that received the communication, and the information is
verbally confirmed to be correct or corrected by the party who initiated the communication. The protocol
should be followed until the party issuing the information is satisfied that a party receiving the information
has understood the communication and confirmed it.
Response: The SDT has removed the definition for “Three-part communication” and has included revised
language for the protocol in the second draft of COM-003-1 Requirements R2 and R3. Requirements R2
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
and R3 in the second draft of the standard addresses your concerns.
NYSRC disagrees with the definition of Interoperability Communication. NYSRC believes the Standard is
addressing the communication of the Operating State of BES equipment and facilities. The proposed
definition utilizes the phrase “change the state ... of a BES facility” which can be interpreted as the position,
e.g. open, close, tap position, etc., thereby extending this Standard into routine switching and operation of
the BES. The SAR stated this Standard was “to use specific communications protocols under normal,
abnormal and emergency conditions to relay critical reliability-related information in a timely and effective
manner”. The proposed definition can be interpreted in a manner that extends this to all reliability related
information for every BES operation
Response: The SDT has addressed your concerns by eliminating the term “Interoperability
Communications” and revised the draft standard to include the new term “Operating Communications,”
which includes all communications that change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System. However, please note the SDT believes that even routine
switching could affect reliability if proper communications protocols are not used.
The drafting team should also consider adding a definition for Directive or acknowledge the definition in
draft Com-002-03.
Response: The second draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
Response: The SDT thanks you for your comments. Please see our comments above.
NRECA RTF Members
May 2, 2012
Disagree
Comments:
We agree with the new terms for inclusion in the NERC Glossary.
We are somewhat concerned that in this version of the draft standard there was no definition for “directive”
included. We do understand that the term “directive” is no longer capitalized in this version of the standard,
therefore, not required to be included in the NERC Glossary. Since several requirements of this draft
standard require certain actions when a “directive” is issued, the term should be defined. It is necessary to
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
define the term “directive” to ensure that just normal conversations between entities are not later
“interpreted” to be a “directive”.
Response: The SDT thanks you for your comments.
Response: The second draft version of COM-003-1 does not use the terms “directive” or “Reliability Directive,” instead using the new term
“Operating Communications.” The SDT is working to coordinate with Project 2006-06 to eliminate any potential conflicts between the
standards.
Pacific Northwest
Small Utilities
Comment Group
Disagree
Communication protocols extend beyond the verbal and written versions. How does the “non-routable
(communication) protocol” of CIP-006 fit into or not fit into these definitions?
Response: The SDT thanks you for your comments.
The SDT feels “non-routable (communication) protocol” of CIP-006 falls outside of the scope of the COM-003-1 standard, which deals with oral
and written Operating Communications. If you feel it is within the scope, please elaborate.
Consumers Energy
Disagree
Communications Protocol and Three Part Communications have been used in the industry and are
acceptable. There seems to be a better way of stating “informational” communications since Directives are
already discussed.
Response: The SDT thanks you for your comments.
The SDT agrees with your statements, and has revised the draft of COM-003-1 to eliminate the previous definitions. The SDT is proposing a new
term, “Operating Communications,” which includes all communications that change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.
We Energies
May 2, 2012
Disagree
Communications Protocol: This defined term appears only in the Three-part Communication definition and
in titles. Titles are expected to be capitalized and are not necessarily the defined term. The COM-003-1
Standard title is “Operating Personnel Communications Protocols”, but the purpose is not restricted to verbal
and written information, so “Communications Protocol” does not seem to refer to the defined term in this
title. Similarly, it is not necessarily the defined term in CPOP. It is not clear where this definition is being
utilized in the standard.
Response: The SDT agrees and has removed the definition of “Communications Protocol.”
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Consideration of Comments on OPCP SDT — Project 2007-02
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Three-Part Communication: Should be required for “Reliability Directives” only. It seems that this is currently
being addressed, and could remain, in an updated version of COM-002-003. This should be coordinated
between standards and duplication should be avoided.
Response: The SDT disagrees that three-part communication should be used only for Reliability Directives.
Miscommunications occur during routine operations and the impact on reliability can be the same. The
SDT is working to coordinate with Project 2006-06 to eliminate any potential conflicts between the
standards.
Interoperability Communication: This definition is excessively broad, and the terminology “reliability related
information” is ambiguous and vague. Communication is used elsewhere within the NERC Standards to
include voice, data, email, memos, NERCnet, etc. Since communication of any type may be used to change
the “state or status” of the Bulk Electric System, this definition seems to pertain to every communication in
every form, which could be interpreted to include market information which is continuously used to drive
changes to the “state or status”.
Response: The SDT has eliminated the term “Interoperability Communication,” and replaced it with the
term “Operating Communications.” With this new definition including all communications that change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System, the SDT
believes it has removed any ambiguity over the utilization of communication protocols between or among
Functional Entities in the same or in other organizations.
By extension, a CPOP would need to include every communication of any type (voice, data, email, memos,
etc.), which is over-reaching and open to conflict with the CPOP’s developed independently by other entities.
Interoperability Communications should apply only to situations covered in Attachment 1, and definitions
should better reflect applicability to communications between separate, distinct entities (not
communications within the same organization).
Response: The SDT has removed the CPOP requirement and Interoperability Communication from the
second version of the draft COM-003-1 standard.
Response: The SDT thanks you for your comments. Please see our responses above.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
MRO NERC Standards
Review
Subcommittee
Disagree
Question 1 Comment
Concerning Three Part Communications: Please clarify by answering the following. Does the word
“correctly” mean repeating back word for word or would paraphrasing the intent of the message received
prove that the receiving party understands the intent and specific action of what they are required to
accomplish?
Response: The second draft of the Standard has been modified to address this by adding the phrase “not
necessarily verbatim”.
Please verify that Three Part Communications will be required when issuing directives related to emergency
situations, and not every time communications is required between two parties.
Response: In the second draft, three-part communication is required any time that verbal communication
is intended to change or maintain the state or status of the BES.
We believe the proposed definition for the term “Interoperability Communication” is too broad and
ambiguous. We recommend the following instead:
“Communication between two or more Functional Entities (not within the same organization) to exchange
reliability-related information to be used by the entities to change the state or status of Facilities of the Bulk
Electric System.”
The inclusion of the terms “Functional Entities” and “Facilities” removes the ambiguity which we believe is
contained in the proposed definition. (Both of these terms are defined in NERC’s Glossary) In addition, the
inclusion of the phrase “not within the same organization” clarifies that the focus of definition is to address
communication between different Functional Entities.
Response: Your definition approximates the proposed definition of “Operating Communication” —
Communication of instruction to change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. The SDT believes flawed operating communication within the same
organization can impact the reliability of the BES during normal operations. With this new definition of
“Operating Communications” including all communications that change or maintain the state, status,
output, or input of an Element or Facility of the Bulk Electric System, the SDT believes it has removed any
ambiguity over the utilization of communication protocols between or among Functional Entities in the
same or in other organizations.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
The way the definition of Three-part Communication is worded applies only when the communication is
understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could be
construed as a violation or at least not fitting the definition. The definition should rather reflect that threepart communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows:
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back to the party that initiated the communication by the second party that received
the communication, and the same information is verbally confirmed to be correct or corrected by the party
who initiated the communication. The protocol should be followed until the party issuing the information is
satisfied that a party receiving the information has understood the communication and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. Those modifications incorporate many of your recommendations.
We believe there should be a definition added for “Directive” as orders given in an emergency situation.
Directive, as currently used in the industry, is understood to mean an emergency situation and the party
issuing the “Directive” states as such, so everyone knows it is an emergency situation. In the “Disposition of
Requirements identified in the SAR for Operations Communications Protocols as Possibly Needing either
Modification or Movement” document included with the proposed standard, it is stated that COM-002-2, R2
is being modified in Project 2006-06 to include a new definition for “Reliability Directive” and that it is to be
included in the NERC Glossary. It also states that when it is completed, it will be moved into COM-003-1 and
COM-002-3 will be deleted. It is our opinion that the definition of Reliability Directive must be included in
the review and approval of COM-003-1, as it is central to many of the actions to be taken. We understand
that the SDT is working closely with the Drafting Team working on Project 2006-06 and believe that this team
needs to use the term “Reliability Directive” as a replacement for the term “directive” which is in the current
version of COM-003-1. The Drafting Team working on Project 2006-06 has defined Reliability Directive as:”A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority where
action by the recipient is necessary to address an actual or expected Emergency.” The NSRS recommends use
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
of this definition and the term “Reliability Directive” as opposed to “directive”.
The second draft version of COM-003-1 does not use the terms “directive” or “Reliability Directive,”
instead using the new term “Operating Communications.” The SDT is working to coordinate with Project
2006-06 to eliminate any potential conflicts between the standards.
Response: The SDT thanks you for your comments. Please see our responses above.
E.ON U.S. LLC
Disagree
For the Communication Protocol definition, please clarify if “written” includes electronic (email.) Change
the definition of “Interoperability” to “Emergency” Entities should not be required to use 3 part
communications on a routine basis, only on emergency issues.
Response: The SDT thanks you for your comments.
The second draft of the standard removes the proposed definition “Communications Protocol” and proposes a new definition for the term
“Operating Communications“ which will apply to all communications to alter or maintain the state of the BES. An email message is one example
of written Operating Communications.
The OPCP SDT disagrees with the concept of only requiring three part communication solely in emergency conditions. Mistakes due to poor
communication can also occur during routine operations. Blackout Report Recommendation #26 states communication protocols should be
tightened especially those for alerts and emergency communications, but does not recommend they be tightened only for alert and emergency
conditions. FERC Order 693 P531 directed communication protocols be tightened, and suggested a new COM Reliability Standard as an
acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during alerts
and emergencies,” but did not rule out improving all communications as a way of meeting the objective of the SAR. Additionally the SAR
required “the use of specific communication protocols, enabling information to be efficiently conveyed and mutually understood for all
operating conditions.”
American Electric
Power
Disagree
Given that Three-part Communications is required when using a directive, a “directive” must be clearly
defined. Without this determination, the definitions are incomplete.
Response: The second draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
There are undefined conditions, such as conference calls with multiple parties. Does each participant repeat
back in three-part?
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The SDT clarified that the use of three-part communication is limited to instances involving oral,
person-to-person communication.
Also, the definitions do not address communication of directives that are made in a non-oral format. This is
an important area to address in this standard.
Response: The second draft of the standard provides clarity on which protocols apply to both written and
oral Operating Communications and which protocols apply only to oral Operating Communications.
Lastly, please expand “entities” in the Interoperability Communication definition to be “NERC registered
functional entities.” We are concerned that the definition is much too broad and may expand the scope of
required communication beyond alerts and emergencies.
Response: The SDT is eliminating the term “Interoperability Communications” because of comments citing
ambiguity. We have revised the draft standard by defining the new term “Operating Communications.”
With this new definition including all communications that change or maintain the state, status, output,
or input of an Element or Facility of the Bulk Electric System, the SDT believes it has removed any
ambiguity over the utilization of communication protocols between or among Functional Entities in the
same or in other organizations.
The SDT is addressing more than just alerts and emergencies. Blackout Report Recommendation #26 states
communication protocols should be tightened, “especially” those for alerts and emergency
communications, but does not recommend they be tightened only for alert and emergency conditions. The
SAR for this SDT charged the team to “tighten communication protocols, especially for communications
during alerts and emergencies,” but did not rule out improving all communications as a way of meeting
the objective of the SAR. Mishaps due to miscommunication can and do occur during routine operations,
and have the potential to negatively impact reliability.
Response: The SDT thanks you for your comments. Please see our responses above.
Great River Energy
May 2, 2012
Disagree
GRE believes the proposed definition for the term Interoperability Communication is too broad and
ambiguous. We recommend the following instead:
Communication between two or more Functional Entities to exchange reliability-related information to be
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
used by the entities to change the state or status of Facilities of the Bulk Electric System.
The inclusion of the terms Functional Entities and Facilities removes the ambiguity which we believe is
contained in the proposed definition. (Both of these terms are defined in NERC’s Glossary)
Response: Your definition approximates the new proposed definition of “Operating Communication” —
Communication of instruction to change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. The SDT believes flawed operating communication within the same
organization can impact the reliability of the BES.
The way the definition of Three-part Communication is worded applies only when the communication is
understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could be
construed as a violation or at least not fitting the definition. The definition should rather reflect that threepart communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct. We suggest the definition be revised as follows:
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct or corrected by
the party who initiated the communication. The protocol should be followed until the party issuing the
information is satisfied that a party receiving the information has understood the communication and
confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003.
GRE believes there should be a definition added for Reliability Directive to ensure consistency across the
defined projects for standards development. The Drafting Team working on Project 2006-06 has defined
Reliability Directive as: A communication initiated by a Reliability Coordinator, Transmission Operator or
Balancing Authority where action by the recipient is necessary to address an actual or expected Emergency.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
GRE recommends use of this definition and the term Reliability Directive as opposed to Directive.
Response: The term Reliability Directive is being developed under NERC Project 2006-06 Reliability
Coordination. The current draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
Response: The SDT thanks you for your comments. Please see our responses above.
Sunflower Electric
Power Corp.
Disagree
I feel the use of the NATO phonetic alphabet is over kill. You should use a phonetic alphabet that is in
common use in the USA
Response: The SDT thanks you for your comments.
The SDT has considered your comments and has changed the standard to permit the use of any correct alpha-numeric clarifiers. The North
Atlantic Treaty Organization phonetic alphabet is in common use in the US Military, many police and fire organizations, and the US airline
industry.
Power South Energy
Disagree
Inoperability definition is too broad and not clear.
Response: The SDT thanks you for your comments. The definition for “Interoperability Communication” has been removed and a new definition
has been proposed for the term “Operating Communications” in the second draft of the standard.
National Grid
Disagree
Interoperability Communication: Virtually all communications in a control room environment deal with
changing the state or status of an element of facility, as such there is not a need to define this
communication protocol. However, addition of “real time communication” in the definition will to an extent
address the issue. The definition should be revised as follows:
Real Time Communication between two or more entities to exchange reliability-related information to be
used by the entities to change the state or status of an element or facility of the Bulk Electric System.
Response: Your definition approximates the proposed definition of “Operating Communication” —
Communication of instruction to change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. The SDT believes flawed operating communication within the same
organization can impact the reliability of the BES.
Three-part Communication: The way the definition of Three-part Communication is worded applies only
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
when the communication is understood by the listener the first time. Because the definition requires the
listener to repeat the information back correctly, failure of the listener to understand the information the
first time could be construed as a violation or at least not fitting the definition. The definition should rather
reflect that three-part communication is an iterative process that should be followed until the listener is
confirmed by the speaker to get the information correct.
We suggest the definition be revised as follows:
A Real-Time Operating Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the communication by
the second party that received the communication, and the same information is verbally confirmed to be
correct or corrected by the party who initiated the communication. The protocol should be followed until
the party issuing the information is satisfied that a party receiving the information has understood the
communication and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003.
Response: The SDT thanks you for your comments. Please see our responses above.
Indiana Municipal
Power Agency
Disagree
It is not clear in the definition of Interoperability Communication if this is communication between two
outside entities (two different companies) or could apply to communication between two entities within the
same company. For example, communication between a company's generation plant and the same
company's dispatcher.
Response: The SDT thanks you for your comments.
The SDT is eliminating the term Interoperability Communications because of comments citing ambiguity. We have revised the draft standard by
defining the new term “Operating Communications.” With this new definition requiring the protocols for all operations that change or maintain
the state, status, output, or input of an Element or Facility of the Bulk Electric System, the SDT believes it has removed any ambiguity over the
utilization of communication protocols between or among Functional Entities in the same or in other organizations.
Long Island Power
Authority
May 2, 2012
Disagree
LIPA disagrees with the definition for Three-Part Communication. LIPA prefers the process offered in COM002-03 (draft). In COM-003 the listener must understand the communication the first time. Failure to
understand and repeat back correctly could be a violation of the requirement. The intent three part
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
communication is to have an iterative process whereby the person issuing the message is ultimately satisfied
that the recipient understands the information and will perform the required action. It should not be
defined as three steps and only three steps.
LIPA offers the following definition:
A Real-Time Operating Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back to the party that initiated the communication by the
second party that received the communication, and the information is verbally confirmed to be correct or
corrected by the party who initiated the communication. The protocol should be followed until the party
issuing the information is satisfied that a party receiving the information has understood the communication
and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The new language incorporates much of your suggestion.
LIPA disagrees with the definition of Interoperability Communication. LIPA believes the Standard is
addressing the communication of the Operating State of BES equipment and facilities. The proposed
definition utilizes the phrase “change the state ... of a BES facility” which can be interpreted as the position,
e.g. open, close, tap position, etc... thereby extending this Standard into routine switching and operation of
the BES. The SAR stated this Standard was “to use specific communications protocols under normal,
abnormal and emergency conditions to relay critical reliability-related information in a timely and effective
manner”. The proposed definition can be interpreted in a manner that extends this to all reliability related
information for every BES operation.
Response: The definition for “Interoperability Communication” has been removed. The SDT believes
flawed operating communication within the same organization and during normal or routine operations
can detrimentally impact the reliability of the BES.
The drafting team should also consider adding a definition for Directive or acknowledge the definition in
draft Com-002-03.
Response: The term Reliability Directive is being developed under NERC Project 2006-06 Reliability
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Coordination. The current draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
Response: The SDT thanks you for your comments. Please see our responses above.
NERC Staff
Disagree
NERC staff recommends that the term “Communications Protocol” be removed from the definition section
because the term is only used in the title and in another definition. In addition, the definition adds no
additional clarity than can be provided by a commonly used definition of the terms.
Response: The term “Communication Protocol” has been eliminated from the standard.
Similarly, the term “Three-part Communication” can be removed since it is used in only one requirement,
and the definition can be incorporated in the requirement.
Furthermore, Three-part Communication refers to a process or procedure, not a term. NERC staff
recommends that the term “Interoperability Communication” be modified to “Operating Communication”
with the definition of “communication with the intent to change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System.” This captures all communication that affects BES
reliability, not just communication between function entities.
Response: The proposed definitions in the previous draft have been removed and the new term
“Operating Communications” has been proposed.
Response: The SDT thanks you for your comments. Please see our responses above.
PEF
Disagree
PEF does not agree with the adoption of the proposed term “Interoperability Communication”. The term
“Reliability Communication” should be used instead. The proposed term “Interoperability Communication” is
defined such that it applies to a state or status change of an element or facility of the BES - but there are
many reliability-related communications which do not necessarily apply to a state or status change.
Response: The SDT thanks you for your comments and your recommendation.
The proposed term “Interoperability Communication” has been removed from the previous draft of the standard. Instead the SDT is proposing
the new term “Operating Communications” to focus on the communications that change or maintain the state of the BES.
Pepco Holdings, Inc. May 2, 2012
Disagree
PHI believes the proposed definition for the term Interoperability Communication is too broad and
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Affiliates
Question 1 Comment
ambiguous. It is inconsistent with the effort to develop results based standards which would have an effect
in the reliability of bulk electric system.
Additionally, PHI does not see the need of a definition of Interoperability Communication now that the term
Reliability Directive has been defined in draft standard COM-002-3 which is currently posted for review.
Response: The SDT thanks you for your comments.
The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new term
“Operating Communications” to focus on the communications that change or maintain the state of the BES.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem Statement for this standard is that
miscommunication can lead to action or inaction harmful to the reliability of BES. This was identified by the NERC President in his January 2011
report to the industry as one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The Goal, therefore, is to specify
clear, formal and universally applied communication protocols that reduce the possibility of miscommunication. The key Objective to
accomplish this Goal is to use communication protocols to reduce or correct misunderstandings. The requirements have been written to
accomplish this Objective, and are risk-mitigating requirements (while operator performance is measured, the actions themselves are primarily
designed to mitigate the risk of miscommunication that could lead to poor BES performance). We believe this standard is consistent with
results-based principles, and it will improve the reliability of the BES.
The SDT believes the term Reliability Directives as defined in COM 002-03 does not fully address the range of miscommunication risks that could
seriously impact the reliability of the BES.
American Municipal
Power
Agree
Please define "directive" as a term.
Response: The SDT thanks you for your comments. The second draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate with Project 2006-06 to eliminate any
potential conflicts between the standards.
The Empire District
Electric Company
May 2, 2012
Disagree
Replace the proposed COM-003-1 definition of "Thee-part Communication with what is used here:
Three Part Communication: A communications protocol to be used when a Reliability Directive is initiated
verbally, whereby the action to be taken is identified as a Reliability Directive; the recipient repeat the details
of the Reliability Directive back to the issuer of the Reliability Directive; and the issuer acknowledges the
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
response from the recipient of the Reliability Directive as correct, or re-issues the Reliability Directive to
resolve any misunderstanding.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The new language incorporates much of your suggestion.
Response: The SDT thanks you for your comments. Please see our responses above.
Southern Company
Transmission
May 2, 2012
Disagree
Southern Company supports the SERC SOS comments.
SERC SOS comments: We feel that the definition of Interoperability Communication is much too broad and is
inconsistent with the effort to develop results-based standards. Adherence to such results-based standards
would have a measurable and observable effect on the reliability of the bulk electric system. The definition
of Interoperability Communication, as written, can include virtually any information exchange/instruction
between entities, both routine and emergency. Such communication may or may not have a measurable
and observable effect on bulk system reliability.
The concern is that, since the broad term Interoperability Communication is used in every requirement in
COM-003-1, entities will be required to use the English language, the central time zone, and 3-part
communication in even the most routine exchanges of information. This could create a burden on operating
personnel and a distraction from their reliability duties.
Response: The SDT is eliminating the term Interoperability Communications because of comments citing
ambiguity. We have revised the draft standard by defining the new term “Operating Communications.”
With this new definition including all communications that change or maintain the state, status, output,
or input of an Element or Facility of the Bulk Electric System, the SDT believes it has removed any
ambiguity over the utilization of communication protocols between or among Functional Entities in the
same or in other organizations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the
reliability of BES. This was identified by the NERC President in his January 2011 report to the industry as
one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred
in the past where miscommunication was a contributing factor to the event or exacerbated the severity of
the event. The Goal, therefore, is to specify clear, formal and universally applied communication protocols
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
that reduce the possibility of miscommunication. The key Objective to accomplish this Goal is to use
communication protocols to reduce or correct misunderstandings. The requirements have been written to
accomplish this Objective, and are risk-mitigating requirements (while operator performance is measured,
the actions themselves are primarily designed to mitigate the risk of miscommunication that could lead to
poor BES performance). We believe this standard is consistent with results-based principles, and it will
improve the reliability of the BES.
This group does not feel the need for a definition of Interoperability Communication, since the term
Reliability Directive has been defined in draft standard COM-002-3, which is currently posted for review. The
Reliability Directive term is emergency-focused and consistent with the results-based standards process.
Response: The SDT believes the term Reliability Directive as defined in COM 002-03 does not fully address
the range of miscommunication risks that could seriously impact the reliability of the BES.
The Need for this standard is that miscommunication can lead to action or inaction harmful to the
reliability of BES, not just that miscommunications associated with emergencies can lead to action or
inaction harmful to the reliability of BES. As such this standard is consistent with results-based principles.
To the extent that entities feel actions or inactions caused by miscommunication have no ability to impact
the reliability of the BES, then those entities simply disagree with the Need, but that does not indicate the
standard is inconsistent with the results-based principles.
In addition, the definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state - repeat - acknowledge) apply to Reliability Directives, while in COM-003-1 the
definition of Three-part Communication refers to “information” in general.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The requirement now also applies only to “Operating Communications,” which includes
all communications that change or maintain the state, status, output, or input of an Element or Facility of
the Bulk Electric System
May 2, 2012
44
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
If, as stated in the Disposition of Requirements, the revisions to COM-002-3 will be moved to COM-003-1,
the definition of Three-part Communication in this draft standard should be consistent with the
requirements of COM-002-3.
Response: The SDT agrees with this recommendation for consistency, however as envisioned, the
requirements of COM-002-3 will be retired when the requirements of COM-003-1 become effective.
Southern Company comments:
Interoperability Communication - Communication between two or more entities to exchange reliabilityrelated information regarding the Bulk Electric System. Why is a change in state or status required to make a
communication between two entities an Interoperability Communication? What term should be used when a
conference call is made to all of the RCs in an Interconnection to discuss low frequency?
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications” to focus on the communications
that change or maintain the state of the BES.
Conference calls and discussions to determine actions and options would not constitute Operating
Communications if they do not directly request a change to, or maintain, the state, status, output, or input
of an Element or Facility of the Bulk Electric System.
Response: The SDT thanks you for your comments. Please see our responses above.
Progress Energy
Carolina, Inc
Disagree
The definition for Interoperability Communication needs more clarification/an interpretation since the type
of communications is not defined, the term "reliability-related information" undefined, and it may be so
diluting as to de-emphasize true reliability directives.
Response: The SDT thanks you for your comments.
The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new term
“Operating Communications” to focus on the communications that change or maintain the state of the BES.
NYSEG
Disagree
May 2, 2012
The definition for Interoperability Communication needs to be further explained. The current definition
would appear to include not only communication between two control centers, but also between a control
center and field personnel for all normal and routine switching, which we do not believe is the intent of the
45
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Standard.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications” to focus on the communications
that change or maintain the state of the BES. That definition would also extend to communication
between two control centers, and between a control center and field personnel for all normal and routine
switching to the extent it meets the criteria of the Operating Communications definition.
Miscommunication during routine operations can result in mistakes that could seriously impact reliability
on the BES.
Communication Protocol as a separate definition does not appear to be necessary. The provided definition
describes the term in a simple and generic way and is not specific enough to provide anymore guidance than
is already provided in a general understanding of the word “communication” or “protocol”.
Response: The SDT agrees and has removed the term.
Three-part communication should be revised as follows:
An iterative process where verbal communication from a sender to receiver is repeated back to the sender
by the receiver to eventually ensure correct and accurate transmission of the entire message.
We believe this definition is more consistent with COM-002 R2, which is proposed to be retired once COM003-1 is approved and Three-part Communication is adopted.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The new language incorporates the intent of your recommendation.
Response: The SDT thanks you for your comments. Please see our responses above.
Ameren
May 2, 2012
Disagree
The definition for three part implies the exact message must be repeated back. What should be said is the
content must be repeated back in original or modified forms such that the originator is sure the recipient
understands and can execute the action.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
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Consideration of Comments on OPCP SDT — Project 2007-02
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Yes or No
Question 1 Comment
draft of COM-003. We have incorporated the language to not require a verbatim repeat-back.
As far as Interoperability, what is state or status? Is the dispatch instruction to change from 500 MW to 505
MW such a communication? (which changed, state or status?)
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
A dispatch instruction to change from 500 MW to 505 MW would be such a communication. The input or
output on the system was changed in your example.
Response: The SDT thanks you for your comments. Please see our responses above.
Entergy Services
Disagree
The definition for Three-part communication is deficient when compared with the requirements of the
recently posted COM-002-3 which describes an iterative process in which the communicating party corrects
the recipient in the situation where the repeated message contains inconsistencies. The party receiving the
message will not always get the message right the first time.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The new language incorporates the concept of iteration, and also includes the phrase,
“not necessarily verbatim.”
Also, Entergy does not believe that the introduction of the term Interoperability Communications is
necessary. In the questions below, we identify specific ways that the requirements could be improved by
including the term Reliability Directive as included in the recently posted COM-002-3. The term
Interoperability Communications is very broad, covering both normal and emergency communications,
creates a new category of communications without providing any real benefit to the industry.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
May 2, 2012
47
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Bulk Electric System.
The SDT believes the term Reliability Directives as defined in COM 002-03 does not fully address the range
of miscommunication risks that could seriously impact the reliability of the BES.
Response: The SDT thanks you for your comments. Please see our responses above.
Transmission System
Operations
Disagree
The definition of “Interoperability Communication” is not clear. What does the term “reliability-related”
information entail? Does “Interoperability Communication” include instructions from a control room to a
generator to adjust vars, from the control room to field personnel to direct the changing of transformer taps,
from the control room to field personnel to implement switching instructions, etc? What is the definition of
“entity”? Does this mean if switching instructions are given from a control room of one company to
personnel in its own company (i.e., the same entity), that the interaction would not be classified as
“Interoperability Communication”?
Response: The SDT thanks you for your comments.
The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new term
“Operating Communications,” which includes all communications that change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. Each of your examples, if they direct a change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System, will be subject to the protocols in COM 003 including three part communication.
Florida Municipal
Power Agency
(FMPA) and some
members
Disagree
The definition of Communications Protocol can be improved as: Policies and procedures that govern how
verbal and written communication is exchanged.
Response: The SDT agreed with the numerous comments that the term was not useful and eliminated it
from the Standard.
The definition of Three-part Communication could be improved by simplifying the language as:
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly by the party receiving the communication to the initiating party, and
the same information is verbally confirmed to be correct by the initiating party.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
draft of COM-003. The new language incorporates much of your suggestion.
The definition of Interoperability Communication can be improved by using NERC Glossary of Terms
definitions, e.g., Element and Facility ought to be capitalized in the definition, and the use of both Element
and Facility is redundant and only the term Facility needs to be used since a Facility is essentially defined as a
BES Element.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. The SDT has capitalized the terms “Element “and “Facility” as suggested, but
elected to keep both terms in the definition. The NERC Glossary term Facility is not defined as a BES
Element, but as “A set of electrical equipment that operates as a single Bulk Electric System Element.”
Response: The SDT thanks you for your comments. Please see our responses above.
Georgia Transmission
Corp
Disagree
The definition of Interoperability Communication is very broad and has no real benefit.
Response: The SDT thanks you for your comments.
The SDT eliminated the term “Interoperability Communications.” Instead, the SDT has revised the draft standard by defining the new term
“Operating Communications.” With this new definition including all communications that change or maintain the state, status, output, or input
of an Element or Facility of the Bulk Electric System, the SDT believes it has improved the standard to be clearer and less ambiguous.
Santee Cooper
Disagree
The definition of Interoperability Communication needs to be clarified. What is the intent of the word
“entities” in this definition? This definition may no longer be needed with the recent definition of a
Reliability Directive.
Three-part Communication should be required when issuing and receiving a Reliability Directive. This term
has recently been defined by a SDT.
Response: The SDT thanks you for your comments.
The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new term
“Operating Communications,” which includes all communications that change or maintain the state, status, output, or input of an Element or
May 2, 2012
49
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Facility of the Bulk Electric System.
The SDT disagrees that Three-part Communication should be required only when issuing and receiving a Reliability Directive. The SDT believes
the term Reliability Directives as defined in COM 002-03 does not fully address the range of miscommunication risks that could seriously impact
the reliability of the BES.
Kansas City Power &
Light
Disagree
The definition of Three-part Communication applies only when the communication is understood by the
listener the first time. Because the definition requires the listener to repeat the information back correctly,
failure of the listener to understand the information the first time could be construed as a violation or at
least not fitting the definition. The definition should rather reflect that three-part communication is an
iterative process that should be followed until the listener is confirmed by the speaker to get the information
correct.
We suggest the definition be revised as follows:”A Communications Protocol where information is verbally
stated by a party initiating a communication, the information is repeated back correctly to the party that
initiated the communication by the second party that received the communication, and the same
information is verbally confirmed to be correct or corrected by the party who initiated the communication.
The protocol should be followed until the party issuing the information is satisfied that a party receiving the
information has understood the communication and confirmed it.”
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003.
The definition for Interoperability Communication is too broad. Currently, this could mean any
communication of information. This should be confined to emergency or unusual operating conditions.
Response: The SDT disagrees that three-part communication should be confined to emergency or unusual
operating conditions; miscommunication occurs during routine operations that could seriously impact the
reliability of the BES. The proposed term “Interoperability Communication” has been removed from the
standard and replaced with the new term “Operating Communications.” This term includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. As such, this limits the scope of the requirements so that not all communications of
information are included under the standard.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comments. Please see our responses above.
Midwest ISO
Standards
Collaborators
Disagree
The definition of Three-part Communication applies only when the communication is understood by the
listener the first time. Because the definition requires the listener to repeat the information back correctly,
failure of the listener to understand the information the first time could be construed as a violation or at
least not fitting the definition. The definition should rather reflect that three-part communication is an
iterative process that should be followed until the listener is confirmed by the speaker to get the information
correct.
We suggest the definition be revised as follows:”
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct or corrected by
the party who initiated the communication. The protocol should be followed until the party issuing the
information is satisfied that a party receiving the information has understood the communication and
confirmed it.”
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. The SDT has also added language to specify responses are not necessarily required to
be verbatim.
These principles are included in Requirements R2 and R3 in the recently issued draft Standard COM-002-3 in
Project 2006-06.We believe the term “Interoperability Communication” creates confusion within the
industry and contradicts the work by RTO and RC SDT in Project 2006-06 that limits the requirement to use
three-part communications when issuing Reliability Directives (defined in Project 2006-06) that address
anticipated and actual emergency conditions.
Response: The current draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.” The SDT is working to coordinate
with Project 2006-06 to eliminate any potential conflicts between the standards.
The OPCP SDT disagrees with the concept of only requiring three part communication solely in emergency
conditions. Mistakes due to poor communication can also occur during routine operations. Blackout
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Report Recommendation #26 states communication protocols should be tightened, “especially” those for
alerts and emergency communications, but does not recommend they be tightened only for alert and
emergency conditions. FERC Order 693 P531 directed communication protocols be tightened, and
suggested a new COM Reliability Standard as an acceptable approach. The SAR for this SDT charged the
team to “tighten communication protocols, especially for communications during alerts and emergencies,”
but did not rule out improving all communications as a way of meeting the objective of the SAR.
Additionally the SAR required “the use of specific communication protocols, enabling information to be
efficiently conveyed and mutually understood for all operating conditions.”
Additionally, it appears that this definition would encompass all verbal communications and, as such, we
question the need for such definition. While using three-part communications during routine operations
may be a best operating practice, we do not believe that it is so critical to reliability that it becomes an
enforceable requirement for routine operating instructions. Rather we believe the enforceable requirement
should be limited to require three-part communications during actual emergency and anticipated emergency
conditions only.
Response: The SDT disagrees that three-part communication should be confined to emergency or unusual
operating conditions; miscommunication can occur during routine operations that could seriously impact
the reliability of the BES.
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized.
Response: The SDT did not retain the term, “Interoperability Communication” in the second draft of the
standard. However, where the SDT proposed a new term, “Operating Communication” that uses the
terms, “Element” and “Facility” and the SDT has capitalized these words where used so in the new term.
In addition, the term “entities” is confusing and needs to be defined.
The SDT believes the word entity is well understood in the industry – however the term, “Interoperability
Communication” is not used in the second draft of the standard
May 2, 2012
52
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The SDT thanks you for your comments. Please see our responses above.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
Please see our response to the comments filed by the PJM System Operations Subcommittee (SOS) Group.
ERCOT ISO
Disagree
The purpose of the standard is for timely communication of reliability-related information “especially during
alerts and emergencies”. The definition and use of Interoperability Communication in this standard expands
the intended scope of the standard beyond alerts and emergencies.
The OPCP SDT disagrees with the concept of requiring three part communication solely in emergency
conditions. Mistakes due to poor communication can also occur during routine operations. Blackout
Report Recommendation #26 states communication protocols should be tightened, “especially” those for
alerts and emergency communications, but does not recommend they be tightened only for alert and
emergency conditions. FERC Order 693 P531 directed communication protocols be tightened, and
suggested a new COM Reliability Standard as an acceptable approach. The SAR for this SDT charged the
team to “tighten communication protocols, especially for communications during alerts and emergencies,”
but did not rule out improving all communications as a way of meeting the objective of the SAR.
Additionally the SAR required “the use of specific communication protocols, enabling information to be
efficiently conveyed and mutually understood for all operating conditions.”
Guidance should be provided for verbal communications with respect to hot-line calls (one party too many)
and how three-part communication should be handled. This definition assumes a one on one
communication.
Response: The SDT clarified, in the second draft of the standard, that the use of three-part communication is
limited to instances involving oral, person-to-person communication.
Response: The SDT thanks you for your comments. Please see our responses above.
Northeast Utilities
May 2, 2012
Disagree
The term “Interoperability Communication” creates confusion within the industry and contradicts the work
by RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part communications when
53
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
issuing Reliability Directives (defined in Project 2006-06) that address anticipated and actual emergency
conditions. Additionally, it appears that this definition would encompass all verbal communications and, as
such, we question the need for such definition.
The definition of “three-part communication” may be viewed as accurate and consistent with the work that
has been done and substantially progressed through two other SDTs, we believe the RC SDT requirement,
which includes “and shall acknowledge the response as correct or repeat the original statement to resolve
any misunderstandings”, is more complete.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second
draft of COM-003. We are following the progress of Project 2006-06 (RCSDT) to work toward consistency.
Again, we believe the term “Interoperability Communication” contradicts this work and creates confusion
within the industry. It appears to mandate 3-part communication during operational strategic discussions, as
well as other “non-action” oriented communications. We believe this Requirement would, in fact, be
adverse to reliability instead of enhancing reliability by reducing the amount of pre-action communications
that may occur prior to taking action because operators may be more concerned with not repeating back
during such pre-action, strategic calls and/or discussion.
Response: The proposed term “Interoperability Communication” has been removed from the revised
standard. Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. With this change, the SDT does not believe the standard can be construed as
requiring repeating back during such conversations on pre-action, strategic calls and/or discussions.
Response: The SDT thanks you for your comments. Please see our responses above
Tri-State Generation
& Transmission
Assoc.
Disagree
The term directive is not defined therefore it is unclear what constitutes a directive.
Response: The SDT thanks you for your comments. The second draft version of COM-003-1 does not use the terms “directive” or “Reliability
Directive,” instead using the new term “Operating Communications.”
May 2, 2012
54
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Dynegy
Disagree
Question 1 Comment
The way the definition of “Three-part Communication” is worded applies only when the communication is
understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could be
construed as a violation or at least not fitting the definition. The definition should rather reflect that threepart communication is an iterative process that should be followed until the listener is confirmed by the
speaker to get the information correct.
We suggest the definition be revised as follows:
”A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct or corrected by
the party who initiated the communication. The protocol should be followed until the party issuing the
information is satisfied that a party receiving the information has understood the communication and
confirmed it.”
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
applicable requirements to specify repeat-backs are not required to be verbatim.
It should also be noted that these principles are included in Requirements R2 and R3 in the recently issued
draft Standard COM-002-3 in Project 2006-06. This definition in this Standard is not needed.
We believe the term “Interoperability Communication” creates confusion within the industry and contradicts
the work by RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part
communications when issuing Reliability Directives (defined in Project 2006-06) that address anticipated and
actual emergency conditions. Additionally, it appears that this definition would encompass all verbal
communications and, as such, would be a distraction to Operators. Therefore, there is no reliability need for
this definition.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
May 2, 2012
55
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Bulk Electric System. We are following the progress of Project 2006-06 (RCSDT) to work toward consistency.
While using three-part communications during routine operations may be a best operating practice, we do
not believe that it is so critical to reliability that it needs to become an enforceable requirement for routine
operating instructions. Rather we believe the enforceable requirement should be limited to require threepart communications during actual emergency and anticipated emergency conditions only.
The OPCP SDT disagrees with the concept of only requiring three part communication solely in emergency
conditions. Mistakes due to poor communication can also occur during routine operations. Blackout
Report Recommendation #26 states communication protocols should be tightened, “especially” those for
alerts and emergency communications, but does not recommend they be tightened only for alert and
emergency conditions. FERC Order 693 P531 directed communication protocols be tightened, and
suggested a new COM Reliability Standard as an acceptable approach. The SAR for this SDT charged the
team to “tighten communication protocols, especially for communications during alerts and emergencies,”
but did not rule out improving all communications as a way of meeting the objective of the SAR.
Additionally the SAR required “the use of specific communication protocols, enabling information to be
efficiently conveyed and mutually understood for all operating conditions.”
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized.
Response: The SDT did not retain the term, “Interoperability Communication” in the second draft of the
standard. However, where the SDT proposed a new term, “Operating Communication” that uses the
terms, “Element” and “Facility” and the SDT has capitalized these words where used so in the new term.
In addition, the term “entities” is confusing and needs to be defined.
Response: The SDT believes the word entity is well understood in the industry – however the term,
“Interoperability Communication” is not used in the second draft of the standard.
Response: The SDT thanks you for your comments. Please see our responses above.
Hydro-Quebec
TransEnergie
May 2, 2012
Disagree
The way the definition of “Three-part Communication” is worded applies only when the communication is
understood by the listener the first time. The RC SDT requirement which includes “and shall acknowledge the
56
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
response as correct or repeat the original statement to resolve any misunderstandings” is more complete.
Because the definition requires the listener to repeat the information back correctly, failure of the listener to
understand the information the first time could be construed as a violation or at least not fitting the
definition. The definition should reflect that three-part communication is an iterative process that should be
followed until the listener is confirmed by the speaker to get the information correct.
A suggested revision to the definition:
A Real-Time Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back to the party that initiated the communication by the
second party that received the communication, and the information is verbally confirmed to be correct or
corrected by the party who initiated the communication. The protocol should be followed until the party
issuing the information is satisfied that a party receiving the information has understood the communication
and confirmed it.
These principles are included in Requirements R2 and R3 in the recently issued draft Standard COM-002-3 in
Project 2006-06.
An alternative suggestion to the definition of Three-part Communication: A Real-Time Operating
Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the information is verbally confirmed to be correct by the party who
initiated the communication.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
applicable requirements to specify repeat-backs are not required to be verbatim.
In the definition of Communications Protocol, the term “Interoperability Communication” creates confusion
within the industry, and contradicts the work by RTO and RC SDT in Project 2006-06 that limits the
requirement to use three-part communications when issuing Reliability Directives (defined in Project 200606) that address anticipated and actual emergency conditions, and do not agree with its definition. What
also must be considered is that the RC SDT has stated that when someone “says”, it is a directive--operating
conditions are not distinguished. This definition unnecessarily and counterproductively encompasses all
May 2, 2012
57
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
verbal communications and, as such, is not needed. It is not so critical to reliability that it should become an
enforceable requirement for routine operating instructions.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
The OPCP SDT disagrees with the concept of only requiring three part communication solely in emergency
conditions. Mistakes due to poor communication can also occur during routine operations. Blackout
Report Recommendation #26 states communication protocols should be tightened, “especially” those for
alerts and emergency communications, but does not recommend they be tightened only for alert and
emergency conditions. FERC Order 693 P531 directed communication protocols be tightened, and
suggested a new COM Reliability Standard as an acceptable approach. The SAR for this SDT charged the
team to “tighten communication protocols, especially for communications during alerts and emergencies,”
but did not rule out improving all communications as a way of meeting the objective of the SAR.
Additionally the SAR required “the use of specific communication protocols, enabling information to be
efficiently conveyed and mutually understood for all operating conditions.”
The enforceable requirement should be limited to require three-part communications, and be left to the
entity that needs the action to be taken to establish the need for three-part communications by stating in
the communication that they are issuing a directive. This would be a clear trigger, and be auditable and
measurable. Virtually all communications in a control room environment deal with changing the state or
status of an element of facility, as such there is not a need to define this communication protocol.
Response: The SDT believes it is just as clear a trigger to use three part communication based on the
criteria that three-part communication must be used for any communication that intends to change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System.
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized.
May 2, 2012
58
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The SDT did not retain the term, “Interoperability Communication” in the second draft of the
standard. However, where the SDT proposed a new term, “Operating Communication” that uses the
terms, “Element” and “Facility” and the SDT has capitalized these words where used so in the new term.
In addition, the term “entities” is confusing and needs to be defined.
Response: The SDT believes the word entity is well understood in the industry – however the term,
“Interoperability Communication” is not used in the second draft of the standard.
Response: The SDT thanks you for your comments. Please see our responses above
Northeast Power
Coordinating Council
Disagree
The way the definition of “Three-part Communication” is worded applies only when the communication is
understood by the listener the first time. The RC SDT requirement which includes “and shall acknowledge
the response as correct or repeat the original statement to resolve any misunderstandings” is more
complete. Because the definition requires the listener to repeat the information back correctly, failure of the
listener to understand the information the first time could be construed as a violation or at least not fitting
the definition. The definition should reflect that three-part communication is an iterative process that
should be followed until the listener is confirmed by the speaker to get the information correct.
A suggested revision to the definition:
A Real-Time Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the communication by
the second party that received the communication, and the same information is verbally confirmed to be
correct or corrected by the party who initiated the communication. The protocol should be followed until
the party issuing the information is satisfied that a party receiving the information has understood the
communication and confirmed it.
These principles are included in Requirements R2 and R3 in the recently issued draft Standard COM-002-3 in
Project 2006-06.
An alternative suggestion to the definition of Three-part Communication:
A Real-Time Operating Communications Protocol where information is verbally stated by a party initiating a
communication, the information is repeated back correctly to the party that initiated the communication by
May 2, 2012
59
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
the second party that received the communication, and the same information is verbally confirmed to be
correct by the party who initiated the communication.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
applicable requirements to specify repeat-backs are not required to be verbatim.
A suggestion to the definition of Communications Protocol: The SDT could not locate the content here.
The term “Interoperability Communication” creates confusion within the industry, and contradicts the work
by RTO and RC SDT in Project 2006-06 that limits the requirement to use three-part communications when
issuing Reliability Directives (defined in Project 2006-06) that address anticipated and actual emergency
conditions, and do not agree with its definition. What also must be considered is that the RC SDT has stated
that when someone “says”, it is a directive--operating conditions are not distinguished. This definition
unnecessarily and counterproductively encompasses all verbal communications and, as such, is not needed.
It is not so critical to reliability that it should become an enforceable requirement for routine operating
instructions.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
The OPCP SDT disagrees with the concept of only requiring three part communication solely in emergency
conditions. Mistakes due to poor communication can also occur during routine operations.
Recommendation #26 states communication protocols should be tightened, “especially” those for alerts
and emergency communications, but does not recommend they be tightened only for alert and emergency
conditions. FERC Order 693 P531 directed communication protocols be tightened, and suggested a new
COM Reliability Standard as an acceptable approach. The SAR for this SDT charged the team to “tighten
communication protocols, especially for communications during alerts and emergencies,” but did not rule
out improving all communications as a way of meeting the objective of the SAR. Additionally the SAR
May 2, 2012
60
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
required “the use of specific communication protocols, enabling information to be efficiently conveyed
and mutually understood for all operating conditions.”
The enforceable requirement should be limited to require three-part communications, and be left to the
entity that needs the action to be taken to establish the need for three-part communications by stating in
the communication that they are issuing a directive. This would be a clear trigger, and be auditable and
measurable. Virtually all communications in a control room environment deal with changing the state or
status of an element of facility, as such there is not a need to define this communication protocol.
Response: The SDT believes it is just as clear a trigger to use three part communication based on the
criteria that three-part communication must be used for any communication that intends to change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System.
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? If so, the terms need to be
capitalized.
Response: The SDT did not retain the term, “Interoperability Communication” in the second draft of the
standard. However, where the SDT proposed a new term, “Operating Communication” that uses the
terms, “Element” and “Facility” and the SDT has capitalized these words where used so in the new term.
The term “entities” is confusing and needs to be defined.
Response: The SDT believes the word entity is well understood in the industry – however the term,
“Interoperability Communication” is not used in the second draft of the standard.
Response: The SDT thanks you for your comments. Please see our responses above
IRC Standards Review
Committee
May 2, 2012
Disagree
The way the definition of Three-part Communication is worded applies only when the communication is
understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could be
construed as a violation or at least not fitting the definition. The definition should rather reflect that threepart communication is an iterative process that should be followed until the listener is confirmed by the
61
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
speaker to get the information correct.
We suggest the definition be revised as follows:
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct or corrected by
the party who initiated the communication. The protocol should be followed until the party issuing the
information is satisfied that a party receiving the information has understood the communication and
confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
specify repeat-backs are not required to be verbatim.
We believe the term “Interoperability Communication” contradicts the work by the RTO and RC SDT that
limits the requirement to use three-part communications to only those communications that explicitly state
that the communication is a Reliability Directive and creates confusion within the industry. Additionally, it
appears that this definition would encompass all verbal communications and, as such, we question the need
for such definition. While we support using three-part communications during routine operations as a best
operating practice, we do not believe that it is so critical to reliability that it becomes an enforceable
requirement for routine operating instructions. Rather we believe the enforceable requirement should be
left to the entity that needs the action to be taken to establish the need for three-part communications by
stating in the communication that they are issuing a directive. This would be a clear trigger and auditable
and measureable.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. The SDT believes this provides just as clear a trigger.
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
May 2, 2012
62
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
capitalized.
Response: The SDT agrees and has done so within the new term, “Operating Communications”.
Response: The SDT thanks you for your comments. Please see our responses above.
ISO New England Inc.
Disagree
The way the definition of Three-part Communication is worded applies only when the communication is
understood by the listener the first time. Because the definition requires the listener to repeat the
information back correctly, failure of the listener to understand the information the first time could be
construed as a violation. The definition should rather reflect that three-part communication is an iterative
process that should be followed until the listener is confirmed by the speaker to get the information correct.
We suggest the definition be revised as follows:
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back to the party that initiated the communication by a second party that received
the communication, and the information is verbally confirmed to be correct or corrected by the party who
initiated the communication. The protocol should be followed until the party issuing the information is
satisfied that a party receiving the information has understood the communication and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
applicable requirements to specify repeat-backs are not required to be verbatim.
We believe the term “Interoperability Communication” contradicts the work by the RTO and RC SDT that
limits the requirement to use three-part communications to only those communications that explicitly state
that the communication is a Reliability Directive and creates confusion within the industry. Additionally, it
appears that this definition would encompass all verbal communications and, as such, we question the need
for such definition. While we support using three-part communications during routine operations as a best
operating practice, we do not believe that it is so critical to reliability that it becomes an enforceable
requirement for routine operating instructions. Rather we believe the enforceable requirement should be
left to the entity that needs the action to be taken to establish the need for three-part communications by
stating in the communication that they are issuing a directive. This would be a clear trigger and auditable
May 2, 2012
63
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
and measureable.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. The SDT believes this provides just as clear a trigger.
The way the definition of Three-part Communication is worded seems to only apply when the communication is understood by the listener the first
time. Because the definition requires the listener to repeat the information back correctly, failure of the listener to understand the information the
first time could be construed as a violation. The definition should, rather, reflect that three-part communication is an iterative process that should
be followed until the listener is confirmed by the speaker to get the information correct. We suggest the definition be revised as follows:
A Communications Protocol where information is verbally stated by a party initiating a communication, the information is repeated back to the
party that initiated the communication by a second party that received the communication, and the information is verbally confirmed to be correct
or corrected by the party who initiated the communication. The protocol should be followed until the party issuing the information is satisfied that
a party receiving the information has understood the communication and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the performance of three-part
communication into the language of Requirements R2 and R3 in the second draft of COM-003. The new language incorporates much of your
suggestion. The SDT has also added language to applicable requirements to specify repeat-backs are not required to be verbatim.
FirstEnergy
May 2, 2012
Disagree
Three-part Communication The phrase "the information is repeated back correctly" may pose compliance
problems if the second party does not repeat the information back correctly the first time.
We suggest the definition be revised as follows:
"A Communications Protocol where information is verbally stated by one person to a second person
whereby communication is initiated, the second person repeats the information back to the first person as
means to verify the communication. The initiating party either confirms the response as correct or repeats
the original statement and resolves any misunderstandings.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The new language incorporates much of your suggestion. The SDT has also added language to
specify repeat-backs are not required to be verbatim.
64
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
"Interoperability Communication
We recommend this definition be removed and be incorporated into the RCSDT's proposed definition of
Reliability Directive. Please see our comments in Question 6 for a complete explanation.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
Please see response to comments in Question 6 as well.
Response: The SDT thanks you for your comments. Please see our responses above
PPL
Disagree
Three-part Communication is too prescriptive. How will “all call/blast” communications be handled? Also, it
is unclear what communications are included in Interoperability Communication.
Response: The SDT thanks you for your comments.
The SDT has eliminated the definition of three-part communication and has incorporated it into the language of Requirements R2 and R3 in the
new draft. The language has been modified to be more flexible and support different scenarios. The SDT considered adding a requirement to
address “all call” or “blast” communications but determined that a requirement is not necessary. As revised, the need to perform a ‘”repeat
back” of an Operating Communication is limited to oral person-to-person communications.
California
Independent System
Operator
May 2, 2012
Disagree
Three-Part Communications:
There is no leeway given if the “intent” of the information is repeated back correctly. If the initiating party
mispronounces a word and the receiver does not, is it a violation?
Also there is a possibility of delaying actions due to multiple repeat backs while attempting to repeat back
verbatim. The air traffic control /pilot communications could be held up as the current best practice
standard in critical communications, and utilizing three-part techniques... and they do NOT use verbatim
word-for-word repeat. Rather the messages are often truncated, but still indicate an understanding of the
message.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
65
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
of COM-003. The SDT has also added language to applicable requirements to specify repeat-backs are not
required to be verbatim.
Interoperability Communication:
The proposed definition does not distinguish between internal and external entities. A more specific term
than entity is needed here for clarity. With no more guidance than provided, a Generation Dispatcher may
be considered a separate entity than the Transmission Dispatcher in the same room. As proposed the
definition opens the doors for wildly different interpretations. We think this term, in this usage, applies to
communication between companies, but we are not sure.
Response: We agree with your comments. The SDT is eliminating the term “Interoperability
Communications” because of comments citing ambiguity. We have revised the draft standard by defining
the new term “Operating Communications.” With this new definition including all communications that
change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System,
the SDT believes it has removed any ambiguity over the utilization of communication protocols between
or among Functional Entities in the same or in other organizations.
Interoperability Communication is a bit of an unconventional use of the word interoperability. The standard
strives to ensure communication protocols ensure interoperability. Communication Interoperability normally
in usage, refers to the ability of dissimilar systems to exchange data. Its use here is unnecessarily confusing.
It’s a rather messy way of saying, inter-company communication.
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
Response: The SDT thanks you for your comments. Please see our responses above.
Electric Market Policy
May 2, 2012
Disagree
We do not agree with the adaptation of the proposed term “Interoperability Communication”. As defined, it
is limited to the communication of information to be used to change the state or status of a BES element or
facility. That definition is too limiting in that there are many types of reliability-related information that need
66
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
to be clearly communicated that do not lead to changing the state of a BES facility. For example; information
related to ratings, information related to the results of studies, information related to data errors or loss of
data, etc.
If the term “Interoperability Communication” is to be retained, we strongly suggest a name change. The
word “interoperability” is widely used to refer to the ability of a system to work with or use the parts or
equipment of another system. For example please see the current standards development efforts identified
in the NIST Framework and Roadmap for Smart Grid Interoperability Standards available at:
http://www.nist.gov/public_affairs/releases/smartgrid_interoperability.pdf. Using the term
“interoperability” to refer to reliability-related human communications could be confusing to regulators,
compliance personnel, auditors, and many others who have to deal with a variety of standards.
Response: The SDT thanks you for your comments.
Response: The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new
term “Operating Communications,” which includes all communications that change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.
PJM
Disagree
May 2, 2012
We feel that the definition of Interoperability Communication is much too broad and is inconsistent with the
effort to develop results-based standards which would have a measurable and observable effect on the
reliability of the bulk electric system. The definition of Interoperability Communication, as written, can
include virtually any information exchange/instruction between entities, both routine and emergency. Such
communication may or may not have a measurable and observable effect on bulk system reliability. Since
the broad term Interoperability Communication is used in every requirement in COM-003-1, entities will be
required to use the English language, the central time zone, and 3-part communication in even the most
routine exchanges of information. This could create a burden on operating personnel and a distraction from
their reliability duties. This group does not feel the need for a definition of Interoperability Communication,
since the term Reliability Directive has been defined in draft standard COM-002-3, which is currently posted
for review. The Reliability Directive term is emergency-focused and consistent with the results-based
standards process
Response: Response: The proposed term “Interoperability Communication” has been removed from the
standard. Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
67
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Bulk Electric System. Routine operations that would affect the BES as described would be subject to the
use of the communication protocols in COM 003. The SDT believes the term Reliability Directives as
defined in COM 002-03 does not fully address the range of miscommunication risks that could seriously
impact the reliability of the BES.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the
reliability of BES. This was identified by the NERC President in his January 2011 report to the industry as
one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred
in the past where miscommunication was a contributing factor to the event or exacerbated the severity of
the event. The Goal, therefore, is to specify clear, formal and universally applied communication protocols
that reduce the possibility of miscommunication. The key Objective to accomplish this Goal is to use
communication protocols to reduce or correct misunderstandings. The requirements have been written to
accomplish this Objective, and are risk-mitigating requirements (while operator performance is measured,
the actions themselves are primarily designed to mitigate the risk of miscommunication that could lead to
poor BES performance). We believe this standard is consistent with results-based principles, and it will
improve the reliability of the BES.
In addition, the definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state - repeat - acknowledge) apply to Reliability Directives, while in COM-003-1 the
definition of Three-part Communication refers to “information” in general. If, as stated in the Disposition of
Requirements, the revisions to COM-002-3 will be moved to COM-003-1, the definition of Three-part
Communication in this draft standard should be consistent with the requirements of COM-002-3.The way the
definition of Three-part Communication is worded applies only when the communication is understood by
the listener the first time. Because the definition requires the listener to repeat the information back
correctly, failure of the listener to understand the information the first time could be construed as a violation
or at least not fitting the definition. The definition should rather reflect that three-part communication is an
iterative process that should be followed until the listener is confirmed by the speaker to get the information
correct.
We suggest the definition be revised as follows:
May 2, 2012
68
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
”A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct or corrected by
the party who initiated the communication. The protocol should be followed until the party issuing the
information is satisfied that a party receiving the information has understood the communication and
confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The SDT has also added language to applicable requirements to specify repeat-backs are not
required to be verbatim.
Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized.
Response: The SDT agrees and has done so within the new term, “Operating Communications”.
Response: The SDT thanks you for your comments. Please see our responses above
PJM SOS Comments
May 2, 2012
Disagree
We feel that the definition of Interoperability Communication is much too broad and is inconsistent with the
effort to develop results-based standards which would have a measurable and observable effect on the
reliability of the bulk electric system. The definition of Interoperability Communication, as written, can
include virtually any information exchange/instruction between entities, both routine and emergency. Such
communication may or may not have a measurable and observable effect on bulk system reliability. Since
the broad term Interoperability Communication is used in every requirement in COM-003-1, entities will be
required to use the English language, the central time zone, and 3-part communication in even the most
routine exchanges of information. This could create a burden on operating personnel and a distraction from
their reliability duties. This group does not feel the need for a definition of Interoperability Communication,
since the term Reliability Directive has been defined in draft standard COM-002-3, which is currently posted
for review. The Reliability Directive term is emergency-focused and consistent with the results-based
standards process.
69
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Response: The proposed term “Interoperability Communication” has been removed from the standard.
Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. Routine operations that would affect the BES as described would be subject to the
use of the communication protocols in COM 003. The SDT believes the term Reliability Directives as
defined in COM 002-03 does not fully address the range of miscommunication risks that could seriously
impact the reliability of the BES.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the
reliability of BES. This was identified by the NERC President in his January 2011 report to the industry as
one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred
in the past where miscommunication was a contributing factor to the event or exacerbated the severity of
the event. The goal, therefore, is to specify clear, formal and universally applied communication protocols
that reduce the possibility of miscommunication. The key objective to accomplish this goal is to use
communication protocols to reduce or correct misunderstandings. The requirements have been written to
accomplish this objective, and are and risk-mitigating requirements (while operator performance is
measured, the actions themselves are primarily designed to mitigate the risk of miscommunication that
could lead to poor BES performance). We believe this standard is consistent with results-based principles,
and it will improve the reliability of the BES.
In addition, the definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state - repeat - acknowledge) apply to Reliability Directives, while in COM-003-1 the
definition of Three-part Communication refers to “information” in general. If, as stated in the Disposition of
Requirements, the revisions to COM-002-3 will be moved to COM-003-1, the definition of Three-part
Communication in this draft standard should be consistent with the requirements of COM-002-3.The way the
definition of Three-part Communication is worded applies only when the communication is understood by
the listener the first time. Because the definition requires the listener to repeat the information back
correctly, failure of the listener to understand the information the first time could be construed as a violation
or at least not fitting the definition. The definition should rather reflect that three-part communication is an
May 2, 2012
70
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
iterative process that should be followed until the listener is confirmed by the speaker to get the information
correct.
We suggest the definition be revised as follows:”
A Communications Protocol where information is verbally stated by a party initiating a communication, the
information is repeated back to the party that initiated the communication by the second party that received
the communication, and the information is verbally confirmed to be correct or corrected by the party who
initiated the communication. The protocol should be followed until the party issuing the information is
satisfied that a party receiving the information has understood the communication and confirmed it.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
of COM-003. The SDT has also added language to applicable requirements to specify repeat-backs are not
required to be verbatim.
”Both element and facility are used in the Interoperability Communication definition and are NERC defined
terms. Did the drafting team intend that the NERC definitions should apply? Then the terms need to be
capitalized.
Response: The SDT agrees and has done so within the new term, “Operating Communications”.
Response: The SDT thanks you for your comments. Please see our responses above
SERC OC&SOS
Standards Review
Group
May 2, 2012
Disagree
We feel that the definition of Interoperability Communication is much too broad and is inconsistent with the
effort to develop results-based standards. Adherence to such results-based standards would have a
measurable and observable effect on the reliability of the bulk electric system. The definition of
Interoperability Communication, as written, can include virtually any information exchange/instruction
between entities, both routine and emergency. Such communication may or may not have a measurable
and observable effect on bulk system reliability. The concern is that, since the broad term Interoperability
Communication is used in every requirement in COM-003-1, entities will be required to use the English
language, the central time zone, and 3-part communication in even the most routine exchanges of
information. This could create a burden on operating personnel and a distraction from their reliability
duties. This group does not feel the need for a definition of Interoperability Communication, since the term
71
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
Reliability Directive has been defined in draft standard COM-002-3, which is currently posted for review. The
Reliability Directive term is emergency-focused and consistent with the results-based standards process.
Response: The SDT is eliminating the term Interoperability Communications because of comments citing
ambiguity. We have revised the draft standard by defining the new term “Operating Communications.”
With this new definition requiring the protocols for all operations that change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System, the SDT believes it has
removed any ambiguity over the utilization of communication protocols between or among Functional
Entities in the same or in other organizations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the
reliability of BES. This was identified by the NERC President in his January 2011 report to the industry as
one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred
in the past where miscommunication was a contributing factor to the event or exacerbated the severity of
the event. The goal, therefore, is to specify clear, formal and universally applied communication protocols
that reduce the possibility of miscommunication. The key objective to accomplish this goal is to use
communication protocols to reduce or correct misunderstandings. The requirements have been written to
accomplish this objective, and are and risk-mitigating requirements (while operator performance is
measured, the actions themselves are primarily designed to mitigate the risk of miscommunication that
could lead to poor BES performance). We believe this standard is consistent with results-based principles,
and it will improve the reliability of the BES.
In addition, the definition of Three-part Communication in this standard does not match the three-part
communication requirements stated in COM-002-3. In COM-002-3, the requirements for three-part
communication (state - repeat - acknowledge) apply to Reliability Directives, while in COM-003-1 the
definition of Three-part Communication refers to “information” in general. If, as stated in the Disposition of
Requirements, the revisions to COM-002-3 will be moved to COM-003-1, the definition of Three-part
Communication in this draft standard should be consistent with the requirements of COM-002-3.
Response: The SDT has eliminated the definition of three-part communication and has incorporated the
performance of three-part communication into the language of Requirements R2 and R3 in the second draft
May 2, 2012
72
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 1 Comment
of COM-003. The SDT agrees with your comments on consistency between the 2 standards.
Response: The SDT thanks you for your comments. Please see our responses above
NIPSCO
Agree
When COM-002-3 is fully incorporated, more definitions such as Reliability Directive will need to be added.
Response: The SDT thanks you for your comments.
Duke Energy
Disagree
When viewed in the context of its use in R5 and R6, the definition of Interoperability Communication is
excessively broad and unclear. R5 refers to the issuing of a “directive” during verbal Interoperability
Communications. The term “directive” is undefined.
R6 requires the use of the NATO phonetic alphabet during verbal Interoperability communications such as
directives, notifications, directions, instructions, orders or other reliability related operating information.
This could conceivably encompass all communications.
Response: The proposed term “Interoperability Communication” has been removed from the revised
standard. Instead the SDT is proposing the new term “Operating Communications,” which includes all
communications that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System.
Also, the definition refers to communications between two or more “entities”. Does “entities” refer to
functional entities or registered entities?
Response: The new term “Operating Communications” does not contain the word “entities.”
Response: The SDT thanks you for your comments. Please see our responses above
Westar Energy
Disagree
Would like to see the Interoperability Communication definition be more specific.
Response: The SDT thanks you for your comments.
The proposed term “Interoperability Communication” has been removed from the standard. Instead the SDT is proposing the new term
“Operating Communications,” which includes all communications that change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. The SDT believes this is more specific.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
2. The SDT incorporated TOP-002-2 Requirement R18 into this new standard COM-003-1 as Requirement R7. In
TOP-002-2, Requirement R18 applies to the Transmission Service Provider and Load Serving Entity. These
entities are now added to COM-003-1. Do you agree with this proposal? If not, please explain in the comment
area.
Summary Consideration: While many commenters did agree with the proposal, most commenters who responded to this question
disagreed with the proposal.
The dissenting commenters addressed several key issues. Many indicated that Requirement R7 should not be applicable to TSPs and
LSEs because these entities were not included in the SAR for this project. The SDT agrees and has removed TSPs and LSEs from the
standard to be consistent with the approved SAR.
Additional commenters indicated the word “equipment” as used in Requirement R7 was too broad. The standard has been modified
to use the defined terms “Element” and “Facility” instead in the revised standard Part 1.1.4.
Other commenters indicated Requirement R7 addressed a planning function already included in TOP-002, and should not be
included in COM-003. While the SDT agrees that TOP-002-2a R18 is a planning function the drafting team working on TOP-002
revisions under Project 2007-03 has proposed retiring this requirement, and the OPCP SDT believes communications between
entities would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT
proposes the concept of R7 be retained and transferred to Requirement R1, Part 1.1.4.
Commenters indicated a general consensus for the mandatory use of line and equipment identifiers applying only to interface
Elements, not Elements or Facilities internal to the footprint of the entity. The SDT agreed, and modified the standard to apply only
to interface Elements and Facilities.
Some additional comments were received indicating the previously posted standard was too prescriptive in specifying “how” to
communicate, instead of “what.” They also indicated the proposed standard was unnecessary and would distract operators from
reliably controlling the system. The SDT disagreed based on Blackout Task Force Report recommendation 26, which calls for
tightening communication to improve reliability. The SDT proposes that the second draft of the standard is more focused on “what”
protocols to use in specific situations.
There were additional comments that uniform and mutually agreed line and equipment identifiers should not be mandated so long
as the identifiers are pre-determined. The SDT agrees documentation of mutual agreement is not necessary, so long as the
identifiers are pre-determined, understood and used during Operating Communications. The standard has been modified to reflect
this change – Requirement R7 was absorbed into R1 as Part 1.1.4 as shown below:
May 2, 2012
74
Consideration of Comments on OPCP SDT — Project 2007-02
R1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator, and Distribution Provider
shall use the following communications protocols:
1.1 When participating in oral or written Operating Communications:
1.1.4. When referring to a Transmission interface Element or Transmission interface Facility, use the name
specified by the owner(s) for that Transmission interface Element or Transmission Facility.
Organization
Yes or No
Ameren
Agree
American
Municipal Power
Agree
British Columbia
Transmission
Corporation
Agree
Bureau of
Reclamation
Agree
California
Independent
System
Operator
Agree
ERCOT ISO
Agree
ExxonMobil
Research and
Engineering
Agree
FirstEnergy
Agree
Georgia
Transmission
Agree
May 2, 2012
Question 2 Comment
75
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 2 Comment
Corp
Long Island
Power Authority
Agree
New York State
Reliability
Council
Agree
NIPSCO
Agree
NYSEG
Agree
Oncor Electric
Delivery
Agree
Orange and
Rockland
Utilities, Inc.
Agree
PacifiCorp
Agree
PEF
Agree
Pepco Holdings,
Inc. - Affiliates
Agree
PowerSouth
Energy
Agree
South Carolina
Electric and Gas
Agree
Sunflower
Electric Power
Corp.
Agree
May 2, 2012
76
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Sunflower
Electric Power
Corporation
Agree
Transmission
System
Operations
Agree
Westar Energy
Agree
Western Area
Power
Administration
Agree
Xcel Energy
Agree
Washington City
Light & Power
Disagree
The Empire
District Electric
Company
Disagree
Question 2 Comment
A more efficient method of designation common pre-determined line and equipment identifiers would be through
the Reliability Coordinator. Having the Reliability Coordinator establish this would create a single methodology as
opposed to several different methodologies that would have to be agreed upon between entities and a significant
amount of work for all entities.
The SDT thanks you for your comments. The second draft of the standard requires that, when referring to a Transmission interface
Element/Facility, entities must use the name specified by the owner(s) of that Element /Facility. We believe that assignment to be the most
appropriate since it will not require any entity to change its existing practice.
Santee Cooper
Disagree
May 2, 2012
A TSP and LSE should not be subjected to other requirements within the COM 003 Standard such as Three-part
Communications.
In addition, R18 of TOP002-2 required the use of uniform line identifiers among neighboring BAs. As this
requirement (R7) is now written in COM003 it is not clear that this is when the use of uniform line identifiers is
required. As currently written, it could be interpreted that the use of uniform line identifiers is required for all
communication which is more restricting.
77
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 2 Comment
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
The second draft of the standard requires that, when referring to a Transmission interface Element/Facility, entities must use the name specified by
the owner(s) of that Element /Facility.
E.ON U.S. LLC
Disagree
As the requirement already exists it is redundant to incorporate it into COM-003. The incorporation not only
exposes a responsible entity to double jeopardy, it now exposes Transmission Service Providers and LSEs to COM003 requirements that should not apply to these entities.
Response: The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities consistent with your
comments.
TOP-002 addresses planning ahead of the operating hour whereas COM-003 addresses communication during realtime operations. In the absence of evidence that the lack of common identifiers is an imminent and continuing risk
to BES reliability, it does not make sense to have operators addressing urgent, real-time situations bear significant
penalty risk should they refer a BES element by something other than a newly established common identifier.
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT
believes this requirement is necessary in COM-003-1 for reliable real-time operations. Not ensuring that
operators are communicating about the same piece of equipment can lead to actions or inactions that could
compromise reliability.
Is it the intent of the requirement that the common identifiers be the same for all neighboring parties, all of whom
must “agree” to the identification? If not, then an element might be referred to by one identifier with Party A,
another with Party B etc. which might well defeat the purpose of the requirement. If it is required that there be a
single identifier, then all neighbors would have to agree upon the identifier constrained as each may be by, for
example, the formatting limitation of their respective SCADA/EMS systems.
Response: The second draft of the standard no longer requires explicit agreement. The new Requirement R1
Part 1.1.4 calls for the owner of the transmission asset to specify the name for its interface Elements and
Facilities.
May 2, 2012
78
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 2 Comment
Cost to modify software to accommodate common identifiers could be significant and NERC should weigh these
costs and the aforementioned operational risks against the perceived incremental improvements to the BES
reliability.
Response: The standard does not require modifications to software. To the extent entities wish to modify their
internal systems to facilitate this requirement, the SDT disagrees the cost to modify software would be
significant, as it would be limited to only interface Elements/Facilities as stated in R1.1.4 of the second draft of
the standard.
Response: The SDT thanks you for your comments. Please see our responses above.
American
Electric Power
Disagree
Based on definitions provided in the functional model, the inclusion of the TSP and LSE in this standard is
inappropriate. These entities manage the relationship with the end-use customer and are not responsible for the
operation or maintenance of BES facilities.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
We Energies
Disagree
Because applicability to a TSP and LSE of this standard stems solely from TOP-002-2 R18, R7 should be the only
requirement that applies to a TSP or LSE.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Bonneville
Power
Administration
Disagree
BPA Would like further clarification about what is meant by “pre-determined, mutually agreed upon line and
equipment identifiers”.
Response: The second draft of the standard requires that, when referring to a Transmission interface
Element/Facility, entities must use the name specified by the owner(s) of that Element /Facility.
Is it a specified format no matter which part of the system is being used, or is it only for 115 kV and above as it
applies to LSE’s and TSP’s. If it only refers to Transmission equipment above 115 kV, then BPA would likely agree.
Response: The SDT has limited the standard to communication with the intent to change or maintain the state,
May 2, 2012
79
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 2 Comment
status, output, or input of an Element or Facility of the Bulk Electric System (see definition of “Operating
Communications.” As such, the format would only apply in those situations. In addition, the SDT removed LSEs
and TSPs as responsible entities in the second draft of the standard.
Response: The SDT thanks you for your comments. Please see our responses above.
Old Dominion
Electric
Cooperative
Disagree
Comments: We believe that it may be important for entities registered as a Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider , Load
Serving Entity and Distribution Provider to have a formalized Communications Protocol Operating Procedure
(CPOP) for Interoperability Communications, but this requirement will place an unnecessary burden on the
personnel at many of the smaller Load Serving Entities and Distribution Providers on the NERC Compliance Registry.
In most real-time scenarios, the BES facilities are not operated nor maintained by the Load Serving Entity or
Distribution Provider. As with many standards, entities will be required to demonstrate why the
standard/requirement is applicable. We suggest the drafting team consider modifying the applicability of this
standard as follows similar to the format used in PRC-OO5:4.
Applicability:
4.1. Transmission Operator
4.2. Transmission Owner
4.3. Balancing Authority
4.4. Reliability Coordinator
4.5. Generator Operator
4.6. Distribution Provider that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
4.7. Transmission Service Provider
4.8. Load Serving Entity that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
Response: The SDT thanks you for your comments and suggestion.
The SDT has deleted the requirement for a Communications Protocol Operating Procedure.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
May 2, 2012
80
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 2 Comment
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity.
Electric Market
Policy
Disagree
In our experience, neither the TSP nor the LSE provide or receive information about specific lines or equipment in
real-time. Therefore, requirement R7 should not apply to them absent clear evidence that a realistic (not
hypothetical) threat to reliability would exist if they are omitted. We do not think that such a threat would exist.
Applying R7 to TSPs and LSEs would only cause them grief and further burden the compliance staffs of the regional
entities for no appreciable benefit.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Kansas City
Power & Light
Disagree
Including “equipment” is too broad. This could mean anything and should be limited to transmission devices that
could affect the reliable operation of the bulk electric system.
Response: The SDT thanks you for your comments.
R7 (now R1.1.4) has been revised in the second draft of the standard, and refers to interface Elements and interface Facilities rather than
“equipment”.
PPL
Disagree
It is not clear what real time communications take place with a TSP and/or a LSE that would put the BES in jeopardy
and thus necessitate them to be included as an applicable entity.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Manitoba Hydro
Disagree
May 2, 2012
Leave TOP-002-2 R18 in its original location.
1)”Mutual line and equipment identifiers” should not be moved from TOP-002-2 and placed in COM-003-1 R7.TOP002-2 Standard’s focus is “Planning, coordination and procedures” whereas:
o R1 is “Maintain current Plans”
o R2 is “Participate in planning and design”
o R3 is “LSE coordinate with Host”
o R4 is “BA coordinate with neighbours”
o R5 is “plan to meet schedules”
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o R6 is “plan to meet N-1”
o R7 is “plan to meet capacity and reserves”
o R8 is “plan to meet VAR limits”
o R9 is “plan to meet interchange”
o R10 is “plan to meet IROL, SOL’s”
o R11 is “perform studies for SOL’s” and “utilize identical SOL’s for common facilities”
o R12 is “include known SOLs or IROLs”
o R13 is “GO shall verify generation capability”
o R14 is “GO shall notify of changes”
o R15 is “GO shall provide generation forecast”
o R16 is “shall notify RC of changes”
o R17 is “notify RC of R1 to R16”
o R18 is “shall use uniform identifiers”
o R19 is “maintain computer models for planning”
2)TOP-002-2 R18 “shall use uniform identifies” appears to be more strongly related to where it already exists and
would have more impact to have it moved between R2 and R3.
3) Uniform identifiers are determined in the planning stages and are common knowledge to entities by the time
they are in service and not a real time communication issue.
a. Having TOP-002-2 R18 moved to COM-003-1 R7, takes the purpose of the COM-003 standard outside its context
of “timely convey reliability information . . . especially during alerts and emergencies”.
b.COM-003-1’s purpose and all its requirements directly relate to real time communication.
4) TOP-002-2 R11 “identical SOL’s for common facilities” complements R18 “shall use uniform identifiers” and again
are both planning requirements. 5)The unofficial comment for “Pre-determined Line and Equipment Identifiers”
indicates that mutual agreement of these identifiers are to be reached in advance, thus agreeing with above.
Leave R18 in TOP-002-2, but possibly move it between R2 and R3, thus R2 in COM-003-1 would be removed.
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT
believes communications between entities would be improved when use of pre-determined identifiers is
May 2, 2012
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required for interface Elements and Facilities. The SDT proposes the concept of R7 being retained and
transferred to R1 Part 1.1.4. The SDT feels that this requirement is appropriate under COM-003, as the use of
pre-determined names for interface Elements/Facilities during oral and written Operating Communications
supports the purpose of COM-003.
Regarding adding TSP and LSE, no comment added.
Response: The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Response: The SDT thanks you for your comments. Please see our responses above.
Tri-State
Generation &
Transmission
Assoc.
Disagree
LSE and TSP are not responsible for the reliability of the Bulk Electric System. That responsibility resides with the
TOP.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
National Grid
National Grid has no specific stand either ways. However, please refer to response to Question 8 for issues
pertaining to the language of the requirement.
Response: The SDT thanks you for your comments.
Please refer to the SDT response to Question 8.
NERC Staff
Disagree
NERC staff agrees with the proposal, but would offer the following modification in order to add clarity. We
recommend that the phrase “when issuing directives, notifications, directions, instructions, orders or other
reliability related operating information that involves alpha-numeric information during verbal Interoperability
Communications” be replaced with “when verbal Operating Communications with alpha-numeric information is
involved.” This would utilize the definition of Operating Communications offered in the response to Question 1.
This will hopefully eliminate the need to further define what communication is or is not included in the phrase
“directives, notifications, directions, instructions, orders or other reliability related operating information.”
Response: The SDT thanks you for your comments.
May 2, 2012
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Question 2 Comment
The SDT agrees with your comments and has incorporated the Operating Communications revisions to R7 (now R1 Part 1.1.4) in the second draft
of the standard.
Pacific
Northwest Small
Utilities
Comment Group
Our utilities agree with the move in principle, but are concerned about the transition. How will NERC ensure that
registered entities are not doubly jeopardized during the time when the same requirement exists in two active
standards? The addition of LSE to COM-003 goes way beyond the obligations in TOP-002-2 R18; LSE’s are now in
every requirement of COM-003.
Response: The SDT thanks you for your comments.
The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT believes communications between entities
would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT proposes the concept of R7
being retained and transferred to R1 Part 1.1.4.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Puget Sound
Energy
Disagree
PSE agrees in the consolidation of communication type activities into one standard; however the blanket addition
of the TSP and LSE across all requirements doesn't seem appropriate. Additional thought should be given in the
potential for these two entities to participate in the communication activities contemplated by each requirement,
rather than incorporating them wholesale. For example, a quick search on the term “directive” in the current set of
standards indicated that neither Transmission Service Providers or Load Serving Entities (or even some of the other
entities covered by the proposed standard) are likely to issue directives under the requirements of those standards,
so is it appropriate to subject them to the requirements of Requirement 5?
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR, agrees with your comments and has removed TSPs and LSEs as applicable entities.
PJM
Disagree
May 2, 2012
Requirement R7, regarding the use of pre-determined line & equipment identifiers, applies to TSPs & LSEs.
However, the other requirements of this standard do not seem to apply to these entities. For instance, most of the
reliability-related alerts are communicated through the Reliability Coordinator Information System (RCIS). TSPs do
not have access to this real-time communication tool, so the TSP should not be included in the applicability for the
entire standard.
Response: The SDT reviewed the SAR, agrees with your comments and has removed TSPs and LSEs as applicable
entities.
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Furthermore, Requirement R18 in TOP-002-2 mandated that neighboring Balancing Authorities use the uniform
line identifiers. In COM-003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring
BAs.
Response: The SDT understands the comment in regard to the use of the word “neighboring”. The SDT agrees
and has modified Requirement R7 to only apply to interface Elements/Facilities.
This requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how. The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel.
The SDT proposes that the second draft of the standard is more focused on “what” protocols to use in specific
situations. In addition to three-part communication, the SDT believes the standard should consider other
necessary protocols that prevent miscommunication.
Response: The SDT thanks you for your comments. Please see our responses above.
PJM SOS
Comments
Disagree
Requirement R7, regarding the use of pre-determined line & equipment identifiers, applies to TSPs & LSEs.
However, the other requirements of this standard do not seem to apply to these entities. For instance, most of the
reliability-related alerts are communicated through the Reliability Coordinator Information System (RCIS). TSPs do
not have access to this real-time communication tool, so the TSP should not be included in the applicability for the
entire standard.
Response: The SDT reviewed the SAR, agrees with your comments and has removed TSPs and LSEs as applicable
entities.
Furthermore, Requirement R18 in TOP-002-2 mandated that neighboring Balancing Authorities use the uniform
line identifiers. In COM-003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring
BAs.
Response: The SDT understands the comment in regard to the use of the word “neighboring”. The SDT agrees
May 2, 2012
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and has modified Requirement R7 (now R1 Part 1.1.4) to only apply to interface Elements/Facilities.
This requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how. The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the Standard should address other necessary
protocols that prevent miscommunication.
Response: The SDT thanks you for your comments. Please see our responses above.
Southern
Company
Transmission
Disagree
Southern Company supports SERC SOS comments.
SERC SOS comments:
Requirement R7, regarding the use of pre-determined line & equipment identifiers, applies to TSPs & LSEs.
However, the other requirements of this standard do not seem to apply to these entities. For instance, most of the
reliability-related alerts are communicated through the Reliability Coordinator Information System (RCIS). TSPs do
not have access to this real-time communication tool, so the TSP should not be included in the applicability for the
entire standard.
Response: The SDT reviewed the SAR, agrees with your comments and has removed TSPs and LSEs as applicable
entities.
Furthermore, Requirement R18 in TOP-002-2 mandated that neighboring Balancing Authorities use the uniform
line identifiers. In COM-003-1, this requirement is lost, since Requirement R7 makes no mention of neighboring
BAs.
Response: The SDT understands the comment in regard to the use of the word “neighboring”. The SDT agrees
and has modified Requirement R7 to only apply to interface Elements/Facilities.
Southern Company comments:
May 2, 2012
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Question 2 Comment
No proposed revision to remove R18 from TOP-002-2 has been provided in this SDT proposal. If this standard is
adopted and TOP-002-2 is not revised at the same time the same requirement will be in two reliability standards.
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT
team believes communications between entities would be improved when use of pre-determined identifiers is
required for interface Elements and Facilities. The SDT proposes the concept of R7 being retained and
transferred to R1 Part 1.1.4.
Response: The SDT thanks you for your comments. Please see our responses above.
Florida
Municipal Power
Agency (FMPA)
and some
members
Agree
The implementation plan does not specify that TOP 002 2, R18 will be retired. The disposition of the SAR explains
this, but, it should be clear in the implementation plan.
Response: The SDT thanks you for your comments.
The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT believes communications between entities
would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT proposes the concept of R7
be retained and transferred to R1 Part 1.1.4.
Indiana
Municipal Power
Agency
Disagree
The OPCP SDT does not give a real justified reason on making this requirement move from TOP-002-2 to COM-0031, except saying that the team believes it is appropriate. Unless there is a very sound or technical justification for
moving it, the requirement should be left in the current standard (TOP-002-2) to reduce the extra work and
confusion this may cause among
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP SDT
believes communications between entities would be improved when use of pre-determined identifiers is
required for interface Elements and Facilities. The SDT proposes the concept of R7 being retained and
transferred to R1 Part 1.1.4.
In addition, since Inoperability Communication is not clearly defined, if two LSE entities are communicating, do
they have to follow the communication protocol required in COM-003?
Response: The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
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Yes or No
Question 2 Comment
Response: The SDT thanks you for your comments. Please see our responses above.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments. Please refer to our response to the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Dynegy
Disagree
The SDT actually expanded Requirement R18 of TOP-002-2 by adding the term “equipment”. In any event, this
Requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not how.
Response: The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and
has modified Requirement R7 to only apply to interface Elements/Facilities.
The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel.
The SDT proposes that the second draft of the standard is more focused on “what” protocols to use in specific
situations.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the use of the three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: In addition to three-part communication, the SDT believes the standard should address other
protocols that prevent miscommunication.
Midwest ISO
Standards
Collaborators
Disagree
The SDT actually expanded Requirement R18 of TOP-002-2 by adding the term “equipment”.
Response: The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and
has modified Requirement R7 (now R1 Part 1.1.4) to only apply to interface Elements/Facilities.
In any event, this Requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how. The only real need for a requirement is to establish that each entity issuing a directive shall use
three-part communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
May 2, 2012
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Question 2 Comment
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the standard should consider protocols that prevent
miscommunication.
Response: The SDT thanks you for your comments. Please see our responses above.
Hydro-Québec
TransEnergie
Disagree
The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”.
Response: The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and
has modified Requirement R7 (now R1 Part 1.1.4) to only apply to interface Elements/Facilities
This Requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and understood.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the standard should consider other protocols that
prevent miscommunication.
LSEs and TSPs do not own or operate equipment, and as such should not fall under the mandates of this
requirement. Neither the TSP nor the LSE provide or receive information about specific lines or equipment in realtime. Therefore, requirement R7 should not apply to them absent clear evidence that a realistic (not hypothetical)
threat to reliability would exist if they are omitted. We do not think that such a threat would exist.
Response: The SDT reviewed the SAR, agrees with your comment and has removed TSPs and LSEs as applicable
entities.
Response: The SDT thanks you for your comments. Please see our responses above.
Northeast
Power
Disagree
May 2, 2012
The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”.
Response: The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and
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Yes or No
Coordinating
Council
Question 2 Comment
has modified Requirement R7 (now R1 Part 1.1.4) to only apply to interface Elements/Facilities.
This Requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and understood.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. In
addition to three-part communication, the SDT believes the Standard should address other protocols that
prevent miscommunication.
LSEs and TSPs do not own or operate equipment, and as such should not fall under the mandates of this
requirement. Neither the TSP nor the LSE provide or receive information about specific lines or equipment in realtime. Therefore, requirement R7 should not apply to them absent clear evidence that a realistic (not hypothetical)
threat to reliability would exist if they are omitted. We do not think that such a threat would exist.
Response: The SDT reviewed the SAR, agrees with your comment and has removed TSPs and LSEs as applicable
entities.
Northeast
Utilities
Disagree
The SDT expanded Requirement R18 of TOP-002-2 by adding the term “equipment”.
Response: The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and
has modified Requirement R7 (now R1 Part 1.1.4) to only apply to interface Elements/Facilities.
This Requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and understood.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
May 2, 2012
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Question 2 Comment
In addition to three-part communication, the SDT believes the Standard should address other protocols that
prevent miscommunication.
LSEs and TSPs do not own or operate equipment, and as such should not fall under the mandates of this
requirement. Neither the TSP nor the LSE provide or receive information about specific lines or equipment in realtime. Therefore, requirement R7 should not apply to them absent clear evidence that a realistic (not hypothetical)
threat to reliability would exist if they are omitted. We do not think that such a threat would exist.
Response: The SDT reviewed the SAR, agrees with your comment and has removed TSPs and LSEs as applicable
entities
Response: The SDT thanks you for your comments. Please see our responses above.
Progress Energy
Carolina, Inc
Disagree
The word "Neighboring" is used in TOP-002 R18. Excluding this word in the proposed COM-003-1 means that each
entity would have to coordinate the uniform identifiers with an undefined number of entities in the entire
Interconnection.
Response: The SDT thanks you for your comments.
The SDT agrees and has modified R7 to only apply only to interface Elements and interface Facilities.
Transmission
Agency of
Northern
California
Disagree
There is no additional reliability benefit to the proposed applicability of COM-003-1 Requirement R7 to
Transmission Service Providers (TSP) and Load Serving Entities (LSE), since TSP and LSE must already comply with
effectively the same terms in TOP-002-2 Requirement R18. Furthermore, TSP and LSE exposure to penalties and
sanctions associated with non-compliance of TOP-002-2 Requirement R18 would effectively be doubled if they
were required to also comply with COM-003-1 Requirement R7.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR, agrees and has removed TSPs and LSEs as applicable entities. Note that the drafting team working on proposed
revisions to TOP-002 has recommended retiring Requirement R18.
Consumers
Energy
Disagree
May 2, 2012
There is no reason to move R18 from TOP-002 to COM-003. There is also no reason to utilize a shotgun blast
method of coverage for this standard. Also, regardless of technical accuracy, TOP-002-2 R18 should not be moved
to COM-003-1 without a simultaneous and corresponding change to TOP-002-2, lest an entity be found noncompliant with both standards for a compliance violation.
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Response: The SDT thanks you for your comments.
The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP team believes communications between entities
would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT proposes the concept of R7
be retained and transferred to R1 Part 1.1.4.
Next Era Energy
Resources, LLC
Disagree
This requirement is already covered by TOP-002. If the TOP-002 standard is deemed deficient because certain
entities have been excluded or language appears to be missing, the changes need to occur to TOP-002 as opposed
to copying and revising the existing requirement elsewhere. This would ensure that compliance oversight,
understanding, and adherence goals are unencumbered by unnecessary redundancies. Moreover, this would
ensure that the industry continues to re-enforce standards with changes that are within the scope of their original
reliability purpose. The latter is in line with one of the core objectives of the Performance-based Reliability
Standards Task Force’s recommendations to focus on identifying and minimizing duplicated requirements.
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP team believes communications
between entities would be improved when pre-determined names are used for referencing interface Elements and Facilities. The SDT proposes
the concept of R7 being retained and transferred to R1 Part 1.1.4.
Transmission
Owner
Disagree
This requirement is already covered by TOP-002. If the TOP-002 standard is deemed deficient because certain
entities have been excluded or language appears to be missing, the changes need to occur to TOP-002 as opposed
to copying and revising the existing requirement elsewhere. This would ensure that compliance oversight,
understanding, and adherence goals are unencumbered by unnecessary redundancies. Moreover, this would
ensure that the industry continues to re-enforce standards with changes that are within the scope of their original
reliability purpose. The latter is in line with one of the core objectives of the Performance-based Reliability
Standards Task Force’s recommendations to focus on identifying and aggregating duplicated requirements.
Response: The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP team believes communications
between entities would be improved when use of pre-determined names is required for interface Elements and Facilities. The SDT proposes the
concept of R7 be retained and transferred to R1 Part 1.1.4.
Independent
Electricity
Disagree
May 2, 2012
This requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
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System
Operator
Question 2 Comment
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also use three-part communication protocol until the
message’s correct understanding is confirmed.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the Standard should address other protocols that
prevent miscommunication.
Response: The SDT thanks you for your comments. Please see our responses above.
IRC Standards
Review
Committee
Disagree
This requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the Standard should address other protocols that
prevent miscommunication.
ISO New
England Inc.
Disagree
This requirement represents a “how” and not a “what”. In general, standards should be focused on “what” not
how.
The only real need for a requirement is to establish that each entity issuing a directive shall use three-part
communications and the recipient of a directive shall also properly participate in the of use three-part
communication protocol until the message has been correctly spoken and comprehended.
Response: The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT
proposes that the second draft of the standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the Standard should address other protocols that
prevent miscommunication.
Response: The SDT thanks you for your comments. Please see our responses above.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
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Yes or No
ATC and ITC
Disagree
Question 2 Comment
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring to transmission
facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO, TOP, GOP, TSP, LSE and DP shall
use pre-determined, mutually agreed upon line and equipment identifiers for verbal and written Interoperability
Communications. TOP-002 allowed the TOP to communicate what the line identifiers were via a list and use during
communications. The new requirement implies that the parties must agree upon the line identifiers and that
agreement must be documented.ATC believes that the requirement should state that “mutual agreement” allows
for multiple identifiers. We believe that this is needed in order to avoid the following issues.
1) This clarification will avoid any need for arbitration or formal dispute resolution steps.
2) If the standard does not allow for this provision entities will be forced to deviate from their own line naming
convention and will result in entities to modify their drawings, field signs, and SCADA systems.
Response: The SDT thanks you for your comments.
The SDT agrees that mutual agreement is not necessary so long as the identifiers are pre-determined, unique and used during Operating
Communications. The second draft of the standard requires that, when referring to a Transmission interface Element/Facility, entities must use
the name specified by the owner(s) of that Element /Facility.
MRO NERC
Standards
Review
Subcommittee
Disagree
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring to transmission
facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO, TOP, GOP, TSP, LSE and DP shall
use pre-determined, mutually agreed upon line and equipment identifiers for verbal and written Interoperability
Communications. TOP-002 allowed the TOP to communicate what the line identifiers were via a list and use during
communications. The new requirement implies that the parties must agree upon the line identifiers and that
agreement must be documented.
We believe the requirement should require the exchange of line identifies but not impose that they be mutually
agreed upon. This requirement represents a “how” and not a “what”. In general, standards should be focused on
“what” not how.
Response: The SDT thanks you for your comments.
The SDT agrees that mutual agreement is not necessary so long as the identifiers are pre-determined, unique and used during Operating
Communications. The second draft of the standard requires that, when referring to a Transmission interface Element/Facility, entities must use
the name specified by the owner(s) of that Element /Facility.
The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the
May 2, 2012
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Yes or No
Question 2 Comment
standard is more focused on “what” protocols to use in specific situations.
In addition to three-part communication, the SDT believes the Standard should address other protocols that prevent miscommunication.
Great River
Energy
Disagree
TOP-002_R18 is fundamentally different from the new proposed requirement in COM-003-1_R7. TOP-002 R18
states that the BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring to transmission facilities
of an interconnected network. COM-003-1_R7 states that each RC, BA, TO, TOP, GOP, TSP, LSE and DP shall use
PRE-DETERMINED, MUTUALLY AGREED UPON line and equipment identifiers for verbal and written Interoperability
Communications. GRE believes the TOP-002_R18 could be included in COM-003-1 but included as stated verbatim
in TOP-002.
Response: The SDT thanks you for your comments and recommendation.
The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP team believes communications between entities
would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT proposes the concept of R7
being retained and transferred to R1 Part 1.1.4.
The SDT agrees that mutual agreement is not necessary so long as the identifiers are pre-determined, unique and used during Operating
Communications. The second draft of the standard requires that, when referring to a Transmission interface Element/Facility, entities must use
the name specified by the owner(s) of that Element /Facility.
Entergy Services
Disagree
TSP and LSE are not typically included in real-time communications and should not be included in this requirement.
The intent this requirement in TOP-002-2 pertained to communications between neighboring BAs and TOPs.
Adding LSE and TSP to this requirement doesn’t make sense, and this change should not be made.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR, agrees with your comment and has removed TSPs and LSEs as applicable entities.
SERC OC&SOS
Standards
Review Group
Disagree
TSPs and LSEs are not typically included in real-time communications and should not be included in COM-003-1.
The intent of requirement R18 in TOP-002-2 pertained to communications between neighboring BAs and TOPs.
Adding LSEs and TSPs to the applicability of this standard doesn’t make sense, and this change should not be made.
Response: The SDT thanks you for your comments.
The SDT reviewed the SAR, agrees with your comment and has removed TSPs and LSEs as applicable entities.
Duke Energy
Disagree
May 2, 2012
We disagree with moving R18 into COM-003-1 and broadening it to include every line and piece of equipment. This
would create an enormous amount of effort to implement, and would substantially increase compliance risk,
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Yes or No
Question 2 Comment
without any increase in reliability. Furthermore, if R18 is moved into COM-003-1, when would it be removed from
TOP-002-2? Until R18 is actually removed from TOP-002-2, entities would be subject to compliance double
jeopardy.
Response: The SDT thanks you for your comments.
The SDT appreciates the comment in regard to the use of the word “equipment”. The SDT agrees and has modified Requirement R7 to only apply
to interface Elements/Facilities.
The drafting team working on revisions to TOP-002-2a has recommended retiring R18. The OPCP team believes communications between entities
would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT proposes the concept of R7
being retained and transferred to R1 Part 1.1.4.
NRECA RTF
Members
Agree
Yes, we believe that the use of pre-determined, mutually agreed upon line and equipment identifiers for verbal and
written Interoperability Communications enhances the reliable operation of the BES.
Response: The SDT thanks you for your comments.
May 2, 2012
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3. Requirement R1 of the draft COM-003-1 states, “Each Reliability Coordinator, Balancing Authority,
Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider, Load Serving
Entity and Distribution Provider shall develop a written Communications Protocol Operating Procedure (CPOP)
for Interoperability Communications among personnel responsible for Real-time generation control and Realtime operation of the interconnected Bulk Electric System. The CPOP shall include but is not limited to all
elements described in Requirements R2 through R7 to ensure effective Interoperability Communications.” Do
you agree with this proposal? If not, please explain in the comment area.
Summary Consideration:
The majority of the commenters indicated a Communications Protocol Operating Procedure (CPOP) would be administrative in
nature and would not satisfy the criterion of enhancing the reliable operation of the BES.
The SDT agrees that a CPOP is administrative in nature, and does not satisfy the criteria of enhancing the reliable operation of the
BES. The SDT has removed it from the proposed standard.
The SDT also removed TSPs and LSEs from the list of applicable entities because they were not named in the SAR. DPs have been
maintained as applicable entities in the standard, as they were named in the SAR and perform activities impacting the BES.
Organization
Yes or No
Bureau of
Reclamation
Agree
NIPSCO
Agree
Oncor Electric
Delivery
Agree
PacifiCorp
Agree
PEF
Agree
South Carolina
Electric and Gas
Agree
Sunflower Electric
Power Corp.
Agree
May 2, 2012
Question 3 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Western Area Power
Administration
Agree
ATC and ITC
Disagree
Question 3 Comment
: Based upon the concerns that we have with R2-R7 we would not support this requirement. We would support
the requirement if it stopped after the first sentence and then merely listed the minimum requirements that
should be included in the Procedure such as; (1) time zone, (2) language spoken, (3) when phonetic alphabet will
be used, etc.. This will allow the Entities to draft their own CPOP per the intent of the requirement and avoid the
concerns that we have documented for the remainder of the requirements.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Progress Energy
Carolina, Inc
Disagree
A requirement to create a CPOP and mandating absolute adherence to that CPOP is overly prescriptive, may not
improve reliability of BES operations, and may serve to delay communications and therefore delay actions
necessary to respond to threats to the reliability of the BES.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
American Municipal
Power
Disagree
A written CPOP will place an unnecessary burden on smaller entities without an increase in reliable
communications. I feel that the other requirements are somewhat self-explanatory and that an annual review of
the phonetics and three-part communications would improve reliability more than having a written CPOP
requirement.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Puget Sound Energy
May 2, 2012
Disagree
As discussed in Question 2, further consideration should be given to whether it is appropriate to include all the
listed entities in this requirement.
Additionally, the phrase “is not limited to” should be removed from the last sentence of the proposed
requirement. The standard should specifically spell out what should be included in the CPOP. This phrase would
lead to confusion about what an entity must include in the CPOP and is likely to result in inconsistent
enforcement of the requirement.
Also R1 appears to require a CPOP that will be used by personnel responsible for Real-time generation control
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Organization
Yes or No
Question 3 Comment
and Real-time operation of the interconnected Bulk Electric System. It is unclear if this specificity in who has to
follow this extends to R2-R7 as well (while as noted the CPOP has to include elements of R2-R7). Without that
clarity, the aspects of R2-R7 could seeming extend to communication between non-critical personnel regarding
non-critical information.
In addition, it appears that each of these entities must develop their own CPOP with clarity how the protocol gets
vetted so that it is effectively employed across the entities. Finally, when reviewing the Functional Model
document and its discussion of tasks and relationships to other entities, it is unclear why the TO is included in the
applicability as they perform no real-time functions and provide no real time information.
Response: The SDT thanks you for your comments. The SDT did remove the TSP and LSE from the second draft of the standard. Many of the
comments we received pointed out that having a CPOP does not directly contribute to reliability. The SDT agrees, and has deleted the requirement
for a CPOP.
British Columbia
Transmission
Corporation
Disagree
BCTC agrees with R1, R2, R3, R5 and R7 but strongly objects to R4 and R6.
As a majority of the Interoperability Communications is within our time zone the is no advantage in using Central
Standard Time as this will only make the communications more difficult as both parties are required to change
time, R4 is unreasonable.
R6 requiring the use of North American Treaty Organization (NATO) phonetic alphabet adds no value and will only
cause confusion presently an instruction would be issued as:”At Kelly Lake open 5CB4” R6 it will now become “At
Kelly Lake open Fife Charlie Bravo Fow-er”
Response: The SDT thanks you for your comments. Since the comments made by BCTC are directed specifically to requirements R4 and R6, the SDT
responses to BCTC are covered in the responses to the relevant section for those requirements. You are correct, based on the requirement to use a
phonetic alphabet, an operator that might normally say “At Kelly Lake open 5CB4” will now be required to say something similar to “At Kelly Lake
open Fife Charlie Bravo Fow-er.” This is intended to ensure that the recipient of the communication does not mistake the instruction for “At Kelly
Lake open 5CP4.” While “B” and “P” may sounds similar, “Bravo” and “Papa” clearly do not.
Bonneville Power
Administration
Disagree
BPA does not agree with the one time zone or the NATO Standard. We believe the protocols are unnecessary and
in fact will add more confusion to the process. We also do not agree, if this requires creating a brand new
documented procedure just to address this standard, when elements are already covered in a different standard
(common language in TOP).
Response: The SDT thanks you for your comments. Since the comments made by BPA are directed specifically to requirement R6, the SDT
May 2, 2012
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Organization
Yes or No
Question 3 Comment
responses to BPA are covered in the responses to the relevant requirements. Note that the SDT is proposing an alternative to R6.
California
Independent System
Operator
Disagree
CAISO Comment; The requirement does not distinguish between intra and inter communications. Even though
the proposed definition of “Interoperability Communications” is between two “entities”, how will an auditor
interpret it? Will this be taken to the extreme and be required to address communications between two different
functions within one organization? For example, between the generation desk and the scheduling desk? How
important is this plan? This requirement has a low Violation Risk Factor while the individual requirements that
makeup the plan have High Violation Risk Factors. Furthermore, the Violation Security Levels do not address
failure to follow the protocol in the plan. Based on the VFR and VSL, it is easy to conclude this plan does little in
supporting an adequate level of reliability.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP. Additionally, it should be noted that the SDT has removed the definition
and any reference to “Interoperability Communications”.
NorthWestern
Energy
Disagree
COM-001 and COM-002 standards, along with Operator Training, adequately address this issue. Therefore there
is no need for this additional requirement.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
New York State
Reliability Council
Disagree
Comments: NYSRC agrees with the need for CPOP but does not agree that R4 can or should apply to all
interoperability communications between entities. Since the examples in Attachment 1 specifically state RC and
TOP, this standard should not apply to any other entity except for the RC and TOP. COM-002-03(draft) could
require the other entities to utilize three part communication for reliability-related Interoperability
communication.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP. The concern stated by NYSRC regarding R4 is addressed in the SDT
responses to question #5.
Old Dominion
Electric Cooperative
May 2, 2012
Disagree
Comments: We believe that it may be important for entities registered as a Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider , Load
Serving Entity and Distribution Provider to have a formalized Communications Protocol Operating Procedure
(CPOP) for Interoperability Communications, but this requirement will place an unnecessary burden on the
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Organization
Yes or No
Question 3 Comment
personnel at many of the smaller Load Serving Entities and Distribution Providers on the NERC Compliance
Registry. In most real-time scenarios, the BES facilities are not operated nor maintained by the Load Serving Entity
or Distribution Provider. As with many standards, entities will be required to demonstrate why the
standard/requirement is applicable. We suggest the drafting team consider modifying the applicability of this
standard as follows similar to the format used in PRC-OO5:4. Applicability:
4.1. Transmission Operator
4.2. Transmission Owner
4.3. Balancing Authority
4.4. Reliability Coordinator
4.5. Generator Operator
4.6. Distribution Provider that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
4.7. Transmission Service Provider
4.8. Load Serving Entity that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP. We did not include the LSE or TSP because they were not listed in the
SAR but did include DPs in the standard as DPs carry out actions related to the reliability of the Bulk Electric System such as voltage reduction and
load shedding.
Tri-State Generation
& Transmission
Assoc.
Disagree
DP, LSE and TSP are not responsible for the reliability of the Bulk Electric System. Also, attachment 1 explains
Operating State Alert Levels that defines colors that are already in use by the Department of Homeland Security.
Re-using these colors presents confusion to the operators of the BES. This places an unnecessary additional
burden on Real Time day-to-day operations with a high risk of confusion in an emergency.
Response: The SDT thanks you for your comments. The SDT appreciates the comments with regards to concerns related to including TSPs, DPs and
LSEs. The SDT has removed the LSE and TSP functions from the applicability of the current draft of the standard, which is consistent with the SAR.
However, the SDT believes that DPs carry out actions related to the reliability of the Bulk Electric System such as voltage reduction and load
shedding. Several existing standards contain requirements concerning operating communications that DPs must presently comply with that would
be governed by the protocols of COM -003-1. It should be noted that the requirements of the second draft of COM-003-1 are only applicable to
May 2, 2012
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Organization
Yes or No
Question 3 Comment
Operating Communications. To the extent that these entities do not take actions that change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System, COM-003-1 would not apply.
The SDT refers Tri-State Generation & Transmission Assoc. to response to Question 9 to see responses showing changes proposed on Attachment 1
of COM-003.
Pacific Northwest
Small Utilities
Comment Group
Disagree
DPs and LSEs are in general users, not owners or operators of interconnected BES equipment per the registry
criteria. DPs and LSEs should be removed from this requirement since LSEs typically do not own or operate the
interconnected BES equipment
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable entity.
Transmission Owner
May 2, 2012
Disagree
FPL agrees with the reliability goal of establishing a set of agreed upon communication standards to ensure
consistent communications particularly for actual and anticipated emergency coordination needs. FPL also
believes that existing coordination/communication standards already fulfill this objective and that it might be of
“training” or “reference” value to aggregate those requirements to a single document or view. However, FPL is
not convinced that this requirement, largely administrative in nature, will result in marked improvement in
reliability. Organizations tend to take the path of least resistance and unless forced out of that path with
extensive and granular guidance on what CPOPs should contain above and beyond existing standards or contract
language, CPOPs would likely become a simple patchwork of requirements constructed out of existing NERC
standard language and contract language. Standards need to be clearly implementable before they are approved
yet important implementation questions do not appear to have been answered.
(1) What if parties cannot reach agreement?
(2) Is it enough to have attempted to coordinate?
(3) What if parties already have agreed upon procedures such as NPIRs, or those stated in Interconnection
Agreements - do they take precedent or must they be redesigned/relegated?
(4) What if CPOPs differ greatly across interconnections because of differing parties? (One might conclude that by
formalizing these different practices, as opposed to mandating standard practices, the goal of more reliable
coordination may not have been achieved)
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Question 3 Comment
(5) What level of evidence constitutes “agreement” especially in circumstances where entities may be remiss to
agree?
(6) What if CPOPs are simply a patchwork of requirements constructed out of existing NERC standard language
and contract language - does that achieve the CPOP goal?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Consumers Energy
Disagree
I agree written Communication Protocols should be in place. Since we do not agree with all of the requirements
mentioned we cannot agree with this statement. Furthermore, since these protocols will have to be between
Functional Entities and most likely multiple companies, a methodology needs to be in place to prevent duplication
of efforts and double jeopardy in the audit process.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Florida Municipal
Power Agency
(FMPA) and some
members
Disagree
If one of the goals is consistent communications, why would the standard require each Entity to develop a
separate CPOP? For consistency, shouldn’t the Reliability Coordinator develop the CPOP (with input from the
other Entities) and all other Entities within the RC’s area adopt it?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Entergy Services
Disagree
Interoperability communications should be removed as recommended in our response to question 1. Creating
requirements for the communications protocol will by necessity require entities to document how they meet the
requirements. A requirement for an operating procedure is redundant. The requirement to have an operating
procedure in effect makes this a “how” requirement. An entity could choose to have more than one procedure
that described their communications protocol. This requirement as written could force an entity to put all of
their communications procedures into one CPOP, which doesn’t improve reliability. Therefore the requirement is
not needed and should not be included in the standard.
Response: The SDT thanks you for your comments. “Interoperability Communications” has been removed because it appeared to be ambiguous and
unclear.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 3 Comment
Many of the comments we received pointed out that having a CPOP does not directly contribute to reliability. The SDT agrees, and has deleted the
requirement for a CPOP.
We Energies
Disagree
It is not clear what the purpose of the CPOP is, or how having it would improve reliability of the Bulk Electric
System. This standard, (or alternatively COM-002-003) should focus on requiring Three-Part Communication
during Reliability Directives. In addition, the vague and broad nature of the existing definition of Interoperability
Communication makes creating CPOP’s problematic and open to conflict with the CPOP’s developed
independently by other entities. As noted in question 2, R1 should not apply to a TSP or LSE.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities.
Independent
Electricity System
Operator
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions without inclusion of the elements to be communicated as they cover a wide
range of conditions which can vary among the communicating parties.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
IRC Standards
Review Committee
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. The NERC BOT has approved pursuing the Performance-based Reliability
Standard Task Force’s recommendations to assess the existing standards, modify and develop standards that
support reliability performance and risk management, and work on an overall plan to transition existing standards
to a new set of standards. One goal of this effort is to delineate actionable reliability requirements from
record/documentation requirements.
This proposal takes the opposite approach and incorporates a new administrative requirement. We - and the
industry as a whole based on the response to the Task Force - do not support such an approach. We suggest
deleting this Requirement from the Standard.
Furthermore, the establishment of R2-R7 as elements of the CPOP required in R1 appears to contradict the recent
May 2, 2012
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Yes or No
Question 3 Comment
shift in direction that NERC has taken regarding defining criteria as bullets under a requirement. See NERC’s
August 10th informational filing regarding assignment of violation risk factors and violation severity levels in
regards to dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10-000.COM-003 R2 states: “shall use predefined system condition terminology as defined in Attachment 1-COM-003-1 for verbal and written
Interoperability Communications.” Why does R1 establish the requirement for a procedure, when the procedure
is essentially defined by R2-R7. If there is such reliability need to establish these requirements, one could
conclude nothing else is so important that it needs to be included because it is not identified in the standard.
Furthermore, R2 appears to define Interoperability Communications for attachment 1 communications only. Is
this the intent of the drafting team?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
ISO New England
Inc.
May 2, 2012
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. The NERC BOT has approved pursuing the Performance-based Reliability
Standard Task Force’s recommendations to assess the existing standards, modify and develop standards that
support reliability performance and risk management, and work on an overall plan to transition existing standards
to a new set of standards. One goal of this effort is to delineate actionable reliability requirements from
record/documentation requirements. This proposal takes the opposite approach and incorporates a new
administrative requirement. We - and the industry as a whole based on the response to the Task Force - do not
support such an approach. We suggest deleting this Requirement from the Standard. Furthermore, the
establishment of R2-R7 as elements of the CPOP required in R1 appears to contradict the recent shift in direction
that NERC has taken regarding defining criteria as bullets under a requirement. See NERC’s August 10th
informational filing regarding assignment of violation risk factors and violation severity levels in regards to
dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10-000.COM-003 R2 states: “shall use pre-defined
system condition terminology as defined in Attachment 1-COM-003-1 for verbal and written Interoperability
Communications.” Why does R1 establish the requirement for a procedure, when the procedure is essentially
defined by R2-R7. If there is such a reliability need to establish these requirements, one could conclude nothing
else is so important that it needs to be included because it is not identified in the standard. Furthermore, R2
appears to define Interoperability Communications for attachment 1 communications only. Is this the intent of
the drafting team?
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 3 Comment
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
National Grid
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
PJM
Disagree
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. We feel that there should not be a requirement in the standard to have a
“procedure”. It is our understanding that, to be auditably compliant with a standard, the responsible entity must
develop a procedure, train on that procedure, and be able to demonstrate compliance via documents, data, logs,
records, etc. If Requirements R2 - R7 are included in this standard, the entity will need to develop a procedure to
be compliant. In other words, the procedure itself will become the focus rather than the actual communications
protocol. Therefore, we feel that requirement R1 is redundant and should not be included. The NERC BOT has
approved pursuing the Performance-based Reliability Standard Task Force’s recommendations to assess the
existing standards, modify and develop standards that support reliability performance and risk management, and
work on an overall plan to transition existing standards to a new set of standards. One goal of this effort is to
delineate actionable reliability requirements from record/documentation requirements. This proposal takes the
opposite approach and incorporates a new administrative requirement. We - and the industry as a whole based
on the response to the Task Force - do not support such an approach. We suggest deleting this Requirement
from the Standard. Furthermore, the establishment of R2-R7 as elements of the CPOP required in R1 appears to
contradict the recent shift in direction that NERC has taken regarding defining criteria as bullets under a
requirement. See NERC’s August 10th informational filing regarding assignment of violation risk factors and
violation severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10000Furthermore, R2 appears to define Interoperability Communications for attachment 1 communications only.
Is this the intent of the drafting team?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
PJM SOS Comments
Disagree
Question 3 Comment
It is not clear what the purpose of this communication protocol is or what should even be included in the
protocol. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. We feel that there should not be a requirement in the standard to have a
“procedure”. It is our understanding that, to be auditably compliant with a standard, the responsible entity must
develop a procedure, train on that procedure, and be able to demonstrate compliance via documents, data, logs,
records, etc. If Requirements R2 - R7 are included in this standard, the entity will need to develop a procedure to
be compliant. In other words, the procedure itself will become the focus rather than the actual communications
protocol. Therefore, we feel that requirement R1 is redundant and should not be included. The NERC BOT has
approved pursuing the Performance-based Reliability Standard Task Force’s recommendations to assess the
existing standards, modify and develop standards that support reliability performance and risk management, and
work on an overall plan to transition existing standards to a new set of standards. One goal of this effort is to
delineate actionable reliability requirements from record/documentation requirements. This proposal takes the
opposite approach and incorporates a new administrative requirement. We - and the industry as a whole based
on the response to the Task Force - do not support such an approach. We suggest deleting this Requirement
from the Standard. Furthermore, the establishment of R2-R7 as elements of the CPOP required in R1 appears to
contradict the recent shift in direction that NERC has taken regarding defining criteria as bullets under a
requirement. See NERC’s August 10th informational filing regarding assignment of violation risk factors and
violation severity levels in regards to dockets RM08-11-000, RR08-4-000, RR07-9-000, and RR07-10000Furthermore, R2 appears to define Interoperability Communications for attachment 1 communications only.
Is this the intent of the drafting team?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
NYSEG
Disagree
It is not clear when the Interoperability Communication is required to be used. Is it only for communications
between registered entities (inter) or internal to a registered entity (intra)? And is it required for all
communications or used only in certain circumstances (i.e. emergency (if emergency, it needs to be defined what
constitutes an emergency))?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
PowerSouth Energy
May 2, 2012
Disagree
It's not clear as to who is being targeted as the "personnel responsible for real-time generation control and real107
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 3 Comment
time operation of the BES". Is this just the system operator or is this the generator unit operator or the field
switchman?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The person responsible may be any individual from an Applicable Entity who sends or receives an operating communication changing the state or
status of the BES. Note that in the second draft of this standard, the phrase, “personnel responsible for real-time generation control and real-time
operation of the BES” is not used.
Long Island Power
Authority
Disagree
LIPA agrees with the need for CPOP but does not agree that R4 can or should apply to all interoperability
communications between entities. Since the examples in Attachment 1 specifically state RC and TOP, this
standard should not apply to any other entity except for the RC and TOP. COM-002-03(draft) could require the
other entities to utilize three part communication for reliability-related Interoperability communication.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
City Of Greenfield
Disagree
Listed as an LSE & DP, we are a small municipal utility that does not own nor operate any generation or
transmission equipment. Therefore this standard is not applicable to our facility. Keep in mind, not all LSE's & DP's
operate generation or transmission equipment. There are several small utilities that this standard would not be
applicable to. LSE's & DP's should be put into class sizes depending on the size of the company or utility. Example:
Class #1 LSE & DP : Companies that own & operate generation & transmission
Class #2 LSE & DP :
Companies that do not own or operate generation & transmission.(municipals,co-ops,etc)
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity.
NERC Staff
May 2, 2012
Disagree
NERC staff recommends that Requirement R1 be deleted because it is strictly an administrative requirement that
is not necessary. It is not results-based, and is redundant given the imbedded reference to Requirements R2 to
R7. If an entity can demonstrate compliance with the other requirements, Requirement R1 performs no
additional reliability enhancement. A Requirement should state a performance outcome or a risk to be mitigated.
If there is a need to document something, the appropriate location for that is in the Measures section of the
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standard. A distinction should be made here that producing a document containing specific content necessary for
reliability, such as a system restoration procedure, can be an effective requirement used to minimize risk.
However, documentation that does not stand on its own as a result necessary for reliability should not be made
into a requirement. Such documentation requirements should either be eliminated or moved to an
administrative, informational section of the standards. An example of a weak requirement is “the Responsible
Entity shall document the implementation of security patches”. The requirement that directly contributes to a
risk reduction outcome is to implement applicable cyber security patches. Documentation of the implementation
is simply a vehicle for demonstrating compliance. The NERC staff does not find that the CPOP satisfies the
criterion of reducing risk.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
NextEra Energy
Resources, LLC
Disagree
NextEra agrees with the reliability goal of establishing a set of agreed upon communication standards to ensure
consistent communications particularly for actual and anticipated emergency coordination needs. NextEra
believes that existing coordination/communication standards already fulfill this objective and that it might be of
“training” or “reference” value to aggregate those requirements to a single document or view. However, NextEra
is not convinced that this requirement, largely administrative in nature, will result in marked improvement in
reliability. Organizations tend to take the path of least resistance and unless forced out of that path with
extensive and granular guidance on what CPOPs should contain above and beyond existing standards or contract
language, CPOPs would likely become a simple patchwork of requirements constructed out of existing NERC
standard language and contract language. Standards need to be clearly implementable before they are approved
yet important implementation questions do not appear to have been answered. (1) What if parties cannot reach
agreement? (2) Is it enough to have attempted to coordinate? (3) What if parties already have agreed upon
procedures such as NPIRs, or those stated in Interconnection Agreements - do they take precedent or must they
be redesigned/relegated? (4) What if CPOPs differ greatly across interconnections because of differing parties?
(One might conclude that by formalizing these different practices, as opposed to mandating standard practices,
the goal of more reliable coordination may not have been achieved) (5) What level of evidence constitutes
“agreement” especially in circumstances where entities may be remiss to agree? (6) What if CPOPs are simply a
patchwork of requirements constructed out of existing NERC standard language and contract language - does that
achieve the CPOP goal?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
May 2, 2012
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to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Pepco Holdings, Inc.
- Affiliates
Disagree
PHI agrees that communications procedures are necessary. We do not see the need to create a CPOP that
includes requirements R2 through R7 given that each requirement defines how and what is to be communicated.
This requirement as written could force entities to incorporate all of their communication procedures into a CPOP
which will not improve reliability.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Orange and
Rockland Utilities,
Inc.
Disagree
R4 - Use of the CST time format would present challenges affecting hardware, software, and training in the ECC
and is counter to practices of scheduling, switching execution, and time-stamping of activities currently executed
by the ECC. A more defined definition of “Interoperability Communications” needs to be instituted in conjunction
with R4 applicability.
Response: See the responses under question #5 which addresses R4. The SDT has eliminated the term “Interoperability Communications”
E.ON U.S. LLC
Disagree
Requiring production of a document that merely repeats Requirement 2-7 of COM-003 does not further BES
reliability. Requirements R2-R7 set forth all that such a document would contain. Stating that the CPOP should
include but not be limited to R2-R7 is nonsensical. What additional issues should the CPOP be required to
address and why aren’t those issues the subject of a COM-003 requirement?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Southern Company
Transmission
May 2, 2012
Disagree
Southern Company supports the SERC SOS comments.
SERC SOS comments: This group feels that there should not be a requirement in the standard to have a
“procedure”. It is our understanding that, to be auditably compliant with a standard, the responsible entity must
develop a procedure, train on that procedure, and be able to demonstrate compliance via documents, data, logs,
records, etc. If Requirements R2 - R7 are included in this standard, the entity will need to develop a procedure to
be compliant. Therefore, we feel that requirement R1 is redundant and should not be included.
Southern company comments: The VSF for not having a written procedure is Severe. If an entity does not have a
written procedure but complies with the other requirements in this standard has the reliability of the Bulk Electric
System been affected? If the reliability of the Bulk Electric System is not affected by not having a written
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procedure why is this requirement in a Reliability Standard?
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Great River Energy
Disagree
The NERC BOT has approved pursuing the Performance-based Reliability Standard Task Force’s recommendations
to assess the existing standards, modify and develop standards that support reliability performance and risk
management, and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to eliminate administrative requirements. This proposal takes the opposite approach and
incorporates a new administrative requirement. GRE does not support such an approach. GRE suggests deleting
this Requirement from the Standard.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Duke Energy
Disagree
There is no need to have a CPOP to describe how an entity will comply with R2 through R7. A CPOP would just be
a restatement of the requirements. If an entity complies with R2 through R7, there’s no reliability related benefit
to having a CPOP.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
ERCOT ISO
Disagree
This approach of an administrative type requirement is in conflict with the NERC BOT approval of pursuing the
development of standards to support reliability performance and eliminate administrative requirements. It is not
necessary to have a separate CPOP document to insure operating personnel communicate effectively.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
SERC OC&SOS
May 2, 2012
Disagree
This group feels that there should not be a requirement in the standard to have a “procedure”. It is our
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understanding that, to be auditably compliant with a standard, the responsible entity must develop a procedure,
train on that procedure, and be able to demonstrate compliance via documents, data, logs, records, etc. If
Requirements R2 - R7 are included in this standard, the entity will need to develop a procedure to be compliant.
Therefore, we feel that requirement R1 is redundant and should not be included.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Ameren
Disagree
This is a near fill-in-the-blank requirement. The mere inclusion, or recitation, of the R2-7 elements does not
assure a meaningful plan. It is easy to say “Our plans includes R3”. That does not assure reliable communications.
This requirement should describe a functional CPOP.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Georgia
Transmission Corp
Disagree
This is a requirement for an operating procedure which is redundant and would require the entities to document
how they met the requirement.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Dynegy
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be included in this
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions.
The NERC BOT has approved pursuing the Performance-based Reliability Standard Task Force’s recommendations
to assess the existing standards, modify and develop standards that support reliability performance and risk
management, and work on an overall plan to transition existing standards to a new set of standards. One goal of
this effort is to eliminate administrative requirements. This proposed Requirement takes the opposite approach
and incorporates a new administrative requirement. We - and the industry as a whole based on the response to
the Task Force - do not support such an approach. We suggest deleting this Requirement from the Standard.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Hydro-Québec
May 2, 2012
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be included in this
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Question 3 Comment
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions for all entities involved in real time operations. The NERC BOT has approved
pursuing the Results-based Reliability Standard Task Force’s recommendations to assess the existing standards,
modify and develop standards that support reliability performance and risk management, and work on an overall
plan to transition existing standards to a new set of standards. One goal of this effort is to eliminate
administrative requirements. This proposal takes the opposite approach and incorporates a new administrative
requirement. The industry as a whole, based on the response to the Task Force, does not support such an
approach. This Requirement should be deleted from the Standard. There is no need to create a CPOP that
includes requirements R2 through R7 given that each requirement spells out how and what is to be
communicated. A CPOP may be needed for Interoperability Communications that are not addressed in R2-7.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Kansas City Power &
Light
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be included in this
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions and using agreed upon terminology for switching equipment for bulk electric
system.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Midwest ISO
Standards
Collaborators
Disagree
This proposed communication protocol is redundant to Requirements R2-R7 and should not be included in this
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. The NERC BOT has approved pursuing the Performance-based Reliability
Standard Task Force’s recommendations to assess the existing standards, modify and develop standards that
support reliability performance and risk management, and work on an overall plan to transition existing standards
to a new set of standards. One goal of this effort is to eliminate administrative requirements. This proposal takes
the opposite approach and incorporates a new administrative requirement. We - and the industry as a whole
based on the response to the Task Force - do not support such an approach. We suggest deleting this
Requirement from the Standard.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
May 2, 2012
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to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Northeast Power
Coordinating Council
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be included in this
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. The NERC BOT has approved pursuing the Results-based Reliability Standard
Task Force’s recommendations to assess the existing standards, modify and develop standards that support
reliability performance and risk management, and work on an overall plan to transition existing standards to a
new set of standards. One goal of this effort is to eliminate administrative requirements. This proposal takes the
opposite approach and incorporates a new administrative requirement. The industry as a whole, based on the
response to the Task Force, does not support such an approach. This Requirement should be deleted from the
Standard. There is no need to create a CPOP that includes requirements R2 through R7 given that each
requirement spells out how and what is to be communicated. A CPOP may be needed for Interoperability
Communications that are not addressed in R2-7.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Northeast Utilities
Disagree
This proposed communication protocol is redundant to Requirements R2-R7, and should not be included in this
Standard. This standard only needs to focus on requiring three-part communications during actual and
anticipated emergency conditions. The NERC BOT has approved pursuing the Results-based Reliability Standard
Ad Hoc Working Group recommendations to assess the existing standards, modify and develop standards that
support reliability performance and risk management, and work on an overall plan to transition existing standards
to a new set of standards. One goal of this effort is to eliminate administrative requirements. This proposal takes
the opposite approach and incorporates a new administrative requirement. The industry as a whole, based on
the response to the Task Force, does not support such an approach. This Requirement should be deleted from
the Standard.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Electric Market
Policy
May 2, 2012
Disagree
We agree that communications procedures are necessary, but we do not agree with several of the requirements
proposed to be addressed in the elements of the CPOP. See our comments on specific requirements elsewhere in
our responses.
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We do not see the need to create a CPOP that includes requirements R2 through R7 given that each requirement
spells out how and what is to be communicated. We could agree that a CPOP may be needed for Interoperability
Communications that are not addressed in R2-7.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Xcel Energy
Disagree
We agree with the structure of the standard, however we have issues with several of the CPOP elements being
proposed. (See detail comments in following questions.)
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Santee Cooper
Disagree
We believe that a company’s documentation demonstrating compliance for R2 through R7 would eliminate the
need for a CPOP document.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Sunflower Electric
Power Corporation
Disagree
We believe that distribution providers (electric cooperatives) should be removed from this standard unless they
control a BES segment
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity subject to the DPs’ impact
on Elements on the BES.
NRECA RTF
Members
May 2, 2012
Disagree
We believe that it may be important for entities registered as a Reliability Coordinator, Balancing Authority,
Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider , Load Serving
Entity and Distribution Provider to have a formalized Communications Protocol Operating Procedure (CPOP) for
Interoperability Communications, but this requirement will place an unnecessary burden on the personnel at
many of the smaller Load Serving Entities and Distribution Providers on the NERC Compliance Registry. In most
real-time scenarios, the BES facilities are not operated nor maintained by the Load Serving Entity or Distribution
Provider. As with many standards, entities will be required to demonstrate why the standard/requirement is
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applicable. We suggest the drafting team consider modifying the applicability of this standard as follows similar to
the format used in PRC-OO5:
4. Applicability:
4.1. Transmission Operator
4.2. Transmission Owner
4.3. Balancing Authority
4.4. Reliability Coordinator
4.5. Generator Operator
4.6. Distribution Provider that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
4.7. Transmission Service Provider
4.8. Load Serving Entity that is responsible for Real-time generation control and Real-time operation of the
interconnected Bulk Electric System
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity subject to the DPs’ impact
on Elements on the BES.
Washington City
Light & Power
Disagree
We believe that it may be important for entities registered as a Reliability Coordinator, Balancing Authority,
Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider , Load Serving
Entity and Distribution Provider to have a formalized Communications Protocol Operating Procedure (CPOP) for
Interoperability Communications, but this requirement will place an unnecessary burden on the personnel at
many of the smaller Load Serving Entities and Distribution Providers on the NERC Compliance Registry. In most
real-time scenarios, the BES facilities are not operated nor maintained by the Load Serving Entity or Distribution
Provider. As with many standards, entities will be required to demonstrate why the standard/requirement is
applicable.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
May 2, 2012
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to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have been
retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity subject to the DPs’ impact
on Elements on the BES.
Transmission System
Operations
Disagree
We believe the phrase, “but is not limited to” should be deleted. The elements required to be in the CPOP should
be well-defined.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
FirstEnergy
Disagree
We feel that procedures are beneficial for entities to have as far as internal training of new personnel and as a
reference guide for all personnel, but we do not agree that it should be a requirement of a reliability standard. It
is not appropriate to subject an entity to monetary fines for not having a procedure even if that entity has fully
complied with all the other requirements (R2 through R7) of this standard that the procedure is referencing.
Although this requirement may fall into the category of best practices and administrative requirements, it
certainly does not rise to the level of performance-based, risk-based, or competency-based requirements. The
real evidence of an entity implementing R2 through R7 is by evaluating the measures of those requirements and a
variety of information could be used by an entity such as training records, procedures, voice recordings etc.
Having a procedure does not need to be a standalone requirement.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
MRO NERC
Standards Review
Subcommittee
May 2, 2012
Disagree
We request that R1 be rewritten for real time operation of elements and facilities connected to the BES.
Based upon the concerns that we have with Requirements R2-R7 we would not support this requirement. We
would support requirement R1 if it stopped after the first sentence and then merely listed the minimum
requirements that should be included in the Procedure such as; (1) time zone, (2) language spoken, (3) when
phonetic alphabet will be used, etc.. This will allow the Entities to draft their own CPOP per the intent of the
requirement and avoid the concerns that we have documented for the remainder of the requirements. Reliability
Standards are supposed to describe “What” is required, not “How” compliance would be achieved. We believe
this proposed Reliability Standard describes more the “How”, and is contrary to the Results Based Standards
Initiative being implemented by NERC. The NERC BOT has approved pursuing the Performance-based Reliability
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Standard Task Force’s recommendations to assess the existing standards, modify and develop standards that
support reliability performance and risk management, and work on an overall plan to transition existing standards
to a new set of standards. One goal of this effort is to eliminate administrative requirements. This proposal takes
the opposite approach and incorporates a new administrative requirement. We - and the industry as a whole
based on the response to the Task Force - do not support such an approach. We suggest deleting this
Requirement from the Standard. The CPOP should only apply to verbal communications. It could be implied that
written communications (switching order affecting the BES) must have a CPOP, which would essentially be a
writing guide procedure for how to write a procedure. The CPOP would need to be developed for each entity on
how to write a CPOP and all the requirements contained in this draft standard. Every entity has unique switching
instruction templates that have been developed over time in negotiations with unions, third-parties, etc, which
have detailed procedures for their use. Requiring the use of a CPOP on top of that is adding additional complexity
that adds nothing to the reliability of the BES.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The Empire District
Electric Company
Disagree
What benefit to the BES would this provide? Rather I see more confusion by having entities develop different
CPOPs. How will this benefit real time operation? This seems to be a requirement by NERC to assist NERC in
analysis "after the fact" of an event, but in reality it can hinder daily operations.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Indiana Municipal
Power Agency
Disagree
What reliability purpose is served by restating requirements two through seven in a Communications Protocol
Operating Procedure (CPOP)? Since these requirements are the only required items in the CPOP, entities will just
be restating these requirements in their CPOP. In addition, this is an administrative requirement which does not
fit into the new performance-based standard principle that should be used by SDT's.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
American Electric
Power
May 2, 2012
Disagree
While having a procedure is important and the responsible entities should have a procedure to be compliant,
there is not necessary to establish this requirement to have a procedure. We need to stay focused on what the
purpose of the standard is to be and not dilute its effectiveness by focusing on documented procedures.
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Furthermore, if the extent of communication concerns warrants the extensive effort to establish pre-defined line
and equipment identifiers, then this should be established in a uniform manner and not left to result in
multitudes of approaches. There will likely need to be system modifications to address character limitations with
respect to line and equipment identifiers.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Westar Energy
Disagree
While I agree that a CPOP in necessary and should include the elements of the requirements, I am not sold on all
of the requirements yet as written.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP. Please comment on the revisions we made to the remaining
requirements.
ExxonMobil
Research and
Engineering
Disagree
While recording telephone conversations may be routine for utility companies, many industrial facilities that fall
under the jurisdiction of this standard do not currently have the facilities necessary to record the conversations
and store them for an extended length of time. If a company does not currently possess the capability to record
telephone conversations, is it the intent of this standard to require them to install such facilities? If so, what is
the time frame surrounding the installation of the facilities necessary to record and store telephone
conversations? Currently, we maintain a log of our communications which includes the question or instruction
and our (or in the case of a question the third party’s) response. Does this satisfy the requirements for evidence
as defined in measures M2 through M7?
Response: The SDT thanks you for your comments. The SDT respectfully refers to the measures, which identify types of evidence that may be used.
The SDT recognizes that similar requirements already exist within the COM standards and that the same types of evidence have been included in the
associated measures. Having voice recordings is an example of what could be used as evidence; not what is required or the only type of evidence.
Time frames for implementation of the Requirements of COM-003-1 are identified under the Proposed Effective Date in the second draft of the
standard.
PPL
Disagree
Will the CPOPs be developed regionally, by RCs, by TOPs, by BAs? Will some entities have to adhere to various
CPOPs since they may operate in various areas? Too many unanswered questions to support this concept.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
May 2, 2012
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to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
Manitoba Hydro
Agree
Yes, with comments
1) In this requirement “Interoperability Communications between personnel responsible for real time” becomes
clouded when compared to the “Interoperability Communications” definition that states “exchange information
between entities”.
a. Improving the “Interoperability Communication” definition as per early suggestion should clarify this.
2) Changing the order of requirements would make the flow of the standard smoother.
a. Since this standard is mostly designed for real time communication, the requirements should pyramid down.
o R1 is fine.
o R2 should be “English”
o R3 should be “NATO”
o R4 should be “Time”
o R5 should be “Three-part communications”
o R6 reserved for “Full name identification” (See below for clarification)
Conclusion: This requirement is acceptable as long as the enclosed comments are considered.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that having a CPOP does not directly contribute
to reliability. The SDT agrees, and has deleted the requirement for a CPOP.
The SDT supports the ordering of the comments you suggested. After aggregating all of the industry comments and changes, the SDT reformatted
the posted Standard. While it is not Identical, some groupings and concepts are similar. We would be interested in your comments on this next draft
version.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
4. Requirement R2 of the draft COM-003-1 states, “Each Responsible Entity shall use pre-defined system
condition terminology as defined in Attachment 1-COM-003-1 for all verbal and written Interoperability
Communications.” Do you agree with this proposal? If not, please explain in the comment area.
Summary Consideration:
Most stakeholders who responded to this question disagreed with the proposal.
The major recommendation from the comments for question 4 was that the term “Interoperability Communications” should be
removed from the standard. The OPCP SDT agreed and changed “Interoperability Communications” to “Operating Communications”
which is now defined as – “Communication of instruction to change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System.”
Several commenters pointed out that “Alert Levels” with defined colors are already in use by the Department of Homeland Security
and may be misinterpreted.
Other commenters stated that attempting to mold all possible situations into the pre-defined terms is overly restrictive and may
result in reduced accuracy, unnecessary confusion and misinterpretation.
The SDT proposes that determining alert levels falls outside the scope of a “communication protocol” and has removed the
requirement (R2) to use Attachment 1 from the revised standard.
Organization
Yes or No
British Columbia
Transmission
Corporation
Agree
ExxonMobil
Research and
Engineering
Agree
Florida Municipal
Power Agency
(FMPA) and some
members
Agree
May 2, 2012
Question 4 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Old Dominion
Electric
Cooperative
Agree
Oncor Electric
Delivery
Agree
Orange and
Rockland Utilities,
Inc.
Agree
PacifiCorp
Agree
Sunflower Electric
Power Corp.
Agree
Transmission
System Operations
Agree
Westar Energy
Agree
American Electric
Power
Disagree
Question 4 Comment
AEP suggests that RCIS be expanded to include the additional parties necessary to support Interoperability
Communications. Without such an expansion, the communication requirements for the RC are burdensome
and the effectiveness may be compromised by the volume of parties that will need to be included. Is it practical
for RFC to communicate across some 60 parties or should this be limited to only those that need to know?
Attachment 1 does not seem consistent with the stated purpose of this standard as Attachment seems to focus
on defining the operating condition, not communication during alerts and emergencies. The SDT should
consider if the scope of the standard is appropriate to resolve this discrepancy. To the extent that it gets
mandated, Attachment 1 could be administered through the addition of “check boxes” on the expanded RCIS.
Response: The SDT thanks you for your comments and recommendations regarding RCIS expansion. While the SDT believes that it has merit,
such an initiative is beyond the scope of this standard’s development. The team will recommend your proposal to the proper authority for their
consideration.
The SDT determined that determining alert levels falls outside the scope of a “communication protocol” and has removed the requirement to
May 2, 2012
122
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
use Attachment 1 from the revised standard.
Sunflower Electric
Power Corporation
Agree
As defined in Attachment 1 - COM-003-1
Response: The SDT thanks you for your comments. Note that the SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Tri-State
Generation &
Transmission
Assoc.
Disagree
Attachment 1 explains Operating State Alert Levels that defines colors that are already in use by the
Department of Homeland Security. Re-using these colors presents confusion to the operators of the BES. This
places an unnecessary additional burden on Real Time day-to-day operations with a high risk of confusion in an
emergency. Additionally, this is too complicated and requires a complete retraining of operators in the English
language.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Duke Energy
Disagree
Attachment 1 is limited to notifications from the RC to other entities regarding Alerts for Physical Security
Emergency, Cyber Security Emergency or Transmission Emergency. Also, these types of notifications wouldn’t
meet the definition of “Interoperability Communications”, because they wouldn’t necessarily be used to effect
a change in the state or status of an element or facility of the Bulk Electric System.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
The term Interoperability Communications has been removed from the second draft of the standard.
NorthWestern
Energy
Disagree
Attachment 1 seems too overly complicated for emergency Operating circumstances and provides an additional
burden for Real Time personnel who are stressed with difficult decisions already.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Kansas City Power
& Light
May 2, 2012
Disagree
Attachment 1 should be removed from this standard. This is a duplication of the alerts by the NERC Alerts
system and the EISAC. In addition, these are reliability standards and should deal with real-time and expected
future reliability issues. Alerts are an inappropriate for this standard.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
We Energies
Disagree
Attempting to mold all possible circumstantial situations into the pre-defined terminologies is overly restrictive
and may result in reduced accuracy, unnecessary confusion and misinterpretation. R2 should have the word
“all” included (as is stated in this question) in order to restrict the applicability of Interoperability
Communications to only those situations defined in Attachment 1.As noted in question 2, R2 should not apply
to a TSP or LSE.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Note that the definition of “Interoperability Communications” has been deleted from the revised standard and replaced with the term,
“Operating Communication” with a more narrow focus on communications that change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System.
The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
California
Independent
System Operator
Disagree
CAISO Comments;
Regarding CEA;
CIP-002 requires responsible entities to identify their cyber assets and critical cyber assets. This requirement
does not address any identification and requires responsible entities to declare emergency conditions for noncritical assets. How does this provide an adequate level of reliability? What technical justification did the SDT
use in determining an actual or imminent cyber or physical threat to any BES generating facility, substation, or
transmission line constitute an emergency declaration?
Regarding PSEA and CEA;
This requirement does not provide an adequate level of reliability. As a general statement, receiving notification
from the RC stating XXXX BA has identified (actual or imminent) physical or cyber threats affecting 1 or 999
control center(s), generating facility(ies), substation(s), or transmission line(s) close to your jurisdiction would
provide an adequate level of reliability compared to XXXX BA has declared a PSEA or CEA condition ORANGE.
Why is the SDT promoting requirements that reduce reliability and dumb-down communications?
Is this the correct standard to add a requirement such as this? Physical and Cyber threats are addressed in the
May 2, 2012
124
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
CIP standards and emergencies are addressed in the EOP standards. Both require notification so why include it
in a COM standard?
Is there a possibility of double jeopardy between this requirement and CIP requirements?
If this requirement must be included, Per attachment 1 - COM-003-1 (PSEA and CEA section) the Reliability
Coordinator is the only responsible entity with any defined actions. It is suggested the SDT remove the BA, TO,
TOP, GO, TSP, LSE, and DP due to lack of applicability. The same entities should be removed from the measure
(M2) also. Until “soft words” such as “threat” and “sabotage” are defined or clarity is provided the industry
should not be proposing standards based upon them.
Regarding TEA;
What technical justification did the SDT use in determining that notifying all BA, DP, GOP, TOP, and TO in the RC
area of a possible IROL violation provides an adequate level of reliability? There are no associated actions for
the BA, DP, GOP, TO, and TOP to perform upon notification so what is the purpose of this requirement?
The Alert Level Guide is still in the test phase; does not the Alert Level Guide need to be approved prior to any
standard which references the guide be approved?
Comments: Per attachment 1 - COM-003-1 the Reliability Coordinator is the only responsible entity with any
actions. Suggest removing BA, TO, TOP, GO, TSP, LSE, and DP. Or assign them actions. The same entities should
be removed from the measure (M2) also.
Response: The SDT thanks you for your comments. The SDT determined, based on your comments and the comments of other stakeholders,
that determining alert levels falls outside the scope of a “communication protocol” and has removed the requirement to use Attachment 1 from
the revised standard.
New York State
Reliability Council
May 2, 2012
Disagree
Comments: NYSRC believes the use of “shall” and “all” coupled with the broad applicability of this Standard and
the broad definition of Interoperability Communication will result in entities either not complying with R2 or
making statements regarding the Operating Alert State when unnecessary. Attachment 1-Com-003 is very
prescriptive in the use pre-defined terminology, colors and levels, and what to report on. There is no benefit to
specifying the specific terminology. This requirement should require the RC to define the terms/levels/alert
states to include within the CPOP that sufficiently communicate the increased levels of Alert or Response
encountered/required. Many entities have invested time and training in the existing processes that meet the
intent of this requirement.
Read strictly, the only predefined alert conditions are Physical security, Cyber security and Transmission
125
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Security as it applies to the RC and TOP only.
NYSRC notes that R2 in the draft Standard does not match R2 in this question. Specifically the word ALL is not in
the Standard.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“Communication Protocol” and has removed the requirement to use Attachment 1 from the revised standard.
The SDT notes you referenced the term “Interoperability Communication” and the requirement to have a CPOP. Both have been eliminated in
the second draft of the Standard. The SDT appreciates the observation and the word “all” was not in the requirement. It should not have been in
the question.
National Grid
Disagree
Defining specific wording per Attachment 1 is overly prescriptive. The requirements should focus on what is
required not how. The RC and encompassing entities should be required to define terms that will be used in
communications. This would allow for the use of terms that are well understood in an area rather than adding
new terms.
Also, System operators need to spend time looking for the right color and level to communicate the prevailing
system condition terminology to avoid violating the standard. This task does not lend itself to promptly and
effectively deal with the emergency situation.
There is still plenty of grey area in Attachment 1 and there does not appear to be any differentiation in actions
taken based on the alert levels.
Finally, the section Background Information in the Comment's form mentions “The SDT proposes four system
condition alerts instead of initial three in the RCWG version.” However, Attachment 1 only mentions 3 alerts Physical Security, Cyber Security, and Transmission Emergency Alerts leading to confusion.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a “communication
protocol” and has removed the requirement to use Attachment 1 from the revised standard.
American
Municipal Power
Agree
Eliminating lax communications and improving identifiers is one of the cheapest and easiest ways to improve
reliability.
Response: The SDT thanks you for your comments. Your insight is refreshing as well as accurate.
Transmission
May 2, 2012
Disagree
FPL agrees that standard system condition terminology could be beneficial in communications but this
126
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Owner
Question 4 Comment
requirement introduces alert level conventions with no clarity on what the corresponding associated actions for
such levels are and as a result, aside from the value derived from have improvement in terminology during
communications, it is unclear what reliability improvements this will achieve in carrying out instructions since
details on what sort of tasks need to be carried out for each level have not been defined. Also, this requirement
should clearly indicate that this alerting system and any communication conventions be required for emergency
conditions.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Bonneville Power
Administration
Agree
In Attachment #1 - Operating State Alert Levels, for the Transmission Emergency Alert (TEA) Level 2 definition, a
“why” needs to be incorporated into the definition. It appears that the reason we're going to TEA 2 is to avoid
violation of an SOL but it needs to be called out.
Response: The SDT thanks you for your comments. The SDT is interested in your comment but would require additional information and
discussion to address it properly.
Northeast Utilities
Disagree
It is not clear what value there is in identifying alert levels since there does not appear to be any differentiation
in actions taken based on the alert levels. Additionally, it has been our experience of during the field-test of
these Alert Levels, that there are inconsistencies in when to implement various stages of Alerts and, we believe,
this introduces more confusion than exists today.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Independent
Electricity System
Operator
Disagree
It is not clear what value there is in identifying alert levels. There does not appear to be any differentiation in
actions taken based on the alert levels. Why not just state the number of substations attacked, etc? Further,
the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System operators
need to spend time looking for the right color and level to communicate the prevailing system condition
terminology to avoid violating the standard. This task, in and of itself, does not ensure nor improve reliability
and does not lend itself to promptly and effectively deal with the emergency situation.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
May 2, 2012
127
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
IRC Standards
Review Committee
Disagree
Question 4 Comment
It is not clear what value there is in identifying alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a “communication
protocol” and has removed the requirement to use Attachment 1 from the revised standard.
ISO New England
Inc.
May 2, 2012
Disagree
It is not clear what value there is in identifying alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
128
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a “communication
protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Dynegy
Disagree
It is not clear what value there is in identifying alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a “communication
protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Great River Energy
May 2, 2012
Disagree
It is not clear what value there is in identifying alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
129
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a “communication
protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Hydro-Québec
TransEnergie
May 2, 2012
Disagree
It is not clear what value there is in identifying these alert levels. There does not appear to be any
differentiation in actions taken based on the alert levels. Just stating the severity and details of the incident
should suffice.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators will need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation. The level(s) identified in the notification text are at odds with the condition
(color versus numerical). Suggest that the standard either use Condition (color) or the level (numerical).
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the listed entities such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 are not consistent with the definition of Interoperability Communications. By definition,
Interoperability Communication pertains to all communications about how entities change the state of the BES
(not just physical or cyber attacks). Attachment 1 is about notifying of what physical and cyber attacks have
already happened to the BES. It is not clear in the context of Interoperability Communications what the
recipient of a specific notification is expected to do when there is a change of state or status of an element or
facility of the Bulk Electric System.
Attachment 1 pertains specifically to Operating State Alert Levels and says nothing about the communication of
information to be used to change the state or status of a BES element or facility (which is the SDT’s proposed
definition of Interoperability Communications). Therefore, it is not appropriate to require that all verbal and
written Interoperability Communications use the pre-defined terminology in Attachment 1. Only those
communications concerning Operating State Alert Levels should be required to use that terminology.
By the proposed definition, such communications are not Interoperability Communications since the
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
information is not used to change the state or status of a BES element or facility. The SDT needs to revise this
requirement to clarify that it pertains only to communicating the Operating State Alert Levels and nothing
more.
None of the examples in either of the attachments appear to address EEAs (EEA is mentioned in the top
paragraph of page 9 that is included in EOP-002-2.1) or SOLs. This limits the use of Interoperability
Communications to only events where there exists either a physical or cyber threat, or where an IROL can’t be
mitigated.
The requirements should focus on what is required, not how. The RC and encompassed entities should be
required to define terms that will be used in communications. This would allow for the use of terms that are
well understood in an area, rather than having to add new terms.
The Background Information in this Comment Form introductory section mentions “The SDT proposes four
system condition alerts instead of initial three in the RCWG version.” However, Attachment 1 only mentions 3
alerts - Physical Security, Cyber Security, and Transmission Emergency Alerts leading to confusion.
Finally, Attachment should only be used as a guide.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Midwest ISO
Standards
Collaborators
Disagree
It is not clear what value there is in identifying alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Why not just state
the number of substations attacked, etc?
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 are not consistent with the definition of Interoperability Communications. By definition,
Interoperability Communication pertains to all communications about how entities change the state of the BES
(not just about physical or cyber attacks). Attachment 1 is only about notifying of what physical and cyber
attacks and transmission emergencies have already happened to the BES.
Response: The SDT thanks you for your comments. Response: The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
May 2, 2012
131
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Northeast Power
Coordinating
Council
Disagree
May 2, 2012
Question 4 Comment
It is not clear what value there is in identifying these alert levels.
There does not appear to be any differentiation in actions taken based on the alert levels. Just stating the
severity and details of the incident should suffice.
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators will need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation. The level(s) identified in the notification text are at odds with the condition
(color versus numerical). Suggest that the standard either use Condition (color) or the level (numerical).
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the listed entities such as Distribution Provider and Generator Operator cannot have access to these
systems due FERC standards of conduct requirements.
Attachment 1 and R2 are not consistent with the definition of Interoperability Communications. By definition,
Interoperability Communication pertains to all communications about how entities change the state of the BES
(not just physical or cyber attacks). Attachment 1 is about notifying of what physical and cyber attacks have
already happened to the BES.
It is not clear in the context of Interoperability Communications what the recipient of a specific notification is
expected to do when there is a change of state or status of an element or facility of the Bulk Electric System.
Attachment 1 pertains specifically to Operating State Alert Levels and says nothing about the communication of
information to be used to change the state or status of a BES element or facility (which is the SDT’s proposed
definition of Interoperability Communications). Therefore, it is not appropriate to require that all verbal and
written Interoperability Communications use the pre-defined terminology in Attachment 1. Only those
communications concerning Operating State Alert Levels should be required to use that terminology. By the
proposed definition, such communications are not Interoperability Communications since the information is not
used to change the state or status of a BES element or facility. The SDT needs to revise this requirement to
clarify that it pertains only to communicating the Operating State Alert Levels and nothing more.
None of the examples in either of the attachments appear to address EEAs (EEA is mentioned in the top
paragraph of page 9 that is included in EOP-002-2.1) or SOLs. This limits the use of Interoperability
Communications to only events where there exists either a physical or cyber threat, or where an IROL can’t be
mitigated. The requirements should focus on what is required, not how.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
The RC and encompassed entities should be required to define terms that will be used in communications. This
would allow for the use of terms that are well understood in an area, rather than having to add new terms.
The Background Information in this Comment Form introductory section mentions “The SDT proposes four
system condition alerts instead of initial three in the RCWG version.” However, Attachment 1 only mentions 3
alerts - Physical Security, Cyber Security, and Transmission Emergency Alerts leading to confusion.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Western Area
Power
Administration
Disagree
It’s very confusing to refer to each condition using a color and/or a level number. In other areas, we are
accustomed to using Alert Levels (i.e. EEA states). The color designation seems to throw in an unnecessary
element that doesn’t add any value.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Long Island Power
Authority
Disagree
LIPA believes the use of “shall” and “all” coupled with the broad applicability of this Standard and the broad
definition of Interoperability Communication will result in entities either not complying with R2 or making
statements regarding the Operating Alert State when unnecessary.
Attachment 1-Com-003 is very prescriptive in the use pre-defined terminology, colors and levels, and what to
report on. There is no benefit to specifying the specific terminology. This requirement should require the RC to
define the terms/levels/alert states to include within the CPOP that sufficiently communicate the increased
levels of Alert or Response encountered/required.
Many entities have invested time and training in the existing processes that meet the intent of this
requirement.
Read strictly, the only predefined alert conditions are Physical security, Cyber security and Transmission
Security as it applies to the RC and TOP only.
LIPA notes that R2 in the draft Standard does not match R2 in this question. Specifically the word ALL is not in
the Standard.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
May 2, 2012
133
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Manitoba Hydro
Disagree
Question 4 Comment
Move this new requirement R1.2 in COM-002-2.
1) COM-003-1 R2 “Pre-defined system condition terminology” are all planned definitions.
a.COM-003-1 purpose is to “convey information effectively” meaning the use of English, NATO, three-part
communication, 24 time format are all verbal aspects to accomplish this purpose and not suited to pre-defined
or planned items.
2) COM-003-1 R2 appears more appropriate and relevant placed in COM-002-2. COM-002-2’s Purpose is
“capabilities for addressing real time emergencies and to ensure communications by personnel are effective.”
a. Placing “Pre-defined system condition terminology” in COM-002-2 after R1.1 as R1.2 appears to have more of
a chronological approach.
i.R1.1 states “conditions that could threaten”
ii.R1.2 use “pre defined system conditions”
Conclusion: Remove COM-003-1 R2 and replace in COM-002-2 as R1.2
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
NERC Staff
May 2, 2012
Disagree
NERC staff agrees with the principle behind Requirement R2. However, it appears that two separate
communication actions are being performed, the action to notify the Reliability Coordinator, and the action by
the Reliability Coordinator to communicate the alert level to affected functional entities. Therefore, we
recommend that that Requirement R2 be split into two requirements and offer the following wording:
A Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service
Provider, Load Serving Entity and Distribution Provider shall notify its Reliability Coordinator when it becomes
aware that there is a situation involving the facilities under its control that meets the criteria for an alert, as
specified in Attachment 1 - Operating State Alert Levels, to keep the Reliability Coordinator informed on the
initial and subsequent status of the situation.
When a Reliability Coordinator is notified (or becomes aware) that there is a situation within its Reliability
Coordinator Area that meets conditions specified in Attachment 1 - Operating State Alert Levels, the Reliability
Coordinator shall use the phraseology when making the notifications specified in Attachment 1 to keep others
informed on the initial and subsequent status of the situation.
The NERC staff recommends that the SDT review the content of the Attachment for consistency, clarity and
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
omissions (such as found in the table on page 14 of the draft - the cell, “Notify the following entities:” is blank).
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
NextEra Energy
Resources, LLC
Disagree
NextEra agrees that standard system condition terminology could be beneficial in communications but this
requirement introduces alert level conventions with no clarity on what the corresponding associated actions for
such levels are and as a result, aside from the value derived from having improvement in terminology during
communications, it is unclear what reliability improvements this will achieve in carrying out instructions.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Indiana Municipal
Power Agency
Disagree
No. Does attachment 1 cover all possible communication scenarios and terminology?
Using pre-defined condition terminology does not allow flexibility in communications and for near changes in
communications that might be needed depending on the situation.
Response: The SDT thanks you for your comments. Response: The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
PEF
Disagree
PEF recommends that the color coding and definitions that are used by Homeland Security also be used for the
notification of physical and cyber emergency alerts reported to the RC. This would follow the ES-ISAC standard
already adopted by the electric industry.
If the attachment is adopted as is, PEF recommends adding the EEA levels to provide “pre-defined system
condition terminology.”
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
NYSEG
Disagree
May 2, 2012
R2 indicates the need to use pre-defined system condition terminology for all verbal and written
Interoperability Communications yet Attachment 1 only defines transmission loading and physical and cyber
security threats. Either need to rewrite the Requirement to include only these circumstances, or define every
possible system condition used in Interoperability Communications.
Additionally, there does not appear to be any benefit in attempting to pre-define transmission loading, and
physical and cyber alert system conditions since the actions associated with each are similar, if not the same,
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
for almost all conditions.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Bureau of
Reclamation
Disagree
Reclamation does not agree with the Attachment 1 condition color coding as it will conflict with the DHS system
of notification of change in threat condition. The three color system is unique to the notifications issued by
DHS. Use of that color system is reserved by the DHS. Federal agencies are required to perform specific tasks
when DHS issues alerts or changes the threat condition. Only DHS can change the threat condition. The
concept needs to be revised considerably to avoid the conflict or create a potential security issue.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Pepco Holdings,
Inc. - Affiliates
Disagree
Requiring system operators to use the color-coded system condition terminology during communication adds a
layer of responsibility that will distract from the operator’s real-time reliability-related tasks.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Georgia
Transmission Corp
Disagree
Should only include physical security emergency, cyber security emergency, or transmission emergency as
stated in Attachment 1 instead of Interoperability Communications.
Response: The SDT thanks you for your comments. The proposed term “Interoperability Communication” has been removed from the Standard.
The SDT determined that determining alert levels falls outside the scope of a “communication protocol” and has removed the requirement to
use Attachment 1 from the revised standard.
Southern
Company
Transmission
May 2, 2012
Disagree
Southern Company supports the SERC SOS comments.
SERC SOS comments:
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliability-related
communications. Both the Reliability Directive and Interoperability Communication, as currently defined,
require some emergency action or change of equipment status. Yet the Alert Level Guides were intended for
announcement, not actions
Requiring system operators to use the color-coded system condition terminology during communication adds a
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
layer of responsibility that will distract from the operator’s real-time reliability-related tasks.
We also do not feel that these Alert Level Guides apply to all the responsible entities identified under
Applicability in the draft standard - for example, TSPs and LSEs are not included in the list of notifications.
The requirement to use the central time zone for logging the time of an alert is problematic in that all
communication tools, such as the RCIS, will need to be re-vamped
We question whether there will be a measurable reliability benefit by so doing. There is also some redundancy
in the Alert Level Guides - for example, the CIP-001 standard requires notification of sabotage events - it should
not be repeated in this standard.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Entergy Services
Disagree
Term Interoperability Communications should be removed from the standard. As written, the actions that fall
into interoperability communications are much broader than the set of conditions described in the table in
attachment 1. To the extent that the communications are outside of the ones in the table, entities will be noncompliant because their communications are not pre-defined.
Recommend that this requirement be changed to indicate that “Any Reliability Coordinator or Transmission
Operator experiencing a physical security emergency, cyber security emergency, or transmission emergency will
communicate their status using the conditions and processes in Attachment 1.”
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
PJM
Disagree
May 2, 2012
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliability-related
communications. Both the Reliability Directive and Interoperability Communication, as currently defined,
require some emergency action or change of equipment status. Yet the Alert Level Guides were intended for
announcement, not actions.
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
We also do not feel that these Alert Level Guides apply to all the responsible entities identified under
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Applicability in the draft standard - for example, TSPs and LSEs are not included in the list of notifications.
The requirement to use the central time zone for logging the time of an alert is problematic in that all
communication tools, such as the RCIS, will need to be re-vamped.
We question whether there will be a measurable reliability benefit by doing so. There is also some redundancy
in the Alert Level Guides - for example, the CIP-001 standard requires notification of sabotage events - it should
not be repeated in this standard. This also needs to be reconciled with EOP-004 and CIP-001 and the SAR
formed to address those redundancies.
It is not clear what value there is in identifying alert levels. There does not appear to be any differentiation in
actions taken based on the alert levels. Why not just state the number of substations attacked, etc?
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
PJM SOS
Comments
May 2, 2012
Disagree
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliability-related
communications. Both the Reliability Directive and Interoperability Communication, as currently defined,
require some emergency action or change of equipment status. Yet the Alert Level Guides were intended for
announcement, not actions.
Further, the “pre-defined” system conditions and alert levels are too detailed and overly prescriptive. System
operators need to spend time looking for the right color and level to communicate the prevailing system
condition terminology to avoid violating the standard. This task does not lend itself to promptly and effectively
deal with the emergency situation.
We also do not feel that these Alert Level Guides apply to all the responsible entities identified under
Applicability in the draft standard - for example, TSPs and LSEs are not included in the list of notifications.
The requirement to use the central time zone for logging the time of an alert is problematic in that all
communication tools, such as the RCIS, will need to be re-vamped.
We question whether there will be a measurable reliability benefit by doing so. There is also some redundancy
in the Alert Level Guides - for example, the CIP-001 standard requires notification of sabotage events - it should
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
not be repeated in this standard. This also needs to be reconciled with EOP-004 and CIP-001 and the SAR
formed to address those redundancies.
It is not clear what value there is in identifying alert levels. There does not appear to be any differentiation in
actions taken based on the alert levels. Why not just state the number of substations attacked, etc?
Attachment 1 and R2 do not appear to be in synch primarily due to the definition of Interoperability
Communications. By definition, Interoperability Communication is about how entities change the state of the
BES and Attachment 1 is about notifying of what already happened to the BES.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
SERC OC&SOS
Standards Review
Group
Disagree
The Alert Level Guides in Attachment 1 are not consistent with the proposed definitions of reliability-related
communications. Both the Reliability Directive and Interoperability Communication, as currently defined,
require some emergency action or change of equipment status. Yet the Alert Level Guides were intended for
announcement, not actions
Requiring system operators to use the color-coded system condition terminology during communication adds a
layer of responsibility that will distract from the operator’s real-time reliability-related tasks.
We do not feel that these Alert Level Guides apply to all the responsible entities identified under Applicability in
the draft standard - for example, TSPs and LSEs are not included in the list of notifications.
There is also some redundancy in the Alert Level Guides - for example, the CIP-001 standard requires
notification of sabotage events - it should not be repeated in this standard.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
E.ON U.S. LLC
May 2, 2012
Disagree
The attachment adds a whole new lexicon for BES operators. E.ON U.S. suggests integrating attachment 1 and
the relative alert levels into the EOP standards. The purpose of COM-003 indicates this standard is to ensure
understanding of information during emergency alerts and emergency situations and not to establish the
conditions, required notification, or levels of emergency alerts.
While the attachment has been identified as a product of the RCWG it is unclear whether it has been reviewed
and approved through the normal NERC and industry vetting.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
MRO NERC
Standards Review
Subcommittee
Disagree
The attachment only applies to the RC. We recommend R2 state that the RC shall use pre-determined system
condition terminology and the BA, DP, GOP, TOP, and TO shall follow orders and directives unless such acts
violate safety, etc. Either the attachment should be changed or the requirement should be changed for
accurate accountabilities.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
ATC and ITC
Disagree
The Attachment pertains to requirements of the RC, not all entities. Either the attachment should be changed
or the requirement should be changed for accurate accountabilities.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Consumers Energy
Disagree
The COM Standards should put forth the methodology of communication, not provide communication for each
event. For example, CIP-001 describes the communication to take place for CIP attacks, be they physical or
cyber, EOP-002 describes the process for Generation and Capacity Emergencies. Utilizing the similar sounding
vernacular (EEA,CEA,PSEA,TEA) is not prudent.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Progress Energy
Carolina, Inc
Disagree
The link between COM-003-1 R2 and Attachment 1 for entities other than the Reliability Coordinator is unclear.
R2 links with Attachment 1 and is applicable to a host of entities while Attachment 1 seems to only provide predefined system condition terminology for use during notifications by the RC to other entities.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Please see our responses to by the PJM System Operations Subcommittee (SOS) Group.
Pacific Northwest
Small Utilities
Comment Group
Disagree
The referenced attachment appears to list alert levels for RCs to use in communicating threats to BAs, DPs, GOs,
TOPs and TOs. This requirement should apply only to RCs.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Xcel Energy
Disagree
The use of Yellow, Orange and Red, as related to the various alert levels, may conflict with existing color
requirements that entities already have in use. We recommend instead only refer to the PSEA, CEA and TEA
levels. Additionally, it is unclear how R2 applies to anyone other than the RC. Attachment 1 seems to only apply
to the RC. If this is correct, then why would the other entities listed in R2 have to incorporate that terminology
into their CPOP? If this is not correct, please clarify the requirement so that the other entities can clearly
understand what is expected.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
The Empire District
Electric Company
Disagree
This attachment is not needed. It is a duplicate of the NERC Alert process that is already established as well as
CIP-001 Sabotage reporting requirement R2 along with requirements of EOP-001 R5 and EOP-004 R2 dealing
with disturbance reporting. The last thing the industry needs is more paperwork requirements that are
redundant when an emergency event happens on the system.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Ameren
May 2, 2012
Disagree
This is an ambiguous reference in all of NERC standards for all but the RC. How would an LSE interpret this in
communication between them and a DP. Would there ever be a red condition for issues that affect them? And
as it relates to operating, it looks like this is exclusive of EEA type events, i.e. BA type emergencies seem to not
be represented. It would seem that the pre-defined conditions should be established for each interaction that
each entity might have, e.g. a predefined set for a BA to a TOP, a BA to an LSE, et al. While each entity can
certainly address the 3 scenarios in Attachment 1 (RC to entity) those are not the only conditions where
communication affects BES reliability.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
NIPSCO
Disagree
This may not be necessary.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Power South
Energy
Disagree
This requirement is unnecessary.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
PPL
Disagree
This requirement should be applicable to a RC only. Some registered entities may not even receive these types
of communications. Since the responses are the same for all levels noted in attachment 1, there is questionable
value to defining this level of additional administrative detail.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Puget Sound
Energy
May 2, 2012
Disagree
This requirement, along with the associated M2, will be almost impossible to substantiate for audit purposes.
For example, would an entity be required to present, and an auditor be required to listen to, voice recorder
records for the data retention time? It is difficult to image another way to prove an entity complied with this
requirement
Further the statement "as defined in Attachment 1" implies a set of definitions can be found and yet
Attachment 1 is not structured in such that way.
Is the system condition terminology just the terms "condition yellow", "condition orange", and "condition red".
The procedural and time aspects described in this attachment create confusion as to whether compliance is
required under this standard or a different one.
Suggest more simplified presentation of definitions or glossary for clarity.
Finally the inclusion of "written" communications creates a question relative to real-time information or
whether this is extending beyond that timeframe. Most real time information sharing is verbal due to the
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 4 Comment
urgency of it. Suggest removal of written.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
Santee Cooper
Disagree
Utilization of a color-coded system for all verbal and written Interoperability Communications adds a layer of
complexity to the System Operator that is not necessary.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
South Carolina
Electric and Gas
Agree
We agree with the proposal, however we feel that the color system should be evaluated to better distinguish
the type of attack for example using P-YELLOW for physical vs. C-YELLOW for cyber instead of just "YELLOW" for
both.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
NRECA RTF
Members
Agree
We believe there is a need to use pre-defined system condition terminology and the ones provided in the
attachment are easy to understand.
Response: The SDT thanks you for your comments. Note that based on stakeholder comments, the team deleted the requirement. The SDT
determined that determining alert levels falls outside the scope of a “communication protocol” and has removed the requirement to use
Attachment 1 from the revised standard.
FirstEnergy
Disagree
We do not support R2 and its referenced attachment and feel that they should be removed. The requirement
and attachment are too convoluted, create confusion among system operators, and not necessary with regard
to the goal of this standard. This standard mandates proper three-part communication in all reliability-related
communication (including alert level situations). Other standards should define and mandate rules associated
with the specifics surrounding urgent action situations (i.e. CIP, TOP, EOP standards). Together these standards
will arrive at proper communication between entities during alerts.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
May 2, 2012
143
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Electric Market
Policy
Disagree
Question 4 Comment
We object due to the following reasons;
1 - There are 3 versions of Attachment 1-COM-003-1 which is potentially confusing. We suggest separating into
3 attachments, one for each type of notification.
2 - The level(s) identified in the notification text are at odds with the condition (color vs. numerical). It is
suggested that the standard either use to Condition (color) or the level (numerical).
3 - None of the Operating State Alert Levels in Attachment 1 appears to address Energy Emergency Alerts
(EEAs). The note in the “Attachment 1-COM-003-1 defines normal, alert, and emergency operating conditions
as they relate to Transmission Loading, Physical and Cyber Security. These definitions for Transmission Loading,
Physical and Cyber Security Alert states align with the Emergency Energy Alert (EEA) states (as already described
in NERC Reliability Standard EOP-002-2.1). The time frame for declaration of these Alert states shall be
consistent with the approach used to declare EEAs and would normally apply to Real Time declarations and not
forecast conditions.” This seems to limit use of Interoperability Communications to only events where there
exists either a physical or cyber threat, or where an IROL can’t be mitigated. This emphasizes the confusion as
described in item 2 above where the EEA levels in EOP-002-2.1 uses numerical values (i.e. EEA Level 1) without
the colored conditions. We recommend adding a new section to Attachment 1 ‘Operating State Alert Levels’ as:
‘Reliability Coordinator Notifications for Energy Emergency Alerts.
’4-Attachment 1 pertains specifically to Operating State Alert Levels and says nothing about the communication
of information to be used to change the state or status of a BES element or facility (which is the SDT’s proposed
definition of Interoperability Communications). Therefore, it is not appropriate to require that all verbal and
written Interoperability Communications use the pre-defined terminology in Attachment 1.
Only those communications concerning Operating State Alert Levels should be required to use that
terminology. By the proposed definition, such communications are not Interoperability Communications since
the information is not used to change the state or status of a BES element or facility. The SDT needs to revise
this requirement to clarify that it pertains only to communicating the Operating State Alert Levels and nothing
more.
Response: The SDT thanks you for your comments. The SDT determined that determining alert levels falls outside the scope of a
“communication protocol” and has removed the requirement to use Attachment 1 from the revised standard.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
5. Requirement R4 of the draft COM-003-1 states, “Each Responsible Entity shall use Central Standard Time (24
hour format) as the common time zone for all verbal and written Interoperability Communications.” Do you
agree with this proposal? If not, please explain in the comment area.
Summary Consideration:
The majority of commenters stated Requirement R4 would add confusion for the operators and decrease reliability. Some
recommend the use of another time in place of Central Standard Time. In response, the OPCP SDT has modified the standard to use
the 24 hour format (new 1.1.2) in all Operating Communications and the inclusion of a time zone reference (new 1.1.3) when
Operating Communications occur between entities in different time zones.
There were also several comments of a general nature that indicated time zone issues as a non-factor for reliability. The OPCP SDT
has modified the requirement to focus on Operating Communications in a format that it believes would increase reliability as it
would reduce the potential for a miscommunication related to the desired time of a system operation.
Organization
Yes or No
Bureau of
Reclamation
Agree
ExxonMobil
Research and
Engineering
Agree
Georgia
Transmission Corp
Agree
Independent
Electricity System
Operator
Agree
Old Dominion
Electric
Cooperative
Agree
Oncor Electric
Agree
May 2, 2012
Question 5 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
Delivery
Sunflower Electric
Power Corp.
Agree
Westar Energy
Agree
Santee Cooper
Disagree
A common time zone is not necessary and is overly prescriptive. Companies should not have to worry about
self-reporting or receiving a compliance violation if someone states the wrong time during a conversation.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity must explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
American Electric
Power
Disagree
AEP believes that the significant efforts and significant system changes necessary to support a common time
zone does not provide a significant enough reliability benefit. In fact, the focus on a common time may divert
attention away from more pressing operational reliability needs.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone , and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Electric Market
Policy
May 2, 2012
Disagree
Any confusion about what time is being verbally communicated should be cleared up by three-part
communications. There should be no confusion about what time is being communicated in writing as long as
the time zone and AM\PM designation are included. Besides, many entities exchange written information via
web-enabled applications that allow the users to configure their interface to show time in whatever format
and time zone they prefer. This eliminates confusion. Operators will continue to use local time in their
communications with field personnel, support staff, and management, and we see no demonstrable reliabilityrelated need to require every operator in North America to have to convert their local time to CST in their
communications with other operators. However, if the SDT feels a standard time must be adopted, it should be
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
GMT as this is the time that used by all ‘true time’ devices.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone , and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Manitoba Hydro
Disagree
As per below.
1)The 24 hour format will certainly reduce the confusion of AM and PM and at present seems to be the current
best practice for all entities so should not be a major change.
2)Examining the definition of “Interoperability Communications” means that there is and will be real time
communications with entities in other times zones, thus it is assumed that this being an NERC standard is
enforcing that all other time zones (PST, MST, EST) will be using CST when communicating with
interoperability.
a. If this is the case, it appears that the other time zones (PST, MST and EST) must make effort to modify their
local time to synchronize with CST.
b. This brings to point that when interoperability communication is used, this fact must be mentioned, instead
of 13:53, it should be 13:53 CST.
3) Adding CST to verbal time formats will be difficult to implement, so maybe a statement confirming the time
zone should be appropriate each time interoperability communications is used when required. Conclusion: 24
hour format is fine, further clarify that all other time zones must use CST.
Response: The SDT thanks you for your comments. The second draft version of COM-003-1 eliminates the term “Interoperability
Communication” and now proposes the term “Operating Communications” which is defined as communication of instruction to change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System.
The SDT is proposing an alternative requirement in the second draft of COM- 003 which we believe will address your concerns. Instead of
requiring the use of a single continent-wide time zone, the standard now requires that during Operating Communications an applicable entity
shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard time, when communicating with one or
more entities in a different time zone.
May 2, 2012
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Organization
Yes or No
ATC and ITC
Disagree
Question 5 Comment
ATC is in the Central Standard Time zone, and would not be directly impacted by this requirement. With that
being said we are concerned that forcing an organization to refer to a time zone that is not local may result in
an increase of errors and a decrease in reliability. See comments for question #3.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Please see response to question #3.
British Columbia
Transmission
Corporation
Disagree
BCTC's position: as a majority of the Interoperability Communications is within our time zone there is no
advantage in using Central Standard Time as this will only make the communications more difficult as both
parties are required to change time, R4 is unreasonable.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
California
Independent
System Operator
Disagree
CAISO Comments; Any standardization of time zones, in order to enhance reliability or reduce costs would use
GMT as the reference zone in our opinion. The use of Central Standard Time is problematic because some
months of the year other time zones would be at the same time as CST (Eastern Daylight Savings Time) and
others not. Adopting systems that require system operators to sometimes operate in a time zone that is not
their own local time and sometimes to operate in a time zone that is equivalent to their own local time is
standardization that is not actually standard. How does using Central Standard Time for all verbal and written
communication improve or support reliability? The SDT needs to explain how this requirement provides an
adequate level of reliability for real-time operations for any entity operating outside the Central Standard Time
Zone.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
May 2, 2012
148
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Organization
Yes or No
Question 5 Comment
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
New York State
Reliability Council
Disagree
Comments: This requirement will burden those entities whose operations and communication needs are with
other entities in the same time zone, which represents the overwhelming majority of all communications
performed. It will increase the likelihood of errors for such entities. Further, some entities are operating both
NERC BES elements and non-BES elements from the same control room. This requirement will significantly
impact the efficiency and the safety of workers within those entities. NYSRC notes that R4 in the draft Standard
does not match R2 in this question. Specifically the word ALL is not in the Standard.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communication an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Consumers Energy
Disagree
Common Time Zone has been discussed for decades. There was little or no evidence a common time zone
standard would have prevented any of the system disturbances experienced since 1996 let alone the blackout
of 2003.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Xcel Energy
Disagree
Do not agree with the requirement to use CST. By requiring the use of CST it may actually introduce an
element of error for those who do not routinely operate in that time zone and must make mental corrections
for the time zone they are in. Additionally, some agreements already exist that stipulate what time zone is to
be used.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
May 2, 2012
149
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Organization
Yes or No
Question 5 Comment
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
NextEra Energy
Resources, LLC
Disagree
Existing market and reliability communication methods already ensure that time-zone adjustments occur. It is
critical that the feasibility, impact, and logistical aspects of implementing this change be rigorously reviewed
and understood to inform this standard’s development. Conceivably, the result of that analysis could expose
significant risks outweighing the purported benefits of implementing a single time-zone policy. Any
implementation or transition gaps between the time format and references used by reliability coordinators,
their corresponding systems, and the interfaced systems of market participants would be extremely
detrimental to system stability and ongoing market operations.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Transmission
Owner
Disagree
Existing market and reliability communication methods already ensure that time-zone adjustments occur. It is
critical that the feasibility, impact, and logistical aspects of implementing this change be rigorously reviewing
and understood to inform this standard’s development. Any implementation or transition gaps between the
time format and references used by reliability coordinators, their corresponding systems, and the interfaced
systems of market participants would be extremely detrimental to system stability and ongoing market
operations.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Sunflower Electric
Power Corporation
May 2, 2012
Agree
General question will time follow central prevailing time (standard/daylight savings)?
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Organization
Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, and include whether the time is standard or daylight saving when communicating with one or more entities in a different time zone.
Hydro-Québec
TransEnergie
Disagree
HQT agrees with using 24 hour format.
However, there is no reliability need to use a common time zone for communications. There is already a
requirement to use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards
where needed. There is no additional reliability need to use a common time zone.
The time zone should be identified in the communication. Not only does this requirement attempt to
determine HOW entities operate within their various footprints, it would significantly change the way many
markets are structured. To implement this into existing Markets would cost significant time, money and
resources while not enhancing reliability in these areas. When operating across time-zones, simply referencing
“Central Standard Time” or “Eastern Standard Time” is sufficient for operating entities to reliably operate. The
time zone adopted by the respective Reliability Coordinator (RC) and their area control center, e.g., NYISO
Eastern Standard Time (EST), should be used. If each entity in the area and the RC are all using EST (or daylight
savings), then why would a time zone be used that is foreign to all parties in the area? This can lead to
considerable confusion. What cannot be ignored is how many entities would have to modify their existing
practices, hardware, software, Control System, billing systems, bidding systems, etc.
We are strongly opposed to this requirement. The requirement should be that those entities which need to
communicate and are in different time zones define which time they will use for communications
.Any confusion about what time is being verbally communicated should be cleared up through three-part
communications. There should be no confusion about what time is being communicated as long as the time
zone (where applicable), and the 24 hour format designations are included. Besides, many entities exchange
written information via web-enabled applications that allow the users to configure their interface to show time
in whatever format and time zone they prefer. This eliminates confusion.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
May 2, 2012
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Organization
Yes or No
Question 5 Comment
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
NIPSCO
Agree
I believe we call this "system time" in our area
Response: The SDT thanks you for your comments. Many stakeholders proposed modifications to the standard – and the SDT revised the
standard to only require inclusion of time and time zone when communicating with one or more entities in a different time zone.
E.ON U.S. LLC
Disagree
If it is the intent that the requirements of this standard apply not only to control room operators but field
personnel (line crews, substation crews, etc.) then E ON US is not in favor of using a common time zone nationwide. The confusion that this change could create in real-time operations outweighs the BES reliability benefit
E.ON US would also like clarification that this requirement does not apply to control systems or elements
thereof that may log equipment operations. The background information above suggests this possible
interpretation.
Response: The SDT thanks you for your comments. This does include communications that involve field personnel.
We Energies
Disagree
If requiring one standard time zone, it would seem prudent to specify Greenwich Mean Time (GMT) as a
universal standard. That being said, solely utilizing Central Standard Time (CST), or even GMT, as the common
time zone may cause undue confusion given that MISO and PJM already operate with established processes
and systems that are inconsistent with this, and are based on their own market timing. In addition, many plant
personnel and procedures already have a long and engrained history of successful operation under existing
timing directions, which are not aligned with market timing. Forcing every plant across multiple time zones to
establish a new standard ignores the need for cases of special consideration and historical circumstances. The
potential confusion due to the forced timing standard across many entities within a given area is too high a
price to pay for the possible clarity by a limited few due to the switch to CST. A preferred alternative would
include focusing the standard on requiring very clear communication of the time zone being specified for a
given Reliability Directive. Thus, compliance enforcement would only pertain to Reliability Directives.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone. This requirement would apply to verbal and written “Operating
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Organization
Yes or No
Question 5 Comment
Communications” as defined in the current draft of the standard. If you are a responsible entity as defined in the requirement then it is
applicable.
The Empire District
Electric Company
Disagree
In dealing in real time, what possible benefit can be had by this requirement? I see this requirement
benefitting NERC analysis after the fact and can lead to more operating mistakes in real time than it benefits. If
a situation is occurring in real time and two entities are in communication with each other, the requirement of
a common time zone holds no benefit.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
American Municipal
Power
Disagree
In other large industries one time zone is usually picked, and the time zone that is usually picked is the EST
zone (JP Morgan Chase is an example). I feel that picking a standard time zone is very important, but I have
not seen significantly good arguments to use CST. EST, on the other hand, is where the majority of the load for
the electric industry resides. I suggest changing the standard to EST but with the 24 hour format.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
NERC Staff
May 2, 2012
Disagree
In the “Background Information” section of this Comment Form, you state, “The SDT believes that
Interoperability Communications would be enhanced with the use of a common time zone. Central Standard
Time was chosen as it is already in use for NERC Time Error Corrections. The Blackout Report cited the need to
tighten communication protocols and the SAR includes consideration of a common time zone to minimize mismatched time signature issues between control systems especially during an emergency.”NERC staff would like
to see more detailed justification on how reliability would be enhanced with this requirement. This appears to
solve issues for communications between time zones, but may add additional confusion for all additional
communications that exist within a common time zone.
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Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
The OPCP SDT believes that any critical element to an Operating Communication (time, ordered action, clear understanding by all parties) must
be governed by protocols that reduce the risk of communicating a misunderstood message. A misunderstood message increases the risk of a
mishap which could destabilize the BES by creating an improper circuit arrangement. The time an event is supposed to occur in a sequence is
critical. If a sender gives a time in EST and the receiver interprets it as CST the risk of a mishap that will affect reliability (not to mention people
and equipment) increases dramatically.
Progress Energy
Carolina, Inc
Disagree
Mandating that all “Interoperability Communications” be based on Central Standard Time could generate an
error precursor- (i.e. some entity communicating a reliability directive in a location using EST to a different
entity in a location using EST having to convert the time stamp to CST introduces possibilities of errors and/or
delays.) A better approach for those entities that communicate across time zones is for those entities to
agree/coordinate on a time standard reference.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communication an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
NorthWestern
Energy
Disagree
NorthWestern appreciates the opportunity to comment. We believe the requirement to use Central Standard
Time will cause unnecessary confusion (translating to a different time zone and possibly to a different time
reckoning - standard or daylight) at a time when the need for clarity is critical. NorthWestern suggests that
each entity use their local time zone when issuing switching orders. Each entity should state the time zone
they are using when giving any time reference (e.g., 15:20 Mountain Daylight Time) if necessary.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and adopted your suggestion. In the second draft of COM 003, instead of requiring the use of a single
continent-wide time zone, the standard now requires that during Operating Communications an applicable entity shall explicitly state the time
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Organization
Yes or No
Question 5 Comment
and time zone when communicating with one or more entities in a different time zone.
PEF
Disagree
PEF feels that the use of CST will create too much confusion within the different entities, particularly during
emergency communications. We recommend the use of GMT instead.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communication an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Pepco Holdings,
Inc. - Affiliates
Disagree
PHI believes that mandating one time zone for all Interoperability Communications will create more confusion
during an emergency that it will prevent and may contribute to increased reliability issues.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
Southern Company
Transmission
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: We feel that this requirement of a
common time zone is overly prescriptive. The requirement should be that entities operating in different time
zones agree on how to best eliminate any confusion regarding the time difference. Entities that routinely
operate in different time zones already have an effective system for dealing with time differences. There
seems to be no incentive to change a system that already works quite well, and the cost of updating computer
systems could prove prohibitive. This group feels that mandating a common time zone across all of North
America can only lead to confusion and increased reliability issues.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communication an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
PSEG Companies
Disagree
Question 5 Comment
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Puget Sound
Energy
Disagree
The requirement for common time zone should be at the discretion of the Reliability Coordinator in the
respective region to determine. The conversion to CST has no apparent value. It would be much more
reasonable to require communications related to time to include the time zone used in that communication. If
common time zone across the nation is required it should only be imposed on the RCs as they would
communicate with each other more readily than entities to other national entities. If an entity does not
operate within the CST, the need to convert during periods of stress may increase the potential for error and
reduce reliability.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
PacifiCorp
Disagree
The sole use of Central Standard time would add confusion to the for Interoperability communication
Communications process that would detract would have the unintended consequence of creating more
confusion, particularly during emergency communications. While PacifiCorp appreciates the need for
minimizing mis-matched time signatures between control systems, it believes that mandating one time zone
for all Interoperability Communications will create more confusion during an emergency that it will prevent.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM- 003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
National Grid
Disagree
Question 5 Comment
The use of central time is unnecessary and may cause more confusion when converting times. The
requirement should be that those entities which need to communicate and are in different time zones, define
which time they will use for communications.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM -003 which we believe will address
your concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating
Communications an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard
time, when communicating with one or more entities in a different time zone.
IRC Standards
Review Committee
Disagree
There is no need to use a common time zone for communications. There is already a requirement to use hour
ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed. There is no
demonstrated benefit to reliability to use a common time zone. The time zone should be identified in the
communication. Use of CST will cause significant and unnecessary costs and the resulting reliability benefit is
not clear. Some of the costs will arise to change systems such as RCIS, IDC, scheduling and E-Tag systems, etc.
Not only does this requirement attempt to determine HOW entities operate within their various footprints, it
would significantly change the way many markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We believe
that, when operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and adopted your suggestion for including the time zone in communications that involve communicating
with one or more entities in a different time zone.
ISO New England
Inc.
May 2, 2012
Disagree
There is no need to use a common time zone for communications. There is already a requirement to use hour
ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed. There is no
demonstrated benefit to reliability to use a common time zone. The time zone should be identified in the
communication. Use of CST will cause significant and unnecessary costs and the resulting reliability benefit is
not clear. Some of the costs will arise to change systems such as RCIS, IDC, scheduling and E-Tag systems, etc.
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Yes or No
Question 5 Comment
Not only does this requirement attempt to determine HOW entities operate within their various footprints, it
would significantly change the way many markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We believe
that, when operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We, and our members, are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT understands your concerns and adopted your suggestion for including the time zone in communications that involve communicating
with one or more entities in a different time zone.
Indiana Municipal
Power Agency
Disagree
There is no need to use a common time zone. The time zone should be identified in the communication, if
needed. The reliability benefit is not clear for using one time zone, and the cost associated with using one time
zone will be significant and unnecessary.
The use of just CST will cause confusion, because one ISO has all its systems in EST and another ISO systems
has its systems in EPT. If an entity is required to use CST when verbally communicating to one or both of these
two ISOs, then many mistakes and confusion will result because their portals continue to be in their respective
times.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted your suggestion for including the time
zone in communications that involve communicating with one or more entities in a different time zone.
Dynegy
Disagree
There is no reliability need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed. The
time zone should be identified in the communication. Use of CST in all time zones will actually cause confusion
and significant and unnecessary costs with no foreseeable reliability benefit. Some of the costs will arise to
change systems such as RCIS, IDC, scheduling and E-Tag systems, etc.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted your suggestion for including the time
zone in communications that involve communicating with one or more entities in a different time zone.
Great River Energy
May 2, 2012
Disagree
There is no reliability need to use a common time zone for communications. The prevailing time zone should
be used to avoid confusion between operating staff and field personnel. Use of CST will actually cause
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Yes or No
Question 5 Comment
confusion with no foreseeable reliability benefit.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Kansas City Power
& Light
Disagree
There is no reliability need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed.
There is no additional reliability need to use a common time zone. The time zone should be identified in the
communication. Use of CST will actually cause confusion and significant, unnecessary costs with no
foreseeable reliability benefit. Some of the costs will arise to change systems such as RCIS, IDC, scheduling and
E-Tag systems, etc.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted your suggestion for including the time
zone in communications that involve communicating with one or more entities in a different time zone.
Midwest ISO
Standards
Collaborators
Disagree
There is no reliability need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed.
There is no additional reliability need to use a common time zone. The time zone should be identified in the
communication. Use of CST will actually cause confusion and significant, unnecessary costs with no
foreseeable reliability benefit. Some of the costs will arise to change systems such as RCIS, IDC, scheduling and
E-Tag systems, etc.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted your suggestion for including the time
zone in communications that involve communicating with one or more entities in a different time zone.
Northeast Power
Coordinating
Council
May 2, 2012
Disagree
There is no reliability need to use a common time zone for communications. There is already a requirement to
use hour ending for scheduling purposes, inadvertent accounting, CPS and other standards where needed.
There is no additional reliability need to use a common time zone. The time zone should be identified in the
communication. Not only does this requirement attempt to determine HOW entities operate within their
various footprints, it would significantly change the way many markets are structured. To implement this into
existing Markets would cost significant time, money and resources while not enhancing reliability in these
areas. When operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
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Organization
Yes or No
Question 5 Comment
Time” is sufficient for operating entities to reliably operate. The time zone adopted by the respective
Reliability Coordinator (RC) and their area control center, e.g., NYISO Eastern Standard Time (EST), should be
used. If each entity in the area and the RC are all using EST (or daylight savings), then why would a time zone
be used that is foreign to all parties in the area? This can lead to considerable confusion. What cannot be
ignored is how many entities would have to modify their existing practices, hardware, software, Control
System, billing systems, bidding systems, etc. We are strongly opposed to this requirement. The requirement
should be that those entities which need to communicate and are in different time zones define which time
they will use for communications. Any confusion about what time is being verbally communicated should be
cleared up through three-part communications. There should be no confusion about what time is being
communicated as long as the time zone (where applicable), and the 24 hour format designations are included.
Besides, many entities exchange written information via web-enabled applications that allow the users to
configure their interface to show time in whatever format and time zone they prefer. This eliminates
confusion.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted your suggestion for including the time
zone in communications that involve communicating with one or more entities in a different time zone.
Northeast Utilities
Disagree
There is no reliability need to use Central Standard Time (CST) a common time zone for communications.
Eastern Standard Time (EST) is used in New England and within the NPCC region. Converting to a different
time zone will be confusing to the operators and the field personnel. The time zone that will be used should be
agreed between each operating entity. This should only impact those entities that cross two time zones. If
NERC or a Region were to perform an investigation that involves entities across the eastern interconnection, it
would be appropriate for the investigation team to request data using a specific time zone.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Western Area
Power
Administration
May 2, 2012
Disagree
This could be a potential problem since Operators will need to communicate with field personnel and local
utilities in their local applicable time zone. It could be confusing to communicate by referring to a different
time zone in other instances. It seems like it would make more sense to require that the time zone being used
in a communication must be specifically and clearly referred to and identified. It doesn’t matter so much
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Organization
Yes or No
Question 5 Comment
WHICH time zone is used, it just matters that everyone understands which one is being used.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Bonneville Power
Administration
Disagree
This creates a communication barrier between the utility and its customers and the local population. Do not go
ahead with this provision. The very last thing that we want to do is to create confusion and this approach,
given that the country itself is using different time zones, will do just that. With 3-part communications with
specified time zones in Interoperability Communications as required and a common English language, the
matter is covered.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Entergy Services
Disagree
This is also a “how” requirement and not a “what” requirement. If the industry believes that confusion exists
pertaining to what time zone different entities are referring to in written and verbal communications, the
requirement should be focused on ensuring clear communication of time zone information is included in verbal
and written communication. Forcing entities to change to any one time zone will impose significant effort and
expense without a measurable improvement in reliability. However, Entergy is not aware that reliability issues
have occurred as a result of entities communicating in written or verbal format in different time zones. Entergy
proposes that this requirement be removed from the standard.
Response: The SDT thanks you for your comments. The SDT understands your concerns and adopted the suggestion for including the time zone
in communications that involve communicating with one or more entities in a different time zone.
ERCOT ISO
May 2, 2012
Disagree
This is an administrative task and prescribes how something should be done. Written Interoperability
Communications are typically done through automated systems, in which time zone conversion should not be
an issue. Verbal communication should be thorough enough to confirm the conversion. If the industry is in
favor of this requirement, then perhaps consideration should be to use Central Prevailing Time to alleviate
potential confusion with changes with Daylight Savings Time.
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Organization
Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
PPL
Disagree
This requirement is overly prescriptive and the benefit to reliability by switching everyone to CST is unclear.
Response: The SDT thanks you for your comments. The SDT revised COM-003 so that instead of requiring the use of a single continent-wide
time zone, the revised standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Power South
Energy
Disagree
This requirement will be too confusing and could lead to compliance violations because someone stated the
wrong time during the conversation.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Long Island Power
Authority
Disagree
This requirement will burden those entities whose operations and communication needs are with other
entities in the same time zone, which represents the overwhelming majority of all communications performed.
It will increase the likelihood of errors for such entities. Further, some entities are operating both NERC BES
elements and non-BES elements from the same control room. This requirement will significantly impact the
efficiency and the safety of workers within those entities. LIPA notes that R4 in the draft Standard does not
match R2 in this question. Specifically the word ALL is not in the Standard.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
NYSEG
Disagree
May 2, 2012
Unless the communication is across time zones, there is no benefit to using Central Standard Time, nor is it
sensible. Entire system infrastructures and business processes are driven by current, local standard time and it
is far more safe, reliable, and practical to use the established current time for system operations. If there is a
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
compelling need for definitive time notation across time zones then the requirement should dictate the
addition of the time zone when referring to a specific clock time (i.e., 1400 CST, 1400 EST, 1400 ED[aylight]T,
etc.).
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone. Your
recommendation is the genesis of the proposal we have developed in the standard.
Orange and
Rockland Utilities,
Inc.
Disagree
Use of the CST time format would present significant challenges as expressed in the comments of question #3
listed above.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone. Please see
responses to Question#3 comments above as well.
FirstEnergy
Disagree
Using a specific time zone that is subject to adjustments for daylight savings introduces additional complexity
for an operator and has potential to introduce additional reliability issues. A significant portion of the Eastern
Interconnection transmission operators have dealings with entities that do not span multiple time zones and
are solely within the Eastern Time Zone. We do not feel that it is appropriate for this standard to mandate
how time is communicated during three-part communication. Operating communication can deal with several
different subjects and data during a conversation, and it would be inappropriate to mandate all the possible
subjects and data through standard requirements. As a best practice, and not as a mandated requirement, it
would be appropriate for operators to state the time zone they are in if necessary for the situation or if
requested by an entity.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Ameren
Disagree
We agree that all inter-entity operability communication should be on common time zone but if said
communication includes routine dispatch instructions several RTOs use EST time for market operations, would
they then need to change to CST? And while CST seems to have some value because it is used for time error,
wouldn’t it make more sense to use UTC? It is a world standard and has the benefit of not being associated
with daylight savings times as Central time does (may be confusion at some times between CST and CDT)
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
NRECA RTF
Members
Disagree
We believe that adding the Central Time zone requirement for all verbal and written Interoperability
Communications is unnecessary. For these type of activities there should already be accurate time stamps
from equipment such as RTUs, EMS systems etc... for record keeping and documentation activities. In the
future, with the implementation of Smart Grid technologies, time stamping will be included in the developed
platforms for such technology, therefore, reducing the much of the time stamping errors. Because many of the
actions required for Interoperability Communications, are completed by field personnel this requirement is
onerous. It could potentially impact reliability since the field personnel might be more focused on documenting
the correct time zone, for compliance to the requirement and the potential impact for non-compliance, than
completing the required task safely and accurately. If time-stamping is an issue in event analysis, it might be
more appropriate that Central Standard Time be utilized by recording devices such as RTUs, EMS systems etc...
not for the actual verbal and written communications. In addition, how will daylight savings time be addressed
in the proposed requirement of this standard?
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone and indicate
whether the time is daylight saving or standard.
Florida Municipal
Power Agency
May 2, 2012
Disagree
We believe that any time zone can be used as long as the parties come to a common understanding of time
through communication. Also, if an Entity mistakenly starts off a conversation using a time other than Central
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
(FMPA) and some
members
Question 5 Comment
Standard Time, but corrects themselves during the 3-part communication process, is that a violation? We
believe not, that as long as the communicating entities come to a common understanding of time, there is no
violation. More clarity on this is desired. We assume such opportunity to correct mistakes is present
throughout the standard and the language of the standard ought to reflect that. A high VRF is not appropriate,
especially if the parties involved in the communication have a common understanding of the time, who cares
what time zone?
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
MRO NERC
Standards Review
Subcommittee
Disagree
We believe that requiring the use of Central Standard Time (CST) in the Operating Arena (Real-Time) would
reduce the level of reliability on a real-time basis. We understand that one of the primary reasons for going to
one time zone is to aid in Event Analysis. It is our belief that during the analysis of an event, there is adequate
time to make the necessary adjustments for time zones. The Group performing the analysis could require all
data being submitted be in one time zone as the basis. Requiring the use of CST is an added burden to the
Operations Staff in real-time that does not help them.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Transmission
System Operations
Disagree
We believe that the use of Central Standard Time in non-CST areas would create confusion between the
Reliability Coordinator, Transmission Operator, Transmission Owner, Generator Operators, and field personnel.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM -003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Duke Energy
May 2, 2012
Disagree
We don’t agree with this requirement because it would introduce confusion into communications, especially in
all communications other than RC to RC. RC’s already have protocols in place to deal with time zone
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
differences, and changing that and applying it to all entities would create reliability errors. We think that this is
“a solution in search of a problem”.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
PJM
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should be that
entities operating in different time zones agree on how to best eliminate any confusion regarding the time
difference. Entities that routinely operate in different time zones already have an effective system for dealing
with time differences. There seems to be no incentive to change a system that already works quite well, and
the cost of updating computer systems could prove prohibitive. This group feels that mandating a common
time zone across all of North America can only lead to confusion and increased reliability issues.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
PJM SOS Comments
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should be that
entities operating in different time zones agree on how to best eliminate any confusion regarding the time
difference. Entities that routinely operate in different time zones already have an effective system for dealing
with time differences. There seems to be no incentive to change a system that already works quite well, and
the cost of updating computer systems could prove prohibitive. This group feels that mandating a common
time zone across all of North America can only lead to confusion and increased reliability issues.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
SERC OC&SOS
Standards Review
May 2, 2012
Disagree
We feel that this requirement of a common time zone is overly prescriptive. The requirement should be that
entities operating in different time zones agree on how to best eliminate any confusion regarding the time
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Group
Question 5 Comment
difference. Entities that routinely operate in different time zones already have an effective system for dealing
with time differences. There seems to be no incentive to change a system that already works quite well, and
the cost of updating computer systems could prove prohibitive. For instance, the requirement to use the
central time zone for logging the time of an alert is problematic in that all communication tools, such as the
RCIS, will need to be re-vamped. We question whether there will be a measurable reliability benefit by so
doing. This group feels that mandating a common time zone across all of North America can only lead to
confusion and increased reliability issues.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
South Carolina
Electric and Gas
Disagree
We feel that time zones should be consistent throughout all standards and regulatory reporting
requirements(e.g. TADS)
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Tri-State
Generation &
Transmission Assoc.
Disagree
We have been operating within our individual time zones for many years without incident. Modifying the time
zone to which we operate will pose additional confusion and add unnecessary risk in operating the BES.
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Pacific Northwest
Small Utilities
Comment Group
May 2, 2012
Disagree
While our utilities agree that understanding the actual time is important, stating the time zone and summer
offset (13:34 PDT) should suffice. As an alternative, UTC might be used since it is clearly distinguishable from
local time in all of NERC.
As in R1, LSEs and DPs should be removed from this Requirement.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 5 Comment
Response: The SDT thanks you for your comments. The SDT understands your concerns and is proposing an alternative requirement in the
second draft of COM- 003 which we believe will address your concerns. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communications an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included as applicable entities and have
been retained in COM-003-1. The specified role of the DP to shed load justifies the retention of the DP as an applicable entity.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
6. Requirement R5 of the draft COM-003-1 states, “Each Responsible Entity shall use Three-part Communications
when issuing a directive during verbal Interoperability Communications.” Do you agree with this proposal? If
not, please explain in the comment area.
Summary Consideration:
Most stakeholders who responded to this question disagreed with the
proposed Requirement R5.
Many commenters offered differing recommendations on R5 regarding the
application and definition of “Reliability Directive.” The proposed term
“Reliability Directive” is being developed by the RC SDT for Project 2006-06,
and the OPCP SDT has not utilized this term in the first or second drafts of
COM- 003-1.
Many commenters recommended splitting proposed Requirement R5 to
recognize the two distinct parties (sending and receiving) in a three part
communication process. The OPCP SDT has done so by separating what had
been R5 into two requirements – R2 for the sender and R3 for the receiver of
an oral, person-to-person “Operating Communication.”
Some commenters expressed concerns regarding potential audit citations if a
repeat-back was not word-for-word or verbatim. The OPCP SDT modified the
standard, adding “not necessarily verbatim” to address the concern. In other
words, communication is acceptable as long as the communication is clear and
accurately conveys the Operating Communication and its substantive
components.
Organization
Yes or No
Ameren
Agree
British Columbia
Transmission
Corporation
Agree
May 2, 2012
The Quality Review team recommended that the OPCP SDT
modify Requirements R2 and R3 to clarify that these
requirements for performance of three-part
communication exclude Reliability Directives. This
eliminates the double jeopardy issue that may have existed
if both COM-002 and COM-003 were approved.
Thus – the revised COM-003 does include the term,
Reliability Directive. In addition, the implementation plan
was revised to no longer recommend retirement of COM002. As modified, the two standards can exist without
conflict. COM-002 requires the issuer of an Operating
Communication to identify that communication as a
“Reliability Directive” which gives recipients notice that the
directive is associated with an “Emergency”. COM-003 now
specifically identifies that the requirements for thee part
communication do not include “Reliability Directives.”
Per Standards Committee guidance, the SDT did not revise
all the responses in this report that indicate COM-003 does
not include the term, “Reliability Directive” nor did the
team revise all the responses that indicated the team
recommended retirement of COM-002.
Question 6 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Bureau of
Reclamation
Agree
Consumers Energy
Agree
ExxonMobil
Research and
Engineering
Agree
Kansas City Power
& Light
Agree
NorthWestern
Energy
Agree
Old Dominion
Electric
Cooperative
Agree
Oncor Electric
Delivery
Agree
Orange and
Rockland Utilities,
Inc.
Agree
PacifiCorp
Agree
PEF
Agree
Sunflower Electric
Agree
May 2, 2012
Question 6 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Power Corp.
Sunflower Electric
Power Corporation
Agree
Westar Energy
Agree
Western Area
Power
Administration
Agree
Pepco Holdings,
Inc. - Affiliates
Disagree
As mentioned in Question 1 above, the term Reliability Directive has been defined in the draft standard COM002-3 and should be considered in place of Interoperability Communication since the directive is specific to
emergency operations. PHI recommends that the requirement changed to read “Each responsible entity shall
use Three Part Communication when issuing or receiving a Reliability Directive”.
Response: The SDT thanks you for your comments. The current draft version of COM-003-1 eliminates the term “Interoperability Communication”
and now proposes the term “Operating Communications” which is defined as communications required when the state or status of an Element or
Facility of the BES is changed or altered. Three part communications will be required when oral, person-to-person Operating Communications are
used.
Independent
Electricity System
Operator
Disagree
3-part communication should be used for communicating a directive that must be complied with. The “must be
complied with” is needed to distinguish between an “instruction type” of directive and a “need to perform type”
of directive. We believe it is the latter that should require 3-part communication.
Response: The SDT thanks you for your comments. The current draft version of COM-003-1 eliminates the term “Interoperability Communication”
and now proposes the term “Operating Communications” which is defined as communications required when the state or status of an Element or
Facility of the BES is changed or altered. Three part communications will be required when oral, person-to-person Operating Communications are
used.
FirstEnergy
May 2, 2012
Disagree
Although we agree that proper communication should be used during actions that affect the reliability of the
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
BES, we do not agree with this requirement as written. The following contains our rationale and suggestions:
1. The lower case term "directive" is ambiguous, not defined, and confusing. This is especially true in light of the
proposal of the RCSDT to modify COM-002-3 to include a definition of "Reliability Directive" and their plan to use
this defined term to invoke 3-part communication. Since the plan of this OPCPSDT is to eventually incorporate
the COM-002-3 requirements into this new COM-003-1 standard, we feel the definition of Reliability Directive
should be moved to this standard now (instead of later) and the term should be broadened to include any
actions that affect the BES reliability. Essentially then, the current proposed R1 of COM-002-3 can be moved to
this COM-003-1 standard.
Response: The implementation plan proposes retiring COM-002 when COM-003 becomes effective. We also
agree the term should be broadened to include any actions that affect the BES reliability. As envisioned, the
new term, “Operating Communications” includes “Reliability Directives.”
2. Our proposal for the term Reliability Directive in item 1 above incorporates the verbiage of the proposed
Interoperability Communication definition. Therefore, the proposed term Interoperability Communication is no
longer required and can be eliminated.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and proposes
the term “Operating Communications” which is defined as communications required when the state or status
of an Element or Facility of the BES is changed or altered.
3. Once the term Reliability Directive and proposed R1 from COM-002-3 are moved to this COM-003-1 standard,
the current R5 of COM-003-1 requiring the use of Three-Part Communication could then be revised to require
three-part when a Reliability Directive is issued and continue until the operating condition that invoked the
Reliability Directive is resolved, mitigated, or ended.
The SDT believes that three part communication should be used for all oral, person-to-person Operating
Communications.
4. With respect to the proposed R2 and R3 of COM-002-3 which essentially discuss three-part communication,
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
these requirements could be eliminated and would be covered by COM-003-1. As a result, the COM-002-3
requirements being proposed by the RCSDT can be eliminated in their entirety since we have now incorporated
all of them into this new COM-003-1.
The SDT believes this is the intention as the projects progress through the Standard Development process.
5. Since COM-002-3 included the Purchasing-Selling Entity as an applicable entity, since they could be the
recipient of a Reliability Related Directive and since, with our proposed changes, COM-002-3 can be retired; the
Purchasing-Selling Entity can be added to the applicability section of and incorporated into this new COM-003-1
standard as recommended below.
The SDT again believes this is the intention as the projects as they progress through the Standard
Development process. There are many contingencies that could surface that could impact the final outcome.
In conclusion, we suggest the following changes/additions to COM-003-1:
A. Move a revised version of the term "Reliability Directive" from COM-002-3 to this new COM-003-1 standard
and define it as follows: "A communication initiated by a Reliability Coordinator, Transmission Operator, or
Balancing Authority where the recipient is directed to change the state or report the status of an Element or
Facility of the Bulk Electric System."
B. Delete proposed definition "Interoperability Communication".
C. Delete R2 and R3 of COM-002-3 as suggested in item 4 above.
D. Insert a New Requirement R4, renumbered as R2, into new standard COM-003-1 taken from COM-002-3 R1:
"When a Reliability Coordinator, Transmission Operator or Balancing Authority issues a Reliability Directive, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time]"
E. Revise Requirement R5 and renumber as R3: "Each Reliability Coordinator, Balancing Authority, Transmission
Owner, Transmission Operator, Generator Operator, Transmission Service Provider, Load Serving Entity,
Distribution Provider, and Purchasing-Selling Entity shall use Three-part Communication for all communications
May 2, 2012
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concerning a Reliability Directive that was issued per Requirement R1 and continuing until the actions or status
reporting identified in the Reliability Directive has been completed. [Violation Risk Factor: High][Time Horizon:
Real time]"
F. Add the Purchasing-Selling Entity as an applicable entity to COM-003-1.
The SDT does not believe the requirements of COM-003 are applicable to the PSE. The PSE is not involved in
real-time operating communication. In addition, the SAR for this project did not include the PSE as a
responsible entity.
Response: The SDT thanks you for your comments. Please see our responses above.
Electric Market
Policy
Agree
As currently defined, Three-part Communications presumes the second party will repeat the information back
“correctly.” Failure to do so is assigned a High VRF and a Severe VSL. The practical application of Three-part
Communication involves a sender communicating information, a receiver repeating back the information, and
the sender verifying the repeat back is either correct or incorrect. If the repeat back is incorrect, the process
repeats until both parties have the same understanding of what is being communicated. This iterative process
needs to be addressed within the definition of Three-part Communications.
Response: The SDT thanks you for your comments. The second draft of the standard captures many of your observations in Requirements R2 and
R3. Note that the SDT modified the VRF for both R2 and R3 in the second draft of COM-003 to “Moderate” rather than “High”.
Transmission
System Operations
Disagree
As stated in Question #1, the definition of “Interoperability Communication” needs further clarification. Also,
further clarification is needed as to when “Interoperability Communications” is required to be used.
Response: The SDT thanks you for your comments.
The current draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
The second draft of the standard does identify when Operating Communications are required for oral and written communications.
PJM
Disagree
May 2, 2012
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should be used in
place of Interoperability Communication, since the directive is specific to emergency operations. The
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requirement should read: “Each responsible entity shall use Three-part Communication when issuing a Reliability
Directive”.
In addition, this requirement should apply only to entities which issue reliability directives - BAs, TOPs & RCs.
The other entities listed in the draft standard under Applicability do not issue Reliability Directives.
Response: The SDT thanks you for your comments.
The OPCP SDT met with the RCSDT and RTOSDT members to coordinate efforts on the use of the terms, “Three-part Communications” and
“Reliability Directives.” The teams agreed that the RC SDT will advance the new Glossary term “Reliability Directive” in its Project 2006-06. The
second draft version of COM-003-1 has not used the term “directive” or “Reliability Directive” and instead uses the proposed defined term
“Operating Communications.” The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes
the term “Operating Communications” which is defined as communications required when the state or status of an Element or Facility of the BES
is changed or altered.
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication. The entities listed as
applicable in the second draft are limited to Reliability Coordinators, Balancing Authorities, and Transmission Operators, as senders and Reliability
Coordinator, Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider as receivers of oral person-to-person
Operating Communications.
PJM SOS Comments
Disagree
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should be used in
place of Interoperability Communication, since the directive is specific to emergency operations. The
requirement should read: “Each responsible entity shall use Three-part Communication when issuing a Reliability
Directive”.
In addition, this requirement should apply only to entities which issue reliability directives - BAs, TOPs & RCs.
The other entities listed in the draft standard under Applicability do not issue Reliability Directives.
Response: The SDT thanks you for your comments.
The OPCP SDT met with the RC SDT and RTO SDT members to coordinate efforts on the use of the terms, “Three-part Communications” and
“Reliability Directives”. The teams agreed that the RC SDT will advance the new Glossary term “Reliability Directive” in its Project 2006-06. The
second draft version of COM-003-1 has not used the term “directive” or “Reliability Directive” and instead uses the proposed defined term
“Operating Communications.” The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes
May 2, 2012
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the term “Operating Communications” which is defined as communications required when the state or status of an Element or Facility of the BES
is changed or altered.
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication. The entities listed as
applicable in the second draft are limited to Reliability Coordinators, Balancing Authorities, and Transmission Operators, as senders and Reliability
Coordinator, Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider as receivers of oral person-to-person
Operating Communications.
SERC OC&SOS
Standards Review
Group
Disagree
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should be used in
place of Interoperability Communication, since the directive is specific to emergency operations. The
requirement should read: “Each responsible entity shall use Three-part Communication when issuing a Reliability
Directive”. In addition, this requirement should apply only to BAs, TOPs & RCs. The other entities listed in the
draft standard under Applicability do not issue Reliability Directives.
Response: The SDT thanks you for your comments.
The OPCP SDT met with the RC SDT and RTO SDT members to coordinate efforts on the use of the terms, “Three-part Communications” and
“Reliability Directives”. The teams agreed that the RC SDT will advance the new Glossary term “Reliability Directive” in its Project 2006-06. The
second draft version of COM-003-1 has not used the term “directive” or “Reliability Directive” and instead uses the proposed defined term
“Operating Communications.”
The second draft version of COM-003-1 has not used the term “Interoperability Communication” and has now used the proposed defined term
“Operating Communications” for which the term “Reliability Directive” is included as a subset of “Operating Communications”.
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication. The entities listed as
applicable in the second draft are limited to Reliability Coordinators, Balancing Authorities, and Transmission Operators, as senders and Reliability
Coordinator, Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider as receivers of oral person-to-person
Operating Communications.
ATC and ITC
May 2, 2012
Disagree
ATC believes that the term “directive” should be replaced with the term “Reliability Directive” which is being
developed under Project 2006-06. It is important for BES reliability that NERC use clearly defined term which will
identify the circumstances under which this requirement is enforceable. We provide the definition for
“Reliability Directive”, as it appears in the latest posting for Project 2006-06, in our response to question 1.
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It is our understanding and interpretation that the intent of this requirement is to require entities to use ThreePart Communication during emergency situations in which “Reliability Directives” are being issued. In other
words this requirement as proposed does not apply to normal (non-emergency) day-to-day switching. The
replacement of the term “directive” with “Reliability Directive” provides the additional clarity around an entity’s
compliance obligation.
Response: The SDT thanks you for your comments.
The OPCP SDT met with the RC SDT and RTO SDT members to coordinate efforts on the use of the terms, “Three-part Communications” and
“Reliability Directives”. The teams agreed that the RC SDT will advance the new Glossary term “Reliability Directive” in its Project 2006-06. The
second draft version of COM-003-1 has not used the term directive and has now used the proposed defined term “Operating Communications,”
The OPCP SDT changed Interoperability Communications to become Operating Communications which includes all communications that change or
maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System which could be applicable to routine operations
that impact the BES.
Your comments on the term Reliability Directive reflect the potential outcome of a Standard under development by another drafting team.
IRC Standards
Review Committee
Disagree
Based on the definition of Interoperability Communications, R5 could imply that three-part communications is
required to communicate routine operating instructions. We believe this Requirement contradicts the work that
has been done and substantially progressed through two other SDTs and creates confusion within the industry.
We believe this Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing
the amount of pre-action communications that may occur prior to taking action because operators may be more
concerned with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT which would define a directive based on the determination of the
person giving such an order. We believe, it should be left to the entity that needs the action to be taken to
establish the need for three-part communications by stating in the communication that they are issuing a
directive. This would be a clear trigger and auditable and measureable.R5 is not consistent with the Functional
Model. Only the RC, BA, and TOP issue directives. Thus, the term “....when issuing a directive....” should be
“....when communicating directives....” , so both the issuer and receiver are included in the requirement.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
May 2, 2012
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Question 6 Comment
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3 that
fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating Communications
does not apply to “non action” items, but to those that instruct a change or maintenance of the state, status, output, or input of an Element or
Facility of the Bulk Electric System which could be applicable to routine operations that impact the BES. The entities listed as applicable for issuing
an oral Operating Communication in the second draft of COM-003 are limited to Reliability Coordinators, Balancing Authorities, and Transmission
Operators. The SDT believes miscommunications during routine operations as described in “Operating Communications” can and do lead to
mishaps that impact reliability.
ISO New England
Inc.
Disagree
Based on the definition of Interoperability Communications, R5 could imply that three-part communications is
required to communicate routine operating instructions. We believe this Requirement contradicts the work that
has been done and substantially progressed through two other SDTs and creates confusion within the industry.
We believe this Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing
the amount of pre-action communications that may occur prior to taking action because operators may be more
concerned with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT which would define a directive based on the determination of the
person giving such an order. We believe, it should be left to the entity that needs the action to be taken to
establish the need for three-part communications by stating in the communication that they are issuing a
directive. This would be a clear trigger and auditable and measureable.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3 that
fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating Communications
does not apply to “non action” items, but to those that that instruct a change to, or maintenance of, the state, status, output, or input of an
Element or Facility of the Bulk Electric System which could be applicable to routine operations that impact the BES. The SDT believes
miscommunications during routine operations as described in “Operating Communications” can and do lead to mishaps that impact reliability.
Dynegy
Disagree
May 2, 2012
Based on the definition of Interoperability Communications, R5 implies that three-part communications is
required to communicate routine operating instructions. We believe this Requirement contradicts the work that
has been done and substantially progressed through two other SDTs and creates confusion within the industry.
We believe this Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing
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the amount of pre-action communications that may occur prior to taking action because operators may be more
concerned with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT in Project 2006-06 which would define a Reliability Directive based
on the determination of the person giving such an order. We believe, it should be left to the entity that needs
the action to be taken to establish the need for three-part communications by stating in the communication that
they are issuing a directive. This would be a clear trigger and auditable and measureable.R5 is not consistent
with the Functional Model. Only the RC, BA, and TOP can issue directives.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3
that fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating
Communications does not apply to “non action” items, but to those that that instruct a change to, or maintenance of, the state, status, output, or
input of an Element or Facility of the Bulk Electric System which could be applicable to routine operations that impact the BES. The entities listed
as applicable for issuing an oral Operating Communication in the second draft of COM-003 are limited to Reliability Coordinators, Balancing
Authorities, and Transmission Operators. The SDT believes miscommunications during routine operations as described in “Operating
Communications” can and do lead to mishaps that impact reliability.
Hydro-Québec
TransEnergie
May 2, 2012
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part communications is
required to communicate routine operating instructions, or during operational strategic discussions as well as
other “non-action” oriented communications. This Requirement contradicts the work that has been done and
substantially progressed through two other SDTs and creates confusion within the industry. This Requirement
would, in fact, be adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned with not
repeating back during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person giving such
an order. The entity that needs the action to be taken should establish the need for three-part communications
by stating in the communication that they are issuing a directive. This would be a clear trigger, auditable, and
measureable. R5 is not consistent with the Functional Model. Only the RC, BA, and TOP can issue directives.
Outside of allowing the individual who NEEDS the action to be taken, this is an auditable or measureable
requirement whether it be for 3-part communications or for the receiving entity to actually take said action. By
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definition, Three-part Communications presumes the second party will repeat the information back “correctly.”
Failure to do so is assigned a High VRF and a Severe VSL. The practical application of Three-part Communication
involves a sender communicating information, a receiver repeating back the information, and the sender
verifying the repeat back is either correct or incorrect. If the repeat back is incorrect, the process repeats until
both parties have the same understanding of what is being communicated.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3
that fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating
Communications does not apply to “non action” items, but to those that that instruct a change to, or maintenance of, the state, status, output, or
input of an Element or Facility of the Bulk Electric System which could be applicable to routine operations that impact the BES. The entities listed
as applicable for issuing an oral Operating Communication in the second draft of COM-003 are limited to Reliability Coordinators, Balancing
Authorities, and Transmission Operators. The SDT believes miscommunications during routine operations as described in “Operating
Communications” can and do lead to mishaps that impact reliability.
Midwest ISO
Standards
Collaborators
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part communications is
required to communicate routine operating instructions. We believe this Requirement contradicts the work that
has been done and substantially progressed through two other SDTs and creates confusion within the industry.
We believe this Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing
the amount of pre-action communications that may occur prior to taking action because operators may be more
concerned with not repeating back during such pre-action, strategic calls and/or discussion. We support the
work being done by the RC SDT and RTO SDT in Project 2006-06 which would define a Reliability Directive based
on the determination of the person giving such an order. We believe it should be left to the entity that needs
the action to be taken to establish the need for three-part communications by stating in the communication that
they are issuing a directive. This would be a clear trigger and easily auditable and measureable.R5 is not
consistent with the Functional Model. Only the RC, BA, and TOP can issue directives.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
May 2, 2012
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Question 6 Comment
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3
that fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating
Communications does not apply to “non action” items, but to those that instruct a change to, or maintenance of, the state, status, output, or input
of an Element or Facility of the Bulk Electric System” which could be applicable to routine operations that impact the BES. The entities listed as
applicable for issuing an oral Operating Communication in the second draft of COM-003 are limited to Reliability Coordinators, Balancing
Authorities, and Transmission Operators.
Northeast Power
Coordinating
Council
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part communications is
required to communicate routine operating instructions, or during operational strategic discussions as well as
other “non-action” oriented communications. This Requirement contradicts the work that has been done and
substantially progressed through two other SDTs and creates confusion within the industry. This Requirement
would, in fact, be adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned with not
repeating back during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person giving such
an order. The entity that needs the action to be taken should establish the need for three-part communications
by stating in the communication that they are issuing a directive. This would be a clear trigger, auditable, and
measureable.R5 is not consistent with the Functional Model. Only the RC, BA, and TOP can issue directives.
Response: The second draft version of COM-003-1 does not use or define the term directive and now proposes
defined term “Operating Communications”. The SDT is aware of the term Reliability Directive proposed under
NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second
draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part
communication. The use of three-part communication with Operating Communications does not apply to “non
action” items, but to those that instruct a change to, or maintenance of, the state, status, output, or input of
an Element or Facility of the Bulk Electric System which could be applicable to routine operations that impact
the BES. The entities listed as applicable for issuing an oral person-to-person Operating Communication in the
second draft of COM-003 are limited to Reliability Coordinators, Balancing Authorities, and Transmission
Operators. The SDT believes miscommunications during routine operations as described in “Operating
May 2, 2012
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Communications” can and do lead to mishaps that impact reliability.
Outside of allowing the individual who NEEDS the action to be taken, this is an auditable or measureable
requirement whether it be for 3-part communications or for the receiving entity to actually take said action. By
definition, Three-part Communications presumes the second party will repeat the information back “correctly.”
Failure to do so is assigned a High VRF and a Severe VSL. The practical application of Three-part Communication
involves a sender communicating information, a receiver repeating back the information, and the sender
verifying the repeat back is either correct or incorrect. If the repeat back is incorrect, the process repeats until
both parties have the same understanding of what is being communicated.
Response: The SDT has added “not necessarily verbatim” to Requirement R3.
Response: The SDT thanks you for your comments. Please see our responses above.
Northeast Utilities
Disagree
Based on the definition of Interoperability Communications, R5 implies that three-part communications is
required to communicate routine operating instructions, or during operational strategic discussions as well as
other “non-action” oriented communications. This Requirement contradicts the work that has been done and
substantially progressed through two other SDTs and creates confusion within the industry. This Requirement
would, in fact, be adverse to reliability instead of enhancing reliability by reducing the amount of pre-action
communications that may occur prior to taking action because operators may be more concerned with not
repeating back during such pre-action, strategic calls and/or discussion. The work being done by the RC SDT and
RTO SDT in Project 2006-06 defines a Reliability Directive based on the determination of the person giving such
an order. The entity that needs the action to be taken should establish the need for three-part communications
by stating in the communication that they are issuing a directive. This would be a clear trigger, auditable, and
measurable.
The second draft version of COM-003-1 does not use or define the term directive and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Interoperability Communication” has been removed from the second draft of COM-003. The second draft includes a new R2 and R3 that
fully assign the responsibility for accomplishing three-part communication. The use of three-part communication with Operating Communications
does not apply to “non action” items, but to those that instruct a change to, or maintenance of, the state, status, output, or input of an Element
or Facility of the Bulk Electric System which could be applicable to routine operations that impact the BES. The SDT believes miscommunications
May 2, 2012
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Yes or No
Question 6 Comment
during routine operations as described in “Operating Communications” can and do lead to mishaps that impact reliability.
National Grid
Disagree
Based on the definition of Interoperability Communications, this would require 3- part communication to be
used during virtually all control room communications. The definition of Interoperability Communications should
be revised as proposed in response to Question 1.
Response: The SDT thanks you for your comments.
The OPCP SDT replaced “Interoperability Communications” with “Operating Communications” which includes all communications that instruct a
change to, or maintenance of, the state, status, output, or input of an Element or Facility of the Bulk Electric System. By use of the term,
“Operating Communications” the second draft of COM-003 requires three-part communication only for operations that change or maintain the
state, status, output, or input of an Element or Facility of the Bulk Electric System.
California
Independent
System Operator
Disagree
CAISO Comments:
Until “directive” is a defined term the industry should not accept requirements governing actions regarding
directives. Directive is currently being defined in an interpretation. Subsequent interpretations may subvert the
standards drafting process. Terms should be formally defined before inclusion in other standards to prevent
future interpretation issues, including the changing of a standard outside of the accepted Standard Development
process.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
New York State
Reliability Council
Disagree
Comments:
The SDT should define Directive. Draft Com-002 -3 has a similar requirement to identify a directive and then
utilize three-part communication. Also Com-002-3 Three part communication differs from the description of
Three-part communication in this Standard. NYSRC prefers Com-002-3 usage of the word “intent” in the repeat
back. Also see comments to Question 1.
Response: The SDT thanks you for your comments.
May 2, 2012
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Question 6 Comment
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The second draft of the standard includes the phrase, “not necessarily verbatim” in describing the repeat back.
Tri-State
Generation &
Transmission Assoc.
Disagree
Directive is not defined. This would require issuing a directive for each and every verbal communication
between entities, even those that pose no risk to the BES, which is not necessary.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination. Unless a
communication would impact the BES as described in the proposed definition of “Operating Communications” the SDT does not believe every
conversation would require three-part communications.
E.ON U.S. LLC
Disagree
E ON US believes more specificity is required as to what constitutes a “directive”. Moreover, this requirement is
redundant in light of COM-002 R2 for normal operations. If COM-003 is only applicable to emergencies, then
this R5 would appear reasonable. E.ON U.S. suggests editing R5 and M5 as follows: Each Responsible Entity shall
use Three-part Communications when issuing and/or receiving a directive during verbal Interoperability
Communications
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”.
COM -003 is not limited to emergencies only.
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication and uses the new term
Operating Communication.
American Municipal
Power
May 2, 2012
Agree
I feel that there needs to be a way to verify what has been said. Three-part Communications accomplish the
verification that may be required as a result of the communication medium. If a better method is developed I
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propose that it be used.
Response: The SDT thanks you for your comments.
American Electric
Power
Disagree
Is a “directive” from the RC a “directive” all the way through the communication process, including down to the
plant orders? Again, based on definitions provided in the functional model, the inclusion of the TSP and LSE in
this standard is inappropriate. These entities manage the relationship with the end-use customer and are not
responsible for the operation or maintenance of BES facilities. Consequently, when would such entities be
responsible for issuing “directives?”
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The term Reliability Directive is proposed under NERC Project 2006-06 Reliability Coordination.
The SDT agrees with your comments on TSPs and LSEs and has removed them because they were not bound by this requirement in the originating
SAR.
NIPSCO
Disagree
It's not clear whether this is limited to emergency situations. In the Purpose section of this standard the line
"especially during alerts and emergencies" seems rather vague. When does this standard exactly apply?
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination. The second
draft of COM-003 proposes requiring use of three part communications for, verbal “Operating Communications” to any communication that
instructs a change to, or maintenance of, the state, status, output, or input of an Element or Facility of the Bulk Electric System and is not limited
to emergencies.
Manitoba Hydro
Move requirement as planned but keep Three-part Communication definition as stated originally in COM-002-2
R2.
1) Reading the “Disposition/Explanation” it appears that COM-002-2 R2 will eventually be moved into COM-003
R5. This appears logical as COM-002-2 ensures staffing and communication capabilities.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
a .The statement in COM-002 R2 is reasonably descriptive, but loses its depiction when replaced with statement
found in COM-003-0 R5.
2) Regarding COM-002-2 R2, Manitoba Hydro interprets part 2 (repeat back correctly) of Three-part
Communication to mean; that the party receiving the directive has clearly received it in its full form and
understands completely what is expected of him and to convey this to the sender
i. We delineated “repeating back correctly” to mean any of the three protocols as acceptable:
1. Actually repeating back the directives correctly.
2. The recipient verifies the issued directive(s) are identical to a copy they have at hand.
Example for clarification: “The steps you have read are identical to what I have here on Order
Number 1234, Revision 5 and I understand I can proceed with steps 3, 4 and 5.”
3.The recipient summarizes the issued directive(s) to a copy they have at hand.
Example for clarification: “I will do step 8, open all 115 kV disconnects as read to me and are
identical to the order 1234 Revision 5 that I have at hand”.
4. This all could be resolved by using the term “repeat back the intent of the directive”. This statement
could allow the operator to determine if the recipient fully understands and is capable of carrying out the
directive, by the method of the recipient reply (any literate person can read back a written statement, but
do they understand what they are doing and the consequences).
ii.The purpose of protocols 2 and 3 are to alleviate potential of “lose of attention” due to the tedious
receptiveness of long written directives. Summarizing or verifying these types of written orders will maintain the
interest and attention to the detail.
iii.Verbally detailing a directive at least once in any single conversation by either party should be sufficient to
fulfill the first two parts of Three-part Communications (Clear and concise, repeat back).
iv. Part 3 (acknowledge to satisfaction of the originator) could ensure that the person receiving the directive is
capable and competent of carrying out the directive.
v. None written (changes, revisions, real time emergency switching) and radio communication directives are a
must for repeating back and are covered by other local policies. Part Two “Three Part Identification”
May 2, 2012
186
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
The SDT believes many of the details you have listed above are incorporated into the new R2 and R3 in the
second draft of COM 003-01. We would appreciate your comments in the initial ballot.
3) This new Standard COM-003-1 should contain a requirement for “Three Part Identification” or more
commonly known as “Full Name Identification”. This is not addressed fully anywhere in the NERC standards.
4)We have defined “Three Part Identification” based loosely on common industry best practice into three parts:
1. Location - Company Name, Control Room Name, etc.
2. Area of responsibility or authority (function) - The operator at the desk must identity his position such as
Balancing Authority or Distribution Operate, etc.
3. Identification - Unique identifier such as first and last Name.
The SDT acknowledges and believes your comments on Full Name Identification do constitute a strong best
practice which would add additional clarity to operating communications. For many organizations that
becomes overly prescriptive and conflicts with their existing nomenclature scheme.
Response: The SDT thanks you for your comments. Please see our responses above.
NERC Staff
May 2, 2012
Disagree
NERC staff agrees with the principle behind Requirement R5. We recommended in Question 1 that the term
“Three-part Communication” be removed since it is only used in this requirement. We feel that this requirement
should be split into two requirements so that the sender and receiver each have responsibility in the
communication. Therefore, we offer the following as suggested replacement language for Requirement R5:Each
Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator,
Transmission Service Provider, Load Serving Entity and Distribution Provider that receives a verbal Operating
Communication shall repeat the communication to the initiator. Each Reliability Coordinator, Balancing
Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission Service Provider,
Load Serving Entity and Distribution Provider that initiates a verbal Operating Communication shall ensure that
the receiving party has repeated the communication, and shall verbally confirm the communication to be correct
or reinitiate the communication.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
The SDT has removed the definition for “Three-part communication” in the second draft of COM-003-1 standard.
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication.
NextEra Energy
Resources, LLC
Disagree
NextEra believes that by associating the “3-part communication” method with “directives” this standard drafting
team could be at risk of unintentionally defining a directive as anything that takes the 3-part communication
form. We would encourage the standard drafting team to continue to use the terms already employed in the
draft standard: “... three-part communication be used when issuing instructions related to actual or expected
emergency conditions.”
Response: The SDT thanks you for your comments.
In the second draft of COM-003, the SDT proposes that three-part communication would be required when verbal person-to-person “Operating
Communications” take place for any communication to instruct a change to, or maintenance of, the state, status, output, or input of an Element or
Facility of the Bulk Electric System. This could include non emergency conditions.
PPL
Disagree
Only RCs, TOPs, & Bas issue directives. The other entities should be removed from this requirement.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications” for any communication to instruct a change to, or maintenance of, the state, status, output, or input of an Element or Facility of
the Bulk Electric System. Other entities have to participate so they remain responsible as designated.
Progress Energy
Carolina, Inc
Disagree
PEC supports creating a definition of Reliability Directives. PEC may then agree that each entity shall use 3-part
communications when issuing Reliability Directives during “Interoperability Communications.” Alternatively,
simplify and change to use Three Part Communications when using Interoperability Communications.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
May 2, 2012
188
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
The second draft includes a new R2 and R3 that fully assign the responsibility for accomplishing three-part communication for verbal “Operating
Communications”.
Pacific Northwest
Small Utilities
Comment Group
Disagree
Per TOP-001 and IRO-001, only TOs and RCs have the authority to issue reliability directives (per the proposed
definition of interoperability communications, such directives would qualify as reliability directives). All other
entity types should be removed from this requirement.
The applicable entities in the standard include senders and receivers of three part communications.
As in Q2, the transition is a concern. Unless the effective date of COM-003-1 is the same as the date of
retirement of COM-002; there will either be a reliability gap where neither active standard requires three-part
communication, or there will be a situation where an entity could be doubly jeopardized for a single event.
The implementation plan for COM-003 proposes retiring COM-002 when COM-003 becomes effective – as
envisioned, only one standard will be in place at a time.
Three-part communication is worthless unless the recipient understands what he/she is parroting and is
authorized to take action. For example, many DPs/LSEs do not maintain 24/7 dispatch desks and an afterhours
call may go to an answering service. Three-part communication with the answering service operator will only
delay the requested action. The entity issuing the directive should be required to ensure their employee reaches
someone authorized to take action before delivering the directive via Three-part communication.
The SDT reviewed the SAR and has removed TSPs and LSEs as applicable entities; however DPs were included
as applicable entities and have been retained in COM-003-1. The specified role of the DP to shed load justifies
the retention of the DP as an applicable Entity.
Response: The SDT thanks you for your comments. Please see our responses above.
Georgia
Transmission Corp
Disagree
Replace “directive during verbal Interoperability Communications” with ”Reliability Directive”.
Replace "Each Responsible Entity" with "TOPs & RCs". The other entities listed in the draft standard under
Applicability do not issue Reliability Directives.
Response: The SDT thanks you for your comments.
May 2, 2012
189
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
The term “Reliability Directive is being proposed under NERC Project 2006-06 Reliability Coordination and is not used in COM-003.
The phrase “Each Responsible Entity” was replaced with the name of each of the responsible functional entities.
Entergy Services
Disagree
Should be rewritten to say that “Each Responsible Entity shall use Three-part Communications when issuing a
Reliability Directive.” This should use the definition of Reliability Directive as proposed in project 2006-06.
Entergy recommends not including the definition of Interoperability Communications in this standard or in the
R5 Requirement. Also, the list of responsible entities listed in the requirement R5 is not all able to issue
Reliability Directives. So this requirement should be limited to Reliability Coordinators, Balancing Authorities and
Transmission Operators, who can issue Reliability Directives.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”
which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered. The SDT is aware
of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination. It is a draft proposal and has not been filed or
approved.
There are other entities listed as applicable who have to receive and repeat back “Operating Communications.”
Southern Company
Transmission
Disagree
Southern Company supports the SERC SOS comments.
SERC SOS comments:
As suggested in Question 1 above, the term Reliability Directive (as defined in COM-002-3) should be used in
place of Interoperability Communication, since the directive is specific to emergency operations.
The requirement should read: “Each responsible entity shall use Three-part Communication when issuing a
Reliability Directive”. In addition, this requirement should apply only to BAs, TOPs & RCs. The other entities
listed in the draft standard under Applicability do not issue Reliability Directives.
Southern Company comments: conditional on if the definition of directive is not routine operational instruction.
May 2, 2012
190
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination. The term “Operating
Communications” is not restricted to emergencies.
The other entities who are listed have to receive and repeat back “Operating Communications.”
Bonneville Power
Administration
Agree
Suggest that each entity is also required to use the full station name in verbal communications.
Response: The SDT thanks you for your comments.
Indiana Municipal
Power Agency
Disagree
The definition of Interoperability Communications is not clear and this requirement could require Three-part
Communications to communicate routine, internal instructions within an entity. In addition, the definition of a
directive is being worked on by a NERC SDT, and this definition might help clear up any confusion in this
requirement, along with a better definition of Interoperability Communications.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination.
NYSEG
Disagree
The definition of Three-part Communications and Interoperability Communications needs to be revised as
explained above.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
May 2, 2012
191
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
Please see our response to the PJM System Operations Subcommittee (SOS) Group.
Puget Sound
Energy
Disagree
The requirement should use the NERC defined term “Reliability Directive,” instead of the general term
“directive.”
Response: The SDT thanks you for your comments.
The current draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination.
ERCOT ISO
Disagree
The requirement, based on the definitions of the terms, introduces ambiguity or even conflict. Three part
communication should be required for emergency situations and with the issuance of Reliability Directives (term
not yet formally defined - in the works by the Reliability Coordination SDT). Interoperability communications
refer to any communications in which a status of a facility or element is to be changed, which means not
specifically related to emergencies.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
This will apply to routine operations that impact the BES.
The second draft version of COM-003-1 does not define or use the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination.
The term “Operating Communications” is not restricted to emergencies.
May 2, 2012
192
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Santee Cooper
Disagree
Question 6 Comment
The SDT should consider using the now defined term Reliability Directive in place of Interoperability
Communications. Typically, only BAs, TOPs, or RCs issue Reliability Directives so this requirement should only be
applicable to those entities.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
More applicable entities will be impacted by “Operating Communications” since three part communication involves both senders and receivers of
communications.
Long Island Power
Authority
Disagree
The SDT should define Directive. Draft Com-002 -3 has a similar requirement to identify a directive and then
utilize three-part communication. Also Com-002-3 Three part communication differs from the description of
Three-part communication in this Standard. LIPA prefers Com-002-3 usage of the word “intent” in the repeat
back. Also see comments to Question 1.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination and is not filed or approved. The
SDT current draft “correct but not necessarily verbatim” in describing the repeat back.
South Carolina
Electric and Gas
Disagree
The term "directive" should be changed to "Reliability Directive" as defined in COM-002-3.
Response: The SDT thanks you for your comments.
The term “Reliability Directive’ is not approved. It also has a very narrow focus and in its present form is restricted to emergencies. The OPCP SDT
is proposing the term “Operating Communications” which is more inclusive and would have a bigger scope to improve reliability.
May 2, 2012
193
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Transmission
Owner
Disagree
Question 6 Comment
The term “directive” as of yet has not been explicitly defined. Furthermore, FPL believes that by associating the
“3-part communication” method with “directives” this standard drafting team could be at risk of unintentionally
defining a directive as anything that takes the 3-part communication form. We would encourage the standard
drafting team to continue to use the terms already employed in the draft standard: “... three-part
communication be used when issue instructions related to “actual or expected emergency conditions.”
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not define or use the term “directive” and now proposes the defined term “Operating
Communications” which will require three-part communication for communications required when the state or status of an Element or Facility of
the BES is changed or altered. This will apply to routine operations that impact the BES.
The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination.
We Energies
Disagree
The term “directive” should be replaced with the term “Reliability Directive” as defined by the Drafting Team
working on Project 2006-06 which states it as: “A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is necessary to address an actual or
expected Emergency”. Three-part Communication should be required (with regard to compliance) during
emergency situations in which Reliability Directives are being issued. This requirement should not apply to
normal or non-emergency situations, and should be enforceable between Functional Entities (distinct entities,
not within a given organization). As noted in question 2, R5 should not apply to a TSP or LSE.
Response: The SDT thanks you for your comments.
The term “Reliability Directive’ is not approved. It also has a very narrow focus and in its present form is restricted to emergencies. The OPCP SDT
is proposing the term “Operating Communications” which is more inclusive and will require three-part communications when the state or status
of an Element or Facility of the BES is changed or altered. This will apply to routine operations that impact the BES.
The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination. This standard would have a
bigger scope to improve reliability.
The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
Energy
Disagree
May 2, 2012
The term interoperability communications is not clear.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating
Communications” which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
Xcel Energy
Disagree
The way the standard is written, the term "directive" is still open to interpretation and could be inconsistently
applied. The term "directive" should be defined.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not define or use the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination.
Florida Municipal
Power Agency
(FMPA) and some
members
Agree
The word “directive” is ambiguous. The standard should either require the Reliability Coordinator to define a
“directive” or the standard should make this a defined term so that there is clarity between what is and what is
not a directive. In fact, the “disposition” does state that “Reliability Directive” definition is in the scope of the
SDT’s effort.
We do not think that this merits an increase from a “Medium” VRF in COM-002-2 R2 to a “High” VRF in this
standard, especially if the actual action taken was in accordance with the direction given.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes defined term “Operating Communications”.
The SDT is aware of the term “Reliability Directive” proposed under NERC Project 2006-06 Reliability Coordination.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The SDT believes the new assignments more
accurately classify the VRFs and VSLs assigned to the Requirements in COM-003-01. The VRF associated with the requirement to use three-part
communication in the second draft of COM-003 is “Medium.”
NRECA RTF
Members
May 2, 2012
Disagree
We agree that Three-part communication is a more accurate form of communication for issuing and responding
to a Directive during verbal Interoperability Communications and should remain as a requirement of this
standard. However since the term “directive” has not been defined it is unclear when Three-part communication
is required.
195
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications” and proposes using three-part communication for any communication when the state or status of an Element or Facility of the
BES is changed or altered.
Duke Energy
Disagree
We believe that the term “directive” should be defined. This SDT should work with the COM-002 SDT to come
up with common phraseology and definition for the term “Directive”. Work on COM-003-1 should have begun
by defining “directive”, and limiting the requirement to use 3-part communications to “directives”, and not
requiring it for general day-to-day communications. The entity issuing a “directive” should inform the receiving
entity that it is a directive and therefore requires the use of 3-part communications.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications” which requires use of three-part communication for any communication when the state or status of an Element or Facility of the
BES is changed or altered.
The Empire District
Electric Company
Disagree
When and why would a GO, TSP or LSE ever issue a directive? Directives are given by RC's. Use the definition of
Third Party Communications provided earlier in this comment form.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT appreciates the comments with regards to concerns related to including GOs, TSPs and LSEs that do not own or
operate facilities that are a part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the
originating SAR. The GO was not included in the draft standard of the requirement.
MRO NERC
Standards Review
Subcommittee
May 2, 2012
Disagree
Without defining “directive” the SDT is leaving the industry in the same situation we are currently in. As
discussed in the response to Question #1 above, it is our opinion that the definition of Reliability Directive must
be developed and included in the discussion of this standard (COM-003-1), and should be as defined in Project
2006-06: “A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an actual or expected Emergency.”. Based on the definition
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
of Interoperability Communications, R5 could imply that three-part communications is required to communicate
routine operating instructions. We believe this Requirement contradicts the work that has been done and
substantially progressed through two other SDTs and creates confusion within the industry. We believe this
Requirement would, in fact, be adverse to reliability instead of enhancing reliability by reducing the amount of
pre-action communications that may occur prior to taking action because operators may be more concerned
with not repeating back during such pre-action, strategic calls and/or discussion. We support the work being
done by the RC SDT and RTO SDT which would define a directive based on the determination of the person giving
such an order. We believe, it should be left to the entity that needs the action to be taken to establish the need
for three-part communications by stating in the communication that they are issuing a directive. This would be a
clear trigger and auditable and measureable.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
Communications”. The SDT is aware of the term Reliability Directive proposed under NERC Project 2006-06 Reliability Coordination. The second
draft version of COM-003-1 eliminates the term “Interoperability Communication” and now proposes the term “Operating Communications”
which is defined as communications required when the state or status of an Element or Facility of the BES is changed or altered.
This standard would apply when verbal “Operating Communications” take place and would apply to any communications involving a change to, or
maintenance of, the state, status, output, or input of an Element or Facility of the Bulk Electric System.
Great River Energy
Disagree
Without defining directive the SDT is leaving the industry in the same situation we are currently in. As discussed
in the response to Question #1 above, it is GRE’s opinion that the definition of Reliability Directive must be
developed and included in the discussion of this standard. The term directive should be as defined in Project
2006-06: A communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an actual or expected Emergency.. GRE believes it should
be left to the entity that needs the action to be taken to establish the need for three-part communications by
stating in the communication that they are issuing a directive. This would be a clear trigger and easily auditable
and measureable.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 does not use or define the term “directive” and now proposes the defined term “Operating
May 2, 2012
197
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 6 Comment
Communications” which would apply to any communication involving a change to, or maintenance of, the state, status, output, or input of an
Element or Facility of the Bulk Electric System. The SDT is aware the term “Reliability Directive” is being proposed under NERC Project 2006-06
Reliability Coordination.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
7. Requirement R6 of the draft COM-003-1 states, “Each Responsible Entity shall use the North Atlantic Treaty
Organization (NATO) phonetic alphabet as identified in Attachment 2-COM-003-1 when issuing directives,
notifications, directions, instructions, orders or other reliability related operating information that involves
alpha-numeric information during verbal Interoperability Communications.” Do you agree with this proposal?
If not, please explain in the comment area.
Summary Consideration:
Most stakeholders who responded to this question disagreed with the proposal. Many commenters indicated the use of a phonetic
alphabet is not necessary and should not be required, as it will not improve reliability of the BES and indicated that there are no
instances where the absence of its use has resulted in reliability problems. The SDT disagrees with this comment and believes that
enhanced clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
Commenters stated requiring strict adherence to and precise pronunciation of the NATO phonetic alphabet is overly prescriptive,
and the proposed standard should allow for other phonetic clarifiers where clarity on alpha-numeric information is necessary. The
SDT agrees, and has modified the requirement to allow use of “accurate alpha-numeric clarifiers," which could include alphanumeric clarifiers other than the NATO phonetic alphabet.
Commenters pointed out that the requirement is being applied too broadly (e.g. to notifications, directions, instructions, orders and
other reliability related operating information). The SDT agrees and has modified the proposed standard by restricting the
requirement's applicability only to verbal Operating Communication.
A few commenters showed concern over having operators potentially struggling to remember the NATO phonetic alphabet during
emergency situations, rather than focusing on the communication itself, in contradiction with the stated purpose of the standard.
The SDT disagrees and believes that adequate training, familiarity with and use of alpha-numeric clarifiers will eliminate struggles for
operators and avoid operating errors due to miscommunication.
Still other commenters stated this proposed requirement is a best practice. They suggest that the use of the NATO phonetic
alphabet should only be required when needed for clarity. The SDT believes the use of a phonetic alphabet during verbal real-time
communication between BES operating entities goes beyond a best practice and should be a mandatory requirement.
Organization
Yes or No
Bureau of
Agree
May 2, 2012
Question 7 Comment
199
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
Reclamation
Consumers Energy
Agree
ExxonMobil
Research and
Engineering
Agree
Kansas City Power &
Light
Agree
Old Dominion
Electric Cooperative
Agree
Oncor Electric
Delivery
Agree
PacifiCorp
Agree
PEF
Agree
Sunflower Electric
Power Corporation
Agree
Bonneville Power
Administration
Disagree
Orange and
Rockland Utilities,
Inc.
Disagree
American Electric
Power
Disagree
AEP does not believe that this should be a requirement. It is understood that three-part communications
represent best practices, but it is not necessary to mandate the NATO phonetic alphabet. We are not aware of an
instance where the use of “Ed” rather than “Echo” has resulted in a reliability compliance breakdown.
Response: The SDT thanks you for your comments.
The SDT agrees with your second comment, and has modified the requirement to allow for any accurate alpha-numeric clarifier.
May 2, 2012
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The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
Indiana Municipal
Power Agency
Disagree
An entity should not be required to use a specific phonetic alphabet. If a letter needs to be clarified, then boy, bob
or beta should be allowed to convey the letter "B". In an emergency, an entity wants its coordinators to be
concentrating on the situation and not worrying about using the p\roper phonetic alphabet word for the letter
"B".
Response: The SDT thanks you for your comments.
The SDT agrees with your comments, and has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in
verbal Operating Communications and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Transmission System
Operations
Disagree
As stated in Question #1, the definition of “Interoperability Communication” needs further clarification. Directives,
notifications, directions, instructions, orders, and other reliability operating information needs to be clearly
defined, including what it consists of and when it is to be utilized.
Response: The SDT thanks you for your comments.
The SDT has eliminated “Interoperability Communication” and is proposing the new term “Operations Communications.” “Operations
Communications” are communications instructing a change to, or maintenance of, the state, status, output, or input of an Element or Facility of the
Bulk Electric System. The use of a phonetic clarifier will be required during verbal “Operating Communications.”
NERC Staff
Disagree
As stated in response to Question 2, NERC staff agrees with the proposal, but would offer the following
modification in order to add clarity. We recommend that the phrase “when issuing directives, notifications,
directions, instructions, orders or other reliability related operating information that involves alpha-numeric
information during verbal Interoperability Communications” be replaced with “when verbal Operating
Communications with alpha-numeric information is involved.” This would require using the definition of
Operating Communications offered in the response to Question 1. This will hopefully eliminate the need to
further define what communication is or is not included in the phrase “directives, notifications, directions,
instructions, orders or other reliability related operating information.”
Response: The SDT thanks you for your comments.
The SDT has eliminated “Interoperability Communication” and is proposing the new term “Operations Communications.” “Operations
Communications” are communications instructing a change to, or maintenance of, the state, status, output, or input of an Element or Facility of the
May 2, 2012
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Bulk Electric System. The use of a phonetic clarifier will be required during verbal “Operating Communications.”
The SDT agrees with your second comment, and has modified the requirement. The new language is in Requirement R1 Part 1.2. “When
participating in verbal Operating Communications and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
British Columbia
Transmission
Corporation
Disagree
BCTC's position: R6 requiring the use of North American Treaty Organization (NATO) phonetic alphabet adds no
value and will only cause confusion. Presently an instruction would be issued as:”At Kelly Lake open 5CB4” R6 it
will now become: “At Kelly Lake open Fife Charlie Bravo Fow-er"
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
The SDT intends for R6 (new R1 Part 1.2 in the second draft of the standard) to apply to unique facility/element identifiers and not commonly used
acronyms such as “CB” for circuit breaker. If “5CBR” is the unique facility/element identifier, then it would apply.
New York State
Reliability Council
Disagree
Comments: While NYSRC understands the benefit of utilizing a phonetic alphabet, we question the designation of
a specific phonetic alphabet. This prescriptive requirement may result in absurd non-compliance reports, such as,
using “Dog” for “D” instead of “Delta”. R6 requires the use of the alphabet when issuing information, but not in
the repeat back step. This may be an oversight. Also Does the RC in its communication utilize the abbreviation for
the threat type, e.g. PSEA, or does the RC use the NATO-Alphabet? If NATO, then the example in Attachment 1
should state this need.
Response: The SDT thanks you for your comments.
The SDT agrees, and has modified the Requirement to allow for any accurate alpha numeric clarifier.
The SDT believes that the proposed new requirements in the second draft of the COM-003-01 standard address the concern mentioned in the
comment concerning use of the requirement only during the issuing and not the repeating back. The RC would only be required to communicate the
abbreviation of verbally conveyed alpha-numeric information using an accurate alpha numeric clarifier or the NATO alphabet if it was during verbal
“Operating Communications”. The SDT intends for new Requirement R1 Part 1.2 to apply to unique facility/element identifiers and not commonly
used acronyms.
Power South Energy
Disagree
Completely unnecessary to require each operator to learn and use the NATO alphabet for situations that may
occur on a very limited basis.
Response: The SDT thanks you for your comments.
May 2, 2012
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Question 7 Comment
The SDT has modified the requirement. The new language is in requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
Tri-State Generation
& Transmission
Assoc.
Disagree
Directive is not defined. This poses an undue burden on the operators, which does not improve the reliability of
the BES. NERC should only concern themselves with issues related to maintaining the reliability of the BES.
Response: The SDT thanks you for your comments.
The current draft version of COM-003-1 does not use or define the term “directive” that task is assigned to the RCSDT – Project 2006-06. See
Question 6.
Entergy Services
Disagree
Entergy has 2 concerns with this requirement as written.
First, the use of the NATO phonetic alphabet is overly prescriptive to convey alpha-numeric information. For
instance, if I use the word “baker” instead of “bravo” in my communications, I would have still successfully
communicated the letter “B” to the person receiving my communication. My communication may have supported
reliable interconnected operations. However, according to this requirement, I would still have violated the
standard.
Second, the requirement as written is very broad, applying not just to directives, but also to “notifications,
directions, instructions, orders and other reliability related operating information”. These terms are not defined,
so I would assume that this covers Reliability Directives, and everything else. If the industry supports using a
phonetic alphabet, it should be limited just to directives containing alpha-numeric information. Again, the
requirement to use the NATO phonetic alphabet imposes a significant operational burden, creates a human error
trap for operating personnel, and does not improve reliability. It should not be included in the new standard.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT also agrees with your second comment and has modified the proposed standard by restricting the requirement's applicability to only those
alpha numeric identifiers used during verbal “Operating Communications”.
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ERCOT ISO
Disagree
ERCOT ISO does not agree with this approach, which seems to be overly prescriptive (“directives, notifications,
directions, instructions, orders, or other reliability related information”), which goes beyond the purpose of
“during alerts and emergencies”. This is an administrative requirement that would increase communication timing
and possibly negatively affect reliability. If using a common language and three part communication for directives
is effective this is not required.
Response: The SDT thanks you for your comments.
The SDT agrees and has modified the proposed standard by restricting the requirement's applicability to only those alpha numeric identifiers used
during verbal “Operating Communications”.
The SDT believes that clarity for verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time communication
between BES operating entities.
Note that the scope of this standard is not limited to communications related to alerts and emergencies.
SERC OC&SOS
Standards Review
Group
Disagree
First, please note that “NATO” does not stand for North American Treaty Organization; it stands for North Atlantic
Treaty Organization. Use of the NATO phonetic alphabet should be considered a “best practice” and should not be
included as a requirement in a reliability standard. One failure, such as saying “Baker” instead of “Bravo”, results
in a severe violation without any impact on system reliability. This group is concerned that operating personnel
will be focused on using the correct word rather than managing the power system.
Response: The SDT thanks you for your comments.
The SDT agrees that NATO stands for “North Atlantic Treaty Organization” and that “American” was used in error.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
Transmission Owner
May 2, 2012
Disagree
FPL believes that though aspiring to use a single strict phonetic alphabet is important, it is more important to
ensure that ease of communication takes precedence especially under emergency conditions. As such, this
requirement should be written more as a best practice or guideline. FPL believes this requirement could be
improved by stating that under such emergency conditions, the NATO phonetic alphabet can be used as a baseline reference but that usage of ad-hoc phonetic alternatives that achieve the same real-time communication goal
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can also be used.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities during routine or emergency conditions.
Pepco Holdings, Inc.
- Affiliates
Disagree
Having system operators potentially struggle to remember the NATO phonetic alphabet during communications
rather than focus on the communication and managing the bulk electric system itself is in contradiction with the
purpose of the standard. Use of the NATO phonetic alphabet should be considered a “best practice” and should
not be included as a requirement in a reliability standard. One failure, such as saying “Baker” instead of “Bravo”,
results in a severe violation without any impact on system reliability.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that clarity for verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time communication
between BES operating entities
Florida Municipal
Power Agency
(FMPA) and some
members
Disagree
How strict are the NATO pronunciations? E.g., “Uniform” is designated as pronouncing the “i” as a long “ee”, most
people I know do not do that. Similarly, there are multiple pronunciations of “Quebec”, “Sierra”, “Victor”, “Three”,
“Four”, “Five”, and “Nine” to name a few, yet one pronunciation is specified. We presume that if the wrong
pronunciation is used in the current draft of the standard, there would be a violation, currently at a high risk factor
and high severity level, which seems rather severe. FMPA suggests that the SDT revisit this with an eye towards at
least not penalizing someone for saying “five” instead of “fife”, and possibly with an eye towards saying “‘F’ as in
‘frank’” is OK, rather than being strict with NATO nomenclature.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Sunflower Electric
May 2, 2012
Disagree
I don't feel we should use NATO phonetic alphabet. Use something in common use in the USA
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Power Corp.
Response: The SDT thanks you for your comments.
The NATO phonetic alphabet is commonly used in the US and Canada. Some examples are the military, police and fire protection, medical industry
and the air traffic control system. The BES, as in the previous examples, is a critical system requiring the same level of communication clarity.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Progress Energy
Carolina, Inc
Disagree
NATO stands for North Atlantic Treaty Organization. This proposed requirement is a best practice and does not
serve to increase the reliability of the BES.
Response: The SDT thanks you for your comments.
The SDT agrees that NATO stands for “North Atlantic Treaty Organization” and that “American” was used in error.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT disagrees with your second comment. The NATO phonetic alphabet is commonly used in the US and Canada. Some examples are the
military, police and fire protection, medical industry and the air traffic control system. The BES, as with the previous examples, is a critical system
requiring the same level of communication clarity. The use of the NATO alphabet provides this clarity which prevents miscommunication which
reduces the risk of a mishap.
NextEra Energy
Resources, LLC
Disagree
NextEra believes that though aspiring to use a single strict phonetic alphabet may be beneficial it is more
important to ensure that ease of communication takes precedent especially under emergency conditions. The
requirement for 3-part communication already ensures that understanding between two parties occurs.
Moreover, it is overly burdensome to require that the phonetic alphabet be used in all communications which
would include communications related to mundane interactions between interconnected parties and that might
broadly fit the mold of the “interoperability” definition but not truly require the formality or rigor commanded by
a phonetic approach.
Response: The SDT thanks you for your comments.
The second draft version of COM-003-1 proposes in Requirement R1 Part 1.2 to use an accurate alpha-numeric clarifier such as the NATO phonetic
alphabet during verbal Operating Communications when alpha-numeric identifiers are involved. Beyond that, its use to clarify confusion over a
communication, mundane or otherwise, is not discouraged but is not required.
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Pacific Northwest
Small Utilities
Comment Group
Agree
Question 7 Comment
No Comment
Response: The SDT acknowledges No Comment.
NorthWestern
Energy
Disagree
NorthWestern appreciates the opportunity to comment. The requirement, as drafted, appears to open the
possibility of sanctions for incorrect use of the NATO phonetic alphabet during any verbal communication between
entities. The use of the NATO phonetic alphabet would be difficult when performing local switching orders to field
personnel. NorthWestern suggests that the requirement be reworded to state that entities “shall use a phonetic
code (e.g., the NATO phonetic alphabet) when necessary, to verify accurate reception of alpha-numeric
information.”
Response: The SDT thanks you for your comments.
The SDT agrees and has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating
Communications and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Western Area Power
Administration
Disagree
Not everyone is familiar with the NATO phonetic alphabet, so it would be another thing for operators to have to
memorize or to always have in front of them to refer to.
Response: The SDT thanks you for your comments.
The SDT believes that operators will not have difficult problems adapting to the NATO alphabet. With proper training and familiarization it becomes
a natural part of an individual’s vocabulary. The SDT also agrees with overall industry comment and has modified the Requirement (R1 Part 1.2 in
the second draft of the standard) to require use of an accurate alpha-numeric clarifier such as the NATO phonetic alphabet during verbal Operating
Communications when alpha-numeric identifiers are involved.
ISO New England
Inc.
Disagree
Not only does this requirement attempt to determine HOW entities operate with their various footprints, it may
change the way many Markets are structured. What is the difference between using the word “Zebra” instead of
“Zulu” to signify the letter “Z”? And, why would this be enforceable? Perhaps this would be better served as a
guideline document rather than an enforceable Requirement. Also, many organizations may have established
communications protocols which are functioning properly and making a change may actually hinder reliable
operations by introducing unnecessary confusion.
Response: The SDT thanks you for your comments.
May 2, 2012
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Question 7 Comment
The SDT does not understand how this requirement would change market structure, please provide details for us to address.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
" So “Zebra” instead of “Zulu” to signify the letter “Z” would be acceptable, “Xerox” instead of “Zulu” to signify the letter “Z” would be non
compliant.
Northeast Utilities
Disagree
Not only does this requirement attempt to determine HOW entities operate with their various footprints, it may
change the way many Markets are structured. What is the difference between using the word “Zebra” instead of
“Zulu” to signify the letter “Z”? And, why would this be enforceable. Perhaps this should be a guideline document
rather than an enforceable Requirement. There is no reliability need for this Requirement.
Response: The SDT thanks you for your comments.
The SDT does not understand how this requirement would change market structure, please provide details for us to address.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“Zebra” instead of “Zulu” to signify the letter “Z” would be acceptable, “Xerox” instead of “Zulu” to signify the letter “Z” would be non compliant.
The SDT believes there is a critical need for this requirement. The eclectic pattern of communication protocols that exist and those that do not exist
across the BES is an ever present risk for miscommunication, which breeds mishaps.
Westar Energy
Disagree
One of the more common or ad-hoc phonetic alphabets which are easier to remember could be a better fit since
these communications happen infrequently. Having operators potentially struggle to remember the NATO
phonetic alphabet during communications rather than focus on the communication itself is in contradiction with
the stated purpose of the standard.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Ameren
Disagree
Requirement should be revised to say that Attachment 2 needs to be used when single alphabetic characters, or
when needed for clarity, are needed in communications. If we have a Bee Hollow-51 circuit, that is alpha-numeric
information. But we wouldn’t support that Bee Hollow needs to be spelled out as Bravo-Echo-Echo-space-Hotel
Response: The SDT thanks you for your comments.
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The SDT intends for R6 to apply to a unique Facility/Element identifier and not commonly used acronyms such as “CB” for circuit breaker; or names
such as “Bee Hollow”. In the case of this comment the identifier “Bee Hollow Five One” would meet the requirement.
Southern Company
Transmission
Disagree
Southern Company supports the SERC SOS comments. SERC SOS comments: Use of the NATO phonetic alphabet
should be considered a “best practice” and should not be included as a requirement in a reliability standard. One
failure, such as saying “Baker” instead of “Bravo”, results in a severe violation without any impact on system
reliability. This group is concerned that operating personnel will be focused on using the correct word rather than
managing the power system.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in
verbal Operating Communications and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Southern Company comments: This requirement should be removed from the standard. Requirement 5 requires
understanding by both parties during communication. Requirement 6 requires common identifiers which will
enhance the chances of both parties understanding communications. Although using the phonetic alphabet may
be necessary some times in order to gain understanding between two parties it should not be required. If both
parties understand A as well as they do Alpha the reliability of the system has not been affected. No entity should
be found in non-compliance of a Reliability Standard if reliability was not affected.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear
and effective real-time communication between BES operating entities.
Response: The SDT thanks you for your comments.
E.ON U.S. LLC
May 2, 2012
Disagree
The entire standard should only apply to emergency operations, not all communications. If it is the intent that the
requirements of this standard apply not only to control room operators but also field personnel (line crews,
substation crews, etc.) then E ON U.S. is not in favor of using the NATO phonetic alphabet. The confusion that this
change could create in real-time operations outweighs the BES reliability benefit. E ON U.S. suggests that if the
objective is to avoid confusion over similarly pronounced words, use of an ad-hoc phonetic alphabet would more
easily address the concern. E ON U.S. is also concerned that the attention paid to “how” orders are given and
acknowledged may well detract from “what” it is responsible entities are attempting to do. Are responsible
entities supposed to spell out each number and word using the phonetic alphabet? The drafting team should be
more specific as to what is meant by “alpha-numeric information.”
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Question 7 Comment
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities during routine and emergency operating conditions.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT intends for Requirement R1 Part 1.2 to apply to unique Facility/Element alpha-numeric (numbers and letter codes or designators)
identifiers and not commonly used acronyms such as “CB” for circuit breaker or names such as “Bee Hollow”. For example the identifier for Bee
Hollow 51A circuit would be “Bee Hollow Five One Alpha” circuit.
American Municipal
Power
Agree
The NATO Phonetic alphabet is easy to learn and use. Most people can learn it on their own much faster than it
will take the SDT to read all of the comments for COM-003.
Response: The SDT thanks you for your comments and your observation.
The Empire District
Electric Company
Disagree
The NATO phonetic alphabet is too descriptive as a requirement. A common phonetic alphabet where both parties
understand the communication should be a better requirement and left up to the parties in communication with
each other as common across the USA.
Response: The SDT thanks you for your comments.
The SDT disagrees that use of the NATO phonetic alphabet is too descriptive as a requirement, but has modified the requirement based on
stakeholder suggestions that other alpha-numeric identifiers should also be acceptable. The new language is in Requirement R1 Part 1.2. “When
participating in verbal Operating Communications and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the Requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate struggles for operators.
May 2, 2012
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Question 7 Comment
MRO MRO NERC
Standards Review
Subcommittee
Disagree
The required use of the phonetic alphabet should be documented in the Entities CPOP per our comments to
question #3. While this requirement may represent a good utility practice or even a best practice, it is not so
necessary to be enforceable through enforceable requirements.
All information passed by a NERC Certified System operator falls under the scope of Requirement 6: “directives,
notifications, directions, instructions, orders or other reliability related operating information”. Based on that
definition, all communication would fall under this Requirement.
The NATO phonetic alphabet does not allow for the use of numbers ten and beyond. An entity WOULD be found
non compliant for saying “open switch fourteen bravo”. We do not believe this is reasonable as it adds nothing to
the reliability of the BES is too prescriptive and all encompassing and could potentially confuse or slow down the
communication process.
We recommend that use of the NATO phonetic alphabet be included in the NERC operator certification training
program and removed from this standard .As we recommended above, the term “directive” should be replaced
with “Reliability Directive”.
Response: The SDT thanks you for your comments.
The SDT has elected to eliminate the requirement to have a CPOP based on Industry Comment.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities and warrants being an enforceable requirement.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Numbers over nine are referred to by each individual digit for example 14 = “one, four”; 2559 = “two, five, five, nine” when communicating a unique
alpha-numeric identifier. The SDT has modified the proposed standard by restricting the requirement's applicability only to verbal “Operating
Communications.”
The SDT respectfully considers your recommendation to remove this from the standard and include it in the NERC operator certification training
program but elects to keep this as a requirement because it enhances reliability by reducing human error. Its integration into the NERC operator
certification training program is a very good recommendation, but beyond the scope of the drafting team.
ATC and ITC
May 2, 2012
Disagree
The use of the phonetic alphabet should be documented in the Entities CPOP per our comments to question #3.
We do not agree that it needs to be included in Requirement 5 because it is too prescriptive and all encompassing
and could potentially confuse or slow down the communication process. As we recommended in question 6 the
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term “directive” should be replaced with “Reliability Directive”.
Response: The SDT thanks you for your comments.
The SDT has elected to eliminate the requirement to have a CPOP based on Industry Comment.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities. Many critical process industries utilize the NATO alphabet because it is effective in preventing
mishaps due to miscommunication. Some examples are the military, medical and air traffic fields. The SDT feels strongly that operation of the BES is
a similar critical process and should employ a proven communication protocol.
The SDT has modified the second draft of the COM-003 standard by restricting the requirement's applicability only to verbal “Operating
Communications”.
The RCSDT is developing the term “Reliability Directive” in project 2006-06. The terms, “directive” and “Reliability Directive” are not used in the
second draft of COM-003.
PPL
Disagree
The way this could be interpreted is that every type of communication between every applicable entity would
have to use the NATO phonetic alphabet. This would be impractical since many of the current communications do
not require this level of specificity.
Response: The SDT thanks you for your comments.
The SDT has required the use of the NATO Alphabet or an accurate alpha numeric clarifier to clarify alpha numeric identifiers during verbal
“Operating Communications” because operations on the BES do require this level of specificity.
Georgia
Transmission Corp
Disagree
This is an operational burden and could easily cause a violation by using a different common identifier. If used, it
should only apply to Reliability Directives.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The proposed standard is required during both emergency operating states and also normal operating states.
California
Independent System
Operator
May 2, 2012
Disagree
This requirement is a best practice. Maybe the standardized alpha-numeric communication is something that
companies should be required to train their personnel on, maybe it could even be a requirement of their
CharliePapaOscarPapa. As this requirement is literally written a system operator who used the word ‘cat’ instead
of the word ‘Charlie’ when giving a directive would violate a sanctionable standard with a VRF of ‘High’ and a VSL
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of ‘Severe’.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities
The “Charlie, Papa, Oscar, Papa” requirement has been eliminated.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT has modified the VRF and VSL to conform to NERC and FERC guidelines.
Puget Sound Energy
Disagree
This requirement is too burdensome when compared to its benefits. The proposed requirement covers many
different types of verbal communication and converts a useful communication protocol into mandatory
requirement, which carries with it large potential penalties. Under this requirement, an operator’s use of the
phrase “M as in Mary” instead of “M as in Mike” would be violation of NERC reliability standards. The
requirement for Three-Part Communications covers most of this ground in a much more useful fashion and
ensures parties understand the information. The use of this protocol is a matter that should be left for entities to
consider for inclusion in their CPOPs, but should not be a mandatory requirement to use the protocol. Further it is
again assumed that based on R1, this information is related to real time. As well further examples of what a real
time issuing of a "notification" is and what "other reliability related operation information would be needs to be
specified.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities. The implementation of the requirement should not be overly burdensome.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The requirement to have a CPOP has been eliminated.
With regard to the value of phonetic alphabet clarification, many critical process industries utilize the NATO alphabet because it is effective in
preventing mishaps due to miscommunication. Some examples are the military, medical and air traffic control fields. The SDT feels strongly that
operation of the BES is a similar critical process and should employ a proven communication protocol.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
NIPSCO
Disagree
This should not be a requirement, but could be a suggested option. If one were recorded using the wrong phonetic
would that be a compliance violation? This doesn't seem reasonable.
Response: The SDT thanks you for your comments.
If you use Baker instead of Bravo for “B” that is compliant. If you use Phase instead of Foxtrot for “F” you would be non compliant.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Manitoba Hydro
Disagree
To using NATO full time
1) Being trained or being familiar with NATO Phonetics is a great idea, but should only be implemented, in bad
communication connections, or upon request due to accents, quiet voice, fast talk, too loud, unusual request, etc.
2) Communication technology for the most part is exceptionally clear, and the regular use of NATO Phonetics
would be difficult to implement and time consuming to use. The RC and neighbouring entities are familiar with
common terminology between each other.
Response: The SDT thanks you for your comments.
1. The SDT believes that clarity around verbally conveyed alpha-numeric information during “Operating Communications” is critical for ensuring
clear and effective real-time communication among BES operating entities. The SDT would not discourage its use outside of “Operating
Communications” in the context of your comments.
2. Communication technology may be exceptionally clear for much of the time, but human factors and natural electromagnetic abnormalities do
occur on a frequent basis making it important to have structured and clear communication protocols to prevent miscommunication.
Xcel Energy
May 2, 2012
Disagree
Use of the NATO phonetic alphabet should be a best practice not a reliability requirement. We are not convinced
that there is any threat to reliability if someone were to use a different phonetic than what is indicated.
Additionally, we do not feel that it is necessary to use the phonetic alphabet unless there is an indication that the
initial communication has been misunderstood. If the drafting team feels this requirement should remain in the
standard, we feel it should be modified to address:
1) There should be an exception for approved acronyms, such as NERC, FERC, etc.,
The SDT intends for Requirement R1, Part 1.2 in the revised standard to apply to unique Facility/Element alphanumeric (numbers and letter codes or designators) identifiers and not commonly used acronyms such as “CB”
for circuit breaker; or names such as “Bee Hollow”.
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Organization
Yes or No
Question 7 Comment
2) it should only be required upon repeat-back, when the first communication was misunderstood, and
It will be required when alpha numeric identifiers are used only during verbal “Operating Communications.”
3) Any phonetic alphabet should be acceptable for use, such as military or police, not just NATO's.
The SDT has modified the requirement to allow the use of any phonetic alphabet. The new language is in
Requirement R1 Part 1.2. “When participating in verbal Operating Communications and using alpha-numeric
identifiers, use accurate alpha-numeric clarifiers.”
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators. The
military, medical and air traffic control fields utilize the NATO alphabet as a proven means of voice communication clarification.
PJM
Disagree
Use of the NATO phonetic alphabet should be considered a “best practice” and should not be included as a
requirement in a reliability standard. One failure, such as saying “Baker” instead of “Bravo”, results in a severe
violation without any impact on system reliability. This group is concerned that operating personnel will be
focused on using the correct word rather than managing the power system. Also, many organizations may have
established communications protocols which are functioning properly and making a change may actually hinder
reliable operations by introducing unnecessary confusion.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
The NATO alphabet is a proven means of voice communication clarification.
PJM SOS Comments
May 2, 2012
Disagree
Use of the NATO phonetic alphabet should be considered a “best practice” and should not be included as a
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Organization
Yes or No
Question 7 Comment
requirement in a reliability standard. One failure, such as saying “Baker” instead of “Bravo”, results in a severe
violation without any impact on system reliability. This group is concerned that operating personnel will be
focused on using the correct word rather than managing the power system. Also, many organizations may have
established communications protocols which are functioning properly and making a change may actually hinder
reliable operations by introducing unnecessary confusion.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
The NATO alphabet is a proven means of voice communication clarification.
Santee Cooper
Disagree
Use of the NATO phonetic alphabet should not be a requirement of this standard. This also adds a layer of
complexity to the system operator position that is not necessary.
Response: The SDT thanks you for your comments.
The SDT disagrees and believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
Electric Market
Policy
May 2, 2012
Disagree
Use of this adds a lot to verbal communication but has little value. Where either the issuing or receiving party is
unsure as to which letter was used, their choice of word to associate with the alphabet need not be dictated by a
specific phonetic alphabet. If I am unclear, whether I ask “did you say ‘F’ as in Frank or ‘F’ as in Foxtrot, it is my
belief that we will both know that I heard the letter F not the letter S. Using Frank instead of Foxtrot will result in a
violation of Requirement R6 which carries a High VRF and a Severe VSL; even though there would be no impact on
effective communication. There is no compelling reason to require every operator in North America to learn and
use the NATO phonetic alphabet. It would be overkill to do so, and it could create some really bizarre
conversations. For example, consider a TOP in the eastern time zone who calls his RC (also in the eastern time
zone) at 10:00 A.M.to confirm that a line that tripped earlier that morning will be ready to switch back in service at
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Organization
Yes or No
Question 7 Comment
10:35. Taken to the extreme, a strict interpretation of R6 and R4 (the CST requirement) would say that the TOP
operator would have to state the estimated time of restoration as “niner tree fife, Alpha Mike, Charlie Sierra
Tango”. There is no need for that.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT intends for Requirement R1, Part 1.2 in the revised standard to apply to unique Facility/Element alpha-numeric (numbers and letter codes
or designators) identifiers and not commonly used acronyms such as “CB” for circuit breaker; or names such as “Bee Hollow”. Since your example is
not a unique Facility/Element alpha-numeric identifier it would read as “0-9-3-5 Central Standard Time” You would not use am/pm as R3 (new
Requirement R1 Part 1.1.2) requires the 24 hour format.
Please note under proposed R3 (new requirement R1 Part 1.1.3) The SDT has offered an alternative to the single time zone.
National Grid
Disagree
Using the NATO phonetic alphabet is useful, but to what extent? Does it apply to facility identifications, key words,
or every letter of every word? Is it up to the judgment of the operators? If so how will compliance be monitored? If
during a communication, personnel used a term different than that in the NATO alphabet i.e. D as in Dog rather
than Delta however, the listener understood the message and the correct action was taken would there still be the
possibility of a compliance violation?
Response: The SDT thanks you for your comments.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
D as in “Dog” rather than “Delta” would be compliant; F as in “phase” rather than “Foxtrot” would be non compliant.
The revised requirement applies during verbal “Operating Communications”, when alpha-numeric information is involved.
NRECA RTF
Members
May 2, 2012
Disagree
We agree that using the NATO phonetic alphabet is a more accurate form of communication for issuing and
responding to a directive during verbal Interoperability Communications. However, other forms of phonetic
alphabet communications could be utilized to achieve the same results and entities should not be forced to use
only the NATO phonetic alphabet. As stated in question 6 we are concerned about the undefined term “directive”.
In addition to the NATO alphabet, did the drafting team consider including the 10-Code system many utilities use
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Yes or No
Question 7 Comment
for verbal communication (ex: 10-4)? If not, why not and if so, why not included?
Response: The SDT thanks you for your comments.
The SDT has eliminated “Interoperability Communication” and is proposing the new term “Operations Communications.” “Operations
Communications” are communications with the intent to change or maintain the state, status, output, or input of an Element or Facility of the Bulk
Electric System. The use of a phonetic clarifier will be required only during verbal “Operating Communications” that involve alpha-numeric
identifiers.
The SDT has modified the Requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes the ten code system is not appropriate for use with unique Facility/Element alpha numeric identifiers. The ten code system varies
over North America and may not exist in Canada. The NATO alphabet, as an example, is more universal, consistent and more applicable.
Duke Energy
Disagree
We believe that R6 should be deleted, because it is focused on the details of the “how” rather than the “what” in
communications. The key is accurate 3-part communications for “directives”, as required by R5. R6 is far too
broad in the communications that would be included. Also, we believe that there is no reasonable way to
implement, self-certify or audit compliance with this requirement.
Response: The SDT thanks you for your comments.
The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the standard
is more focused on “what” protocols to use in specific situations.
The SDT has modified the proposed standard by restricting the requirement's applicability only to verbal “Operating Communications” that involve
alpha-numeric identifiers.
The measure (now contained within M1 but previously M6) includes types of evidence that may be used to demonstrate compliance with this
requirement.
South Carolina
Electric and Gas
Disagree
We believe this should only be required when issuing Reliability Directives.
Response: The SDT thanks you for your comments.
The SDT has modified the proposed standard by restricting the requirement's applicability only to verbal “Operating Communications” which can
include normal, alert and emergency operating conditions and involve alpha-numeric identifiers.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
NYSEG
Disagree
Question 7 Comment
While it is perhaps a good practice to include the use of phonetics to avoid miscommunications, it should be left
up to each entity to determine the appropriateness of adopting such a practice (e.g., field switching, internal
instructions, etc.) and should not be included in the Requirement, especially if Interoperability is not further
clarified/defined.
Response: The SDT thanks you for your comments.
The SDT has eliminated “Interoperability Communication” and is proposing the new term “Operations Communications.” “Operations
Communications” are communications with the intent to change or maintain the state, status, output, or input of an Element or Facility of the Bulk
Electric System. The SDT has modified the proposed standard by restricting the requirement's applicability (Requirement R1, Part 1.2 in the revised
standard) only to verbal “Operating Communications” alpha-numeric identifiers.
Long Island Power
Authority
Disagree
While LIPA understands the benefit of utilizing a phonetic alphabet, we question the designation of a specific
phonetic alphabet. This prescriptive requirement may result in absurd non-compliance reports, such as, using
“Dog” for “D” instead of “Delta”. R6 requires the use of the alphabet when issuing information, but not in the
repeat back step. This may be an oversight. Also Does the RC in its communication utilize the abbreviation for the
threat type, e.g. PSEA, or does the RC use the NATO-Alphabet? If NATO, then the example in Attachment 1 should
state this need.
Response: The SDT thanks you for your comments.
The SDT has modified the requirement to allow for the "NATO phonetic alphabet or another “accurate alpha numeric clarifier.", so D as in “Dog”
rather than “Delta” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
The SDT intends for Requirement R1, Part 1.2 in the revised standard to apply to unique Facility and Element alpha numeric identifiers and not
commonly used acronyms such as “PSEA” for Physical Security Emergency Alert.
The SDT has modified the proposed standard by restricting Part 1.2 of the revised requirement's applicability only to verbal “Operating
Communications” that involve alpha-numeric identifiers.
We Energies
May 2, 2012
Disagree
While R6 could be recommended as a good utility practice when communicating Reliability Directives, it is not
appropriate to enforce it as a requirement for all communications. The focus of the standard should be on the
achievement of clear communications, with individual organizations retaining some freedom to implement
practices appropriate for their own unique situations. If Violation Severity Levels will be “high” as indicated in
Attachment 1-COM-003-1, then the standard must be much more specific as to what constitutes “directives,
notifications, directions, instructions, orders or other reliability operating information”. Assigning a high Violation
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
Severity Level to the failure to use a specific phonetic alphabet (NATO) instead of to a failure to use any phonetic
alphabet seems unreasonable and is likely to cause as much confusion as failing to use any sort of phonetic
pronunciation. If attachment 2 is utilized, it should only be required for situations where Attachment 1 applies. As
noted in question 2, R6 should not apply to a TSP or LSE.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric identification information is critical for ensuring clear and effective real-time
communication among BES operating entities and should be enforceable.
The SDT agrees with your concerns over applicable communications and has modified the proposed standard by restricting Part 1.2 of the revised
requirement's applicability only to verbal “Operating Communications” that involve alpha-numeric identifiers.
The new language is Requirement R1 Part 1.2. “When participating in verbal Operating Communications and using alpha-numeric identifiers, use
accurate alpha-numeric clarifiers.”
The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
Dynegy
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary to be used in
all verbal Interoperability Communications and is certainly not necessary to be included as an enforceable
Requirement. Imagine the situation in which an operator says “A as in apple” instead of using the NATO Alpha.
Even though the listener should clearly be able to discern the correct meaning, the speaker’s company could be
sanctioned even if the correct actions were taken as a result of the clear communication. There is no reliability
need for this Requirement.
Response: The SDT thanks you for your comments.
The SDT has modified the proposed standard by deleting the term Interoperability Communications and adding the new term - “Operating
Communications”.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
The SDT believes there is a reliability need for this requirement and that it will enhance reliability by clarifying communications to prevent
misunderstandings that could cause mishaps on the BES.
Hydro-Québec
May 2, 2012
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary to be used in
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Organization
Yes or No
TransEnergie
Question 7 Comment
all verbal Interoperability Communications, and is certainly not necessary to be included as an enforceable
Requirement.
For example, a situation in which an operator says “A” as in apple” instead of using the NATO Alpha. Even though
the listener should clearly be able to discern the correct meaning, the speaker’s company could be sanctioned
even if the correct actions were taken as a result of the clear communication. The objective of good
communications is to assure that the parties understand each other. The statement “... shall use the NATO
phonetic alphabet” doesn’t make sense for North America. If the Real-Time Operator states “breaker 6-North,”
under the NATO phonetic alphabet that would be unacceptable, because the operator did not use the appropriate
NATO term “breaker 6-November,” even thought the “N” on the one line diagram refers to the “North” breaker
and not the “South” breaker. Many organizations may have established communications protocols which are
working well. Making a change may actually hinder reliable operations by introducing unnecessary confusion and
questioning. Not only does this requirement attempt to determine HOW entities operate with their various
footprints, it may change the way many Markets are structured. What is the difference between using the word
“Zebra” instead of “Zulu” to signify the letter “Z”? And, why would this be enforceable. Perhaps this should be a
guideline document rather than an enforceable Requirement. There is no reliability need for this Requirement.
Furthermore, the use of three part communication eliminates the need for a mandatory use of NATO phonetic
alphabet.
Response: The SDT thanks you for your comments.
The SDT believes there is a reliability need for this requirement (Requirement R1, Part R1.2 in the revised standard) and that clarity around verbally
conveyed alpha-numeric information is critical for ensuring clear and effective real-time communication between BES operating entities.
The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications and using alpha-numeric identifiers, use
accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
With regard to “breaker 6-North,” under the NATO phonetic alphabet and the revision for a correct phonetic alphabet substitute that would be
acceptable as long as the operator used either NATO term “breaker 6-November,” or correct phonetic alphabet substitute “breaker 6-North.” If the
operator used the term “breaker 6-“N” (pronounced “en”) he or she would be non compliant.
Midwest ISO
Standards
Collaborators
May 2, 2012
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary to be used in
all verbal Interoperability Communications and is certainly not necessary to be included as an enforceable
Requirement. Imagine the situation in which an operator says “A as in apple” instead of using the NATO Alpha.
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Organization
Yes or No
Question 7 Comment
Even though the listener should clearly be able to discern the correct meaning, the speaker’s company could be
sanctioned even if the correct actions were taken as a result of the clear communication. There is no reliability
need for this Requirement.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
Northeast Power
Coordinating Council
Disagree
While this Requirement may represent a good utility practice in certain situations, it is not necessary to be used in
all verbal Interoperability Communications, and is certainly not necessary to be included as an enforceable
Requirement. For example, a situation in which an operator says “A as in apple” instead of using the NATO Alpha.
Even though the listener should clearly be able to discern the correct meaning, the speaker’s company could be
sanctioned even if the correct actions were taken as a result of the clear communication. The objective of good
communications is to assure that the parties understand each other. The statement “... shall use the NATO
phonetic alphabet” doesn’t make sense for North America. If the Real-Time Operator states “breaker 6-North,”
under the NATO phonetic alphabet that would be unacceptable, because the operator did not use the appropriate
NATO term “breaker 6-November,” even thought the “N” on the one line diagram refers to the “North” breaker
and not the “South” breaker. Many organizations may have established communications protocols which are
working well. Making a change may actually hinder reliable operations by introducing unnecessary confusion and
questioning.
Not only does this requirement attempt to determine HOW entities operate with their various footprints, it may
change the way many Markets are structured. What is the difference between using the word “Zebra” instead of
“Zulu” to signify the letter “Z”? And, why would this be enforceable. Perhaps this should be a guideline document
rather than an enforceable Requirement. There is no reliability need for this Requirement.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities and enhances reliability.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
With regard to “breaker 6-North,” under the NATO phonetic alphabet and the revision for a correct phonetic alphabet substitute that would be
acceptable as long as the operator used either NATO term “breaker 6-November,” or correct phonetic alphabet substitute “breaker 6-North.” If the
operator used the term “breaker 6-“N” (pronounced “en”) he or she would be non compliant.
Great River Energy
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so necessary to be
enforceable through enforceable requirements. The NATO phonetic alphabet does not allow for the use of
numbers ten and beyond. An entity WOULD be found non compliant for saying OPEN SWITCH FOURTEEN BRAVO.
GRE does not believe this is reasonable as it adds nothing to the reliability of the BES. It is too prescriptive and all
encompassing and could potentially confuse or slow down the communication process especially in an emergency
situation.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
If the nomenclature of the switch on the single line is “14B” the requirement would have it read as “One, Four Bravo.” The number “2347” would be
read as “Two, Three, Four, Seven” under R6 (new R1 Part 1.2).
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
Independent
Electricity System
Operator
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so necessary to be
enforceable through sanctionable requirements. Similar to R2, having to use the NATO phonetic alphabet is
overly prescriptive and forces system operators to learn and remember “languages” in addition to the power
system language. System operators should not be penalized for using some means other than the NATO phonetic
alphabet to communicate equally effectively. We see no short coming in operations that would require these
additional requirements and that the added complexity and additional training requirements may deteriorate
reliability.
Response: The SDT thanks you for your comments.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
IRC Standards
Review Committee
Disagree
While this requirement may represent a good utility practice or even a best practice, it is not so necessary to be
enforceable through enforceable requirements. Imagine the situation in which an operator says “A as in apple”
instead of using the NATO Alpha. Even though the listener should clearly be able to discern the correct meaning,
the speaker’s company could be sanctioned even if the correct actions were taken as a result of the clear
communication. Also, many organizations may have established communications protocols which are functioning
properly and making a change may actually hinder reliable operations by introducing unnecessary confusion.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication among BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
FirstEnergy
Disagree
While we agree that using the NATO phonetic alphabet may be a best practice, we feel that it is not practical to
regulate its use. This requirement is too prescriptive. The focus should be on the correct understanding of verbal
communication which will be accomplished via Three-party Communication, whether an entity uses NATO or "A as
in Apple, B as in Boy", this should not be codified within the standard. Substantiating compliance with this
requirement is not reasonable to expect, practical to prove, nor does it produce an improvement in reliability.
Response: The SDT thanks you for your comments.
The SDT believes that clarity around verbally conveyed alpha-numeric information is critical for ensuring clear and effective real-time
communication between BES operating entities.
The SDT has modified the requirement. The new language is in Requirement R1 Part 1.2. “When participating in verbal Operating Communications
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 7 Comment
and using alpha-numeric identifiers, use accurate alpha-numeric clarifiers.”
“A as in apple” instead of using the NATO “Alpha” would be compliant; F as in “Phase” rather than “Foxtrot” would be non compliant.
The SDT believes that adequate training, familiarity with and use of the phonetic alphabet will avoid and eliminate confusion among operators.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
8. Requirement R7 of the draft COM-003-1 states, “Each Responsible Entity shall use pre-determined, mutually
agreed upon line and equipment identifiers during for all verbal and written Interoperability Communications.”
Do you agree with this proposal? If not, please explain in the comment area.
Summary Consideration:
Most stakeholders who responded to this comment disagreed with the proposal.
Many commenters said the terms “. . . pre-determined, mutually agreed upon . . . ” are confusing and difficult to measure. The SDT
agrees and modified the requirement to remove the term “mutually agreed upon”.
Commenters indicated a general consensus for the mandatory use of line and equipment identifiers applying only to interface
Elements or Facilities, not Elements or Facilities internal to the footprint of the entity. The SDT agreed, and modified the standard to
apply only to interface Elements and Facilities.
There were additional comments that uniform and mutually agreed line and equipment identifiers should not be mandated so long
as the identifiers are pre-determined. The SDT agrees documentation of mutual agreement is not necessary, so long as the
identifiers are pre-determined, understood and used during Operating Communications. The SDT has modified the requirement to
require use of the name specified by the owner(s) of the Transmission interface Element/Facility when referring to that
Element/Facility.
Many commenters indicated Requirement R7 should not have been applicable to TSPs and LSEs. The SDT agrees, and has removed
TSPs and LSEs from the standard to be consistent with the approved SAR.
Additional commenters indicated the word “equipment” as used in Requirement R7 was too broad. The standard has been modified
to use the defined terms “Element” and “Facility” instead.
Other commenters indicated Requirement R7 addressed a planning function already included in TOP-002, and should not be
included in COM-003. While the SDT agrees that TOP-002-2a R18 is a planning function, the team believes communications between
entities would be improved when use of pre-determined identifiers is required for interface Elements and Facilities. The SDT
proposes the concept of R7 be retained and transferred to R1 Part 1.1.4.
Some additional comments were received indicating the previously posted standard was too prescriptive in specifying “how” to
communicate, instead of “what.” The SDT proposes that the second draft of COM-003 provides identifies “what” communications
protocols to use and when to use them.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Some commenters also indicated the proposed standard was unnecessary and would distract operators from reliably controlling the
system. The SDT disagreed based on Blackout Task Force Report recommendation 26, which calls for tightening communication to
improve reliability.
Question 8 mis-states R7 in that it inserts the word “all” in the question and it was not in R7. The performance that was specified in
Requirement R7 in the initial draft of COM-003 has been modified so it is more narrowly focused and allows greater flexibility in
meeting the reliability objective. See Requirement R1, Part 1.1.4 in the second draft of COM-003:
R1.
Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator and Distribution
Provider shall use the following communications protocols:: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations ]
1.1.
When participating in oral or written Operating Communications:
1.1.1.
Use the English language when communicating between functional entities, unless another language is
mandated by law or regulation.
1.1.2.
Use the 24-hour clock format when referring to clock times.
1.1.3.
When communicating with one or more entities in different time zones, include the time, local time
zone and indicate whether time is daylight saving time or standard time.
1.1.4.
When referring to a Transmission interface Element or a Transmission interface Facility, use the name
specified by the owner(s) for that Transmission interface Element or Transmission interface Facility. .
Organization
Yes or No
British Columbia
Transmission
Corporation
Agree
Bureau of
Reclamation
Agree
ExxonMobil
Research and
Engineering
Agree
Georgia
Agree
May 2, 2012
Question 8 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
Transmission Corp
Hydro-Quebec
TransEnergie
Agree
Northeast Power
Coordinating Council
Agree
Northeast Utilities
Agree
Old Dominion
Electric Cooperative
Agree
Oncor Electric
Delivery
Agree
Orange and
Rockland Utilities,
Inc.
Agree
PacifiCorp
Agree
PEF
Agree
PowerSouth Energy
Agree
South Carolina
Electric and Gas
Agree
Sunflower Electric
Power Corp.
Agree
Sunflower Electric
Power Corporation
Agree
Transmission System
Operations
Agree
May 2, 2012
228
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Westar Energy
Agree
Western Area Power
Administration
Agree
Progress Energy
Carolina, Inc
Disagree
American Electric
Power
Disagree
Question 8 Comment
AEP does not believe it is appropriate for the standard to have been edited to remove the clarification that
neighboring BAs use uniform line identifiers when communicating information about their lines and to add the
addition requirement of using pre-determined “equipment” identifiers.
Response: The SDT thanks you for your comments. The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use
of the name specified by the owner(s) of a Transmission interface Element/Facility, when referring to that Element/Facility. The term “interface” is
used instead of neighboring for greater clarity.
FirstEnergy
Disagree
Although we agree with moving this current TOP-002 R18 requirement to this standard, we question the use of
the phrase "mutually agreed upon". It is not clear how the line and equipment identifiers will be mutually agreed
upon and how this will be measured. We suggest using similar wording from the current TOP-002 R18 and reword
COM-003-1 R7 as follows: "Each Reliability Coordinator, Balancing Authority, Transmission Owner, Transmission
Operator, Generator Operator, Transmission Service Provider, Load Serving Entity and Distribution Provider shall
use uniform line and equipment identifiers for verbal and written communications."
Response: The SDT thanks you for your comments.
The SDT modified the requirement to remove the term “mutually agreed upon”. The SDT developed Requirement R1 Part 1.1.4 in the second draft
of the standard to require use of the name specified by the owner(s) of a Transmission interface Element/Facility, when referring to that
Element/Facility during verbal and written Operating Communications.
Puget Sound Energy
May 2, 2012
Disagree
As discussed in Question 2, Requirement 18 should be removed from TOP-002-2 (or any successor standard) upon
adoption of this standard if this requirement is included in this standard. Further the term mutually agreed
implies that a discussion has occurred prior to the need to verbalize or write these types of communications. The
additional specificity of "pre-determined" is duplicative or leads one to think there is formal guidance as to what
the "identifier" should be. Remove "pre-determined". It also begs the question of timeframe which could bring
interpretation issues during an audit.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
Response: The SDT thanks you for your comments.
The drafting team asserts that communications between entities would be tightened when use of pre-determined identifiers are required for
interface Elements/Facilities. The SDT proposes for R7 (R1 Part 1.1.4 in the second draft of this standard) to remain on its own merit. The SDT
modified the requirement to remove the term “mutually agreed upon”.
The SDT modified the requirement so that during oral and written Operating Communications entities must use the name specified by the owner(s)
of a Transmission interface Element/Facility when referring to that Element/Facility.
Bonneville Power
Administration
Disagree
BPA Would like further clarification about what is meant by “pre-determined, mutually agreed upon line and
equipment identifiers”. Is it a specified format no matter which part of the system is being used, or is it only for
115 kV and above as it applies to LSE’s and TSP’s. If it only refers to Transmission equipment above 115 kV, then
BPA would likely agree.
Response: The SDT thanks you for your comments.
The SDT modified the requirement to remove the term “mutually agreed upon”. The SDT developed Requirement R1 Part 1.1.4 in the second draft
of the standard to require use of the name specified by the owner(s) of a Transmission interface Element/Facility, when referring to that
Element/Facility. The new term “Operating Communications” applies when communications involve actions relative to Elements or Facilities of the
Bulk Electric System.
Ameren
Agree
But how does CMEP process check this “mutually agreed”. Much more work needs to be done with this
requirement and measures to address this.
Response: The SDT thanks you for your comments.
The SDT modified the requirement to remove the term “mutually agreed upon”.
California
Independent System
Operator
Disagree
CAISO Comments; This Requirement is problematic as it doesn’t actually steer towards standardization. It
mandates that companies have potentially scores of agreements agreeing on terms with each party it interacts
with, all of which may be different. It ensures the system operator will spend more time ensuring terminology is
correct for a given inter-company communication and once again, less time actually reliably operating the system.
Standardization can only occur in a meaningful manner at very minimum, the interconnection level. Also the
language in the VSL section uses “mutually understood”, which the CAISO supports as opposed to the
requirement and measure use “mutually agreed upon”. Mutually agreed upon is overly prescriptive.
Response: The SDT thanks you for your comments.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
The SDT does not agree there will more time spent ensuring terminology is correct for a given inter-company communication and less time actually
reliably operating the system.
The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use of the name specified by the owner(s) of a
Transmission interface Element/Facility, when referring to that Element/Facility. The SDT modified the requirement and VSLs to be consistent with
each other.
The SDT modified the requirement to remove the term “mutually agreed upon” which should address your concern on multiple agreements.
NYSEG
Agree
COM-003-1 R7 is more clearly defined than TOP-002 RI8 in that R7 and associated M7 speak only to written and
verbal Interoperability Communication, where TOP-002 R18 and M10 dictate a more extensive use of the
identifier. The adoption of a more narrow purpose is preferred.
Response: The SDT thanks you for your comments.
New York State
Reliability Council
Agree
Comments: NYSRC notes that R7 in the draft Standard does not match R2 in this question. Specifically the word
ALL is not in the Standard.
Response: The SDT thanks you for your comments. The SDT appreciates the observation and the word “all” is not in the requirement. It should
not have been in the question.
Duke Energy
Disagree
Delete this requirement. See our response to Question #2 above.
Response: The SDT thanks you for your comments. Please see the response to Question #2.
ERCOT ISO
Disagree
Does the phrase ‘mutually agreed upon line and equipment identifiers’ mean that identifiers do not have to be
identical, but that all parties understand the equipment discussed? If this is the general understanding, then no
further comment, otherwise, please clarify. Although the related bullet item in the Background Information
section describes that they do not have to be identical, many auditors many only look at the requirement
language
Response: The SDT thanks you for your comments.
The SDT modified the requirement to remove the term “mutually agreed upon”.
The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use of the name specified by the owner(s) of a
Transmission interface Element/Facility, when referring to that Element/Facility. The SDT would expect a single pre-determined name for each
interface Element/Facility to reduce the potential for confusion among operators.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Pacific Northwest
Small Utilities
Comment Group
Disagree
Question 8 Comment
DPs and LSEs are typically users, not owners or operators of interconnected BES equipment per the registry
criteria. DPs and LSEs should be removed from this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including DPs and LSEs that do not own or operate facilities that are a part of
the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR. However, the SDT
believes that DPs carry out actions related to the reliability of the Bulk Electric System such as voltage reduction and load shedding. Several existing
standards contain requirements concerning operating communications that TSPs, DPs and LSEs must presently comply with that would be governed
by the protocols of COM-003-1. It should be noted that the requirements of COM-003-1 are only applicable to “Operating Communications.” To the
extent that these entities do not operate or do not take actions that change or maintain the state, status, output, or input of an Element or Facility
of the Bulk Electric System, COM-003-1 would not apply.
MRO NERC
Standards Review
Subcommittee
Disagree
Field personnel may not have access to the predetermined agreed to line and equipment identifiers. Requiring
universal use of these identifiers could lead to confusion with field personnel within and between companies.
This could lead to a decrease in the reliability and safety of the BES.As written R7 is expanding the requirement
for agreed upon identifiers. We believe it is not necessary or required to have agreed upon equipment identifiers
between companies as long as the line identifiers have been agreed upon.TOP-002 R18 states that BA, TOP, GOP
TSP and LSE shall use uniform line identifiers when referring to transmission facilities of an interconnected
network. COM-003-1, R7 states that each RC, BA, TO, TOP, GOP, TSP, LSE and DP shall use pre-determined,
mutually agreed upon line and equipment identifiers for verbal and written Interoperability Communications.
TOP-002 allowed the TOP to communicate what the line identifiers were via a list and use during
communications. The new requirement implies that the parties must agree upon the line identifiers and that
agreement must be documented. We believe the requirement should require the exchange of line identifiers but
not impose that they be mutually agreed upon.
Response: The SDT thanks you for your comments.
The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use of the name specified by the owner(s) of a
Transmission interface Element/Facility, when referring to that Element/Facility.
The new term “Operating Communications” applies when communications involve actions relative to Elements or Facilities of the Bulk Electric
System.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
The SDT modified the requirement to remove the term “mutually agreed upon”.
Florida Municipal
Power Agency
(FMPA) and some
members
Agree
For clarity, a NERC Glossary defined term is more appropriate than “line or equipment” identifiers, such as
“Facility” or “Element” identifiers’ VRF of “High” is not appropriate. Note that TOP-002-2, R18, which this
requirement retires, was “Medium”.
Response: The SDT thanks you for your comments. The SDT changed “equipment” to Element or Facility.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The SDT believes the new assignments (Medium VRF
for each of the requirements in the second draft of the standard) more accurately classify the VRFs assigned to the Requirements in COM-003-1.
Transmission Owner
Disagree
FPL believes that R7 should be withdrawn as it repeats TOP-002 R18 requirements. Please refer to comments on
Q3.
Response: The SDT thanks you for your comments.
SDT feels that this requirement is appropriate under COM-003. The use of the names specified by the owner(s) of Transmission interface Elements
and Transmission interface Facilities during oral and written Operating Communications supports the purpose of COM-003 by preventing
miscommunication.
Please see response to Q3.
American Municipal
Power
Agree
How many substations have the same name?
Unique identifiers easily and inexpensively eliminate confusion and errors.
Response: The SDT thanks you for your comments.
The Empire District
Electric Company
Disagree
I would suggest a more efficient method of designating common pre-determined line and equipment identifiers
through the Reliability Coordinator. As similar to the response earlier. A definition of "Equipment" is needed as
well.
Response: The SDT thanks you for your comments.
The SDT believes your recommendation has merit but may be viewed by some stakeholders as overly prescriptive.
The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use of the name specified by the owner(s) of a
Transmission interface Element/Facility, when referring to that Element/Facility.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
E.ON U.S. LLC
Disagree
Question 8 Comment
In the absence of evidence that the lack of common identifiers is an imminent and continuing risk to BES
reliability, it does not make sense to have operators addressing urgent, real-time situations that bear significant
penalty risk should they refer to a BES element by something other than the common identifier. The operator
focus at such times should be on resolving the situation not avoiding penalties over nomenclature. Is it the intent
of the requirement that the common identifiers be the same for all neighboring parties, all of whom must “agree”
to the identification? If not, then an element might be referred to by one identifier with Party A, another with
Party B, and so on, which might well defeat the purpose of the requirement. If it is required that there be a single
identifier, then all neighbors would have to agree upon the identifier constrained as each may be by, for example,
the formatting limitation of their respective SCADA/EMS systems. Cost to modify software to accommodate
common identifiers could be significant and NERC should weigh these costs and the aforementioned operational
risks against the perceived incremental improvements to the BES reliability.
Response: The SDT thanks you for your comments.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as an
acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during alerts and
emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditions.”
SDT feels that the revised requirement (Requirement R1, Part 1.1.4 in the second draft) is appropriate under COM-003 as the use of identifiers only
for interface Elements/Facilities during oral and written Operating Communications supports the purpose of COM-003. A clear knowledge of Facility
and Element nomenclature at interface interconnections can only strengthen operator performance through understanding how operating system
anomalies could impact their system. It will and has confused operators when they are not familiar with their neighbor’s system and are not
prepared to take action to mitigate the disturbance. The SDT would argue that if the operator is not familiar with his or her neighboring system’s
Elements and Facilities those operators will likely take even more time to attempt to learn in the “heat of battle.”
The SDT disagrees that the cost to modify software would be significant as it would be limited to the interface Elements/Facilities as stated in R1
Part 1.1.4 of the second draft of the standard.
Kansas City Power &
Light
Disagree
Including “equipment” is too broad. This could mean anything and should be limited to transmission devices that
could affect the reliable operation of the bulk electric system.
Response: The SDT thanks you for your comments. The SDT modified the requirement so that entities must use the names specified by the owner(s)
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
of Transmission interface Elements and Transmission interface Facilities when referring to those Elements and Facilities.
Long Island Power
Authority
Agree
LIPA notes that R7 in the draft Standard does not match R2 in this question. Specifically the word ALL is not in the
Standard.
Response: The SDT thanks you for your comments. The SDT appreciates the observation and the word “all” is not in the requirement. It should not
have been in the question.
Manitoba Hydro
Disagree
Move this new requirement R1.3 in COM-002-2.This is similar to Question 4 and should be treated in the same
way: (This requirement is moved from TOP-002-2 R18)
1)COM-003-1 R7 “Pre-determined, mutually agreed upon line and equipment identifiers” are all planned
definitions.
2)COM-003-1 purpose is to “convey information effectively” meaning the use of English, NATO, three-part
communication, 24 time format are all verbal aspects to accomplish this purpose and not suited to predetermined or planned items.a.COM-003-1 R7 appears more appropriate and relevant placed in COM-002-2.
COM-002-2’s Purpose is “capabilities for addressing real time emergencies and to ensure communications by
personnel are effective”.
3)Placing “Pre-determined, mutually agreed upon line and equipment identifiers” in COM-002-2 after R1.1 as
R1.3 appears to have more of a chronological approach.
i. R1.1 states “conditions that could threaten”
ii. R1.2 use “pre defined system conditions”
iii. R1.3 use “pre determined equipment identifiers
”Conclusion: Remove COM-003-1 R7 and replace in COM-002-2 as R1.3
Response: The SDT thanks you for your comments.
SDT respectfully disagrees with shifting what is now Requirement R1, Part 1.1.4 in the second draft of COM-003 to COM-002-2 and feels that
Requirement R1, Part 1.1.4 is appropriate under COM-003-1 as the use of pre-determined identifiers only for interface Elements/Facilities during
oral and written Operating Communications supports the purpose of COM-003-1.
NERC Staff
May 2, 2012
Disagree
NERC staff is unaware of any instance where not having a mutually agreed upon nomenclature has led to an
adverse reliability event. Rather than requiring a national database for all line and equipment identifiers, it
appears that restricting the list to jointly-owned facilities and tie-line would accomplish the team’s goal. We
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
recommend that the phrase “Interoperability Communications” be replaced with “Operating Communications
involving jointly-owned Facilities and tie lines.”
Response: The SDT thanks you for your comments.
The requirement does not require a national database. The SDT modified the requirement to use pre-determined identifiers only for interface
Elements/Facilities during oral and written Operating Communications. The new term “Operating Communications” applies to Element or Facilities
of the Bulk Electric System.
The SDT modified the requirement to remove the term “mutually agreed upon”.
NextEra Energy
Resources, LLC
Disagree
NextEra believes that R7 should be withdrawn as it repeats TOP-002 R18 requirements. Please refer to comments
on Q3.
Response: The SDT thanks you for your comments.
SDT feels that this requirement is appropriate in COM-003 as the use of identifiers only for interface Elements/Facilities during oral and written
Operating Communications supports the purpose of COM-003.
Please see the response to Q3 comments.
IRC Standards
Review Committee
Disagree
Please confirm our understanding of this requirement. We believe that the SDT intends for the requirement to
compel all companies to use the same name for all facilities. If this is the intention, we disagree with the
requirement. This may represent a good utility practice but it is not necessary to be a requirement. The key
question is: “Do the companies’ personnel understand one another?” If I know that my company refers to a tieline as Alpha and my neighboring company calls it Beta, I know what he means when communicating to me. That
is all that matters.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
PJM
Disagree
May 2, 2012
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended
that neighboring Balancing Authorities use uniform line identifiers when communicating information about their
tie lines. This requirement drops that clarification and introduces the additional requirement to use predetermined “equipment” identifiers. Having to mutually agree in advance on identifiers for every switch &
transformer is another example of a prescriptive requirement whose violation will not affect system reliability,
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
yet will expose entities to large fines. The key question is: “Do the companies’ personnel understand one
another?”
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT removed the term “mutually agreed upon”.
The SDT would respectfully answer your last question “no, not always” and to create a protocol to address that issue is proper.
PJM SOS Comments
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended
that neighboring Balancing Authorities use uniform line identifiers when communicating information about their
tie lines. This requirement drops that clarification and introduces the additional requirement to use predetermined “equipment” identifiers. Having to mutually agree in advance on identifiers for every switch &
transformer is another example of a prescriptive requirement whose violation will not affect system reliability,
yet will expose entities to large fines. The key question is: “Do the companies’ personnel understand one
another?”
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT modified the requirement to remove the term “mutually agreed upon”.
The SDT would respectfully answer your last question “no, not always” and to create a protocol to address that issue is proper.
PPL
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended
that neighboring Balancing Authorities use uniform line identifiers when communicating information about their
tie lines. This requirement drops that clarification and introduces the additional requirement to use predetermined “equipment” identifiers. Having to mutually agree in advance on identifiers for every switch &
transformer is another example of a prescriptive requirement whose violation will not affect system reliability,
yet will expose entities to large fines.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
Transmission interface Facilities when referring to those Elements and Facilities. The SDT modified the requirement to remove the term “mutually
agreed upon”.
SERC OC&SOS
Standards Review
Group
Disagree
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended
that neighboring Balancing Authorities use uniform line identifiers when communicating information about their
tie lines. This requirement drops that clarification and introduces the additional requirement to use predetermined “equipment” identifiers. Having to mutually agree in advance on identifiers for every switch &
transformer is another example of a prescriptive requirement whose violation will not affect system reliability,
yet will expose entities to large fines.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities. The SDT modified the requirement to remove the term “mutually
agreed upon”.
Great River Energy
Disagree
See comments for Question 2
Response: The SDT thanks you for your comments.
Please see response to comments for Q2.
Santee Cooper
Disagree
See previous comment on Question 2. In addition the use of the words “equipment identifiers” could be
interpreted to include all pieces of equipment within a line.
Response: The SDT thanks you for your comments.
Please see response to comments for Q2.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
Southern Company
Transmission
May 2, 2012
Disagree
Southern Company supports the SERC SOS comments.
SERC SOS comments:
Requirement R7 in draft COM-003-1 came from TOP-002-2, Requirement R18. The original requirement intended
that neighboring Balancing Authorities use uniform line identifiers when communicating information about their
tie lines. This requirement drops that clarification and introduces the additional requirement to use pre238
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
determined “equipment” identifiers. Having to mutually agree in advance on identifiers for every switch &
transformer is another example of a prescriptive requirement whose violation will not affect system reliability,
yet will expose entities to large fines.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT modified the requirement to remove the term “mutually agreed upon”.
PSEG Companies
Disagree
The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System Operations
Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT modified the requirement to remove the term “mutually agreed upon”.
Entergy Services
Disagree
The requirement as it was written in TOP-002-2 pertained to communication between neighbors for shared lines
and facilities. That intent has been lost in this version of the requirement. Also a term “equipment identifiers”
has been added, but it is not clear what additional equipment is covered by this requirement, or what reliability
concern is being addressed by these changes. Entergy recommends that this requirement be changed to be
similar to the language that exists in TOP-002-2 R18 “Neighboring Balancing Authorities, Transmission Operators,
Generator Operators, Transmission Service Providers and Load Serving Entities shall use pre-determined mutually
agreed upon line identifiers when referring to transmission facilities of an interconnected network.”
Response: The SDT thanks you for your comments.
The SDT agrees and has modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements
and Transmission interface Facilities when referring to those Elements and Facilities.
The new term “Operating Communications” applies when communications involve actions relative to Elements or Facilities of the Bulk Electric
System.
National Grid
May 2, 2012
Disagree
The way this and TOP-002 R18 requirements are written they could be interpreted to mean that the line
identifiers have to be unique. The requirement should be written similar to the bullet on page 7 of the comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
form also listed below.”TOP-002 R18. Neighboring Balancing Authorities, Transmission Operators, Generator
Operators, Transmission Service Providers and Load Serving Entities shall use uniform line identifiers when
referring to transmission facilities of an interconnected network.””Pre-determined Line and Equipment
Identifiers: COM-003-1 requires the use of predetermined line and equipment identifiers in Requirement R7
however the Requirement does not stipulate a single/unique identifier as long as all parties mutually agree on the
identifier for the line or equipment. The mutual agreement shall be reached in advance of the use of the
identifiers as described in the functional entity’s CPOP”
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT modified the requirement to remove the term “mutually agreed upon”.
In the revised standard the requirement to have a CPOP has been eliminated.
Tri-State Generation
& Transmission
Assoc.
Disagree
This is not NERC’s responsibility to define. There are too many lines and too much equipment to identify each as
a NERC definition. Definitions are already agreed upon between operating entities.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The new term “Operating Communications” applies to Element or Facilities of the Bulk Electric System. The new term “Operating Communications”
applies when communications involve actions relative to Elements or Facilities of the Bulk Electric System. It will be the owner’s responsibility to
define names for its interface Elements/Facilities.
Dynegy
Disagree
This may represent a good utility practice but it is not necessary to be included as a Requirement. The key
question is: “Do the companies’ personnel understand one another?” If I know that my company refers to a tieline as Alpha and my neighboring company calls it Beta, I know what he means when communicating to me. That
is all that matters. This is a “how” based Requirement that should be eliminated.
Response: The SDT thanks you for your comments.
The SDT would respectfully answer your question “no, not always” and to create a protocol to address that issue is proper.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
SDT feels that this requirement is appropriate in COM-003 as the use of pre-determined identifiers only for interface Elements/Facilities during oral
and written Operating Communications supports the purpose of COM-003. The SDT is proposing a single predetermined name to reduce the
potential for confusion. The SDT developed Requirement R1 Part 1.1.4 in the second draft of the standard to require use of the name specified by
the owner(s) of a Transmission interface Element/Facility, when referring to that Element/Facility.
Independent
Electricity System
Operator
Disagree
This may represent a good utility practice but it is not necessary to be a requirement. The key is whether or not
operation personnel understand one another. Similar comments as in Q4 and Q7 also apply here.
Response: The SDT thanks you for your comments.
The Blackout Report Recommendation #26 states communication protocols should be tightened, “especially” those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as an
acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during alerts and
emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditions.”
Please see response to comments for Q4 and Q7.
Midwest ISO
Standards
Collaborators
Disagree
This may represent a good utility practice but it is not necessary to be included as a Requirement. The key
question is: “Do the companies’ personnel understand one another?” If I know that my company refers to a tieline as Alpha and my neighboring company calls it Beta, I know what he means when communicating to me. That
is all that matters. This is a “how” based Requirement that should be eliminated.
Response: The SDT thanks you for your comments.
The SDT would respectfully answer your question “no, not always” and to create a protocol to address that issue is proper.
SDT feels that this requirement is appropriate in COM-003 as the use of pre-determined names only for interface Elements/Facilities during oral and
written Operating Communications supports the purpose of COM-003. The SDT is proposing a single predetermined identifier to reduce the
potential for confusion.
NIPSCO
Disagree
This question includes a mis-statement in quotes. This is not what the requirement says. Furthermore, the word
"Neighboring" was removed from the TOP-002 R18 which changes the meaning and intent of the requirement.
Why not bring in R18 verbatim?
Response: The SDT thanks you for your comments.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
The SDT appreciates the observation and the word “all” is not in the requirement. It should not have been in the question.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities. The SDT decided to leave R18 in TOP-002 because it represents a
planning function. Requirement R7 will remain in the second draft of COM 003 as Requirement R1, Part 1.1.4, specifying when to use those
identifiers.
Pepco Holdings, Inc.
- Affiliates
Disagree
This requirement came from TOP-002 R18 and is fundamentally different from the new proposed requirement in
COM-003-1 R7. TOP-002 R18 states that the BA, TOP, GO, LSE and TSP shall use uniform line identifiers when
referring to transmission facilities of an interconnected network. The requirement in COM-003-1 R7 introduces an
additional requirement to use pre-determined “equipment” identifiers is another example of a prescriptive
requirement that will not impact bulk electric system reliability and will expose entities to large fines. PHI believes
the TOP-002 R18 could be included in COM-003-1 but included as defined in TOP-002 R18.
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities. The SDT is proposing a single predetermined identifier established
by the owner of the Element/Facility to reduce the potential for confusion.
The SDT decided to leave R18 in TOP-002 because it represents a planning function. Requirement R7 will remain in the second draft of COM 003 as
Requirement R1, Part 1.1.4, specifying when to use those identifiers.
Consumers Energy
Disagree
This requirement is better served under the TOP Standards. The TOP standards already require this (TOP-002-2
R18), and the requirement should not be duplicated.
Response: The SDT thanks you for your comments.
The SDT decided to leave R18 in TOP-002 because it represents a planning function. Requirement R7 will remain in the second draft of COM 003 as
Requirement R1, Part 1.1.4, specifying when to use those identifiers.
ATC and ITC
May 2, 2012
Disagree
TOP-002 R18 states that BA, TOP, GOP TSP and LSE shall use uniform line identifiers when referring to
transmission facilities of an interconnected network. COM-003 R7 states that each RC, BA, TO, TOP, GOP, TSP,
LSE and DP shall use pre-determined, mutually agreed upon line and equipment identifiers for verbal and written
Interoperability Communications. TOP-002 allowed the TOP to communicate what the line identifiers were via a
list and use during communications. The new requirement implies that the parties must agree upon the line
identifiers and that agreement must be documented.ATC believes that the requirement should state that “mutual
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
agreement” allows for multiple identifiers. We believe that this is needed in order to avoid the following issues.
1) This clarification will avoid any need for arbitration or formal dispute resolution steps.
2) If the standard does not allow for this provision entities will be forced to deviate from their own line naming
convention and will result in entities to modify their drawings, field signs, and SCADA systems.
Response: The SDT thanks you for your comments.
The SDT decided to leave R18 in TOP-002 because it represents a planning function. Requirement R7 will remain in the second draft of COM-003 as
Requirement R1, Part 1.1.4, specifying when to use those identifiers. The SDT is proposing a single predetermined identifier established by the
owner of the Element/Facility to reduce the potential for confusion.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The new term “Operating Communications” applies when communications involve actions relative to Elements or Facilities of the Bulk Electric
System.
The SDT modified the requirement to remove the term “mutually agreed upon”.
We Energies
Disagree
TOP-002-2 R18 requires uniform line identifiers. The wording of R7 and the statement by the SDT that “the
Requirement does not stipulate a single/unique identifier as long as all parties mutually agree” is in conflict with
TOP-002-2 R18. Allowing multiple line and equipment identifiers to be used does not improve reliability or
improve communications in an emergency. TOP-002-2 applies to Transmission Facilities of an Interconnected
Network...R7 should do the same for clarity. Having the term “mutually agreed upon” in a standard is
unworkable, since it allows a non-cooperative party to disrupt the genuine efforts of others and to exploit unfair
leverage in discussions or negotiations. A better approach is having the Transmission Owners develop identifiers
for transmission, and Generation Operators develop identifiers for generation. The process should be defined
such that comments are solicited and input within a pre-specified convention, and then a specific entity is given
the ability to make the final determination. Again, R7 is more appropriate as a best practices recommendation,
rather than a requirement.
Response: The SDT thanks you for your comments.
The SDT decided to leave R18 in TOP-002 because it represents a planning function. Requirement R7 will remain in the second draft of COM 003 as
Requirement R1, Part 1.1.4, specifying when to use those identifiers.
The SDT modified the requirement to remove the term “mutually agreed upon”.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
ISO New England
Inc.
Agree
We agree that the stipulation of a single/unique identifier is unnecessary as long as all parties mutually agree on
the identifier for the line or equipment, and therefore, support this change to the existing Requirement in TOP002.
Response: The SDT thanks you for your comments.
NRECA RTF
Members
Agree
We agree using pre-determined, mutually agreed upon line and equipment identifiers during for all verbal and
written Interoperability Communications is a more accurate form of communication and should remain as a
requirement of this standard.
Response: The SDT thanks you for your comments.
Xcel Energy
Disagree
We feel this requirement needs clarification, particularly regarding how granular an entity would have to go into
the various pieces of equipment/lines. We would also recommend that R7 be modified to not require mutual
agreement. We feel the owner (or majority owner) of the line or equipment should be the one setting the
identifiers. For example, R7 could instead read like this: “Owner-determined line and equipment identifiers shall
be used for all verbal and written Interoperability Communications.”
Response: The SDT thanks you for your comments.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities.
The SDT modified the requirement to use pre-determined identifiers only for interface Elements/Facilities during oral and written Operating
Communications. The new term “Operating Communications” applies when communications involve actions relative to Element or Facilities of the
Bulk Electric System.
The SDT modified the requirement to remove the term “mutually agreed upon”.
Electric Market
Policy
May 2, 2012
Agree
While we agree conceptually, it is our experience that Interoperability Communications concerning BES elements
do not usually specifically identify the element or facility when the BA, RC or TOP is communicating with the TSP,
LSE or GOP. This may have to do with concerns about Standards/Codes of Conduct or may be because specific
identification of the element or facility isn’t required in order to communicate action(s) that entity is required to
take.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 8 Comment
Response: The SDT thanks you for your comments.
The SDT has eliminated the term Interoperability Communications. The SDT has proposed a new term “Operating Communication”.
The SDT modified the requirement so that entities must use the names specified by the owner(s) of Transmission interface Elements and
Transmission interface Facilities when referring to those Elements and Facilities. If an interface Element/Facility is not used in the Operating
Communication, it would not be subject to this requirement.
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
9. Attachment 1-COM-003-1 is based upon work performed by the Reliability Coordinator Working Group (RCWG).
Do you have any concerns or suggestions for improvement of the attachment? If yes, please provide in the
comment area. (If you are involved in the field testing of the Alert Level Guide please share any comments
regarding the use of the guideline as it relates to the field test.)
Summary Consideration:
Most stakeholders who responded to this question indicated the attachment needs improvement.
Commenters indicate the alert for the Physical Emergency and the Cyber Alert are nearly identical and should be combined.
Many commenters indicated that Attachment 1 includes actions only for the RC. Therefore, there is no reason to have the other
Functions listed as having responsibility for Attachment 1.
Commenters suggest that the use of a “color code” adds an unnecessary level of complexity, adds no value to the Alert Level
guidelines, and could result in confusion with Home Land Security terrorist alerts.
Commenters recommend that Distribution Service Provider be changed to Distribution Provider and that change was made.
Commenters stated that the introductory paragraph in COM-003 - Attachment 1 conflicts with the Alert Level Guide.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional
deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard
as outside the scope of this standard.
Organization
Yes or No
American Municipal
Power
Agree
Bureau of
Reclamation
Agree
Georgia
Transmission Corp
Agree
May 2, 2012
Question 9 Comment
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Sunflower Electric
Power Corporation
Agree
Western Area Power
Administration
Agree
Oncor Electric
Delivery
Disagree
Orange and
Rockland Utilities,
Inc.
Disagree
Pacific Northwest
Small Utilities
Comment Group
Disagree
PacifiCorp
Disagree
Santee Cooper
Disagree
Transmission Owner
Disagree
Florida Municipal
Power Agency
(FMPA) and some
members
Agree
Question 9 Comment
(FMPA assumes that commenting "agree" means "yes, we have suggestions for improvement")It seems that the
first two tables on Physical and Cyber Emergency Alerts are nearly identical. Why not combine them?
On the third table on IROLs, are IROLs the only emergencies, e.g., how about a capacity / energy emergency?
Shouldn’t that be in a table as well?
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
American Electric
Power
May 2, 2012
Agree
“Transmission Loading” should be replaced with “IROLs(on the transmission system).” The attachment is very
prescriptive as to the notifications are to take place, but not on conveyance of information to be communicated
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
during alerts and emergencies. The attachment is not a good fit in this standard.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Manitoba Hydro
Disagree
1) Attachment 1-COM-003-1 qualifies for all three requirements stated below and would be better suited in this
Standard.
a.CIP-001-1 Purpose:”sabotage to be reported to appropriate bodies” and includes the following requirements;
R1. Procedure for recognition
R2. Procedure for communication
R3. Response guideline
2) OR COM-003-1 Attachment 1 could also be placed in COM-002-2. COM-002-2’s Purpose is “capabilities for
addressing real time emergencies and to ensure communications by personnel are effective.”
3) COM-003-1 purpose is to “convey information effectively” meaning the use of English, NATO, three-part
communication, 24 time format are all verbal aspects to accomplish this purpose and not suited to pre-defined or
planned items.
4) COM-003-1 Attachment 1 also defines Physical Security threats and notifications which fulfills the purpose of
COM-002-2 more thoroughly (then in COM-003-1) and could even be made as an requirement.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
The Empire District
Electric Company
Disagree
Again this attachment is redundant to the NERC Alert process.
Response: The SDT thanks you for your comments.
Yes. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations,
determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
various alert levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
MRO NERC
Standards Review
Subcommittee
Agree
As Attachment 1 is written it only applies to the RC and is a one-way communications path. The BA, DP, GOP,
TOP, and TO are to be notified by the RC but the attachment doesn’t state what they are to do with the
information. COM-003-1, R1 states that the RC, BA, TO, TOP, GOP, TSP, LSE and DP are to have a CPOP with the
elements in R2 through R7, which refer to Attachment 1. If Attachment 1 is applicable only to the RC, as we
recommend, there is no reason to have the other Functions listed for Attachment 1. Requirement R2 and
Measure M2 need to be revised to be applicable to the RC only. Attachment 1 makes reference to “Distribution
Service Providers”. There is no definition of a Distribution Service Provider in the NERC Functional Model, and we
believe this should either be revised to Distribution Provider, or deleted entirely from the list.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Pepco Holdings, Inc.
- Affiliates
Agree
As noted in our comments to Question 4, Attachment 1 has examples for Reliability Coordinators only. It is not a
good guide for other Interoperability Communications. Additionally, Attachment 1 identifies the Level 1, Level 2
and Level 3 communications by color codes that are not referenced in the sample messages. PHI finds the
addition of color codes to not be helpful and possibly confused with national security Alert Levels. The color
coding should be eliminated and examples for entities in addition to the Reliability Coordinator should be
included.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Ameren
Agree
As stated earlier, this is an excellent document for RC interactions. But it is wholly unclear how this impacts other
entity-to-entity relationships in pre-defining states. And as mentioned having only Attachment 1 seems to ignore
the energy balance alerts/emergencies
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
May 2, 2012
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Entergy Services
Agree
As written, the actions that fall into interoperability communications in requirement 2 are much broader than the
set of conditions described in the table in attachment 1. To the extent that the communications are outside of
the ones in the table, entities will be non-compliant because their communications are not pre-defined.
Recommend that requirement 2 be changed to indicate that “Any Reliability Coordinator or Transmission
Operator experiencing a physical security emergency, cyber security emergency, or transmission emergency will
communicate their status using the conditions and processes in Attachment 1.”Is this a better write up for R1
(New)
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
We Energies
Agree
Attachment 1 is written for an RC. Usage of Attachment 1 by entities other than an RC should be clarified.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
California
Independent System
Operator
CAISO Comments; Information regarding the Alert Level Guide field test has not been widely circulated and
unproductive as of late. Does not the Alert Level Guide need to be approved prior to any standard which
references the guide be approved? What was the outcome of the field testing? Was reliability enhanced?
Attachment 1 describes ‘normal, alert, and emergency operating conditions’, then goes on to never use those
terms again in any meaningful manner. To further confuse it then mixes color coding of steps with levels. Which
is it, Condition Red or Level 3? The attachment directs Reliability Coordinators to make vague notifications to the
functional entities in its footprint. It directs Reliability Coordinators to make these vague notifications to entities
that do not use, in our case the WECCNet. Is it really anticipated that the Reliability Coordinator calling on the
telephone every DP in its footprint with a vague notification will be an enhancement to reliability?
Response: The SDT thanks you for your comments.
May 2, 2012
250
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
New York State
Reliability Council
Agree
Comments: In addition to the response to Question 4, NYSRC does not understand why there are Levels and color
designations since only the threat level numeral is being communicated. Attachment 1-Com-003 is very
prescriptive in the use pre-defined terminology, colors and levels. There is no benefit (Verbatim?) to specifying
the specific terminology. Requiring system Operators to state Colors and Levels would seem to result in slower
and more confused communication.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
E.ON U.S. LLC
Disagree
E.ON U.S. has many concerns with this proposed attachment. The use of color coding and multiple types of
alerts adds unnecessary levels of complexity. Any proposed alert level should be consistent throughout the suite
of reliability standards, e.g. level 1,2,3. Also, as previously noted in our comment to question 4 above, E.ON U.S.
suggests integrating attachment 1 and the relative alert levels into the EOP standards and focusing the COM
standards on the requirements of communications protocol.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Long Island Power
Authority
Agree
In addition to the response to Question 4, LIPA does not understand why there are Levels and color designations
since only the threat level numeral is being communicated. Attachment 1-Com-003 is very prescriptive in the use
pre-defined terminology, colors and levels. There is no benefit to specifying the specific terminology. Requiring
system Operators to state Colors and Levels would seem to result in slower and more confused communication.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
May 2, 2012
251
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Bonneville Power
Administration
Agree
In Attachment #1 - Operating State Alert Levels, for the Transmission Emergency Alert (TEA) Level 2 definition, a
“why” needs to be incorporated into the definition. It appears that the reason we're going to TEA 2 is to avoid
violation of an SOL but it needs to be called out. The color scheme may be confusing with (DHS) Homeland
Security's terrorist alert levels. (The RC makes the notifications to all based upon the Operator’s reported
conditions per the scheme.). Suggest only using the Emergency Energy Alert numerical levels versus the color
scheme, to avoid confusion with Homeland Security alerts. An example: A red alert is a breakup like 2003 and
1996, not shedding of load to prevent it, The color scheme does not work for this. Agree with Notifications for
Physical Security and Cyber Security. Disagree with Notifications for Transmission Emergency Alerts. This
appears to be only IROL related, but could progress to SOL. May have too many of these issued. Suggest the
following: Yellow - approaching IROL limit; Orange - procedures implemented to correct IROL; RED - shedding
firm to respect an IROL.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Hydro-Québec
TransEnergie
May 2, 2012
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Also it has been the experience of several entities during the field test of these Alert Levels that there are
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion than exists
today. Reliability has not been enhanced.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
There is an inconsistency between the inclusion of Attachment 1 and what is stated in the document posted with
the standard entitled Disposition of Requirements Identified in the SAR for Operations Communications Protocols
as Possibly Needing either Modification or Movement. The document states that the standard focuses on “how
to” communicate rather than on specified scenarios of “to whom” or “when to” communicate; however,
Attachment 1 does just the opposite. In condition Orange and Red for TEA Level Two/Three, the initial notification
requirements are redundant with IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model. Refer
to the response to Question #4.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Independent
Electricity System
Operator
May 2, 2012
Agree
It is not clear what value is realized by declaring an alert status particularly with cyber and physical attacks. There
does not appear to be any differing actions taken based on the alert status. Given that no differing actions are
taken for cyber and physical attacks, it seems it would be more beneficial to use specific information such as the
number of substations that have been physically or cyber attacked, etc. This is more meaningful than issuing a
red alert that would only indicate more than one site has been attacked. Also, please see our comments under
Q4.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard. Please see our response to
Q4.
ISO New England
Inc.
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Also it has been the experience of several entities during the field test of these Alert Levels that there are
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion than exists
today. Reliability has not been enhanced.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
In condition Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2.
May 2, 2012
254
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model. Refer
to the response to Question #4.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Northeast Power
Coordinating Council
May 2, 2012
Agree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Also it has been the experience of several entities during the field test of these Alert Levels that there are
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion than exists
today. Reliability has not been enhanced.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
255
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
There is an inconsistency between the inclusion of Attachment 1 and what is stated in the document posted with
the standard entitled Disposition of Requirements Identified in the SAR for Operations Communications Protocols
as Possibly Needing either Modification or Movement. The document states that the standard focuses on “how
to” communicate rather than on specified scenarios of “to whom” or “when to” communicate; however,
Attachment 1 does just the opposite. In condition Orange and Red for TEA Level Two/Three, the initial notification
requirements are redundant with IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model. Refer
to the response to Question #4.
Refer to the response to Question #4.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Please see our reply to Q4.
Dynegy
Disagree
May 2, 2012
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
256
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
IRC Standards
Review Committee
May 2, 2012
Disagree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Also it has been the experience of several entities during the field test of these Alert Levels that there are
inconsistencies as to when to implement various stages of Alerts, and this introduces more confusion than exists
today. It certainly has not enhanced Reliability.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
In condition Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
257
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Midwest ISO
Standards
Collaborators
May 2, 2012
Disagree
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
In condition Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
258
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Transmission System
Operations
Agree
It should be made clear that Attachment 1 applies to the RC’s. It is not specifically stated in R2 that it is the RC’s
responsibility to make notifications. In Attachment 1, we believe the wording under “Initial Notifications” should
be changed. For example, on the 2nd row and 1st column of the matrix, it states that the RC makes initial
notification and states that “...there is a Physical Emergency Alert, PSEA Level One within....” Nowhere is it ever
mentioned that there is a “Condition Yellow”. Since it is never mentioned by the RC in the notification that the
Condition is “Yellow”, what is the use or benefit of having the conditions?
It should also be made clear that when the RC states, for example, that “There is a Physical Security Emergency
Alert-PSEA Level One within...” that this refers to specific definitions given in Attachment 1 of EOP-002-2.1. This
fact is mentioned at the top of the matrix, but the wording of this explanation is not consistent with the wording
used in the body of the matrix.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
NERC Staff
Agree
NERC staff recommends that a line be added to each table that provides the expectation for entities
communicating events to the Reliability Coordinator. Using the existing tables, all expectations and requirements
rest solely on the Reliability Coordinator. We also recommend eliminating the color designations of yellow,
orange, red and the Alerts be changed to Level One, Two and Three for consistency. The use of colors does not
appear to add anything to the clarity or effectiveness in conveying the content of an Alert and may be
inconsistent with the Department of Homeland Security’s threat level system. Additionally, the team should
update Attachment 1 to include the criteria and notifications for Energy Emergency Alerts.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
May 2, 2012
259
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
NIPSCO
Disagree
PPL
No comment
No comments either way since this applies specifically to RCs.
Northeast Utilities
Disagree
No concerns or suggestions (Disagree = No)
Westar Energy
Agree
no suggestions
NextEra Energy
Resources, LLC
Disagree
None at this time.
Consumers Energy
None.
Response: The SDT thanks you for your participation
PJM
Agree
May 2, 2012
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators, not the
industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the RCIS. If the RCIS is
not functioning and the hotline is used instead, is the entity vulnerable to a violation by virtue of the fact that
these alert guides are included in the standard?
We believe that the color-coded system condition terminology should be defined/required externally to the COM
standards. The use of clear & consistent alert level terminology, while important, does not fit in well with the
reliability-related communication standards, especially at these high violation severity levels.
It is our suggestion that the Alert Level Guides be balloted separately, and include the Energy Emergency Alerts
(EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
260
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
In condition Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model. Refer
to the response to Question #4.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
PJM SOS Comments
May 2, 2012
Agree
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators, not the
industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the RCIS. If the RCIS is
not functioning and the hotline is used instead, is the entity vulnerable to a violation by virtue of the fact that
these alert guides are included in the standard?
We believe that the color-coded system condition terminology should be defined/required externally to the COM
standards. The use of clear & consistent alert level terminology, while important, does not fit in well with the
261
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
reliability-related communication standards, especially at these high violation severity levels.
It is our suggestion that the Alert Level Guides be balloted separately, and include the Energy Emergency Alerts
(EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.
It is not clear what value is realized by declaring an alert status particularly with regard to cyber and physical
attacks. There do not appear to be any differing actions taken based on the alert status. Given that no differing
actions are taken for cyber and physical attacks, it seems it would be more beneficial to use specific information,
for example 12 substations have been physically or cyber attacked. This is more meaningful than issuing a red
alert that would only indicate more than one site has been attacked.
Furthermore, we question the value of communicating the physical and cyber alerts. How does this notification
help the BES reliability? Consider the following example. One BA in Oklahoma is 34,323 sq miles. Communicating
that an attack occurred in the BA and RC tells other operators that somewhere in Oklahoma an attack occurred.
This notification does not present any information that could require actions on the operators’ parts, and will only
generate phone calls for more information.
Furthermore, PSE and CSE is a type of sabotage already reported in CIP-001 R2. TEA Alerts are already covered in
IRO-006-East-1, IRO-009, IRO-010, IRO-014.01 R2.
Attachment 1 contains a conflict. The last sentence of the opening paragraph of Attachment 1 reads, “The time
frame for declaration of these Alert states shall be consistent with the approach used to declare EEAs and would
normally apply to Real Time declarations and not forecast conditions.” In Transmission Emergency Alerts
Condition Yellow, Orange and RED: The Reliability Coordinator or Transmission Operator foresees or is
experiencing conditions where all available generation resources are committed to respect the IROL and/or is
concerned about its ability to respect the IROL. Foresees is a forecast condition.
In condition Orange and Red for TEA Level Two/Three, the initial notification requirements are redundant with
IRO-006-East-1 R3.2.
Under the Make Final Notifications, is curtailed intended to mean canceled or terminated? The term Curtailed in
operations generally means cuts for schedules/tags. EEA’s use terminated. Terminated is the preferred term.
Distribution Service Providers should be Distribution Provider to be consistent with the Functional Model. Refer
to the response to Question #4.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
May 2, 2012
262
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
SERC OC&SOS
Standards Review
Group
Agree
Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability Coordinators, not the
industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the RCIS. If the RCIS is
not functioning and the hotline is used instead, is the entity vulnerable to a violation by virtue of the fact that
these alert guides are included in the standard?
We believe that the color-coded system condition terminology should be defined/required externally to the COM
standards.
The use of clear & consistent alert level terminology, while important, does not fit in well with the reliabilityrelated communication standards, especially at these high violation severity levels.
It is our suggestion that the Alert Level Guides be balloted separately, and includes the Energy Emergency Alerts
(EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.1
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
PEF
Agree
PEF recommends that the color coding and definitions that are used by Homeland Security also be used for the
notification of physical and cyber emergency alerts reported to the RC. This would follow the ES-ISAC standard
already adopted by the electric industry. If the attachment is adopted as is, PEF recommends adding the EEA
levels to provide “pre-defined system condition terminology.”
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Xcel Energy
Agree
Please see our response to question 4.
National Grid
Disagree
Please see response to Question 4.
May 2, 2012
263
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Response: The SDT thanks you for your comments.
See response to comments to Question 4.
Progress Energy
Carolina, Inc
Agree
R2 which links with Attachment 1 is applicable to a host of entities while the Attachment seems to only provide
pre-defined system condition terminology for use during notifications by the RC to other entities. PEC feels that
unscripted specific language used by RCs now on RCIS and in verbal communications currently provides the
necessary awareness and information to entities without personnel having to refer to a procedure or remember
color codes to decipher the meaning. This attachment does not serve to increase the reliability of the BES.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Puget Sound Energy
Disagree
See discussion in Question 4. Also the attachment applies to Reliability Coordinators only, yet the requirement
referencing the attachment applies to additional entities. Those entities should be removed from Requirement 2
or the attachment and Requirement 2 should be clarified to address what those additional entities’
responsibilities are under the attachment.
Response: The SDT thanks you for your comments.
See response to comments to Question 4.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
ATC and ITC
Disagree
See question #4.
South Carolina
Electric and Gas
Agree
See question 4.
Response: The SDT thanks you for your comments.
See response to comments to Question 4.
Electric Market
May 2, 2012
Agree
See response to question 4. In addition, there seems to be an inconsistency between the inclusion of Attachment
264
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Policy
Question 9 Comment
1 and what is stated in the document posted with the standard entitled Disposition of Requirements Identified in
the SAR for Operations Communications Protocols as Possibly Needing either Modification or Movement. The
document states that the standard focuses on “how to” communicate rather than on specified scenarios of “to
whom” or “when to” communicate; however, Attachment 1 does just the opposite.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
See response to comments to Question 4.
British Columbia
Transmission
Corporation
Agree
Should a move to a standard time be required then the move should be to Universal Time
Response: The SDT thanks you for your comments.
See response to comments to Question 5.
Southern Company
Transmission
Agree
Southern Company supports the SERC SOS comments.
SERC SOS comments: Our concern is that the Alert Level Guides of Attachment 1 were written for Reliability
Coordinators, not the industry as a whole, and now they are being incorporated into an industry-wide standard.
This attachment is very prescriptive as to how the notifications take place, such as through the RCIS. If the RCIS is
not functioning and the hotline is used instead, is the entity vulnerable to a violation by virtue of the fact that
these alert guides are included in the standard?
We believe that the color-coded system condition terminology should be defined/required externally to the COM
standards.
The use of clear & consistent alert level terminology, while important, does not fit in well with the reliabilityrelated communication standards, especially at these high violation severity levels.
It is our suggestion that the Alert Level Guides be balloted separately, and includes the Energy Emergency Alerts
(EEA) as well. EEA requirements currently exist in NERC Standard EOP-002-2.1
Response: The SDT thanks you for your comments. Please see the response to the SERC SOS comments.
May 2, 2012
265
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Kansas City Power &
Light
Disagree
Question 9 Comment
The attachment is inappropriate for this standard and should be removed. See response to question #4.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Please see response to comments to question #4.
ERCOT ISO
Agree
The intent is for a simple way to look and know the high-level status of an area. This goes way too far into HOW
to do it instead of stating what must be done.
Response: The SDT thanks you for your comments.
The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder comments and additional deliberations, determined
that Requirement R2 is not a requirement that defines a “communication protocol” – rather the requirement was attempting to define various alert
levels. The SDT removed the requirement from the second draft of the standard as outside the scope of this standard.
Tri-State Generation
& Transmission
Assoc.
Agree
The Operating State Alert Levels can be confused with DHS security levels.
DSPs should not be included because they are not subject to BES standards because they do not operate the BES
that responsibility resides with the TOP. The title Distribution Service Providers should be changed to Distribution
Provider to correlate with the NERC functional model.
Under Additional Communication the posting of the alert level should be determined by each entities internal
procedure and not included in this standard. This attachment is too invasive and restrictive.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
NYSEG
Agree
There does not appear to be any compelling practical or reliability reason to adopt the Attachment.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
May 2, 2012
266
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
Sunflower Electric
Power Corp.
Use a Phonetic alphabet in common use in the USA
Response: The SDT thanks you for your comments. See response to Question 7.
FirstEnergy
Disagree
We do not support Att. 1 and feel that it should be removed. This attachment is too convoluted, creates
confusion among system operators, and not necessary with regard to the goal of this standard. This standard
mandates proper three-part communication in all reliability-related communication. Other standards should
define and mandate rules associated with the specifics surrounding urgent action situations (i.e. CIP, TOP, EOP
standards). Together these standards will arrive at proper communication between entities during alert level
situations.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
ExxonMobil
Research and
Engineering
Disagree
We have no concerns or suggestions for improvement.
Response: The SDT thanks you for your comments.
Duke Energy
May 2, 2012
Agree
We support the development of this attachment, but question whether it belongs in this standard, especially
since it is under field trial. We think it belongs in the EOP standards.
We note the Attachment 1 is only associated with notifications by the RC, so we question whether these are
Interoperability Communications as that term is defined.
Also, the introduction on Attachment is very confusing. Attachment 1 states that definitions for Transmission
Loading, Physical and Cyber Security Alert states align with the Emergency Energy Alert (EEA) states as already
described in Standard EOP-002-2.1. EOP-002-2.1 and associated EEA Levels provides guidance on Energy and
Capacity Emergencies rather than Transmission or Physical/Cyber Alerts.
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 9 Comment
Energy Emergency is defined as a condition when a LSE has exhausted all other options and can no longer
provide its customers’ expected energy requirements. This is a totally different classification of Emergency Alert.
We suggest deleting the 2nd and 3rd sentences of the introduction to Attachment 1. In addition, Attachment 1
does not contain four system condition alerts, as the SDT has proposed.
Response: The SDT thanks you for your comments. The SDT reviewed Requirement R2 and the associated attachment and, based on stakeholder
comments and additional deliberations, determined that Requirement R2 is not a requirement that defines a “communication protocol” – rather the
requirement was attempting to define various alert levels. The SDT removed the requirement from the second draft of the standard as outside the
scope of this standard.
PSEG Companies
Agree
Yes. The PSEG Companies agree with the concerns and suggestions expressed in the comments filed by the PJM
System Operations Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments. Please see the response to PJM SOS Group.
May 2, 2012
268
Consideration of Comments on OPCP SDT — Project 2007-02
10.
Are you aware of any regional variances that would be required as a result of this standard? If yes, please
identify the regional variance.
Summary Consideration:
Commenters stated that if the Central Standard Time zone were required as proposed in R4, there should be a regional variance to
allow the WECC to select the time zone to use as a standard. The standard R4 (new Requirement R1, Part 1.1.2) and (new Part 1.1.3)
of COM-003-1 is shown below:
1.1.2 Use the 24-hour clock format when referring to clock times.
1.1.3. When the communication is between entities in different time zones, include the time, time zone and indicate whether time
is daylight saving time or standard time.
Commenters raised questions about requiring the use of “English” which may conflict with legal requirements of non-English
speaking Regions covered by NERC’s standards. The draft standard has been modified to account for law and regulation that
mandates another language other than English.
1.1.1. Use the English language when communicating between functional entities, unless another language is mandated by law or
regulation.
There were comments expressing concern that “blast” or “all-call” communications used by many RCs conflict with FERC Standards
of Conduct issues, especially with respect to Distribution Providers and Generator Operators. The standard no longer references
communications that involve “blast” or “all-call” communications.
Organization
Yes or No
American
Municipal Power
Agree
Bureau of
Reclamation
Agree
American Electric
Power
Disagree
ATC and ITC
Disagree
May 2, 2012
Question 10 Comment
269
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Bonneville Power
Administration
Disagree
British Columbia
Transmission
Corporation
Disagree
Duke Energy
Disagree
Dynegy
Disagree
E.ON U.S. LLC
Disagree
Entergy Services
Disagree
ERCOT ISO
Disagree
Georgia
Transmission
Corp
Disagree
Great River
Energy
Disagree
Independent
Electricity System
Operator
Disagree
Kansas City
Power & Light
Disagree
Manitoba Hydro
Disagree
Midwest ISO
Standards
Collaborators
Disagree
May 2, 2012
Question 10 Comment
270
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
NorthWestern
Energy
Disagree
NYSEG
Disagree
Oncor Electric
Delivery
Disagree
PacifiCorp
Disagree
PEF
Disagree
PPL
Disagree
Santee Cooper
Disagree
South Carolina
Electric and Gas
Disagree
Southern
Company
Transmission
Disagree
Sunflower Electric
Power
Corporation
Disagree
Transmission
Owner
Disagree
Tri-State
Generation &
Transmission
Assoc.
Disagree
We Energies
Disagree
May 2, 2012
Question 10 Comment
271
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
Western Area
Power
Administration
Disagree
Xcel Energy
Disagree
Northeast
Utilities
Disagree
(Disagree = No)
Florida Municipal
Power Agency
(FMPA) and some
members
Disagree
(FMPA assumes "disagree" means that we are not aware of any regional variances)
Response: The SDT thanks you for your comments.
Pacific Northwest
Small Utilities
Comment Group
Agree
(This is a yes or no questions)Yes, The RC in the WECC region has no communication with any entity other than
the sixteen listed in
http://www.bpa.gov/corporate/business/reliability/Docs/2007/PNSC_RE_Data_Letter_2_070723.pdf. Although
the linked document is on PNSC letterhead, WECC as RC continues this policy. Communication paths involving
the RC and any other entity in the west other than the sixteen should be exempt from all the requirements in
this standard.
If DPs and LSEs must be included in this standard, then there should be an agreement in force beforehand
between them and their RC, BA and TOP that they may receive directives, or require the RC, BA and TOP to list
those DPs and LSEs that would not receive directives.
Response: The SDT thanks you for your comments.
The LSEs were eliminated as responsible entities from this standard but some DPs are applicable depending on the impact they have on the BES.
We have discussed the use of the letter cited in your comments with our WECC SDT member and he advises us that this arrangement is
obsolete as the WECC RC does NOT continue to follow that policy. The WECC RC communicates with all registered Balancing Authorities and
Transmission Operators within the Western Interconnection on a regular basis. In accordance with NERC Standard IRO-001-1.1 R3, the RC shall
have clear decision-making authority to act and to direct actions to be taken by the Transmission Operators, Balancing Authorities, Generator
Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability Coordinator Area to
May 2, 2012
272
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
preserve the integrity and reliability of the Bulk Electric System. In accordance with NERC Standard IRO-001-1.1 R8, Transmission Operators,
Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply
with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements.
While it is typical for WECC RC to communicate, advise and direct Balancing Authorities or Transmission Operators, it is important for other
registered entities to recognize that the RC may contact them directly if the situation requires such. Based on this scenario the requirements in
COM 003 would apply to those entities if BES conditions warrant it.
NERC Staff
Agree
Although no questions were asked about Requirement R3, NERC staff is aware that some areas in North
America require a language other than English for official communication. In addition, it may be hard to define
what “internal communications” are. NERC staff recommends that the phrase “Interoperability
Communications. Responsible Entities may use an alternate language for internal communications” be replaced
with “Operating Communications between functional entities, unless prohibited by law.” In addition, regions
that exist solely in one time zone may ask for a variance from the requirement to use CST for communication.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to the possible legal issues associated with the requirement to use English for oral and written
Operating Communications. The draft standard has been modified to exempt entities from use of the English language where another language
is mandated by law or regulation.
The definition for “Interoperability Communication” has been removed and a new definition has been proposed for the term “Operating
Communications”.
The second draft of COM-003 does not mandate the use of the Central Time Zone and should obviate the need for the identified variance. The
second draft of COM-003 includes the following as a replacement for the requirement to use the Central Time Zone:
1.1.3.
When the communication is between entities in different time zones, include the time, local time zone and indicate whether time
is daylight saving time or standard time.
California
Independent
System Operator
Agree
CAISO Comments; The proposed requirement R7 will cause regions operating in any time zone other than
Central to draft regional standards to avoid this non-reliability supporting requirement.
Response: The SDT thanks you for your comments:
The SDT has developed an alternative for the common time zone. Instead of requiring the use of a single continent-wide time zone, the
May 2, 2012
273
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone and indicate
whether time is daylight saving time or standard time when communicating with one or more entities in a different time zone.
Puget Sound
Energy
I might suggest one for R4 by each region that is not in the Central Standard Time zone.
Response: The SDT thanks you for your comments
The SDT has developed an alternative for the common time zone. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone and indicate
whether time is daylight saving time or standard time when communicating with one or more entities in a different time zone
MRO NERC
Standards Review
Subcommittee
Agree
If the Central Standard time zone is required as noted in R4, we believe there should be a regional variance to
allow the WECC to select the time zone to use as a standard.
Response: The SDT thanks you for your comments
The SDT has developed an alternative for the common time zone. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone and indicate
whether time is daylight saving time or standard time when communicating with one or more entities in a different time zone.
Hydro-Québec
TransEnergie
Agree
In the Province of Quebec, the use of French is mandatory, according to law, for communication within the
Province.R3 should include: Within the Québec Interconnection, the French language shall be used for verbal
and written interoperability communication between entities (RC, BA, TO, TOP, GOP, TSP, LSE and DP). For their
interoperability communication with entities outside of the Québec Interconnection, they shall use the English
language.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to the possible legal issues associated with the requirement to use English for oral and written
Operating Communications. The draft standard has been modified to exempt entities from use of the English language where another language
is mandated by law or regulation.
IRC Standards
Review
Committee
May 2, 2012
Agree
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generation Operator cannot have access to these
systems due FERC standards of conduct requirements. Requirement 2 and the listing of functional entities
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
required to be notified within the RC footprint in attachment 1 create a de facto requirement for them to have
RCIS access or an unnecessary burden to communicate with all functional entities listed separately. Having to
communicate to all functional entities in that list verbally and individually would create an unnecessary burden
that distracts the RC from actual system operation and represents a detriment to reliability.
Response: The SDT thanks you for your comments.
The SDT has deleted COM-003 - Attachment 1 and Requirement R2 from the second draft of COM-003 in response to stakeholder concerns.
ISO New England
Inc.
Agree
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generation Operator cannot have access to these
systems due FERC standards of conduct requirements. Requirement 2 and the listing of functional entities
required to be notified within the RC footprint in attachment 1 create a de facto requirement for them to have
RCIS access or an unnecessary burden to communicate with all functional entities listed separately. Having to
communicate to all functional entities in that list verbally and individually would create an unnecessary burden
that distracts the RC from actual system operation and represents a detriment to reliability.
Response: The SDT thanks you for your comments.
The SDT deleted Requirement R2 and the associated COM-003 - Attachment 1 from the second draft of the standard in response to stakeholder
concerns.
Northeast Power
Coordinating
Council
May 2, 2012
Agree
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generation Operator cannot have access to these
systems due FERC standards of conduct requirements. Requirement 2 and the listing of functional entities
required to be notified within the RC footprint in Attachment 1 creates a de facto requirement for them to have
RCIS access or an unnecessary burden to communicate with all functional entities listed separately. Having to
communicate to all functional entities in that list verbally and individually would create that unnecessary
burden, and distract the RC from actual system operation. This is a detriment to reliability.
Some ISO/RTOs have market rules which allow participants to elect NOT to follow instructions issued by their
market operator (who may also perform BA, TOP and/or RC entity functions) unless an Emergency exists.
In the Province of Québec, the use of French is mandatory, according to law, for communication within the
Province. R3 should include: Within the Québec Interconnection, the French language shall be used for verbal
and written interoperability communication between entities (RC, BA, TO, TOP, GOP, TSP, LSE and DP). For their
275
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
interoperability communication with entities outside of the Québec Interconnection, they shall use the English
language.
Response: The SDT thanks you for your comments. The SDT deleted Requirement R2 and the associated COM-003 - Attachment 1 from the
second draft of the standard in response to stakeholder concerns.
The SDT appreciates the comments with regards to the possible legal issues associated with the requirement to use English for oral and written
Operating Communications. The draft standard has been modified to exempt entities from use of the English language where another language
is mandated by law or regulation.
PJM SOS
Comments
Agree
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generation Operator cannot have access to these
systems due FERC standards of conduct requirements. Requirement 2 and the listing of functional entities
required to be notified within the RC footprint in attachment 1 create a de facto requirement for them to have
RCIS access or an unnecessary burden to communicate with all functional entities listed separately. Having to
communicate to all functional entities in that list verbally and individually would create an unnecessary burden
that distracts the RC from actual system operation and represents a detriment to reliability.
Response The SDT thanks you for your comments.
The SDT deleted Requirement R2 and the associated COM-003 - Attachment 1 from the second draft of the standard in response to stakeholder
concerns.
PJM
Disagree
Many RC communications are issued to multiple parties using blast communication systems such as the RCIS.
Several of the parties such as Distribution Provider and Generation Operator cannot have access to these
systems due FERC standards of conduct requirements. Requirement 2 and the listing of functional entities
required to be notified within the RC footprint in attachment 1 create a de facto requirement for them to have
RCIS access or an unnecessary burden to communicate with all functional entities listed separately. Having to
communicate to all functional entities in that list verbally and individually would create an unnecessary burden
that distracts the RC from actual system operation and represents a detriment to reliability.
Response: The SDT thanks you for your comments. The SDT deleted Requirement R2 and the associated COM-003 - Attachment 1 from the
second draft of the standard in response to stakeholder concerns.
The Empire
District Electric
May 2, 2012
Agree
NO
276
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 10 Comment
Company
PSEG Companies
Disagree
No regional variances would be required to the best of PSEG's knowledge.
SERC OC&SOS
Standards Review
Group
Disagree
No, we are not aware of any regional variances.
National Grid
Disagree
None
NIPSCO
Disagree
none
NextEra Energy
Resources, LLC
Disagree
None at this time.
Consumers
Energy
None.
Westar Energy
Agree
not aware
Orange and
Rockland Utilities,
Inc.
Disagree
Not aware
FirstEnergy
Not aware of any
Response: The SDT thanks you for your comments.
Pepco Holdings,
Inc. - Affiliates
Agree
PHI asserts that WECC would say NO to Central Standard Time.
Response: The SDT thanks you for your comments.
The SDT has developed an alternative for the common time zone. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
NRECA RTF
May 2, 2012
Agree
POSSIBLE FRCC VARIENCE - FRCC appears to have developed a communication protocol in which “any or all
277
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Members
Question 10 Comment
conversations on the phone are considered a directive. If this case, we suggest that the drafting team review
the FRCC approach and determine if a regional variance should be included in this standard or consider utilizing
the FRCC approach for clearly defining the term “directive” for inclusion in the NERC Glossary.
Response: The SDT thanks you for your comments.
The SDT cannot comprehend how every conversation could be a directive. The SDT would have to understand the rationale and logic of such a
communication protocol before rendering a response.
Transmission
System
Operations
Agree
Refer to Question #5; we do not agree with using Central Standard Time.
Response: The SDT thanks you for your comments. The SDT has developed an alternative for the common time zone. Instead of requiring the
use of a single continent-wide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly
state the time and time zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities
in a different time zone.
Electric Market
Policy
Agree
Some ISO/RTOs have market rules which allow participants to elect NOT to follow instructions issued by their
market operator (who may also perform BA, TOP and/or RC entity functions) unless an Emergency exists.
Response The SDT thanks you for your comments. The SDT recognizes different regions may have various market rules, but feels that the NERC
Reliability Standards clearly identify requirements to follow reliability directives and indicate acceptable reasons for not complying with a
directive.
ExxonMobil
Research and
Engineering
Disagree
We are not aware of any regional variances that would be required as a result of this standard.
Response: The SDT thanks you for your comments.
May 2, 2012
278
Consideration of Comments on OPCP SDT — Project 2007-02
11.
Are you aware of any conflicts between the proposed standard and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement? If yes, please identify the conflict.
Summary Consideration:
Commenters again point out requiring use of “English” may conflict with legal requirements of non-English speaking footprints
covered by NERC. The draft standard has been modified to exempt entities bound by law or regulation from applicability of R3 (new
Requirement R1, Part 1.1.1).
1.1.1. Use the English language when communicating between functional entities, unless another language is mandated by law or
regulation.
Comments regarding a common Central Standard Time zone reference warned of confusion and cost impacting commercial electric
power capacity and energy markets. R3 (new Requirement R1, Part 1.1.2 and 1.1.3) of COM-003-1 has been modified to:
1.1.2. Use the 24-hour clock format when referring to clock times.
1.1.3. When the communication is between entities in different time zones, include the time, local time zone and indicate whether
time is daylight saving time or standard time.
(Example: 1500 EST or Eastern Standard Time).
Commenters state that TSPs, DPs and LSEs may not own or operate any Facilities, and indicated that inclusion of these entities as
proposed in COM-003 is an unnecessary burden. The SDT removed TSPs and LSEs from the applicability of COM-003 as they were
not identified in the SAR. The specified role of the DP to shed load justifies the retention of the DP as an applicable Entity. The
requirements of COM-003-1 are only applicable to Operating Communications. To the extent that entities do not operate, or do not
take actions that change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System, COM003-1 would not apply.
Commenters raised concern that requirements of the proposed COM-003 Standard conflict with Energy Policy Act of 2005 by
shifting real time operator’s focus from reliable operation of the BES to complying with communication protocol. The SDT
respectfully disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to
enhanced reliable operations of the BES.
Organization
Yes or No
American
Agree
May 2, 2012
Question 11 Comment
279
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
Municipal Power
American Electric
Power
Disagree
ATC and ITC
Disagree
Bonneville Power
Administration
Disagree
British Columbia
Transmission
Corporation
Disagree
California
Independent
System Operator
Disagree
Duke Energy
Disagree
Dynegy
Disagree
Entergy Services
Disagree
ERCOT ISO
Disagree
Georgia
Transmission Corp
Disagree
Great River Energy
Disagree
Independent
Electricity System
Operator
Disagree
Kansas City Power
& Light
Disagree
May 2, 2012
280
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Long Island Power
Authority
Disagree
Manitoba Hydro
Disagree
Midwest ISO
Standards
Collaborators
Disagree
New York State
Reliability Council
Disagree
NYSEG
Disagree
Oncor Electric
Delivery
Disagree
Pepco Holdings,
Inc. - Affiliates
Disagree
PPL
Disagree
South Carolina
Electric and Gas
Disagree
Sunflower Electric
Power Corporation
Disagree
The Empire District
Electric Company
Disagree
Transmission
Owner
Disagree
Transmission
System Operations
Disagree
May 2, 2012
Question 11 Comment
281
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
Tri-State
Generation &
Transmission
Assoc.
Disagree
Western Area
Power
Administration
Disagree
Xcel Energy
Disagree
Northeast Utilities
Disagree
(Disagree = No)
Florida Municipal
Power Agency
(FMPA) and some
members
Disagree
(FMPA assumes that "Disagree" means that we are not aware of any conflicts)
Response: The SDT thanks you for your comments.
Pacific Northwest
Small Utilities
Comment Group
Agree
(This is a Yes or No Questions)Yes, see our comments to Q2.
Response: The SDT thanks you for your comments. Please see SDT response to Q2 comments.
Santee Cooper
Agree
A lot of the requirements in this standard could be considered a “best practice” for the industry rather than
reliability related.
Response: The SDT thanks you for your comments. The SDT believes these requirements play an important role in managing the human factor
to eliminate miscommunication that would result in adverse effects on the BES.
NERC Staff
May 2, 2012
Agree
Although no questions were asked about Requirement R3, NERC staff is aware that some areas in North
America require a language other than English for official communication. In addition, it may be hard to define
what “internal communications” are. NERC staff recommends that the phrase “Interoperability
Communications. Responsible Entities may use an alternate language for internal communications” be replaced
282
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
with “Operating Communications between functional entities, unless prohibited by law.”
Response: The SDT thanks you for your comments. The draft standard has been modified to exempt entities from use of the English language
where another language is mandated bylaw or regulation. The second draft of the standard clarifies that the requirement to use English only
applies with the Operating Communication involves more than one functional entity.
The definition for “Interoperability Communication” has been removed and a new definition has been proposed for the term “Operating
Communications” in the current draft of the standard.
Bureau of
Reclamation
Disagree
As indicated in the previous response the standard conflicted with DHS notifications.
Response: The SDT thanks you for your comments. The SDT removed Requirement R2 and the associated attachment from the revised standard.
MRO NERC
Standards Review
Subcommittee
Agree
Attachment 1, Physical Security is a basis for the SAR for Project 2009-02, Disturbance and Sabotage reporting
SDT.
Response: The SDT thanks you for your comments and bringing that reference for PSEA to our attention. The SDT removed Requirement R2 and
the associated attachment from the revised standard. The SDT has recommended that Project 2009-01 – Disturbance and Sabotage Reporting
pick up the requirement to issue notifications to operating entities when the BES is in an alert or emergency state.
PacifiCorp
Disagree
Currently, PacifiCorp’s Open Oasis Access Same-Time Information System (OASIS) allows time to be shown
displays time in Pacific Standard Time. Mandating all Interoperability Communications to be held in Central
Standard Time may cause confusion with regard to transactions and activities conducted on OASIS - which
ultimately relate to real-time operations.
Response: The SDT thanks you for your comments. The SDT has developed an alternative for the common time zone. Instead of requiring the
use of a single continent-wide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly
state the time and time zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities
in a different time zone.
E.ON U.S. LLC
Disagree
If the requisite protocols are intended to be followed by all field personnel, applicability of these requirements
to Distribution Providers could run afoul of FPA Section 215(a) codified in 18CFR39.1.
Response: The SDT thanks you for your comments. The SDT requires more detail on how FPA Section 215(a) codified in 18CFR39.1 is affected by
the protocols of COM- 003-01. The second draft of COM-003 provides greater clarity on when to use the various communication protocols.
May 2, 2012
283
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
Please review the second draft of the standard to see if you still have concerns about the applicability of these protocols.
We Energies
Agree
In general, establishing CST as a uniform time zone may conflict with individual Tariffs regarding references to
wholesale electric market commercial activities and could cause additional confusion if commercial market time
zone references are independent of reliability time zone references.
Response: The SDT thanks you for your comments.
The SDT has developed an alternative for the common time zone. Instead of requiring the use of a single continent-wide time zone, the
standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time zone, and indicate
whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Hydro-Québec
TransEnergie
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in the
requirements is an unnecessary burden for these areas. The requirement to use CST attempts to determine
HOW entities operate within their various footprints and it would significantly change the way many Markets
are structured. To implement this into existing Markets would cost significant time, and resources while not
enhancing reliability in these areas. When operating across time-zones, simply referencing “Central Standard
Time” or “Eastern Standard Time” is sufficient for other operating entities to reliably operate. Many entities
would have to modify their existing practices, hardware, software, Control System, billing systems, bidding
systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the second draft) and believes it has addressed the concerns
identified in your comments about time zones. Instead of requiring the use of a single continent-wide time zone, the standard now requires that
during Operating Communication an applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight
saving or standard time, when communicating with one or more entities in a different time zone.
IRC Standards
Review Committee
May 2, 2012
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in the
requirements is an unnecessary burden for these areas. The requirement to use CST attempts to determine
HOW entities operate within their various footprints and it would significantly change the way many Markets
are structured. To implement this into existing Markets would cost significant time, money and resources while
not enhancing reliability in these areas. We believe that, when operating across time-zones, simply referencing
284
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
“Central Standard Time” or “Eastern Standard Time” is sufficient for other operating entities to reliably operate;
also, let’s not lose sight of HOW MANY entities would have to modify their existing practices, hardware,
software, Control System, billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate Facilities that are a
part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the second draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
ISO New England
Inc.
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in the
requirements is an unnecessary burden for these areas.
The requirement to use CST attempts to determine HOW entities operate within their various footprints and it
would significantly change the way many Markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We believe
that, when operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the current draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
Northeast Power
Coordinating
Council
May 2, 2012
Agree
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in the
requirements is an unnecessary burden for these areas.
The requirement to use CST attempts to determine HOW entities operate within their various footprints and it
would significantly change the way many Markets are structured. To implement this into existing Markets
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
would cost significant time, and resources while not enhancing reliability in these areas. When operating across
time-zones, simply referencing “Central Standard Time” or “Eastern Standard Time” is sufficient for other
operating entities to reliably operate. Many entities would have to modify their existing practices, hardware,
software, Control System, billing systems, bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the current draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time when communicating with one or more entities in a different time zone.
Progress Energy
Carolina, Inc
no
National Grid
Disagree
None
NIPSCO
Disagree
none
NextEra Energy
Resources, LLC
Disagree
None at this time.
Consumers Energy
None.
Westar Energy
Agree
not aware
Orange and
Rockland Utilities,
Inc.
Disagree
Not aware
FirstEnergy
Not aware of any
Response: The SDT thanks you for your participation.
PEF
Agree
May 2, 2012
PEF recommends that the color coding and definitions that are used by Homeland Security also be used for the
notification of physical and cyber emergency alerts reported to the RC. This would follow the ES-ISAC standard
286
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
already adopted by the electric industry.
Response: The SDT thanks you for your comments. The SDT removed Requirement R2 and the associated attachment from the revised standard.
Electric Market
Policy
Agree
PJM members are only required to comply during an Emergency.
Response: The SDT thanks you for your comments. Please provide the specific Requirements and terms of those requirements that PJM
members “are only required to comply during an Emergency.”
Southern
Company
Transmission
Agree
Southern Company supports the SERC SOS comments. SERC SOS comments: We do see a potential conflict with
the Energy Policy Act 2005, which set the framework for the Electric Reliability Organization (ERO). The ERO’s
mission is to oversee and protect the reliability of the Bulk Electric System. This standard seems to cross the
line between reliability-related activities and other types of operating actions. The concern here is that system
operators will focus on the letter of the standard rather than on good operating practice. The fear of a violation
among operators may have a greater impact on reliability than the violation itself.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regard to concerns that COM-003 conflicts with the Energy Policy Act of 2005. The SDT respectfully
disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to reliable operations of the BES.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as
an acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during
alerts and emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently
conveyed and mutually understood for all operating conditions.” As one element of complying with this charge, the SDT has captured the
industry wide practice of three part communications as an integral element of this standard. This requirement is currently in COM-002-2 R2.
ExxonMobil
Research and
Engineering
Disagree
We are not aware of any conflicts.
Response: The SDT thanks you for your participation.
PJM
Agree
May 2, 2012
We do see a potential conflict with the Energy Policy Act 2005, which set the framework for the Electric
Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of the Bulk Electric
287
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
System. This standard seems to cross the line between reliability-related activities and other types of operating
actions which may be better suited for NAESB action. The concern here is that system operators will focus on
the letter of the standard rather than on good operating practice. The fear of a violation among operators may
have a greater impact on reliability than the violation itself. In some market structures, TSPs and LSE do not own
or operate equipment. Thus, including them in the requirements is an unnecessary burden for these areas.
The requirement to use CST attempts to determine HOW entities operate within their various footprints and it
would significantly change the way many Markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We believe
that, when operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regard to concerns that COM-003 conflicts with the Energy Policy Act of 2005. The SDT respectfully
disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to reliable operations of the BES.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as
an acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during
alerts and emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently
conveyed and mutually understood for all operating conditions.” As one element of complying with this charge, the SDT has captured the
industry wide practice of using three part communications as an integral element of this standard. This requirement is currently in COM-002-2
R2.
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES, The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R2, Part 1.1.3 of the current draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
PJM SOS
Comments
May 2, 2012
Agree
We do see a potential conflict with the Energy Policy Act 2005, which set the framework for the Electric
Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of the Bulk Electric
288
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
System. This standard seems to cross the line between reliability-related activities and other types of operating
actions which may be better suited for NAESB action.
The concern here is that system operators will focus on the letter of the standard rather than on good operating
practice. The fear of a violation among operators may have a greater impact on reliability than the violation
itself.
In some market structures, TSPs and LSE do not own or operate equipment. Thus, including them in the
requirements is an unnecessary burden for these areas.
The requirement to use CST attempts to determine HOW entities operate within their various footprints and it
would significantly change the way many Markets are structured. To implement this into existing Markets
would cost significant time, money and resources while not enhancing reliability in these areas. We believe
that, when operating across time-zones, simply referencing “Central Standard Time” or “Eastern Standard
Time” is sufficient for other operating entities to reliably operate; also, let’s not lose sight of HOW MANY
entities would have to modify their existing practices, hardware, software, Control System, billing systems,
bidding systems, etc. We are strongly opposed to this requirement.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regard to concerns that COM-003 conflicts with the Energy Policy Act of 2005. The SDT respectfully
disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to reliable operations of the BES.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as
an acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during
alerts and emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently
conveyed and mutually understood for all operating conditions.” As one element of complying with this charge, the SDT has captured the
industry wide practice of using three part communications as an integral element of this standard. This requirement is currently in COM-002-2
R2.The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES, The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the current draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
SERC OC&SOS
May 2, 2012
Agree
We do see a potential conflict with the Energy Policy Act of 2005, which set the framework for the Electric
289
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Standards Review
Group
Question 11 Comment
Reliability Organization (ERO). The ERO’s mission is to oversee and protect the reliability of the Bulk Electric
System. This standard seems to cross the line between reliability-related activities and other types of operating
actions.
The concern here is that system operators will focus on the letter of the standard rather than on good operating
practice. The fear of a violation among operators may have a greater impact on reliability than the violation
itself.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regard to concerns that COM-003 conflicts with the Energy Policy Act of 2005. The SDT respectfully
disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to reliable operations of the BES.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as
an acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during
alerts and emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently
conveyed and mutually understood for all operating conditions.” As one element of complying with this charge, the SDT has captured the
industry wide practice of using three part communications as an integral element of this standard. This requirement is currently in COM-002-2
R2.
PSEG Companies
Agree
Yes. The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regard to concerns that COM-003 conflicts with the Energy Policy Act of 2005. The SDT respectfully
disagrees, and believes that COM-003 will lead to a tightening of communications, which in turn will contribute to reliable operations of the BES.
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as
an acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during
alerts and emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently
conveyed and mutually understood for all operating conditions.” As one element of complying with this charge, the SDT has captured the
industry wide practice of using three part communications as an integral element of this standard. This requirement is currently in COM-002-2
R2.
May 2, 2012
290
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 11 Comment
The SDT appreciates the comments with regards to concerns related to including TSPs and LSEs that do not own or operate facilities that are a
part of the BES, The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR.
The SDT has modified Requirement R4 (Now Requirement R1, Part 1.1.3 of the current draft). Instead of requiring the use of a single continentwide time zone, the standard now requires that during Operating Communication an applicable entity shall explicitly state the time and time
zone, and indicate whether the time is daylight saving or standard time, when communicating with one or more entities in a different time zone.
May 2, 2012
291
Consideration of Comments on OPCP SDT — Project 2007-02
12.
Do you have any other comments to improve the draft standard? If yes, please elaborate in the comment
area.
Summary Consideration:
Many commenters stated high VRFs and severe VSLs are too harsh for the
requirements of this standard. The potential penalties associated with
violating these requirements could be very significant for violating a
communication protocol even if no adverse impact occurs on the BES. The
SDT has modified the VRFs and VSLs to comply with approved NERC and
FERC guidelines. The SDT believes the new assignments more accurately
classify the VRFs and VSLs assigned to the Requirements in COM-003-1. In
the second draft of the standard all VRFs are Medium.
Some commenters suggested modifications to COM-002-3 should be
switched from Project 2006-06 and absorbed into COM-003-1 to simplify
coordination of the changes on each of these standards. The Operating
Personnel Communications Protocol SDT has been directed by the NERC
Standards Committee to coordinate with the RC SDT and continue
development of both standards simultaneously. Note however, that the
OPCP SDT proposes retirement of COM-002 when COM-003 becomes
effective.
The Quality Review team recommended that the OPCP SDT
modify Requirements R2 and R3 to clarify that these
requirements for performance of three-part
communication exclude Reliability Directives. This
eliminates the double jeopardy issue that may have existed
if both COM-002 and COM-003 were approved.
Thus – the revised COM-003 does include the term,
Reliability Directive. In addition, the implementation plan
was revised to no longer recommend retirement of COM002. As modified, the two standards can exist without
conflict. COM-002 requires the issuer of an Operating
Communication to identify that communication as a
“Reliability Directive” which gives recipients notice that the
directive is associated with an “Emergency”. COM-003 now
specifically identifies that the requirements for thee part
communication do not include “Reliability Directives.”
Per Standards Committee guidance, the SDT did not revise
all the responses in this report that indicate COM-003 does
not include the term, “Reliability Directive” nor did the
team revise all the responses that indicated the team
recommended retirement of COM-002.
Commenters pointed out the effective date listed in the proposed standard
did not agree with the effective date shown in the COM-003-1
Implementation Plan. After comparing the effective dates listed in the
COM-003-1 Implementation Plan and the proposed standard, the SDT has
modified the Implementation Plan to match the proposed standard’s effective date, providing entities at least six months after
approvals before the standard becomes effective.
One commenter indicated that the Data Retention period should be expressed in days instead of months because of the
inconsistency in the number of days per month. The SDT agrees that that the data retention periods should be expressed in a term
other than months.
Commenters questioned if the standard should apply to Transmission Owners, Generator Owners, Distribution Providers,
Interchange Authorities (Interchange Coordinators), Load-Serving Entities, and Purchasing-Selling Entities. The second draft of the
May 2, 2012
292
Consideration of Comments on OPCP SDT — Project 2007-02
standard has eliminated the Transmission Owner, Load-Serving Entity, and Purchasing-Selling Entity from the list of applicable
entities. The SDT did not remove the Distribution Provider and did not add the Generator Owner or the Interchange Authority
(Interchange Coordinator). The intent of the proposed standard is to apply only to those entities that send or receive Operating
Communications and operate Facilities on the BES as a result of those communications, thus eliminating both the Transmission
Owner and Transmission Service Provider from the standard. Because the Distribution Provider does participate in real-time
communications for actions such as load shedding, the Distribution Provider was not removed from the second draft of the
standard.
A commenter stated that the requirement in the Data Retention section for an entity found to be non-compliant to retain data until
found compliant does not belong in a standard, because it is already mandated in the NERC Compliance Violation Investigation
process. The SDT developed this language to be consistent with the NERC Standard Drafting Team Guidelines.
A commenter recommends the word “timely” should be removed from the Purpose statement since none of the requirements
specify a time period. Since none of the Requirements specify a time limit for executing the required communications, the SDT
removed “timely” from the second draft of COM-003.
Organization
Yes or No
American Municipal
Power
Agree
Bureau of
Reclamation
Agree
ERCOT ISO
Agree
ATC and ITC
Disagree
British Columbia
Transmission
Corporation
Disagree
Entergy Services
Disagree
Georgia
Transmission Corp
Disagree
May 2, 2012
Question 12 Comment
293
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Kansas City Power
& Light
Disagree
Manitoba Hydro
Disagree
NYSEG
Disagree
Oncor Electric
Delivery
Disagree
PacifiCorp
Disagree
Pepco Holdings,
Inc. - Affiliates
Disagree
Sunflower Electric
Power Corporation
Disagree
Western Area
Power
Administration
Disagree
Florida Municipal
Power Agency
(FMPA) and some
members
Agree
Question 12 Comment
(FMPA assumes that "Agree" means "Yes, we do have other comments)
The Violation Risk Factor for R2 should be “Low”, not “High”. It is administrative in nature.
The SDT removed Requirement R2 from the revised standard.
The Measures make the types of evidence an “or” statement, e.g., “(e)vidence may include ... voice recording,
transcripts, operating logs, OR on site observations” (emphasis added). The Data Retention section seems to
make evidence an “and” statement, e.g., “Each ... (Responsible Entity) shall retain ... dated operator logs for the
most recent 12 months AND voice recordings or transcripts ... for ... 3 months” (emphasis added). These
statements are inconsistent with each other and both ought to be “or” statements.
The SDT appreciates the comment in regard to the difference between the Data Retention requirement and the
documentation listed in Measure 2 (new standard format). The Data Retention section “format” for standards
has been modified to eliminate the specificity in the section. As a result the AND language has been eliminated
May 2, 2012
294
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 12 Comment
and the conflict is eliminated.
After consideration, the SDT has decided to modify the language of Due to the variability of the length of a
month, data retention ought to be expressed in days rather than months, e.g., 90 days instead of 3 months.
The SDT agrees that that the data retention periods should be expressed in a term other than months. The
SDT revised the standard so that the data retention now says, “the most recent 365 days.”
Why is the Transmission Owner included in the applicability of the standard? What “Interoperability
Communications” are they involved with? If the Transmission Owner is included, why isn’t the Generation
Owner? Explain the inconsistent treatment of Transmission Owners and Generator Owners.R3
With regard to COM-003-1 the second draft of the standard does not apply to Transmission Owners or
Generator Owners as (according to the Functional Model) they don’t engage in real-time Operating
Communications. The intent of the proposed standard is to apply only to those entities that send or receive
Operating Communications and operate facilities on the BES as a result of those communications.
- what if an entity starts to communicate in a language other than English, but, as part of the 3 part
communication process changes to English and completes all steps of 3-part communication in English, is that
entity non-compliant or compliant?
The SDT would like to point out that R3 is now requirement R1 Part 1.1.1 in the revised standard and uses the
term “Operating Communications”. As envisioned, the oral or written Operating Communication would be in
English no matter what language previous conversations took place in unless another language is mandated
law or regulation.
How should EOP-001-0, R4.1 coordinate with COM-003-1? Should EOP-001-0, R4.1 focus on internal Entity
communications?
R4.1 of EOP-001 as a whole requires “plans” for mitigating emergencies. These communication protocols differ
from COM-003 protocols in that R4.1 (now R3.1 in EOP-001-2b) involves actions and tasks for mitigating
operational emergencies and for coordinating activities; not how to communicate.
May 2, 2012
295
Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 12 Comment
Response: The SDT thanks you for your comments. Please see our responses above.
Pacific Northwest
Small Utilities
Comment Group
Agree
(This is a Yes or No Questions)The proposed standard seems to have just thrown everyone into the pot, and not
considered how registered entities interact with the BES or what other standard requirements apply to them.
We cannot lose sight of the original objective of, not only ERO Compliance, but the “purpose” described in
regards to the development of this standard (Posted as background information on Project 2007-02). The stated
purpose is, “To ensure that reliability-related information is conveyed effectively, accurately, consistently, and
timely to ensure mutual understanding by all key parties, especially during alerts and emergencies.”With this said,
The BA’s, TOP’s and RC’s are the key registered entities that have the power to take action, they are the key
players in the communication of information which “impacts” the BES. We fail to see the value added by
including DP’s and LSE in most of the requirements of this standard. If anything, we see the opposite affect taking
place by adding DP & LSE’s. This may be an extra tier of unnecessary communication that would not only slow
down this process, but just may contribute to greater inefficiencies. Please note that many DP & LSE in the WECC
region are very small utilities that do not have 24 by 7 coverage.
Response: The SDT thanks you for your comments.
The SDT has modified R4 and R5 (now requirement R1 Parts 1.3.1, 1.3.2 and 1.3.3 in the second draft of COM-003) to address your concerns. The
revisions made narrow the list of responsible entities to just those that actually are involved in “Operating Communication” – defined as
communication of instruction to change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric System.
The SDT appreciates the comments with regards to concerns related to including DPs and LSEs. The SDT has removed the LSEs because they were
not bound by this requirement in the originating SAR. The specified role of the DP to shed load justifies the retention of the DP as an applicable
Entity.
COM-003-1 does not address the required real time response or the required coverage for small utilities. To the extent they operate BES assets they
must comply with applicable standards.
Xcel Energy
May 2, 2012
Agree
1) Recommend removal of the references to measures in the data retention section of the standard. It is only
necessary to refer to the requirements, which is already included.
2) The data retention section should also be modified to refer generically to evidence, instead of "dated operator
logs... and voice recordings or transcripts of voice recordings...". This is because the measures specifically allow
for other types of evidence, as stated: "Evidence of use may include but is not limited to voice recordings,
transcripts, operating logs, or on site observations."
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Consideration of Comments on OPCP SDT — Project 2007-02
Organization
Yes or No
Question 12 Comment
Response: The SDT thanks you for your comments.
1 The SDT appreciates the comment in regard to the Data Retention section referring to Requirements instead of Measures. The drafting team has
reviewed the Drafting Team Guideline document and notes that on page 41, both Requirements and Measures appear in Data Retention.
2 The SDT agrees with the comment regarding the use of “evidence” in the Data Retention section and has modified the Data Retention section to
eliminate the specific references to types of evidence in support of your suggestion.
Consumers Energy
Agree
Amplification of the communication process is needed but this draft reaches beyond Communication to the start
of drafting procedures for three separate emergency conditions while it leaves one alone. Focusing on the
communication process is in order.
Response: The SDT thanks you for your comments.
The SDT removed Requirement R2 and the associated Attachment from the second draft of COM-003 based on stakeholder comments and
concerns that the required performance went beyond requiring use of specific communications protocols.
Duke Energy
Agree
As a general comment, all the requirements other than R1 are High VRFS with only Severe VSLs. As this standard
is written to apply broadly to routine as well as emergency communications between entities, we believe that
failure to meet these requirements would rarely impact the reliability of the Bulk Electric System. For example if
in routine switching an operator says “Baker” instead of “Bravo”, the entity is subject to FERC’s most severe
penalty.
Clearly the basis for this standard needs to be reassessed. If we use the test that if a requirement or a standard
supports/encourages reliability and security, then entities should invest the time and effort to track performance
to ensure auditable compliance. For example - Does DCS compliance support/encourage reliability/security? The
industry would generally say yes - so the tracking and determination of auditable compliance is justified. But
would auditable compliance to this draft of COM-003-1 support/encourage reliability/security? We don’t think so,
given the vague and general nature of this draft. It certainly would not justify the amount of work and effort it
would take to ensure auditable compliance with this COM-003-1 draft, given the amount of effort it would take to
monitor all recorded communications that fit within this vague draft standard. Bottom line is that we think COM003 is not needed. As proposed, it is a “how” and not a “what” based standard that will create more distraction
from reliability/security than any value it might add.
Response: The SDT thanks you for your comments.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The VRFs in the second draft are all Medium.
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Additionally, the SDT modified the requirement to approve accurate “accurate alpha-numeric clarifiers” to address the example you provided. (See
Requirement R1, Part 1.2 in the second draft of COM-003.)
The Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for alerts and emergency
communications. FERC Order 693 P531 directed that communication protocols be tightened and suggested a new COM Reliability Standard as an
acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during alerts and
emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditions.”
The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the standard
is more focused on “what” protocols to use in specific situations. In short COM 003 is needed and required.
New York State
Reliability Council
Agree
Comments: R1 requires each entity to create a CPOP. There is not a requirement to coordinate CPOP’s amongst
entities beyond the requirements in the Standard. There is no requirement to exchange CPOP’s between entities
with an operating relationship. The SDT should consider adding a requirement either that allows entities with
operating relationships to request and be provided a copy of the other’s CPOP, or a requirement requiring the
exchange of CPOP between entities with operating relationships.
Additionally, we cannot understand how all requirements but R1 have been determined to have a HIGH VRF
when, many of them are dictating HOW communications should take place and not when and why or what. High
Risk Factor requirement (a) is one that, if violated, could directly cause or contribute to bulk power system
instability, separation, or a cascading sequence of failures, or could place the bulk power system at an
unacceptable risk of instability, separation, or cascading failures. NYSRC does not believe that any requirement in
this Standard if violated would have the results specified in the definition of a High VRF, especially since these
requirements are addressing the HOW of communication.
Response: The SDT thanks you for your comments.
Many of the comments we received pointed out that having a CPOP is an administrative activity. The SDT deleted the requirement for a CPOP in
the second draft of COM-003-1.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of the standard all VRFs are
Medium. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the Requirements in COM-003-1.
ExxonMobil
May 2, 2012
Agree
Compliance paragraph 1.4 bullet 2 implies that all entities retain 3 months worth of telephone voice recordings
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Engineering
Question 12 Comment
through its use of the word ‘and’ in the statement “Distribution Provider shall retain for Requirement 2 through 7,
Measure 2 through 7, dated operator logs for the most recent 12 months and voice recordings or transcripts of
voice recordings for the most recent 3 months”. While many utility companies employ the use of voice recorders,
many industrial facilities do not. When a facility does not currently employ the use of voice recorders, is it the
intent of this document to require the facility to install the infrastructure necessary to record and store telephone
conversations? If so, what is the time line for deploying the infrastructure necessary to record and store
telephone conversations?
Currently, we maintain a log of our communications which includes the question or instruction and our (or in the
case of a question the third party’s) response. Does this satisfy the evidence criteria as defined in measures M2
through M7 of the proposed standard?
Response: The SDT thanks you for your comments.
The SDT appreciates the comment in regard to the difference between the Data Retention requirement and the documentation listed in Measures
2 through 7. After consideration, the SDT has decided to modify the language of the Data Retention section to eliminate specific references to
types of evidence.
Recorded voice conversations are one of several measurement options. The entity is permitted to use any measurement method to demonstrate
compliance. Written transcripts with appropriate and accurate information or on site observations are acceptable forms of evidence.
FirstEnergy
May 2, 2012
Agree
Coordination of SDT Efforts - We feel that the NERC Standards Committee should direct the Reliability
Coordination SDT to hand over COM-002 to this OPCPSDT since those requirements will eventually be moved to
COM-003-1. It is difficult to coordinate all these changes on a separate basis and moving the development to one
SDT would help better coordinate these efforts. The current path forward is inefficient and causes confusion, not
only for industry but also for the two drafting teams.
Purpose Statement - We feel the phrase "especially during alerts and emergencies" implies that using proper
communications protocol during normal operating situations is not as important as during emergencies. It is not
appropriate to include this phrase in the purpose statement of a standard, and we suggest it be removed. Also,
we suggest removing the word "timely" since this standard does not mandate time limits on communications.
Compliance Section 1.4 Data Retention - We do not agree with the following statement for data retention "If a
Transmission Operator, Transmission Owner, Balancing Authority, Reliability Coordinator, Generator Operator,
Transmission Service Provider, Load Serving Entity or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until found compliant." We feel that this is not appropriate in a
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reliability standard since it is already mandated through Compliance Violation Investigations (CVI). Also, we feel
that it is more applicable to NERC’s Rules of Procedure. Therefore, we suggest it be removed from the standard.
Response: The SDT thanks you for your comments.
The SDT sees some merit in your recommendation to hand over COM-002 to this OPCP SDT but the RC SDT and the OPCP SDT are at a stage in the
standards development process where that change would impede progress on both initiatives. The drafting teams are coordinating the efforts of
the two SDTs to address issues and to ensure there are no conflicts. As envisioned, the COM-002 standard will be retried when COM-003 becomes
effective.
The SDT also agrees with your statement that using proper communications protocol during normal operating situations is as important as during
emergencies. We have removed the phrase "especially during alerts and emergencies" from the purpose statement. It now reads:
“To specify clear, formal and universally applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of the BES.”
In addition, the SDT created the proposed term “Operations Communications” that applies to any communications that will change the state of the
BES.
The SDT appreciates the comment in regard to the word “timely” being used in the Purpose statement of the proposed standard. Since none of the
Requirements specify a time limit for executing the required communications, the SDT removed “timely”.
The SDT appreciates the comment in regard to Data Retention for an entity which is found to be non-compliant. The SDT developed this language
to be consistent with the NERC Standard Drafting Team Guidelines. This has been updated to now say, “until mitigation is complete”
Great River Energy
Agree
GRE believes that the existing standard COM-002 is actually better than this standard. This standard actually
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements that add
little or no value to reliability.
Response: The SDT thanks you for your comments. The SDT feels that the current version of the draft COM-003-1 standard clarifies a lot of industry
concerns and will contribute greater value to reliability.
PPL
Agree
If this draft standard would be approved as it is currently proposed, the implementation plan is way too short
considering all the process and system changes that are needed to comply with the numerous additional
requirements.
Response: The SDT thanks you for your comments.
The SDT has made several changes to the draft standard that will simplify the Implementation Plan. The SDT has reviewed the Implementation Plan
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and extended it to give a minimum of six months following approval before the new requirements become effective.
NextEra Energy
Resources, LLC
Agree
In the case of nuclear plant operations, NRC communication requirements and the requirements of NERC NUC001 for nuclear facilities more than adequately cover communication requirements. COM-003 should not be
applicable to Nuclear Generator Operators since doing so will introduce an additional, unnecessary, and
potentially conflicting level of requirements.
Measures: Next Era suggests that the SDT clarify the periodicity of providing evidence of compliance and on what
constitutes sufficient evidence of CPOP acceptance.
Violation Severity Levels: Next Era encourages the SDT to revisit the violation severity levels. In the case of most
of the requirements it is unreasonable to levy Severe penalties in instances where the operator may have
deviated from the requirements but the communication occurred in an unencumbered and successful manner as
evidenced by the use/acknowledgement outcomes of three-part communication.
Response: The SDT thanks you for your comments.
The SDT has reviewed NUC 001, specifically R9.4 and could not readily find a conflict with the second draft of COM 003. The SDT would expect the
entities affected to incorporate the Requirements of COM 003 where applicable.
The SDT has deleted the requirement for a CPOP in the second draft of COM-003-1.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. All requirements in the second draft of the standard
have been assigned a Medium VRF. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in COM-003-1.
Transmission
Owner
May 2, 2012
Agree
In the case of nuclear plant operations, NRC communication requirements and the requirements of NERC NUC001 for nuclear facilities more than adequately cover communication requirements. COM-003 should not be
applicable to Nuclear Generator Operators since doing so will introduce an additional, unnecessary, and
potentially conflicting level of requirements
Measures: FPL suggests that the SDT clarify the periodicity of providing evidence of compliance and on what
constitutes sufficient evidence of CPOP acceptance.
Violation Severity Levels: FPL encourages the SDT to revisit the violation severity levels. In the case of most of the
requirements it is unreasonable to levy severe penalties in instances where the operator may have deviated from
the requirements but the communication occurred in an unencumbered and successful manner as evidenced by
the use/acknowledgement outcomes of three-part communication.
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Response: The SDT thanks you for your comments.
The SDT has reviewed NUC 001, specifically R9.4 and could not readily find a conflict with the second draft of COM 003. The SDT would expect the
entities affected to incorporate the Requirements of COM 003 where applicable.
The SDT has deleted the requirement for a CPOP in the second draft of COM-003-1.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. All requirements in the second draft of the standard
have been assigned a Medium VRF. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in COM-003-1.
Northeast Utilities
Agree
Many of the requirement proposed in this posting either reiterate the drafts as posted (i.e. English language) or
introduce confusion when compared to the drafts as posted. The scope should be limited to R2 and R7, so as not
to duplicate or contradict the on-going work of other SDTs. (Agree = Yes)
Response: The SDT thanks you for your comments.
The SDT feels that the requirements in the second draft of COM 003 are appropriate because they comply with the purpose identified in the SAR.
The SDT also is aware of the efforts and progress of other SDTs and coordinates with them in order to avoid duplicative efforts or contradiction.
NERC Staff
Agree
NERC staff questions whether this standard applies to the Transmission Service Provider and the Transmission
Owner. It is unclear from the functional model where they would be involved in real-time operations
communications.
It is also unclear why the Violation Risk Factor for every requirement is High, and the Violation Severity Level for
all but the first requirement is Severe. This automatically elevates any violation of any of these requirements to
the highest penalty level that is imposed. The NERC staff recommends that the SDT review the latest guidelines
for assignment of VSLs and consider alternatives that could expand/gradate the VSLs to account for varying
severity of non-compliances.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs. The SDT has removed the TSPs because they were not bound
by this requirement in the originating SAR. The SDT removed the Transmission Service Provider and Transmission Owner from the second draft of
the standard. The intent of the proposed standard is to apply only to those entities that send or receive ”Operating Communications.” The SDT has
modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. All requirements in the second draft of the standard have been
assigned a Medium VRF. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the Requirements in COMMay 2, 2012
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003-1.
Westar Energy
Agree
no additional comments
Orange and
Rockland Utilities,
Inc.
Disagree
No additional Comments
Response: The SDT thanks you for your participation.
NorthWestern
Energy
Agree
NorthWestern feels that the current communication standards are sufficient for reliable BES Operations.
Response: The SDT thanks you for your comments. The SDT respectfully points out that various FERC Orders and Directives (FERC Order 693 P531 )
supported by the findings of the Blackout Report Recommendation #26 states, communication protocols should be tightened especially those for
alerts and emergency communications. That communication protocols be tightened and suggested a new COM Reliability Standard as an
acceptable approach. The SAR for this SDT charged the team to “tighten communication protocols, especially for communications during alerts and
emergencies.” Additionally the SAR required “the use of specific communication protocols, enabling information to be efficiently conveyed and
mutually understood for all operating conditions.”
PEF
Agree
PEF believes additional NERC defined entities (such as Generators Owners) should be made applicable to this
standard. Specifically, PEF believes that the Interchange Authority should be added due to the communications
required between the Reliability Coordinator and the Interchange Authority.
PEF also believes that the adoption of R4 would have major implications on the tagging process. PEF believes
that all tagging would be required to be done using CST due to schedule check-out between BAs, TSPs, LSEs and
RCs. Therefore, PSEs should be made applicable as well for R3 and R4.
Response: The SDT thanks you for your comments.
The proposed standard has been made applicable to the Functional Entities defined by the SAR. The intent of the proposed standard is to apply
only to those entities that send or receive Operating Communications and own and operate Facilities on the BES as a result of those
communications.
The SDT understands your concerns and is proposing an alternative requirement in the second draft of COM 003 which we believe will address your
concerns. Instead of requiring the use of a single continent-wide time zone, the standard now requires that during Operating Communication an
applicable entity shall explicitly state the time and time zone, and indicate whether the time is daylight saving or standard time, when
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communicating with one or more entities in a different time zone.
Long Island Power
Authority
Agree
R1 requires each entity to create a CPOP. There is not a requirement to coordinate CPOP’s amongst entities
beyond the requirements in the Standard. There is no requirement to exchange CPOP’s between entities with an
operating relationship. The SDT should consider adding a requirement either that allows entities with operating
relationships to request and be provided a copy of the other’s CPOP, or a requirement requiring the exchange of
CPOP between entities with operating relationships.
Additionally, we cannot understand how all requirements but R1 have been determined to have a HIGH VRF
when, many of them are dictating HOW communications should take place and not when and why or what. High
Risk Factor requirement (a) is one that, if violated, could directly cause or contribute to bulk power system
instability, separation, or a cascading sequence of failures, or could place the bulk power system at an
unacceptable risk of instability, separation, or cascading failures. LIPA does not believe that any requirement in
this Standard if violated would have the results specified in the definition of a High VRF, especially since these
requirements are addressing the HOW of communication.
Response: The SDT thanks you for your comments. Many of the comments we received pointed out that this is an administrative function and not
a reliability function. It has been decided by the SDT to delete the requirement for a CPOP in the second draft of COM-003-1.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. All requirements in the second draft of the standard
have been assigned a Medium VRF. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in the second draft of COM-003-1.
Bonneville Power
Administration
Agree
R3 creates a special need for multi language operators. US and US-involved entities need to use English in all
instances, not only for reliability purposes, but for internal communication purposes and to be able to hire
replacements without competing for an artificially small set of operators and to be auditable by NERC.
Response: The SDT thanks you for your comments. The SDT agrees that English is the mandatory language for ”Operating Communications“ except
where another language is mandated by law or regulation.
We Energies
May 2, 2012
Agree
Remove “timely” from the Purpose section, since a time period is not part of any requirement.
According to the NERC Reliability Standards Development Procedure, Compliance Monitoring Period and Reset
are required elements, and should be included. M1 through M7 should indicate which requirement they pertain
to.
Compliance enforcement should be focused on Reliability Directives only. Rather than proving 100% compliance,
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it is more practical if each party is obligated to report instances of unclear communication to the other
party/parties involved in the Reliability Directive(s). Defining a remediation plan could be part of the
requirement, with a measure being whether or not the remediation was implemented.
An overall observation is that the intended communication updates could be implemented through modification
of existing COM-001 & COM-002 standards without the need for another overlapping standard. Additional
industry focus regarding communication protocols could be further emphasized through NERC System Operation
Certification Program requirements and training.
Response: The SDT thanks you for your comments.
The word “timely” has been removed from the purpose statement in the second draft of COM 003--1.
The requirement for Compliance Monitoring Period and Reset has been removed from the RSDP – the RSDP was retired some time ago. Standards
are now developed in accordance with the Standard Processes Manual.
For the second draft of the standard, the SDT has added a reference to each Measure to identify the requirement it supports.
Compliance will be applicable to all ”Operating Communications” that alter the state of the Bulk Electric System. The terms “directive” and
“Reliability Directive” have not been included in the second draft of COM-003.
With regard to your proposal to report unclear communication, the SDT has changed the standard’s requirement to direct both parties involved in
operating communications to repeat information until clarity is achieved among all parties. (See Requirements R2and R3 in the second draft of
COM-003.)The SDT believes this will address your concern.
The SDT feels that the existing COM standards are not clear in some instances and do not cover important communication protocols. The proposed
plan is to retire COM-002 and any of its successors when COM-003 becomes effective.
Southern Company
Transmission
May 2, 2012
Agree
Southern Company supports SERC SOS comments.
SERC SOS comments:
This review group has identified several problems with this standard, as noted above.
Other observations include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In the standard,
the effective date mentions one calendar year following regulatory approval, while the implementation plan
refers to the third calendar quarter after regulatory approval.
The SDT has made several changes to the draft Standard that required changes to the Implementation Plan.
The SDT updated the Implementation Plan to ensure the changes can be made in an appropriate time frame
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and accurately reflect the changes to the Standard. In the second drafts of the COM-003 standard and
Implementation Plan, the effective dates are identical and provide at least six months for entities to become
compliant.
Furthermore, we do not feel that any of the requirements in this standard warrant Violation Risk Factors or
Violation Severity Levels in the high or severe category. In summary, this review group feels that COM-003-1 is
not yet ready to be acted upon and may have been posted too soon.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard, all requirements have been assigned a Medium VRF. The SDT believes the new
assignments more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of
COM-003-1.
There does not seem to be sufficient coordination between the drafting teams of all the COM standards, or any
attempt to integrate these standards.
The SDT is working with the RC SDT to avoid conflicts – and proposes retiring COM-002 when COM-003
becomes effective.
One example is the inconsistency between COM-003-1 and COM-002-3 regarding the meaning of three-part
communication (mentioned in our response to Question 1 above).As noted above, we feel that many of the
requirements prescribe specific “how to” methods for compliance rather than focusing on the “what” of the
requirement.
Another way of looking at the requirements for three-part communication would be to say that the
requirements specify “what” by requiring confirmation that the message was accurately received.
Overall, COM-003-1 is much too prescriptive to be tied to million dollar-level fines.
Southern Company comments:
There are possible inconsistencies with the references to the term “CIP Free Form” and a more generic term
“Free Form” in the tables described in Attachment 1 - COM-003-1 - Operating State Alert Levels. Reference the
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fields where functional entities “outside” the Reliability Coordinator Area are identified for both the initial alert
notification and the end of alert notification.
•
For Physical Security, the field mentions only RC’s using the “CIP Free Form.” For Cyber Security, the field
mentions RC’s and CIP Participants using the “CIP Free Form.”
•
For Transmission Emergency Alerts, the field mentions only RC’s using the generic “Free Form.” Is there a
distinction between the two forms?
•
Is it consistent to reference CIP Participants only for Cyber Security alerts and not for Physical or
Transmission?
The SDT has reviewed and addressed the form and participation issues you raised. The requirements associated
with the Alert Levels have been removed from the second draft of the standard.
Although this standard is well intentioned it is not ready for presentation to the ballot body. When this standard
is applicable is in question just by the way the Title and Purpose are written. The Purpose needs to make it
absolutely clear to all parties, complying entities as well as compliance enforcement, when the standard is
applicable. For example, the Purpose of the standard is subject to interpretation. Does this standard apply all of
the time or just during Alerts and Emergencies? Or does the word especially mean that a non-compliance during
an emergency is more severe? Is the phonetic alphabet required when an alert is declared or just after the alert is
declared?
The SDT believes the Title is straightforward and has revised the Purpose Statement to read: “To specify clear,
formal and universally applied communication protocols that reduce the possibility of miscommunication
which could lead to action or inaction harmful to the reliability of the BES.” We believe this more accurately
defines the problem and the solution.
This standard has a charge: to address the requirements of the SAR, FERC Order 693 and the Blackout Report –
item 26.
The draft revisions, based on stakeholder comments, clarify applicability with the proposed definition of
Operating Communications which could include routine as well as alert and emergency conditions.
Response: The SDT thanks you for your comments. Please see our responses above.
California
May 2, 2012
Agree
The Drafting team should take a hard look at the VRFs and VSLs established in this standard and contrast them
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against VRFs and VSLs for other adopted standards. We do not feel, as an example, that the use of Spanish in a
normal communication between two companies, while improper, should carry a VRF of ‘high’ with a VSL of
‘severe’. The draft standard focuses too much attention on prescriptive remedy than ensuring understanding.
Response: The SDT thanks you for your comments.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of the standard, all requirements
have been assigned a Medium VRF. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in the second draft of COM-003-1.
Hydro-Québec
TransEnergie
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes more
confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that add little or no value
to reliability. All requirements with the exception of R1 have been determined to have a HIGH VRF, when many of
them are dictating HOW communications should take place and not when, why, or what.COM-002 retirement
does not appear to be consistent with the direction of the RC SDT in Project 2006-06. The RC SDT is adding
requirements. More coordination is required between the Standard Drafting Teams. Again, we support the work
being done by the RC SDT and RTO SDT and do not believe this adds more necessary requirements.
The SDT respectfully disagrees with you statement regarding COM-002 as a superior standard. We do not see it
as comparative nor do we feel the second draft of COM-003 creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. The SDTs are coordinating issues to ensure there are no
conflicts and that one standard supports the requirements of the other. Note that the implementation plan for
COM-003 includes retirement of COM-002.
Many of the requirements proposed in this posting either reiterate the drafts as posted (i.e. English language) or
introduce confusion when compared to the drafts as posted.
The SDTs should limit their scope to R2 and R7, so as not to duplicate or contradict the on-going work of other
SDTs.
The SDT feels that the requirements in the second draft of COM 003 are appropriate because they support the
purpose identified in the SAR.
The SDT appears to have adopted severe violations for every infraction. There should be some gradations, using
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increasing severity based on the number of or severity of any infractions.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard, all requirements have been assigned a Medium VRF. The SDT believes the new
assignments more accurately classify the VRFs and VSLs assigned to the requirements in second draft of COM003-1.
Definitions: The standard should define other terms, as well, including the following:
o reliability-related information,
o “... state or status of an element or facility of the BES ...
The SDT has eliminated the three original definitions to the proposed COM-003-1 standard and defined
Operating Communication in the revised draft to address industry comments.
Note that in the second draft of COM-003, the SDT did capitalize the terms, “Element” and “Facility” to ensure
their meaning is clear.
”The standard should also have provision to include the boundaries (components) of an “element,” and the
meaning of the terms “state or status” in the written communication protocol. For example, is the gas
compressor of a 345kV breaker considered part of this element, and so would a change in its “state or status” be
covered?
Element is a defined term in the NERC Glossary – in the revised standard the term has been capitalized for
clarity.
The VRFs for R2-R7 are all “High”, and the VSLs are all “Severe” are too harsh. Failing to comply with one of the
requirements does not automatically mean that a miscommunication occurred that caused a reliability problem.
There should be a “Moderate” VSL for failure to comply with a requirement, but no miscommunication occurred.
There should be a “High” VSL for failure to comply with a requirement that caused a miscommunication but
resulted in no violation of another reliability standard. The “Severe” VSL should only apply to failures to comply
with a requirement that caused a miscommunication that lead to a violation of another reliability standard, or
caused a reliability problem.
SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of
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the standard, all requirements have been assigned a Medium VRF. The SDT believes the new assignments
more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of COM-003-1.
In addition, as stated earlier, this Standard focuses on “how” certain tasks should be performed and conflicts with
NERC’s position of pursuing performance based and results based Standards.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that
the second draft of the standard is more focused on “what” protocols to use in specific situations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the reliability of
the BES. This was identified by the NERC President in his January 2011 report to the industry as one of the
eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The
goal, therefore, is to specify clear, formal and universally applied communication protocols that reduce the
possibility of miscommunication. The key objective to accomplish this goal is to use communication protocols
to reduce or correct misunderstandings. The requirements have been revised to better accomplish this
objective, and are risk-mitigating requirements (while operator performance is measured, the actions
themselves are primarily designed to mitigate the risk of miscommunication that could lead to poor BES
performance). We believe this standard is consistent with results-based principles, and it will improve the
reliability of the BES.
Based on these considerations, work on this Standard should be stopped until work on Project 2006-06 has been
completed and approved. This approach is consistent with the August 2003 Blackout Recommendation #26
“failure to identify emergency conditions and communicate that status to neighboring systems, and upgrade
communication system hardware where appropriate” which actually focused on communications during
emergencies, which is the scope of Project 2006-06. After Project 2006-06 is completed, a determination can be
made on the disposition of this Standard. This Standard should be effective uniformly continent-wide.
The SDT respectfully disagrees with your statement that the team should stop work on COM-003-1 until project
2006-6 is complete.
The SDT is working in accordance with the August 2003 Blackout Recommendation #26 and FERC Order 693
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Question 12 Comment
directives.
Response: The SDT thanks you for your comments. Please see our responses above.
Northeast Power
Coordinating
Council
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes more
confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that add little or no value
to reliability. All requirements with the exception of R1 have been determined to have a HIGH VRF, when many of
them are dictating HOW communications should take place and not when, why, or what.COM-002 retirement
does not appear to be consistent with the direction of the RC SDT in Project 2006-06. The RC SDT is adding
requirements. More coordination is required between the Standard Drafting Teams. Again, we support the work
being done by the RC SDT and RTO SDT and do not believe this adds more necessary requirements.
The SDT respectfully disagrees with you statement regarding COM-002 as a superior standard. We do not see it
as comparative nor do we feel the second draft of COM-003 creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. The SDTs are coordinating issues to ensure there are no
conflicts and that one standard supports the requirements of the other. Note that the implementation plan for
COM-003 includes retirement of COM-002.
Many of the requirement proposed in this posting either reiterate the drafts as posted (i.e. English language) or
introduce confusion when compared to the drafts as posted.
The SDTs should limit their scope to R2 and R7, so as not to duplicate or contradict the on-going work of other
SDTs.
The SDT feels that the requirements in the second draft of COM 003 are appropriate because they support the
purpose identified in the SAR.
The SDT appears to have adopted severe violations for every infraction. There should be some gradations, using
increasing severity based on the number of or severity of any infractions.
Definitions: The standard should define other terms, as well, including the following:
o reliability-related information,
o “... state or status of an element or facility of the BES ...
The SDT has eliminated the 3 original definitions to the proposed COM-003-1 standard and defined Operating
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Communication in the revised draft to address industry comments. The SDT believes the two terms identified
are well understood and do not need further definition. Note that in the second draft of COM-003, the SDT did
capitalize the terms, “Element” and “Facility” to ensure their meaning is clear.
”The standard should also have provision to include the boundaries (components) of an “element,” and the
meaning of the terms “state or status” in the written communication protocol. For example, is the gas
compressor of a 345kV breaker considered part of this element, and so would a change in its “state or status” be
covered? Similarly, is the heat trace inside a 345kV breaker control cabinet part of this element or not?
Element is a defined term in the NERC Glossary – in the revised standard the term has been capitalized for
clarity.
The VRFs for R2-R7 are all “High”, and the VSLs are all “Severe” are too harsh. Failing to comply with one of the
requirements does not automatically mean that a miscommunication occurred that caused a reliability problem.
There should be a “Moderate” VSL for failure to comply with a requirement, but no miscommunication occurred.
There should be a “High” VSL for failure to comply with a requirement that caused a miscommunication but
resulted in no violation of another reliability standard. The “Severe” VSL should only apply to failures to comply
with a requirement that caused a miscommunication that lead to a violation of another reliability standard, or
caused a reliability problem.
SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of
the standard, all requirements have been assigned a Medium VRF. The SDT believes the new assignments
more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of COM-003-1.
In addition, as stated earlier, this Standard focuses on “how” certain tasks should be performed and conflicts with
NERC’s position of pursuing performance based and results based Standards.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that
the second draft of the standard is more focused on “what” protocols to use in specific situations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the reliability of
the BES. This was identified by the NERC President in his January 2011 report to the industry as one of the
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eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The
Goal, therefore, is to specify clear, formal and universally applied communication protocols that reduce the
possibility of miscommunication. The key Objective to accomplish this Goal is to use communication protocols
to reduce or correct misunderstandings. The requirements have been revised to better accomplish this
Objective, and are risk-mitigating requirements (while operator performance is measured, the actions
themselves are primarily designed to mitigate the risk of miscommunication that could lead to poor BES
performance). We believe this standard is consistent with results-based principles, and it will improve the
reliability of the BES.
Based on these considerations, work on this Standard should be stopped until work on Project 2006-06 has been
completed and approved. This approach is consistent with the August 2003 Blackout Recommendation #26
“failure to identify emergency conditions and communicate that status to neighboring systems, and upgrade
communication system hardware where appropriate” which actually focused on communications during
emergencies, which is the scope of Project 2006-06. After Project 2006-06 is completed, a determination can be
made on the disposition of this Standard. This Standard should be effective uniformly continent-wide.
The SDT respectfully disagrees with your statement that the team should stop work on COM-003-1 until project
2006-6 is complete.
The SDT is working in accordance with the August 2003 Blackout Recommendation #26 and FERC Order 693
directives.
Response: The SDT thanks you for your comments. Please see our responses above.
Transmission
Agency of Northern
California
Agree
The requirements of this standard as drafted should not be applicable to Transmission Owners (TO). This
standard pertains to real-time operations, whereas the TO function does not have real-time operational
responsibilities according to the currently effective and proposed NERC Reliability Functional Model, Versions 4
and 5, respectively.
Response: The SDT appreciates the comment in regard to COM-003-1 applying to Transmission Owners and the SDT has deleted the Transmission
Owners from the second draft of the standard. The intent of the proposed standard is to apply only to those operating entities that send or receive
Operating Communications.
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Santee Cooper
Agree
Question 12 Comment
The SDT has put a lot of work into this standard and we appreciate their effort. The SDT of COM-002 and COM003 may need to integrate the reliability related requirements of these two standards into one standard that the
industry can approve. This standard as written could lead to some extremely high dollar fines when in reality the
reliability of the bulk electric system has not been affected at all.
Response The SDT thanks you for your comments and recommendation.
The SDTs are coordinating issues to ensure consistency and to avoid duplication and conflict. The implementation plan for COM-003 includes
retirement of COM-002 to avoid duplication.
South Carolina
Electric and Gas
Agree
The SDT should consider vertically integrated utilities, where communication between functional entities is
internal.
Response: The SDT thanks you for your comments. The SDT determined that operations communications that change or maintain the state, status,
output, or input of an Element or Facility of the Bulk Electric System are subject to the requirements of the proposed COM–003-1 standard whether
they be external or internal.
Electric Market
Policy
Agree
The VRFs for R2-R7 are all “High”, and the VSLs are all “Severe”. That is too harsh. Failing to comply with one of
the requirements does not automatically mean that a miscommunication occurred that caused a reliability
problem. There should be a “Moderate” VSL for failure to comply with a requirement but no miscommunication
occurred. There should be a “High” VSL for failure to comply with a requirement that caused a
miscommunication but resulted in no violation of another reliability standard. The “Severe” VSL should only
apply to failures to comply with a requirement that caused a miscommunication that lead to a violation of
another reliability standard. If approved, this standard will require a number of distracting things be added to
each entity’s control center with little value added. Clock - set to the ‘standard time’ Attachment 1 - COM-003 (all
3 versions)Attachment 2 - COM-003
Response: The SDT thanks you for your comments.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The second draft of the standard proposes assigning a
Medium VRF to each of the requirements. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in the second draft of COM-003-1.
The SDT would like clarification on your comment “Clock - set to the ‘standard time’ Attachment 1 - COM-003 (all 3 versions) Attachment 2 - COM003” if the current draft of the Standard does not address your concerns.
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Progress Energy
Carolina, Inc
Agree
Question 12 Comment
This proposed revision, if implemented, may introduce unnecessary complications into communications between
entities which may lead to delays and misunderstandings, potentially decreasing the reliability of the BES.
Response: The SDT thanks you for your comments. The SDT does not recognize any specific details in your comment. If the revised draft of the
Standard does not address your specific concerns please provide details for the SDT to address.
The Empire District
Electric Company
Disagree
This proposed standard seems to be a redundant standard to many other already approved NERC standards such
as CIP-001, EOP-001, EOP-004, as well as the NERC alert process. I see little to no benefit from this standard as
proposed.
Response: The SDT thanks you for your comments. The SDT does not see any redundant requirements in the standards you cite in your comments.
SERC OC&SOS
Standards Review
Group
Agree
This review group has identified several problems with this standard, as noted above. Other observations
include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In the standard,
the effective date mentions one calendar year following regulatory approval, while the implementation plan
refers to the third calendar quarter after regulatory approval.
The SDT has made several changes to the draft standard that resulted in changes to the Implementation Plan.
The effective dates in the second drafts of the standard and Implementation Plan are identical and provide at
least six months for entities to become compliant.
Furthermore, we do not feel that any of the requirements in this standard warrant Violation Risk Factors or
Violation Severity Levels in the high or severe category
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard the SDT proposed a Medium VRF for each of the requirements. The SDT believes the new
assignments more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of
COM-003-1.
In summary, this review group feels that COM-003-1 is not yet ready to be acted upon and may have been
posted too soon. There does not seem to be sufficient coordination between the drafting teams of all the COM
standards, or any attempt to integrate these standards. One example is the inconsistency between COM-003-1
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and COM-002-3 regarding the meaning of three-part communication (mentioned in our response to Question 1
above).
The OPCP SDT has been and is aware of the progress and content of other COM standard development teams.
The implementation plan for COM-003 includes retirement of COM-002 to avoid duplication.
As noted above, we feel that many of the requirements prescribe specific “how to” methods for compliance
rather than focusing on the “what” of the requirement.
The OPCP SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes
that the second draft of the standard is more focused on “what” protocols to use in specific situations.
Overall, COM-003-1 is much too prescriptive to be tied to million dollar-level fines.
The SDT acknowledges your concerns and wishes to balance them with the need for reliability on the BES.
With the changes to VRFs, (Medium in the second draft of COM-003) the fear of million dollar-level fines should
be relieved.
“The comments expressed herein represent a consensus of the views of the named members of the SERC
OC&SOS Standards Review group only and should not be construed as the position of SERC Reliability
Corporation, its board or its officers.”
Response: The SDT thanks you for your comments. Please see our responses above.
NIPSCO
Disagree
This standard is based on COM-002-3 however that standard has not been voted-in or NERC approved yet. I think
this COM-003 effort should be put on hold until the 2006-06 project is complete. At that time the term "directive"
should be replaced by "Operational Directive" and "Reliability Directive" based on context and all of these terms
should be defined in the NERC Glossary of Terms.
Response: The SDT thanks you for your comments.
The SDT respectfully disagrees with your statement that the team should stop work on COM-003-1 until project 2006-6 is complete. The SDTs are
coordinating issues to ensure consistency, eliminate conflict and avoid duplication. The implementation plan for COM-003 includes retirement of
COM-002 to avoid duplication.
The SDT has eliminated the term “Interoperability Communications” and revised the draft standard to include the new term “Operating
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Communications”. The SDT feels this term will clarify the issues you have raised. The term “Reliability Directive” is being developed in a different
standard by the RC SDT.
Indiana Municipal
Power Agency
Agree
This standard is not needed because requirement two in COM-002 takes into account the use of Three-part
Communication which is the main reliability requirement from COM-003. The use of a procedure (R1), the English
language (R3), a standard time zone (R4), the NATO phonetic alphabet (R6), and a pre-defined system condition
terminology (R2) are administrative requirements (not performance based requirements) and if not used, all of
them definitely do not have a high VRF. If an entity does not use a procedure, but ensures they follow
requirement 2 of COM-002 and both parties have a clear understanding of the directive what other reliability
requirement is necessary. One recommendation might be for the COM-002 Standard Drafting Team or another
SDT to come up with a definition for a directive.
Response: The SDT thanks you for your comments.
The SDT sees the Requirements of COM 003-1 as key operations communication protocols that will standardize the manner in which Functional
entities communicate BES matters thereby reducing the potential for mishaps due to miscommunications. The SDT does not feel that they are
“administrative requirements”.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of the standard the SDT proposed
a Medium VRF for each of the requirements. The SDT believes the new assignments more appropriately classify the VRFs and VSLs assigned to the
Requirements in the second draft of COM-003-1.
The Implementation Plan calls for COM -002 R2 to be retired when COM-003-1 becomes effective.
The SDT has eliminated the term “Interoperability Communications” and revised COM-003 to include the new term “Operating Communications”.
The SDT feels this term will clarify your concerns. The term “Reliability Directive” is being developed in a standard under development, COM-002-3,
by the RC SDT.
Tri-State
Generation &
Transmission Assoc.
Agree
This standard should not apply to DPs, LSEs or TSPs as they do not have control over the BES. That responsibility
resides entirely with the TOP. Additionally, it is concerning that the term “directive” is not defined. The proposed
definition for Interoperability Communication could be interpreted to include all communication between
entities. This is too restrictive.
Response: The SDT thanks you for your comments.
The SDT appreciates the comments with regards to concerns related to including TSPs, DPs and LSEs that do not own or operate facilities that are a
part of the BES. The SDT has removed the TSPs and LSEs because they were not bound by this requirement in the originating SAR. The specified role
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of the DP to shed load justifies the retention of the DP as an applicable Entity.
The SDT has eliminated the term “Interoperability Communications” and revised the draft standard to include the new term “Operating
Communications”. The SDT feels this term will address your concerns. The term “Reliability Directive” is being developed in a standard under
development, COM-002-3, by the RC SDT.
E.ON U.S. LLC
Disagree
This standard should only apply to alerts and emergencies. E.ON U.S. suggests eliminating “ especially” in the
purpose statement of COM-003-1. During emergency situations, operational focus on the semantics of how
communications are to occur does little to enhance the reliability of the system. High VRFs with Severe VSLs may
add stress and distraction to operation personnel during times of emergency thus potentially harming, not
improving reliability.
Response: The SDT thanks you for your comments.
The term “especially” has been removed from the Purpose Statement. It now reads: “To specify clear, formal and universally applied
communication protocols that reduce the possibility of miscommunication which could lead to action or inaction harmful to the reliability of BES.”
The SDT disagrees with the statement “This standard should only apply to alerts and emergencies”. Is there a difference if a miscommunication
causing a reliability event occurs during routine operations or during alerts or emergency operations? The SDT believes the impact on the BES
would be the same.
The SDT has no knowledge that “stress and distraction induced by high VSRs and VSL severity levels to operation personnel during times of
emergency thus potentially harming, not improving” reliability will occur, and has no response to that comment. Note, however, that the SDT
revised the VRFs and VSLs in the second draft of COM-003 to better align with NERC and FERC guidelines – and the VRFs for the revised
requirements are “Medium.”
American Electric
Power
Agree
Unfortunately, the standard seems to be losing its value as the emphasis overly focusing on procedures while
missing the intent. The SDT should reconsider the standard in the context of “what” rather than “how.”Lastly, we
do not believe that this standard is ready to advance and needs significant re-working before the revised draft is
posted. The SDT should attempt to better coordinate with the necessary other drafting teams as these standards
are integrated.
Response: The SDT thanks you for your comments.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the standard is
more focused on “what” protocols to use in specific situations.
The SDT has made significant changes to the original draft to address valid concerns from the Industry.
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The SDTs involved with various COM standard projects have been and are coordinating to ensure consistency, to avoid conflict and to avoid
duplication.
Independent
Electricity System
Operator
Agree
We believe that the existing standard COM-002 can be simply modified to cover the 3-part communication
requirement. This COM-003 standard actually causes more confusion and ambiguity, and creates unnecessary or
overly cumbersome requirements that add little or no value to reliability. This standard is not needed.
Response: The SDT thanks you for your comments
The SDT believes the revised COM-003-1 standard is more appropriate as a location for three-part communications because it focuses on
communications protocol.
The SDT respectfully disagrees with your comments regarding “This COM-003 standard actually causes more confusion and ambiguity, and creates
unnecessary or overly cumbersome requirements that add little or no value to reliability.” We also respectfully disagree with your comments that
“This standard is not needed”.
IRC Standards
Review Committee
May 2, 2012
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes more
confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that add little or no value
to reliability. All requirements with the exception of R1 have been determined to have a HIGH VRF, when many of
them are dictating HOW communications should take place and not when, why, or what.COM-002 retirement
does not appear to be consistent with the direction of the RC SDT in Project 2006-06. The RC SDT is adding
requirements. More coordination is required between the Standard Drafting Teams. Again, we support the work
being done by the RC SDT and RTO SDT and do not believe this adds more necessary requirements.
The SDT respectfully disagrees with you statement regarding COM-002 as a superior standard. We do not see it
as comparative nor do we feel the second draft of COM-003 creates unnecessary or overly cumbersome
requirements that add little or no value to reliability.
The COM related SDTs are coordinating to ensure there are no conflicts and that one standard supports the
requirements of the other. The implementation plan for COM-003 includes retirement of COM-002 to avoid
duplication.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard the SDT proposed a Medium VRF for each of the requirements. The SDT believes the new
assignments more appropriately classify the VRFs and VSLs assigned to the Requirements in the second draft of
COM-003-1.
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Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for extending three-part
communications. We believe the title of Recommendation 26 is misleading and when reviewed separately from
the supporting text of the recommendation and direct and contributing factors in the report results in an
incorrect interpretation. “Failure to identify emergency conditions and communicate that status to neighboring
systems” is one of the contributing factors and the supporting text of the recommendation clearly refer to
shoring up communications during emergency and anticipated emergency conditions and establishing an
emergency broadcast communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some have
incorrectly inferred the initial clause of Recommendation 26, “Tighten communication protocols”, means the
recommendation applies to all routine communications.
The SDT cites additional “Recommendation 26 of the August 14, 2003 Blackout Report” text from the from the
same section you are referencing:
“On August 14, 2003, reliability coordinator and control area communications regarding conditions in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. Ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the cascade.
Consistent application of effective communications protocols, particularly during alerts and emergencies, is
essential to reliability. “
There are several key points here:
Clearly, ineffective, unprofessional, and confusing communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade.
Note the context of this statement especially the word “particularly (“Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.“). It is
apparent to the SDT that this means all communication should be subject to consistent, structured protocols.
The use of “particularly” and “especially” (used in the Recommendation text) are used for emphasis only for
alerts and emergencies and the intent is not to exclude other types of communications.
The SDT believes the text of Recommendation 26 is very clear and is in no way misleading or confusing and that
the Recommendation means exactly what it says: Tighten communications protocols, especially for
communications during alerts and emergencies.
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Also please read FERC Order 693 paragraph 532 to review clarification on the application of three-part
communications to routine directives. The SDT is working in accordance with the August 2003 Blackout
Recommendation #26 and FERC Order 693 directives.
The first paragraph in Attachment 1 of COM-003-1 an EEA is stated as being an Emergency Energy Alert rather
than an Energy Emergency Alert. This should be corrected for consistency with other standards and to avoid
confusion. Also in this paragraph, the term "states" should be replaced with "levels" in order to maintain
consistency with the tables in the Attachment as well as EOP-002-2.1 to which this Attachment refers.
The SDT has removed the requirement that required use of alert levels from the second draft of the standard.
Response: The SDT thanks you for your comments. Please see our responses above.
ISO New England
Inc.
Agree
The existing standard COM-002 is better than this proposed Standard. This Standard actually causes more
confusion and ambiguity, and creates unnecessary or overly cumbersome requirements that add little or no value
to reliability. All requirements with the exception of R1 have been determined to have a HIGH VRF, when many of
them are dictating HOW communications should take place and not when, why, or what.COM-002 retirement
does not appear to be consistent with the direction of the RC SDT in Project 2006-06. The RC SDT is adding
requirements. More coordination is required between the Standard Drafting Teams. Again, we support the work
being done by the RC SDT and RTO SDT and do not believe this adds more necessary requirements.
The SDT respectfully disagrees with you statement regarding COM-002 as a superior standard. We do not see it
as comparative nor do we feel the second draft of COM-003 creates unnecessary or overly cumbersome
requirements that add little or no value to reliability. The SDTs are coordinating issues to ensure there are no
conflicts and that one SDT supports the requirements of the other.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard the SDT proposed a Medium VRF for each of the requirements. The SDT believes the new
assignments more appropriately classify the VRFs and VSLs assigned to the Requirements in the second draft of
COM-003-1.
Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for extending three-part
communications. We believe the title of Recommendation 26 is misleading and when reviewed separately from
the supporting text of the recommendation and direct and contributing factors in the report results in an
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incorrect interpretation. “Failure to identify emergency conditions and communicate that status to neighboring
systems” is one of the contributing factors and the supporting text of the recommendation clearly refer to
shoring up communications during emergency and anticipated emergency conditions and establishing an
emergency broadcast communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some have
incorrectly inferred the initial clause of Recommendation 26, “Tighten communication protocols”, means the
recommendation applies to all routine communications.
The SDT cites additional “Recommendation 26 of the August 14, 2003 Blackout Report” text from the from the
same section you are referencing:
“On August 14, 2003, reliability coordinator and control area communications regarding conditions in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. Ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the cascade.
Consistent application of effective communications protocols, particularly during alerts and emergencies, is
essential to reliability. “
There are several key points here:
Clearly, ineffective, unprofessional, and confusing communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade.
Note the context of this statement especially the word “particularly (“Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.“). It is
apparent to the SDT that this means all communication should be subject to consistent, structured protocols.
The use of “particularly” and “especially” (used in the Recommendation text) are used for emphasis only for
alerts and emergencies and the intent is not to exclude other types of communications.
The SDT believes the text of Recommendation 26 is very clear and is in no way misleading or confusing and that
the Recommendation means exactly what it says: Tighten communications protocols, especially for
communications during alerts and emergencies.
Also please read FERC Order 693 paragraph 532 to review clarification on the application of three-part
communications to routine directives. The SDT is working in accordance with the August 2003 Blackout
Recommendation #26 and FERC Order 693 directives.
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Lastly, this on-line submittal asks many questions that are YES/NO in nature (i.e. "do you have any concerns
with...", or "if, yes, please explain...") but the radial selections are "agree/disagree" which may be taken out of
context. We suggest changing the on-line submittal back to YES/NO.
Finally the SDT will pass on your recommendation regarding changing the on line submittal to YES/NO.
Response: The SDT thanks you for your comments. Please see our responses above.
National Grid
Agree
We believe that the existing standard COM-002 is actually better than this standard. This standard actually
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements that add
little or no value to reliability. Additionally, we cannot understand how all requirements but R1 have been
determined to have a HIGH VRF when, many of them are dictating HOW communications should take place and
not when and why or what. COM-002 retirement does not appear to be consistent with the direction of the RC
SDT. The RC SDT appears to be adding requirements. More coordination is required between these two teams.
Response: The SDT thanks you for your comments
The SDT disagrees with you statement regarding COM-002 as a superior Standard. We do not see it as comparative nor do we feel the second draft
of COM-003 creates unnecessary or overly cumbersome requirements that add little or no value to reliability.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The SDT believes the new assignments more
accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of COM-003-1.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the standard is
more focused on “what” protocols to use in specific situations.
The SDT feels that the Requirements in the second draft of COM-003 are appropriate because they support the purpose identified in the SAR.
The SDTs involved with COM standard development have been and are coordinating to ensure consistency, to avoid conflict and to avoid
duplication.
The implementation plan for COM-003 includes retirement of COM-002 to avoid duplication.
Dynegy
Agree
May 2, 2012
We believe that the existing standard COM-002 is better than this proposed Standard. This Standard actually
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements that add
little or no value to reliability. Additionally, we cannot understand how all requirements but R1 have been
determined to have a HIGH VRF when, many of them are dictating HOW communications should take place and
not when and why or what. The stated retirement of COM-002 does not appear to be consistent with the
direction of the RC SDT in Project 2006-06. The RC SDT is adding requirements. More coordination is certainly
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required between these two teams .In addition, as stated earlier, this Standard focuses on “how” certain tasks
should be performed and conflicts with NERC’s position of pursuing performance based and results based
Standards.
Response: The SDT thanks you for your comments
The SDT disagrees with you statement regarding COM-002 as a superior Standard. We do not see it as comparative nor do we feel the second draft
of COM-003 creates unnecessary or overly cumbersome requirements that add little or no value to reliability.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second draft of the standard the SDT proposed
a Medium VRF for each of the requirements. The SDT believes the new assignments more accurately classify the VRFs and VSLs assigned to the
Requirements in the second draft of COM-003-1.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that the second draft of the standard is
more focused on “what” protocols to use in specific situations.
The SDT feels that the Requirements in the second draft of COM-003 are appropriate because they support the purpose identified in the SAR.
The SDTs involved with COM standards development have been and are coordinating to ensure consistency, to avoid conflict and to avoid
duplication. The implementation plan for COM-003 includes retirement of COM-002 to avoid duplication.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem Statement for this standard is that
miscommunication can lead to action or inaction harmful to the reliability of the BES. This was identified by the NERC President in his January 2011
report to the industry as one of the eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The Goal, therefore, is to specify clear,
formal and universally applied communication protocols that reduce the possibility of miscommunication. The key Objective to accomplish this
Goal is to use communication protocols to reduce or correct misunderstandings. The requirements have been written to accomplish this Objective,
and are risk-mitigating requirements (while operator performance is measured, the actions themselves are primarily designed to mitigate the risk
of miscommunication that could lead to poor BES performance). We believe this standard is consistent with results-based principles, and it will
improve the reliability of the BES.
Midwest ISO
Standards
Collaborators
May 2, 2012
Agree
We believe that the existing standard COM-002 is better than this proposed Standard. This Standard actually
causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements that add
little or no value to reliability. Additionally, we cannot understand how all requirements but R1 have been
determined to have a HIGH VRF when, many of them are dictating HOW communications should take place and
not when and why or what. COM-002 retirement does not appear to be consistent with the direction of the RC
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SDT in Project 2006-06. The RC SDT is adding requirements. More coordination is certainly required between
these two teams
.In addition, as stated earlier, this Standard focuses on “how” certain tasks should be performed and conflicts
with NERC’s position of pursuing performance based and results based Standards. Based on these considerations,
we suggest that work on this Standard be stopped until work on Project 2006-06 has been completed and
approved.
This approach is consistent with the August 2003 Blackout Recommendation #26 which actually focused on
communications during emergencies which is the scope of Project 2006-06.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that
the second draft of the standard is more focused on “what” protocols to use in specific situations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the reliability of
the BES. This was identified by the NERC President in his January 2011 report to the industry as one of the
eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The
goal, therefore, is to specify clear, formal and universally applied communication protocols that reduce the
possibility of miscommunication. The key objective to accomplish this goal is to use communication protocols
to reduce or correct misunderstandings. The requirements have been written to accomplish this objective, and
are risk-mitigating requirements (while operator performance is measured, the actions themselves are
primarily designed to mitigate the risk of miscommunication that could lead to poor BES performance). We
believe this standard is consistent with results-based principles, and it will improve the reliability of the BES.
The SDT cites additional “Recommendation 26 of the August 14, 2003 Blackout Report” text from the from the
same section you are referencing:
“On August 14, 2003, reliability coordinator and control area communications regarding conditions in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. Ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the cascade.
Consistent application of effective communications protocols, particularly during alerts and emergencies, is
essential to reliability. “
There are several key points here:
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Clearly, ineffective, unprofessional, and confusing communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade.
Note the context of this statement especially the word “particularly (“Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.“). It is
apparent to the SDT that this means all communication should be subject to consistent, structured protocols.
The use of “particularly” and “especially” (used in the Recommendation text) are used for emphasis only for
alerts and emergencies and the intent is not to exclude other types of communications.
The SDT believes the text of Recommendation 26 is very clear and is in no way misleading or confusing and that
the Recommendation means exactly what it says: Tighten communications protocols, especially for
communications during alerts and emergencies.
Also please read FERC Order 693 paragraph 532 to review clarification on the application of three-part
communications to routine directives. The SDT is working in accordance with the August 2003 Blackout
Recommendation #26 and FERC Order 693 directives.
After Project 2006-06 is completed, a determination can be made if this Standard is even required.
The SDT respectfully disagrees with your statement that the team should stop work on COM-003-1 until project
2006-6 is complete. The implementation plan for COM-003 includes retirement of COM-002 to avoid
duplication.
Response: The SDT thanks you for your comments. Please see our responses above.
PJM
Agree
We have identified several problems with this standard, as noted above.
Other observations include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In the standard,
the effective date mentions one calendar year following regulatory approval, while the implementation plan
refers to the third calendar quarter after regulatory approval.
The SDT revised the standard and the implementation plan – and made the effective dates the same in both
documents – the first day of the first calendar quarter six months after applicable approvals.
Furthermore, we do not feel that any of the requirements in this standard warrant Violation Risk Factors or
May 2, 2012
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Question 12 Comment
Violation Severity Levels in the high or severe category. In summary, this review group feels that COM-003-1 is
not yet ready to be acted upon and may have been posted too soon.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard the SDT proposed a Medium VRF for each of the requirements. The SDT believes the new
assignments more accurately classify the VRFs and VSLs assigned to the Requirements in COM-003-1.
There does not seem to be sufficient coordination between the drafting teams of all the COM standards, or any
attempt to integrate these standards. One example is the inconsistency between COM-003-1 and COM-002-3
regarding the meaning of three-part communication (mentioned in our response to Question 1 above).
he SDTs involved with COM standard development have been and are coordinating issues to ensure
consistency, to avoid conflict and to avoid duplication. The implementation plan for COM-003 includes
retirement of COM-002 to avoid duplication.
Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for extending three-part
communications. We believe the title of Recommendation 26 is misleading and when reviewed separately from
the supporting text of the recommendation and direct and contributing factors in the report results in an
incorrect interpretation. “Failure to identify emergency conditions and communicate that status to neighboring
systems” is one of the contributing factors and the supporting text of the recommendation clearly refer to
shoring up communications during emergency and anticipated emergency conditions and establishing an
emergency broadcast communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some have
incorrectly inferred the initial clause of Recommendation 26, “Tighten communication protocols”, means the
recommendation applies to all routine communications.
The SDT cites additional “Recommendation 26 of the August 14, 2003 Blackout Report” text from the from the
same section you are referencing:
“On August 14, 2003, reliability coordinator and control area communications regarding conditions in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. Ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the cascade.
Consistent application of effective communications protocols, particularly during alerts and emergencies, is
May 2, 2012
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Question 12 Comment
essential to reliability.“
There are several key points here:
Clearly, ineffective, unprofessional, and confusing communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade.
Note the context of this statement especially the word “particularly” (“Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.“). It is
apparent to the SDT that this means all communication should be subject to consistent, structured protocols.
The use of “particularly” and “especially” (used in the Recommendation text) are used for emphasis only for
alerts and emergencies and the intent is not to exclude other types of communications.
The SDT believes the text of Recommendation 26 is very clear and is no way misleading or confused and that
the Recommendation means exactly what it says: Tighten communications protocols, especially for
communications during alerts and emergencies.
Also please read FERC Order 693 paragraph 532 to review clarification on the application of three-part
communications to routine directives. The SDT is working in accordance with the August 2003 Blackout
Recommendation #26 and FERC Order 693 directives.
As noted above, we feel that many of the requirements prescribe specific “how to” methods for compliance
rather than focusing on the “what” of the requirement. Overall, COM-003-1 is much too prescriptive to be tied to
million dollar-level fines
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that
the second draft of the standard is more focused on “what” protocols to use in specific situations.
Response: The SDT thanks you for your comments. Please see our responses above.
PJM SOS Comments
May 2, 2012
Agree
We have identified several problems with this standard, as noted above.
Other observations include:
The effective dates in the draft standard and in the implementation plan do not seem to match. In the standard,
the effective date mentions one calendar year following regulatory approval, while the implementation plan
refers to the third calendar quarter after regulatory approval.
The SDT revised the standard and the implementation plan – and made the effective dates the same in both
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Question 12 Comment
documents – the first day of the first calendar quarter six months after applicable approvals.
Furthermore, we do not feel that any of the requirements in this standard warrant Violation Risk Factors or
Violation Severity Levels in the high or severe category.
The SDT has modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. In the second
draft of the standard the SDT proposed a Medium VRF for each of the requirements. The SDT believes the new
assignments more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of
COM-003-1.
In summary, this review group feels that COM-003-1 is not yet ready to be acted upon and may have been
posted too soon. There does not seem to be sufficient coordination between the drafting teams of all the COM
standards, or any attempt to integrate these standards. One example is the inconsistency between COM-003-1
and COM-002-3 regarding the meaning of three-part communication (mentioned in our response to Question 1
above).
The SDTs involved with COM standard development have been and are coordinating issues to ensure
consistency, to avoid conflict and to avoid duplication. The implementation plan for COM-003 includes
retirement of COM-002 to avoid duplication.
Recommendation 26 of the August 14, 2003 blackout report is cited as a driver for extending three-part
communications. We believe the title of Recommendation 26 is misleading and when reviewed separately from
the supporting text of the recommendation and direct and contributing factors in the report results in an
incorrect interpretation. “Failure to identify emergency conditions and communicate that status to neighboring
systems” is one of the contributing factors and the supporting text of the recommendation clearly refer to
shoring up communications during emergency and anticipated emergency conditions and establishing an
emergency broadcast communication system to alert regulatory, state and local officials. The supporting text of
Recommendation 26 only mentions addressing alerts, emergencies or other critical situations. Some have
incorrectly inferred the initial clause of Recommendation 26, “Tighten communication protocols”, means the
recommendation applies to all routine communications.
The SDT cites additional “Recommendation 26 of the August 14, 2003 Blackout Report” text from the from the
May 2, 2012
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Organization
Yes or No
Question 12 Comment
same section you are referencing:
“On August 14, 2003, reliability coordinator and control area communications regarding conditions in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. Ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the cascade.
Consistent application of effective communications protocols, particularly during alerts and emergencies, is
essential to reliability.“
There are several key points here:
Clearly, ineffective, unprofessional, and confusing communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade.
Note the context of this statement especially the word “particularly” (“Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.“). It is
apparent to the SDT that this means all communication should be subject to consistent, structured protocols.
The use of “particularly” and “especially” (used in the Recommendation text) are used for emphasis only for
alerts and emergencies and the intent is not to exclude other types of communications.
The SDT believes the text of Recommendation 26 is very clear and is no way misleading or confused and that
the Recommendation means exactly what it says: Tighten communications protocols, especially for
communications during alerts and emergencies.
Also please read FERC Order 693 paragraph 532 to review clarification on the application of three-part
communications to routine directives. The SDT is working in accordance with the August 2003 Blackout
Recommendation #26 and FERC Order 693 directives.
As noted above, we feel that many of the requirements prescribe specific “how to” methods for compliance
rather than focusing on the “what” of the requirement. Overall, COM-003-1 is much too prescriptive to be tied to
million dollar-level fines The SDT was chartered to develop Communication Protocols for Operating Personnel.
The SDT proposes that the second draft of the standard is more focused on “what” protocols to use in specific
situations.
Response: The SDT thanks you for your comments. Please see our responses above.
NRECA RTF
May 2, 2012
We recommend replacing the term “Distribution Service Providers” in Attachment 1 with the term “Distribution
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Members
Question 12 Comment
Provider” as stated in the Applicability of this standard. In addition, please see our response to Question 3
regarding a modification to the Applicability portion of the standard to address concerns about the inclusion of
Distribution Providers and Load Serving Entities. We are concerned with the onerous communication
requirements for Load Serving Entities and Distribution Providers with field personnel that have rare or possibly
no opportunities to communicate with personnel working at an entity registered as a Transmission Operator,
Transmission Owner, Balancing Authority, Reliability Coordinator, Generator Operator or Transmission Service
Provider.
Response: The SDT thanks you for your comments. We agree with your recommendation on the term “Distribution Provider” and this change is
reflected in the second draft of COM-003. We also note your comments on applicability in Question 3 and have provided our response there.
Transmission
System Operations
Agree
We think the SDT should coordinate their work closely with the team of the Reliability Coordination Project 200606, especially regarding new definitions related to communications and reliability directives.
Response: The SDT thanks you for your comments. The SDT agrees and the SDTs involved with COM standard development have been and are
coordinating issues to ensure consistency, to avoid conflict and to avoid duplication.
The SDT has revised the definitions to the proposed COM-003-1 Standard to define Operating Communication that should address your concerns
over the applicability of three-part communications. The implementation plan for COM-003 includes retirement of COM-002 to avoid duplication.
Ameren
We understand the binary function of VSL that forces Severe for most requirements. However, the standard itself
seems to offer some hope with the definition to address the VSL issue better. The definition has at the end,
“especially during alerts and emergencies” Given that this implies stratification, couldn’t Severe VSL be assigned
to violations during emergencies, High be assigned to alerts, and moderate to all other system conditions. When
emergency conditions exist, entities should have their “A” game on, and failure to communicate during these
times is a more severe violation of the communication protocols than during the thousands of daily interactions
that are not likely to affect BES, (alternatively, the VRF could be adjusted for the situation)
Response: The SDT thanks you for your comments
The SDT has reviewed and modified the VRFs and VSLs to comply with approved NERC and FERC guidelines. The SDT believes the new assignments
more accurately classify the VRFs and VSLs assigned to the Requirements in the second draft of COM-003-1. In the second draft of COM-003 the
requirements are all assigned a “Medium” VRF – and the VSLs are more graduated.
MRO NERC
Standards Review
May 2, 2012
Agree
Without “Directive” being defined, this proposed standard still leaves a huge area that will cause problems and
issues within the industry. We believe the SDT should replace “directive” with “Reliability Directive” and use the
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Question 12 Comment
definition developed in Project 20006-06: “A communication initiated by a Reliability Coordinator, Transmission
Operator or Balancing Authority where action by the recipient is necessary to address an actual or expected
Emergency.”
COM 002 -3 and Reliability Directive are under development by the RC SDT. The term, “Reliability Directive” is
not used in the second draft of COM-003.
We believe Reliability Standard COM-003-1 is entirely too prescriptive, and is in actuality a procedure and not a
standard. The Standard needs to focus on the “What” and not the “How”. If the industry is going to truly
embrace the Results Based Standards Initiative, this standard must be significantly revised to reflect that
philosophy.
The SDT believes that the requirements in the second draft of COM 003 are appropriate because they support
the purpose identified in the SAR. If you believe Reliability Standard COM-003-1 is entirely too prescriptive, and
is in actuality a procedure and not a standard it should have been addressed in the SAR development process.
The SDT was chartered to develop Communication Protocols for Operating Personnel. The SDT proposes that
the second draft of the standard is more focused on “what” protocols to use in specific situations.
The SDT does not believe its work to be inconsistent with results-based principles. The Need or Problem
Statement for this standard is that miscommunication can lead to action or inaction harmful to the reliability of
the BES. This was identified by the NERC President in his January 2011 report to the industry as one of the
eight top priority issues for BPS reliability, and there are a number of events that have occurred in the past
where miscommunication was a contributing factor to the event or exacerbated the severity of the event. The
Goal, therefore, is to specify clear, formal and universally applied communication protocols that reduce the
possibility of miscommunication. The key Objective to accomplish this Goal is to use communication protocols
to reduce or correct misunderstandings. The requirements have been written to accomplish this Objective, and
are risk-mitigating requirements (while operator performance is measured, the actions themselves are
primarily designed to mitigate the risk of miscommunication that could lead to poor BES performance). We
believe this standard is consistent with results-based principles, and it will improve the reliability of the BES.
We believe that the existing standard COM-002 is actually better than this standard. This standard actually
May 2, 2012
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causes more confusion and ambiguity and creates unnecessary or overly cumbersome requirements that add
little or no value to reliability.
The SDT respectfully disagrees with your statement that “COM-002 is actually better than this standard and
this standard actually causes more confusion and ambiguity and creates unnecessary or overly cumbersome
requirements that add little or no value to reliability.” COM 002-2 is too vague and has left much doubt in the
stakeholders’ minds. The SDT believes COM 003 adds clarity to the communication standards.
Response: The SDT thanks you for your comments. Please see our responses above.
PSEG Companies
Agree
Yes. The PSEG Companies agree with the concerns expressed in the comments filed by the PJM System
Operations Subcommittee (SOS) Group.
Response: The SDT thanks you for your. Please see our response to the comments from filed by the PJM System Operations Subcommittee (SOS)
Group.
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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15, 2010.
Description of Current Draft:
This is the second draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
March 2012
2. First ballot of standards.
June 2012
3. Successive Ballot of Standards
September 2012
4. Recirculation ballot of standards.
October 2012
5. Board adopts standards.
November 2012
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms Used in
NERC Reliability Standards it should be cited as the source. When used in written
communications, terms or phrases contained in the Reliability Standards Glossary of Terms
Used in Reliability Standards are capitalized.
Operating Communication — Communication of instruction to change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System.
Reliability Directives are a type of Operating
Communications, to the extent they change or
maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System.
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A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To specify clear, formal and universally-applied communication protocols
that reduce the possibility of miscommunication which could lead to action or inaction
harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
5.
4.1.1
Reliability Coordinator
4.1.2
Transmission Operator
4.1.3
Balancing Authority
4.1.4
Generator Operator
4.1.5
Distribution Provider
Effective Date: First day of the first calendar quarter, six calendar months following
applicable regulatory approval; or, in those jurisdictions where no regulatory approval
is required, the first day of the first calendar quarter a year from the date of Board of
Trustees adoption.
B. Requirements
R1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator and Distribution Provider shall use the following communications protocols:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations ]
1.1. When participating in oral or written Operating Communications:
1.1.1. Use the English language when communicating between functional
entities, unless another language is mandated by law or regulation.
1.1.2. Use the 24-hour clock format when referring to clock times.
1.1.3. When the communication is between entities in different time zones,
include the time and time zone and indicate whether the time is daylight
saving time or standard time.
1.1.4. When referring to a Transmission interface Element or a Transmission
interface Facility, use the name specified by the owner(s) for that
Transmission interface Element or Transmission interface Facility.
1.2. When participating in oral Operating Communications and using alpha-numeric
identifiers, use accurate alpha-numeric clarifiers. 1
1
The North Atlantic Treaty Organization (NATO) Spelling Alphabet is one example of a set of alpha- numeric
clarifiers.
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R2. Each Reliability Coordinator, Transmission Operator and Balancing Authority that
issues an oral, two-party, person-to-person Operating Communication, excluding
Reliability Directives shall:
2.1. Issue the Operating Communication and wait for a response from the receiver.
2.2. After the response is received, or if no response is received, do one of the
following:
•
Confirm the receiver’s response, if the repeated information is correct (not
necessarily verbatim).
•
Reissue the Operating Communication if the repeated information is
incorrect or if the receiver does not issue a response.
•
Reissue the Operating Communication, if requested by the receiver.
[Violation Risk Factor Medium][Time Horizon: Real-Time]
R3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator and Distribution Provider that receives an oral two-party, person-to-person
Operating Communication, excluding Reliability Directives , shall take one of the
following actions:
•
Repeat the Operating Communication (not necessarily verbatim) and wait for
confirmation from the issuer that the repetition was correct.
•
Request that the issuer reissue the Operating Communication.
[Violation Risk Factor: Medium][Time Horizon: Real-Time]
C. Measures
M1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, and Distribution Provider shall provide evidence that the communication
protocols specified by the requirement were implemented during Operating
Communications. For requirement R1, Part 1.1.1, provide a copy of the law or
regulation that mandates use of a language other than English. Evidence may include,
but is not limited to, voice recordings, transcripts of voice recordings, operating logs,
on-site observations, or other equivalent evidence. (R1)
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority, shall
provide evidence that the communication protocol specified by the requirement was
implemented. Evidence may include, but is not limited to, voice recordings, transcripts
of voice recordings, on-site observations, or other equivalent evidence. (R2)
M3. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator and Distribution Provider shall provide evidence that the communication
protocol specified by the requirement was implemented. Evidence may include, but is
not limited to, voice recordings, transcripts of voice recordings, on-site observations, or
other equivalent evidence. (R3)
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D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA),
unless the applicable entity is owned, operated, or controlled by the Regional
Entity. In such cases, the ERO or a Regional Entity approved by FERC or other
applicable governmental authority shall serve as the CEA.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance, as identified below, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
•
Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Generator Operator and Distribution Provider shall retain
evidence for Requirement R1 Measure M1 for the most recent 365
calendar days.
•
Each Reliability Coordinator, Transmission Operator and Balancing
Authority shall retain evidence for Requirement R2, Measure M2, for the
most recent 180 calendar days.
•
Each Reliability Coordinator, Transmission Operator, Balancing
Authority, Generator Operator and Distribution Provider shall retain
evidence for Requirement R3, Measure M3, for the most recent 180
calendar days.
If a Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Compliance Investigation
Self-Reporting
Complaint
1.4. Additional Compliance Information
None
Dra ft 2: Ma y 3, 2012
COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Table of Compliance Elements
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Real-time
Operations
Medium
N/A
Moderate VSL
High VSL
Severe VSL
The responsible entity
did not correctly
implement one (1) of the
four (4) parts of
Requirement R1, Part 1.1
when it was appropriate
to use all four parts.
The responsible entity
did not correctly
implement two (2) of the
four (4) parts of
Requirement R1, Part 1.1
when it was appropriate
to use all four parts.
The responsible entity
did not correctly
implement any of the
parts of Requirement
R1, Part 1.1 when it was
appropriate to use all
four parts.
OR
OR
OR
The responsible entity
did not correctly
implement Part 1.2 of
the requirement.
The responsible entity
did not correctly
implement one (1) of the
four (4) parts of the
requirement when it was
appropriate to use three
of the four parts.
The responsible entity
did not correctly
implement three (3) or
more of the four (4)
parts of Requirement
R1, Part 1.1 when it was
appropriate to use all
four parts.
OR
The responsible entity
did not correctly
implement two (2) of the
four (4) parts of
Requirement R1, Part 1.1
when it was appropriate
to use three of the four
parts.
OR
The responsible entity
did not correctly
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
implement one (1) of the
four (4) parts of
Requirement R1, Part 1.1
when it was appropriate
to use two of the four
Parts of Requirement R1.
R2
Real-time
Operations
Medium
The responsible entity
issued a verbal personto-person Operating
Communication and did
not confirm the
receiver’s response was
correct. (Part 2.2, first
bullet)
The responsible entity
issued a verbal personto-person Operating
Communication and did
not reissue the Operating
Communication when
requested by the receiver.
(Part 2.2, third bullet)
The responsible entity
issued a verbal personto-person Operating
Communication and did
not wait for a response
from the receiver. (Part
2.1)
Or
The responsible entity
issued a verbal personto-person Operating
Communication and did
not reissue the Operating
Communication when
the response was
incorrect or when there
was no response (Part
2.2, second bullet).
R3
Real-time
Operations
Dra ft 2: Ma y 3, 2012
Medium
The responsible entity
received a verbal personto-person Operating
Communication and did
not wait for confirmation
that the repetition was
The responsible entity
received a verbal personto-person Operating
Communication and did
not repeat the Operating
Communication and did
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Dra ft 2: Ma y 3, 2012
Moderate VSL
High VSL
Severe VSL
correct. (R3, first bullet)
not request that the issuer
reissue the Operating
Communication. (R3)
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
E. Regional Variances
None.
F. Associated Documents
North Atlantic Treaty Organization (NATO) Phonetic Alphabet or International
Radiotelephony Spelling Alphabet
Version History
Version
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Date
Action
Change Tracking
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Project 2007-02 Operating Personnel Communications
Protocols
Unofficial Comment Form for Standard COM-003-1 —Operating Personnel Communications Protocols
Please DO NOT use this form. Please use the electronic comment form located at the link below to
submit comments on the proposed draft COM-003-1 Operating Personnel Communications Protocols
standard. Comments must be submitted by June 20, 2012. If you have questions please contact Joseph
Krisiak at [email protected] or by telephone at 609-651-0903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information:
Effective communication is critical for Real-time operations. Failure to successfully communicate
clearly can create misunderstandings resulting in improper operations increasing the potential for
failure of the BES.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and
approved by the Standards Committee on June 8, 2007. It established the scope of work for the
Project 2007-02 Operating Personnel Communications Protocols Standard Drafting Team (OPCP SDT).
The scope described in the SAR is to establish essential elements of communications protocols and
communications paths such that operators and users of the North American Bulk Electric System will
efficiently convey information and ensure mutual understanding. The August 2003 Blackout Report,
Recommendation Number 26, calls for a tightening of communications protocols. FERC Order 693
Paragraph 532 amplifies this need and applies it to all Operating Communications. This proposed
standard’s goal is to ensure that effective communication is practiced and delivered in clear language
and standardized format via pre-established communications paths among pre-identified operating
entities.
The SAR indicated that references to communication protocols in other NERC Reliability Standards may
be moved to this new standard. The SAR instructed the standard drafting team to consider
incorporating the use of Alert Level Guidelines and three-part communications in developing this new
standard to achieve high level consistency across regions. The SDT believes the Alert Level Guidelines,
while valuable, belong in a separate standard and has petitioned the Standards Committee to approve
the transfer to another standard or to start a separate project.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and mutually
understood for communicating changes to real-time operating conditions and responding to directives,
notifications, directions, instructions, orders, or other reliability related operating information.
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The Purpose statement of COM 003-1 states: “To specify clear, formal and universally applied
communication protocols that reduce the possibility of miscommunication which could lead to action
or inaction harmful to the reliability of BES.”
Based on stakeholder comments and observations from the Quality Review team, the OPCP SDT made
the following changes to COM-003-1:
•
New NERC Glossary terms:
The SDT has eliminated the definitions; Communications Protocol, Three-part Communication
and Interoperability Communication proposed in the first draft of the standard and added a
definition for Operating Communications. Operating Communications more accurately defines
the broad class of communications that deal with changing or altering the state of the BES.
Changes to the BES operating state with unclear communications create increased
opportunities for events that could place the BES at an unacceptable risk of instability,
separation, or cascading failures.
•
Communication Protocol Operating Procedure (CPOP):
The SDT eliminated the CPOP from the standard based on stakeholder comments indicating this
is administrative in nature.
•
English Language:
The SDT modified the standard (R3 in the first draft of COM-003-1, R1 Part 1.1.1 in the second
draft of COM-003-1) to address comments which point out that in some regions, the use of
another language other than English may be mandated by law.
•
Pre-defined System Condition Terminology:
The Alert Level Guide document was originally prepared by the Reliability Coordinator Working
Group (RCWG) in accordance with a U.S./Canada Task Force Blackout Report Recommendation.
Recommendation #20 called for the establishment of clear definitions of normal, alert, and
emergency operational system conditions, and to clarify the roles, responsibilities, and
authorities of Reliability Coordinators and other responsible entities under each condition.
After many comments and much discussion the SDT believes the Alert Level Guide is better
suited in its own standard or in a standard that deals with alert conditions and notification. The
content was not related to communication protocols designed to clarify operating
communication on the BES. The SDT has petitioned the Standards Committee to approve of a
transfer to another standard or to a new standard as it deems appropriate.
•
Time Zone Reference:
The first draft of COM-003-1 included a requirement to use Central Standard Time for operating
communications (R4) and stakeholders identified that unless people are communicating in
different time zones, this requirement may be a distraction. The SDT modified the standard to
require inclusion of time zone references only in those situations where communication is
between entities in different time zones.
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•
Three-part Communication:
The first draft of COM-003-1 included a single requirement for use of three-part communication (R5).
Several stakeholders noted that three-part communication is being addressed in two standards. While
the OPCP SDT originally planned on proposing retirement of COM-002-3, the team has been convinced
that keeping three part communication in both COM-002-3 and COM-003-1 has value.
ο The three-part communications in COM-002-3 are limited to Reliability Directives and
have a “High” VRF.
ο The three-part communications in COM-003-1 are focused on Operating
Communication except for Reliability Directives which are a subset of Operating
Communications. The requirements for three-part communications in COM-003 have a
“Medium” VRF.
The OPCP SDT split the three-part communication requirement into two separate proposed
requirements; R2 andR3 to address responsibilities of the issuer and of the receiver respectively during
Operating Communications. The SDT also clarified that repeat-back does not have to be exactly
verbatim; however the message must be accurately conveyed and understood.
•
NATO Alphabet or Correct alpha numeric clarifiers:
The first draft of COM-003-1 had a requirement for use of the NATO Alphabet during operating
communications (R6). Many stakeholders indicated that the NATO Alphabet is only one way of providing
clarity and proposed that other alpha-numeric clarifies should be acceptable. In response the modified
the standard to require use of the NATO Phonetic Alphabet or a correct alpha-numeric clarifier when
issuing and replying to verbal Operating Communications that involve alpha-numeric information. The
revised standard clarifies that the use of another correct alphanumeric clarifier is permitted as long as
the content is fully and accurately conveyed. During spoken communications certain sounds become
difficult to discern because they are audibly similar. The use of the NATO Phonetic Alphabet or proper
phonetically correct clarifiers is not intended for all verbal communications but is required for Operating
Communications involving alpha-numeric identifiers. (See Requirement R1, Part 1.2 in the second draft
of COM-003-1.)
•
Line and Equipment Identifiers:
The first draft of COM-003-1 had a requirement (R7) for use of pre-determined, mutually agreed upon
line and equipment identifiers for verbal and written operating communications. Stakeholders indicated
that obtaining such agreements was not necessary and recommended narrowing the scope of this
requirement. In response, the OPCP SDT modified the scope of the requirement so it only applies to
oral and written operating communications involving a Transmission interface Element or Facility and
replaced the need for an agreement with use of the name of the Facility/Element specified by the owner
of that Transmission interface Element or Facility. (See Requirement R1, Part 1.1.4 in the second draft of
COM-003-1.)
•
VSL and VRF Changes from version one:
The OPSDT reviewed the VRFs and VSLs associated with R1, R2 and R3 and made changes to more
closely conform to NERC and FERC guidelines. Where the first draft of COM-003-1 proposed having a
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(Standard) Project 2007-02
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“High” VRF for all real-time communications, the second draft of COM-003-1 proposes a “Medium” VRF
for each of the three remaining requirements.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of
a miscommunication during Operating Communications. Requirements R1, R2 and R3 are
assigned a Medium Violation Risk Factor – a violation of one of these requirements, by itself,
could directly affect the electrical state or the capability of the Bulk Electric System, or the
ability to effectively monitor and control the Bulk Electric System, but a violation by itself would
not lead to Bulk Electric System instability, separation, or Cascading failures.
The VSLs in the second draft of COM-003-1 are all new.
The drafting team is posting the standard for industry comment for a 45-day comment period.
The Operating Personnel Communications Protocols Drafting Team would like to receive industry
comments on this draft standard. Accordingly, we request that you include your comments on this
form by June 20, 2012.
Unofficial Comment Form
(Standard) Project 2007-02
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*Please use the electronic comment form to submit your final comments to NERC.
1. Do you agree with the addition of “Operating Communication” as a proposed new definition for
the NERC Glossary and the elimination of “Communication Protocol,” “Interoperability
Communication” and “Three part Communications” proposed in the first draft of COM-003-1?
Operating Communication: Communication of instruction to change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System.
If not, please explain in the comment area.
Yes
No
Comments:
2. The SDT eliminated the requirement to have a Communications Protocol Operating Procedure
from the proposed standard because it is administrative in nature. Do you agree with this
modification? If not, please explain in the comment area.
Yes
No
Comments:
3. The SDT has proposed to transfer the requirement to use Alert Levels in Attachment 1 to another
more closely aligned standard or to a separate new standard. Do you agree with this transfer? If
not, please explain in the comment area.
Yes
No
Comments:
4. The SDT modified the standard to allow an exemption from the requirement to use English
language where the use of another language is mandated by law or regulation. (See Requirement
R1, Part 1.1.1) Do you agree with this modification? If not, please explain in the comment area.
Yes
No
Comments:
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(Standard) Project 2007-02
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5. The SDT modified the standard to mandate utilization of a 24 hour clock for all times and to
mandate the use of a time zone and indicate whether the time is daylight saving time or standard
time reference when Operating Communications occur between different time zones. (See
Requirement R1, Part 1.1.3) Do you agree with this modification? If not, please explain in the
comment area.
Yes
No
Comments:
6. The SDT modified the requirement for use of three-part communications for Operating
Communications to clarify that this is not applicable for Reliability Directives and split the single
requirement into two requirements: one for the issuer (R2) and another for the receiver (R3). Do
you agree with this modification?
Yes
No
Comments:
7. The SDT modified the requirement for use of the NATO phonetic alphabet to allow use of
another correct alpha numeric clarifier. (See Requirement R1, Part 1.2.) Do you agree with this
modification?
Yes
No
Comments:
8. The SDT modified the requirement for use of identifiers to limit the applicability to operating
communications involving Transmission interface Elements/Facilities and to require use of the
name for that Element/Facilities specified by the Element/Facility’s owner(s). Do you agree with
this modification?
Yes
No
Comments:
Unofficial Comment Form
(Standard) Project 2007-02
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Project YYYY-##.# - Project Name
9. Do you agree with the VRFs and VSLs for Requirements R1, R2 and R3?
Yes
No
Comments:
10. If you have any other comments or suggestions to improve the draft standard that you have not
already provided in response to the previous questions please provide them here.
Comments:
Unofficial Comment Form
(Standard) Project 2007-02
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols
Prerequisite Approvals
None.
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Communication — Communication of instruction to change or maintain the state, status,
output, or input of an Element or Facility of the Bulk Electric System.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
COM-003-1 Requirement R1 Part 1.1.1
R4. Unless agreed to otherwise, each Reliability
R1. Each Reliability Coordinator,
Coordinator, Transmission Operator, and
Transmission Operator, Balancing
Balancing Authority shall use English as the
Authority, Generator Operator and
language for all communications between and
Distribution Provider shall use the
among operating personnel responsible for the
following communications protocols:
real-time generation control and operation of
1.1. When participating in oral or written
the interconnected Bulk Electric System.
Operating Communications:
Transmission Operators and Balancing
1.1.1. Use the English language when
Authorities may use an alternate language for
communicating between
internal operations.
functional entities, unless
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
another language is mandated
by law or regulation.
Conform ing Changes to Other Standards
Revisions to COM-001-1.1- are under development in two projects. Project 2006-06 includes revisions
to Requirements R1-R3 and R5-R6 and Project 2007-02 includes revisions to R4.
Effective Dates
COM-003-1 shall become effective the first day of the first calendar quarter, six calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter a year from the date of Board of Trustee adoption.
•
If the version of COM-001-2 revised under Project 2006-06 is approved before COM-003-1 is
approved, then the remaining requirement (R4) from COM-001-1.1 shall expire midnight of the
day immediately prior to the Effective Date of COM-003-1 in the particular jurisdiction in which
COM-003-1 is becoming effective.
•
If the version of COM-001-2 revised under Project 2006-06 is not approved before COM-003-1
is approved, then COM-001-1.1 shall expire midnight of the day immediately the version of
COM-001-2 developed under Project 2007-02 shall become effective on the first day of the first
calendar quarter, six calendar months following applicable regulatory approval; or, in those
jurisdictions where no regulatory approval is required, the first day of the first calendar quarter
a year from the date of Board of Trustee adoption.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
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Implementation Plan for COM-003-1 — Operating Personnel Communications Protocols
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols
Prerequisite Approvals
None
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Communication — Communication of instruction to change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System.
Conforming Changes to Requirements in Already Approved Standards
•
•
Remove R4 from COM-001-1
Move R2 (or subsequent replacements) from COM-002-3 into COM-003-1 and retire
COM-002-3
Standard Summary
The OPCP SDT developed this new standard and is proposing removing requirements R4 from
COM-001-1 and R2 (or subsequent replacements) from COM-002-3 for inclusion in this standard.
This standard addresses part of Blackout Recommendation #26 and issues in FERC Order 693.
Compliance with StandardsApplicable Entities
Once these standards become effective, the responsible entities identified in the Applicability
section of the standard must comply with the requirements. These include:
•
•
•
•
•
•
•
•
Reliability Coordinator
Balancing Authority
Transmission Owner
Transmission Operator
Generator Operator
Distribution Provider
Transmission Service Provider
Load Serving Entity
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com
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R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
COM-003-1 Requirement R1 Part 1.1.1
R4. Unless agreed to otherwise, each Reliability R1. Each Reliability Coordinator,
Coordinator, Transmission Operator, and
Transmission Operator, Balancing
Balancing Authority shall use English as the
Authority, Generator Operator and
language for all communications between
Distribution Provider shall use the
and among operating personnel responsible
following communications protocols:
for the real-time generation control and
1.1. When participating in oral or written
operation of the interconnected Bulk
Operating Communications:
Electric System. Transmission Operators
1.1.1. Use the English language
and Balancing Authorities may use an
when communicating
alternate language for internal operations.
between functional entities,
unless another language is
mandated by law or
regulation.
Conform ing Changes to Other Standards
Revisions to COM-001-1.1- are under development in two projects. Project 2006-06 includes
revisions to Requirements R1-R3 and R5-R6 and Project 2007-02 includes revisions to R4.
Effective Date
COM-003-1 shall become The proposed effective date for this standard is the first day of the third
first calendar quarter, six calendar months following after applicable regulatory approval; or, s
have been received (or the Reliability Standard otherwise becomes effective the first day of the
third calendar quarter after BOT adoption in those jurisdictions where no regulatory approval is
not required,). the first day of the first calendar quarter a year from the date of Board of Trustees
adoption.
• If the version of COM-001-2 revised under Project 2006-06 is approved before COM003-1 is approved, then the remaining requirement (R4) from COM-001-1.1 shall expire
midnight of the day immediately prior to the Effective Date of COM-003-1 in the
particular jurisdiction in which COM-003-1 is becoming effective.
•
If the version of COM-001-2 revised under Project 2006-06 is not approved before COM003-1 is approved, then COM-001-1.1 shall expire midnight of the day immediately the
version of COM-001-2 developed under Project 2007-02 shall become effective on the
first day of the first calendar quarter, six calendar months following applicable
regulatory approval; or, in those jurisdictions where no regulatory approval is required,
-2-
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the first day of the first calendar quarter a year from the date of Board of Trustee
adoption.
-3-
Most of the requirements in COM003-1 are new – the only requirement
from COM-001associated with COM003 is COM-001, Requirement R4.
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
Mapping Document Showing Translation of COM-001-1, R4 – Telecommunications into COM-003-1– Operating
Personnel Communications Protocol
Requirement in Approved Standard
Translation to
New Standard
or Other
Action
R4. Unless agreed to otherwise, each Reliability
Moved into
Coordinator, Transmission Operator, and
COM 003-1 R1,
Balancing Authority shall use English as the
Part 1.1.1
language for all communications between and
among operating personnel responsible for the
real-time generation control and operation of the
interconnected Bulk Electric System.
Transmission Operators and Balancing
Authorities may use an alternate language for
internal operations
Comments
R1.
Each Reliability Coordinator, Transmission Operator,
Balancing Authority, Generator Operator and
Distribution Provider shall use the following
communications protocols: [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations ]
1.1.
When participating in oral or written Operating
Communications:
1.1.1. Use the English language when
communicating between functional
entities, unless another language is
mandated by law or regulation.
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity levels (VSLs) for
each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an initial value
range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as defined in the ERO
Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC Guidelines when
proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a Cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or Cascading failures; or a requirement in a
planning time frame that, if violated, could, under Emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a Cascading sequence of failures, or could place the Bulk Electric
System at an unacceptable risk of instability, separation, or Cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to
effectively monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric
System instability, separation, or Cascading failures; or a requirement in a planning time frame that, if violated, could, under Emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk
Project YYYY-##.# - Project Name
Electric System; or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk
requirement is unlikely, under Emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric
System instability, separation, or Cascading failures, nor to hinder restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or a requirement
that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the Emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System. A planning requirement that is administrative in
nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified areas
appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability of the bulk
power system:
• Emergency operations
• Vegetation management
• Operator personnel training
• Protection systems and their coordination
• Operating tools and backup facilities
• Reactive power and voltage control
• System modeling and data exchange
• Communication protocol and facilities
• Requirements to determine equipment ratings
VRF and VSL Justifications May 2012
2
Project YYYY-##.# - Project Name
•
•
•
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main Requirement
Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability goals in
different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s definition of
that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address Guideline 1
directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics that encompass nearly
all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a “High” VRF, Guideline 4 directs
assignment of VRFs based on the impact of a specific requirement to the reliability of the system. The SDT believes that Guideline 4 is
reflective of the intent of VRFs in the first instance and therefore concentrated its approach on the reliability impact of the requirements.
VRF and VSL Justifications May 2012
3
Project YYYY-##.# - Project Name
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have
at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or a
small percentage) of the
required performance
The performance or product
measured has significant value
as it almost meets the full intent
of the requirement.
VRF and VSL Justifications May 2012
Moderate
Missing at least one significant
element (or a moderate
percentage) of the required
performance.
The performance or product
measured still has significant
value in meeting the intent of
the requirement.
High
Severe
Missing more than one
significant element (or is missing
a high percentage) of the
required performance or is
missing a single vital
component.
The performance or product has
limited value in meeting the
intent of the requirement.
Missing most or all of the
significant elements (or a
significant percentage) of the
required performance.
The performance measured
does not meet the intent of the
requirement or the product
delivered cannot be used in
meeting the intent of the
requirement.
4
Project YYYY-##.# - Project Name
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining whether to
approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current Level of
Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level of
compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section
4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.
VRF and VSL Justifications May 2012
5
Project YYYY-##.# - Project Name
VRF Justifications – COM 003-1, R1
Proposed VRF
Medium
NERC VRF Discussion
R1 is a requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric
System, or the ability to effectively monitor and control the Bulk Electric System. However, violation of the
requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF for
this requirement is “Medium,” which is consistent with NERC guidelines
FERC VRF G2 Discussion Guideline 2- Consistency within a Reliability Standard:
Consistency within a Reliability Standard. The requirement has sub-requirements that are of equal importance
and similarly address communication protocols; only one VRF was assigned, so there is no conflict.
FERC VRF G3 Discussion Guideline 3- Consistency among Reliability Standards:
Consistency among Reliability Standards. This requirement calls for the use of communication protocols that
reduce the possibility of miscommunication which could lead to action or inaction harmful to the reliability of BES.
This requirement is analogous to R2 of COM-002-2, which requires the use of communication protocols. The VRF
for this requirement (COM-002-2, R2) is “Medium,” which is consistent with COM-003-1 R1 at a “Medium.” The
SDT considers “Medium” as the proper assignment because it is consistent with NERC and FERC guidelines.
FERC VRF G4 Discussion Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the capability of the
Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System. However, violation
of the requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
FERC VRF G5 Discussion Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective, which is to specify clear, formal and universally-applied
communication protocols that reduce the possibility of miscommunication which could lead to action or inaction
harmful to the reliability of BES. Since the requirement has only one objective, only one VRF was assigned.
VRF and VSL Justifications May 2012
6
Project YYYY-##.# - Project Name
Proposed VSLs for R1
Lower
N/A
Moderate
High
The responsible entity did not correctly
implement one (1) of the four (4) parts
of Requirement R1, Part 1.1 when it was
appropriate to use all four parts.
The responsible entity did
not correctly implement
two (2) of the four (4)
parts of Requirement R1,
Part 1.1 when it was
appropriate to use all four
parts.
OR
The responsible entity did not correctly
implement Part 1.2 of the requirement.
OR
The responsible entity did
not correctly implement
one (1) of the four (4)
parts of the requirement
when it was appropriate to
use three of the four parts.
Severe
The responsible entity did not correctly
implement any of the parts of
Requirement R1, Part 1.1 when it was
appropriate to use all four Parts.
OR
The responsible entity did not correctly
implement three (3) or more of the four
(4) parts of Requirement R1, Part 1.1 when
it was appropriate to use all four parts.
OR
The responsible entity did not correctly
implement two (2) of the four (4) parts of
Requirement R1, Part 1.1 when it was
appropriate to use three of the four parts.
OR
The responsible entity did not correctly
implement one (1) of the four (4) parts of
Requirement R1, Part 1.1 when it was
appropriate to use two of the four parts.
VRF and VSL Justifications May 2012
7
Project YYYY-##.# - Project Name
VSL Justifications – COM 003-1, R1
The most comparable requirement is COM-002-2, R2. Based on
FERC VSL G1
the VSL Guidance, the SDT developed four VSLs based on
Violation Severity Level Assignments Should Not Have the Unintended
misapplication or absence of common communication protocols.
Consequence of Lowering the Current Level of Compliance
If no communication protocols are used at all or if the number of
required protocols falls below the listed thresholds, then the VSL
is Severe.
FERC VSL G2
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment Category
for "Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain
Ambiguous Language
Guideline 2a:
• The VSL assignment for R1 is not binary.
Guideline 2b:
•
The proposed VSL does not use any ambiguous
terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for
similar violations.
FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement
FERC VSL G4
Violation Severity Level Assignment Should Be Based on A Single
Violation, Not on A Cumulative Number of Violations
The VSL is based on a single violation and not cumulative
violations
FERC VSL G5
Requirements where a single lapse in protection can compromise
computer network security, i.e., the ‘weakest link’ characteristic,
should apply binary VSLs
Non CIP
VRF and VSL Justifications May 2012
8
Project YYYY-##.# - Project Name
FERC VSL G6
VSLs for cyber security requirements containing interdependent tasks
of documentation and implementation should account for their
interdependence
Non CIP
VRF Justifications – COM 003-1, R2
Proposed VRF
Medium
NERC VRF Discussion
R2 is a requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric
System, or the ability to effectively monitor and control the Bulk Electric System. However, violation of the
requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF for
this requirement is “Medium,” which is consistent with NERC guidelines
FERC VRF G2 Discussion Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements; only one VRF was assigned, so there is no conflict. No one
subrequirement is a “Low” or a “High,” so a VRF of “Medium” was assigned.
FERC VRF G3 Discussion Guideline 3- Consistency among Reliability Standards:
Consistency among Reliability Standards. This requirement calls for use of formal three-part communication by
the issuer of an Operating Communication. This requirement is analogous to R2 of COM-002-2, which describes a
communication protocol required for operating personnel to use when giving a directive. The VRF for this
requirement is “Medium,” which is consistent with COM-003-1 R2 at a “Medium.” The SDT considers “Medium”
as the proper assignment because it is consistent with NERC and FERC guidelines.
FERC VRF G4 Discussion Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability of the
Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System. However, violation
of the requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
VRF and VSL Justifications May 2012
9
Project YYYY-##.# - Project Name
VRF Justifications – COM 003-1, R2
FERC VRF G5 Discussion Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective; which is to use formal, listed communications protocols.
Since the requirement has only one objective, only one VRF was assigned.
VRF and VSL Justifications May 2012
10
Project YYYY-##.# - Project Name
Proposed VSLs for R2
Lower
Moderate
High
Severe
The responsible entity issued a
verbal person-to-person
Operating Communication and
did not confirm the receiver’s
response was correct. (Part 2.2,
first bullet)
The responsible entity issued a
verbal person-to-person Operating
Communication and did not
reissue the Operating
Communication when requested
by the receiver. (Part 2.2, third
bullet)
The responsible entity issued a
verbal person-to-person Operating
Communication and did not wait
for a response from the receiver.
(Part 2.1)
Or
The responsible entity issued a
verbal person-to-person Operating
Communication and did not
reissue the Operating
Communication when the
response was incorrect or when
there was no response (Part 2.2,
second bullet).
VRF and VSL Justifications May 2012
11
Project YYYY-##.# - Project Name
VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level Assignments Should Not Have the Unintended
Consequence of Lowering the Current Level of Compliance
The most comparable requirement is COM 002-2, R2. Based on
the VSL Guidance, the SDT developed three VSLs based on
misapplication of three-part communication. If the communication
did not include the critical steps required for confirmation or for
additional repetition, then the VSL is Severe.
FERC VSL G2
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment Category
for "Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain
Ambiguous Language
Guideline 2a:
• The VSL assignment for R2 is not binary.
Guideline 2b:
•
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement
FERC VSL G4
Violation Severity Level Assignment Should Be Based on A Single
Violation, Not on A Cumulative Number of Violations
The VSL is based on a single violation and not cumulative violations
FERC VSL G5
Requirements where a single lapse in protection can compromise
computer network security, i.e., the ‘weakest link’ characteristic,
should apply binary VSLs
Non CIP
FERC VSL G6
Non CIP
VRF and VSL Justifications May 2012
12
Project YYYY-##.# - Project Name
VSLs for cyber security requirements containing interdependent tasks
of documentation and implementation should account for their
interdependence
VRF Justifications – COM 003-1, R3
Proposed VRF
Medium
NERC VRF Discussion
R3 is a requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric
System, or the ability to effectively monitor and control the Bulk Electric System. However, violation of the
requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF for
this requirement is “Medium,” which is consistent with NERC guidelines.
FERC VRF G2 Discussion Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned, so there is no conflict. A VRF of “Medium”
was assigned.
FERC VRF G3 Discussion Guideline 3- Consistency among Reliability Standards:
Consistency among Reliability Standards. This requirement calls for use of formal three-part communication by
the receiver of an Operating Communication. This requirement is analogous to R2 of COM-002-2, which describes
a communication protocol required for operating personnel to use when given a directive. The VRF for this
requirement (COM-002-2,2R) is “Medium,” which is consistent with COM-003-1 R3 at a “Medium.” The SDT
considers “Medium” as the proper assignment because it is consistent with NERC and FERC guidelines.
FERC VRF G4 Discussion Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability of the
Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System. However, violation
of the requirement is unlikely to lead to Bulk Electric System instability, separation, or Cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
FERC VRF G5 Discussion Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective; which is to use formal listed communications protocols
VRF and VSL Justifications May 2012
13
Project YYYY-##.# - Project Name
VRF Justifications – COM 003-1, R3
utilize. Since the requirement has only one objective, only one VRF was assigned.
VRF and VSL Justifications May 2012
14
Project YYYY-##.# - Project Name
Proposed VSLs for R3
Lower
VRF and VSL Justifications May 2012
Moderate
High
Severe
The responsible entity received a
verbal person-to-person Operating
Communication and did not wait
for confirmation that the
repetition was correct. (R3, first
bullet)
The responsible entity received a
verbal person-to-person Operating
Communication and did not repeat
the Operating Communication and
did not request that the issuer
reissue the Operating
Communication. (R3)
15
Project YYYY-##.# - Project Name
VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level Assignments Should Not Have the
Unintended Consequence of Lowering the Current Level of
Compliance
The most comparable requirement is COM 002-2, R2. Based on the
VSL Guidance, the SDT developed two VSLs based on misapplication
of three part communication. If the communication did not include
the critical steps required for confirmation or for additional
repetition, then the VSL is Severe.
FERC VSL G2
Violation Severity Level Assignments Should Ensure Uniformity and
Consistency in the Determination of Penalties
Guideline 2a: The Single Violation Severity Level Assignment
Category for "Binary" Requirements Is Not Consistent
Guideline 2b: Violation Severity Level Assignments that Contain
Ambiguous Language
Guideline 2a:
FERC VSL G3
Violation Severity Level Assignment Should Be Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the
associated requirement, and is, therefore, consistent with the
requirement.
FERC VSL G4
Violation Severity Level Assignment Should Be Based on A Single
Violation, Not on A Cumulative Number of Violations
The VSL is based on a single violation and not cumulative violations
FERC VSL G5
Requirements where a single lapse in protection can compromise
computer network security, i.e., the ‘weakest link’ characteristic,
should apply binary VSLs
Non CIP
FERC VSL G6
Non CIP
VRF and VSL Justifications May 2012
• The VSL assignment for R3 is not binary.
Guideline 2b:
•
The proposed VSL does not use any ambiguous terminology,
thereby supporting uniformity and consistency in the
determination of similar penalties for similar violations.
16
Project YYYY-##.# - Project Name
VSL Justifications – COM 003-1, R2
VSLs for cyber security requirements containing interdependent
tasks of documentation and implementation should account for
their interdependence
VRF and VSL Justifications May 2012
17
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COM-0 0 3 -1
Operating Communications Protocols
White Paper
May 2012
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Table of Contents
Ta b le o f Co n t e n t s
Table of Contents .............................................................................................................................ii
Introduction .................................................................................................................................... 1
Three-Part Communication ............................................................................................................ 3
Phonetic Alphabet or Alpha-numeric Clarifiers .............................................................................. 5
COM-003-1 Operating Personnel Communication Protocols ........................................................ 6
Electric Utility Industry Communication Practices ......................................................................... 7
Human Factor Considerations ........................................................................................................ 9
Communication Practices External to the Electric Utility Industry .............................................. 10
Performance of the Electric Utility Industry ................................................................................. 12
COM-003-1 Operating Communications Protocols White Paper – May, 2012
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Chapter 1 — Introduction
I n t r o d u ct io n
Communication (COM) Standard COM-003-1 features requirements, the purpose of which is to
provide clear, formal and universally applied communication protocols that reduce the
possibility of miscommunication that could lead to action or inaction that is detrimental to the
reliability of the Bulk Electric System (BES). Significant events have occurred on the BES when
unclear communication created or exacerbated misunderstandings that led to instability and
separation. Communication protocols used in many industries, militaries and government
departments have added clarity to oral and written communications and have prevented
potential errors that would have resulted in catastrophic events.
Pu r p o s e
The Operations Personnel Communications Protocol Standards Drafting Team (OPCP SDT)
drafted a Standard Authorization Request (SAR) for Project 2007-02. The purpose of the
proposed standard is to: “Require that real time System Operators use standardized
communication protocols during normal and emergency operations to improve situational
awareness and shorten response time.”
The purpose of this paper is to establish the reliability value of requiring three-part
communication for all operations on the BES described in the proposed definition of COM-003 1 “Operating Communications.” Additionally, it addresses the reliability benefit of other
communication protocols featured in COM 003-1 that provide addition clarity for “Operating
Communications.”
Ba ckg ro u n d
NERC Project 2007-02 was created from the 2003 Blackout Report, Recommendation 26. In
April 2004, the “Blackout Report” was submitted to the President of the United States of
America and the Prime Minister of Canada.
The Blackout Report stated that:
“Ineffective communications contributed to a lack of situational awareness and
precluded effective actions to prevent the cascade. Consistent application of
effective communications protocols, particularly during alerts and emergencies,
is essential to reliability.”
The report also recommended that industry,
“Tighten communications protocols, especially for communications during alerts and
emergencies. Upgrade communication system hardware where appropriate.”
FERC Order No. 693, Paragraph 532 directs the ERO and the industry to develop communication
protocols based on the following guidelines:
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Chapter 1 — Introduction
“532. While we agree with EEI that EOP-001-0, Requirement R4.1 requires
communications protocols to be used during emergencies, we believe, and the ERO
agrees, that the communications protocols need to be tightened to ensure Reliable
Operation of the Bulk-Power System. We also believe an integral component in
tightening the protocols is to establish communication uniformity as much as practical
on a continent-wide basis. This will eliminate possible ambiguities in communications
during normal, alert and emergency conditions. This is important because the BulkPower System is so tightly interconnected that System impacts often cross several
operating entities’ areas.”
In response to this recommendation in FERC Order No. 693, a SAR team was established in April
of 2007. These reports, directives and approved guidance documents provide the framework
from which the OPCP SDT derived the concepts that contributed to the development of the
COM-003-1 requirements.
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Chapter 2— Three-Part Communication
Th r e e -Pa r t Co m m u n ica t io n
Ove r vie w
Three-part communication, sometimes known as the “repeat back” method of
communications, is used to communicate changes to physical Facility equipment during work
activities via face-to-face, telephone, or radio communications. This communication protocol
requires three oral exchanges between a sender and a receiver to promote a reliable transfer of
information and understanding. The person originating the communication is the sender and is
responsible for verifying that the receiver understands the message, as intended. The receiver
makes sure he or she understands what the sender is saying and repeats back the message to
the sender.
St e p s fo r Th r e e Pa r t Co m m u n ica t io n
COM-003-1 requires the use of three-part communication for “Operating Communications,”
which is defined as, “Communication of instruction to change or maintain the state, status,
output, or input of an Element 1 or Facility 2 of the Bulk Electric System.”
This is a general description of how three-part communication functions:
1. First - The sender orally transmits information (face-to-face, telephonic or other
electronic equivalent) clearly and concisely to the receiver, directing them to alter an
element that could impact the BES.
2. Second - The receiver orally acknowledges the communication by repeating the
message back to the sender. The receiver does not need to repeat every part of the
communication verbatim, but he or she must restate the equipment-related
information exactly as spoken by the sender. If the receiver does not understand the
message, he or she must ask for clarification.
3. Third - The sender acknowledges the reply and confirms to the receiver that the
message is correct and properly understood by stating the communication was correct.
If the sender does not understand the receiver’s reply, the sender must then respond by
saying, “That is wrong,” (or words to that effect) and then restate the original message.
If corrected, the receiver must acknowledge the corrected message and repeat back the
message to the sender.
1
In the NERC Glossary of Terms, Element is defined as, “Any electrical device with terminals that may be connected to other
electrical devices such as a generator, transformer, circuit breaker, bus section, or transmission line. An element may be
comprised of one or more components.”
2
In the NERC Glossary of Terms, Facility is defined as “a set of electrical equipment that operates as a single Bulk Electric
System Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)”
COM-003-1 Operating Communications Protocols White Paper – May, 2012
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Chapter 2— Three-Part Communication
Verbal three-part communication should be used during the operation or alteration of Facility
equipment. Applicable entities are to use three-part communications when performing steps
or actions using an approved procedure that impact equipment or activities, the safety of
personnel, the environment, or the Facility. Finally, three-part communication should be
implemented for tasks where the consequences of a mishap are unacceptable and could lead to
instability, uncontrolled separation, or Cascading.
As a best practice, it may also be used when discussing the condition of Facility equipment or
the value of an important parameter in utility operations.
COM-003-1 Operating Communications Protocols White Paper – May, 2012
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Chapter 3— Phonetic Alphabet or Alpha-numeric Clarifiers
Ph o n e t ic Alp h a b e t o r Alp h a - n u m e r ic Cla r ifie r s
Ove r vie w
Several letters in the English language sound alike and can be confused in stressful or noisy
situations. For example, some letters sound alike when spoken, and can easily be confused;
such as “D” and “B.” The phonetic alphabet specifies a common word for each letter of the
English alphabet. By using a word for each letter, there is less chance that the person listening
will confuse the letters. Using the phonetic alphabet, “Delta” and “Bravo” are more easily
differentiated. The effects of noise, weak telephone or radio signals, and an individual's accent
are reduced through the use of the phonetic alphabet.
People use the phonetic alphabet and unit designators when describing unique identifiers for
specific components. When the only distinguishing difference between two component labels
is a single letter, then the phonetic alphabet form of the letter should be substituted for the
distinguishing character. For example, 2UL-18L and 2UL-18F would be stated, “two Uniform
Lima dash one eight Lima” and “two Uniform Lima dash one eight Foxtrot.”
COM- 0 0 3 -1 Fe a t u r e d Ph o n e t ic Alp h a b e t
Letter - Word
A - Alpha
B - Bravo
C - Charlie
D - Delta
E - Echo
F - Foxtrot
G - Golf
Number
1 - One
2 - Two
3 - Three
4 - Four
5 – Five
Letter - Word
H - Hotel
I - India
J - Juliet
K - Kilo
L - Lima
M - Mike
N - November
pronounced as:
(wun)
(too)
(tree)
(fow-er)
(fife)
Letter - Word
O - Oscar
P - Papa
Q - Quebec
R - Romeo
S - Sierra
T - Tango
U – Uniform
Number
6 - Six
7 – Seven
8 – Eight
9 – Nine
0 – Zero
Letter - Word
V - Victor
W - Whiskey
X - X-ray
Y - Yankee
Z - Zulu
pronounced as:
(six)
(sev-en)
(ait)
(nin-er)
(zee-row)
The phonetic alphabet or a correct alpha-numeric clarifier is to be used for any,
“Communication of instruction to change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System.”
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Chapter 4— COM-003-1 Operating Personnel Communication Protocols
COM-0 0 3 -1 Op e r a t in g Pe r s o n n e l Co m m u n ica t io n
Pr o t o co ls
The nature of communication between people can be complex and subject to many variables.
Accents, moods, regional jargon, cultural interpretations, multiple languages, individual skill
sets, and physiological conditions are but a few of the universe of factors that can and do have
an impact on the clarity of two-party, person-to-person communication. Until the human
factor is completely eliminated, there will be the risk of human error due to miscommunication.
Miscommunication has created unintended results on the Bulk Electric System (BES) that have
led to outages and, in some cases, the inability of an operator to prevent the spread of
Cascading. Although the potential for human error can never be completely eliminated,
successful, proven communication protocols from other industries that also deal with critical
processes and systems can be implemented to reduce the risk to BES reliability. The successful
implementation of these widely-accepted communication protocols from other industries into
the requirements of COM-003-1 will have a significant, positive impact on the reliability of the
BES.
COM-003-1 requires the use of three-part communication for all Operating Communications.
The reliability benefits of using three-part communication is threefold:
1. The removal of any doubt that communication protocols will be used and when they will
be used. This will reduce the opportunity for confusion and misunderstanding among
entities that may have different doctrine. An example is: One entity uses three-part for
emergencies, and the other uses it for all operating conditions.
2. There will be no mental “transition” when operating conditions shift from normal to
Emergency. The communication protocols for the operators will remain standard during
transitions through all conditions.
3. The formal requirement for three-part communication will create a heightened sense of
awareness in operators that the task they are about to execute is critical, and recognize
the risk to the reliable operation of the BES is increased if the communication is
misunderstood.
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Chapter 5— Electric Utility Industry Communication Practices
Ele ct r ic Ut ilit y I n d u s t r y Co m m u n ica t io n Pr a ct ice s
The risk of BES failure due to miscommunication is very significant in the electric power
industry. Blackouts that affect millions of customers in major cities are guaranteed to create
undesirable media attention. The public at large in North America is heavily dependent on
technology and is intolerant of massive blackouts. The public is conditioned to 24/7 access to
technology, climate control and lighting. A sudden loss of service quickly causes immediate
public frustration. If the root cause was determined to be industry operating
miscommunication instead of uncontrollable environmental factors, criticism increases even
more dramatically. Other industries that currently deal with risks, challenges and potentially
widespread consequences similar to the electric utility industry have successfully reduced
miscommunication by implementing uniform communication protocols similar to those
identified in and required by COM 003-1.
Ta b le o f Co m m u n ica t io n Pr a ct ice s o f t h e Ele ct r ic Ut ilit y I n d u s t r y
The examples listed in the table below represent the communication practices of many major
registered entities that engage in three part communication when altering the operating state
of the BES. These registered entities account for a large amount of the generation, load and
customers served in North America.
Table 1-A Registered Entities that Currently Use Three-Part Communication during Both
Emergencies and Non-emergencies 3
Registered Entity
Location and
Description
South/Central US
Entity (large)
Large Southern
Entity #1
Large Mid
Atlantic RTO
Entity
Large Southern
Entity #2
Large West Coast
Entity#1
Large Canadian
HYDRO
Large
Generation
Operations
Transmission
Operations
Distribution
Operations
Normal
Operations
Emergency
Operations
Customers
Impacted
Load
Yes
Yes
Yes
Yes
Yes
23 Million
82 GW
Yes
Yes
Yes
Yes
Yes
4.4 Million
43 GW
Yes
Yes
NA
Yes
Yes
60 Million
185 GW
Yes
Yes
Yes
Yes
Yes
2.8 Million
30 GW
Yes
Yes
Yes
Yes
Yes
5.1 Million
Not
Available
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
1.3
Million
3.4
27 GW
17 GW
3
Industry use of three part communication analysis is based on publicly published documents, policies, procedures and internal
standards.
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Chapter 5— Electric Utility Industry Communication Practices
Registered Entity
Location and
Description
Midwestern/
Western Utility
Large Florida
TOP
Midwestern RTO
Entity
DOE
INPO
Generation
Operations
Transmission
Operations
Distribution
Operations
Normal
Operations
Emergency
Operations
Customers
Impacted
Load
Million
Yes
Yes
Yes
Yes
Yes
4.5
Million
43GW
Yes
Yes
NA
Yes
Yes
39 Million
110 GW
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
NA
NA
NA
NA
This is strong evidence of an embedded electric utility practice that establishes, without doubt,
the significant element of reliability value of three-part communications and the other
communications protocols. The fact that the majority of BES entities already employ three-part
(or repeat back) communications for routine, alert and Emergency operations (and document it
in very strong language in their policy and procedures) demonstrates that the electric utility
industry recognizes this significant element of value.
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Chapter 6— Human Factor Considerations
Hu m a n Fa ct o r Co n s id e r a t io n s
As previously discussed, there are a myriad of reasons that miscommunications occur. Beyond
the typical environmental concerns (loud background noise, radio static, dialects, etc.), humans
are very likely to have misunderstandings based on other factors. Humans are susceptible to
expectation errors, relating to context and meaning, which will often drive understanding.
People often discern what they want to hear, usually at a subconscious level. The importance
of verifying what is heard becomes the first step in assuring that the message was understood.
When a person hears a message, an interpretation emerges from the different pieces of
conversation data; this is called data-driven or bottom-up processing. Perception can be
largely data-driven because one wants to make sure their understanding accurately reflect
events in the outside world; in this case, the message from the sender. A person wants the
interpretation of a message to be determined mostly by data (perception), then to
understand the information in the environment (comprehension), and to make the
appropriate decision from the senses; not by the listener’s expectations. This data-driven
processing can lead to miscommunications and may affect situational awareness because if
the perception of the information is wrong, the chances of correct understanding and
making proper future decisions are dramatically reduced. 4
Situation awareness is fundamentally based on one’s understanding of a system, how it
operates, its characteristics, and performance parameters; couplings within itself and other
systems and how one interacts with it. This understanding is referred to as one’s mental
model. It is a representation of the surrounding world, the relationships between its various
parts and a person's intuitive perception about his or her own actions and their
consequences. One’s mental model helps to shape one’s behavior and define one’s
approach to solving problems (a personal algorithm) and carrying out tasks, especially within
a system. Mental models can be partially or completely right or wrong, complete or
incomplete, and most often are unique for each individual. Sometimes mental models are
carried throughout an organization through operating norms and commonly understood
practices. Part of building a mental model for a particular problem or event is to gain
information through active communication with others. Miscommunication can hamper
immediate decisions and can also lay in waiting as a latent error, which can expose itself later
when the incorrect information is retrieved or used in the processing of decision making.
4
Endsley, M. R. (1995). Toward a theory of situation awareness in dynamic systems. Human Factors, 37(1), 32-64.
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Chapter 7— Communication Practices External to the Electric Utility Industry
Co m m u n ica t io n Pr a ct ice s Ex t e r n a l t o t h e Ele ct r ic Ut ilit y
I n du st ry
The purpose of effective communication is to create mutual understanding between two or
more people. Effective communication is an important defense in the prevention of errors and
events. Many industries mandate communication protocols due to the high potential for
catastrophic results if an important communication is misunderstood. While the effects of
critical mishaps from ineffective communications differ, the offending organization and
associated industry will find itself dealing with legal, regulatory, financial, market and political
consequences.
Me d ica l Fie ld I n d u s t ry
Ineffective communication is a root cause for nearly 66 percent of all sentinel events (events
that signal the need for immediate investigation and response) reported in the medical
industry. In other words, 66 percent of all reported deaths or serious injuries (accidents) in
healthcare from 1995-2005 were related to ineffective communication. 5
One step the medical industry is implementing to solve ineffective communication problems in
the healthcare industry is to implement a “read-back” process for taking verbal or telephone
orders.
Oral communication possesses a greater risk of misunderstanding compared to written forms of
communication. Misunderstandings are most likely to occur when the individuals involved
have different understandings, or mental models, of the current work situation or use terms
that are potentially confusing. Therefore, confirmation of verbal exchanges of operational
information between individuals must occur to promote understanding and reliability of the
communication. In addition, the medical industry is standardizing abbreviations, acronyms, and
symbols used throughout the field, to include compiling a list of those abbreviations, acronyms,
and symbols that are not to be used.
Co m m e rcia l Air Tr a n s p o r t a t io n I n d u s t r y
Based on available data, in the last 67 years there have been 274 commercial airline accidents
involving at least 60 fatalities or more. Miscommunication between pilots and controllers can
clearly be identified as a causal factor in 36 (13 percent) of these tragedies. Based on this
analysis, the aviation community has implemented interpersonal communication tools like
three-part communications and language standardization.
5
JCAHO1 Root Causes and Percentages for Sentinel Events (All Categories) January 1995−December 2005.
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Chapter 7— Communication Practices External to the Electric Utility Industry
Milit a r y Co m m u n ica t io n Pr o t o co ls
Military organizations have a long history of communication protocols that they have
developed and have improved over time. Firing orders, shipboard orders to the helm, aircraft
launch and recovery contain elements of three-part communication and alpha numeric
clarifiers. The reasons these communication protocols are required are due to the extreme
risks and consequences that exist if miscommunication occurs. Military organizations also
make use of the NATO alphabet and various shorthand codes to provide a status or update.
Ra ilro a d Op e r a t io n s
Rail operations have similar risks of catastrophic results due to miscommunication. Switching
rails, moving cars, coupling, decoupling and loading freight necessitate clear communication
and require three-part communication and formal protocols.
Ot h e r Or g a n iza t io n s
Police and fire dispatch, the Department of Energy, and The Institute of Nuclear Power
Operations (INPO) are among other organizations that value and mandate communication
protocols similar to those in COM-003-01.
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Chapter 8— Performance of the Electric Utility Industry
Pe r fo r m a n ce o f t h e Ele ct r ic Ut ilit y I n d u s t r y
Of all of the System events that NERC has either analyzed or investigated, 50 percent of those
have involved findings of a deficiency of clear, concise communications. These events have
either impacted, or potentially impacted, a significant amount of Load and/or generation.
Significant blackout events, such as the Northeastern Blackout of 2003 and the Florida Blackout
of 2008, have communication issues listed among the top contributors to loss of Load and
generation.
This analysis highlights the fact that industry Operating Communication performance over the
last 10 years still has room for significant improvement. The lack of clear standard
communication protocols when operating the BES will continue to create unacceptable levels of
risk for large-scale failures.
Table 1 indicates that, across electric power industry, internal policies specify three-part
communications for all BES operations, including routine or normal operations. This high level
of compliance can be associated with the history of enforcement of COM 002-2a, R2, which
requires three-part communication for all directives. This requirement has been mandated and
has been enforceable for several years. When compared to COM 002-2a, COM 003-1 features
improved approaches and structure for three-part communication that assigns proper
responsibility for the “issuer” (sender) and for the “receiver.” When combined with the
proposed definition of “Operating Communications,” COM 003 clarifies the circumstances of
when to use three-part communication. The other improvement COM 003-1 offers, to improve
the reliability of the BES, is the addition of several proven communication protocols that will
clarify Operating Communications to reduce the risk of mistakes Clarifying several key elements
of an “Operating Communication;” such as time, time zone, equipment identifiers, a common
language and alpha-numeric clarifiers, all contribute to reducing misunderstandings and reduce
the risk of a grave error during BES operations.
Su m m a r y
The BES across North America is a “tightly” interconnected System where instability can spread
quickly. When a decision is made to alter the state of an Element on the BES, there is an
increased threat to reliability, no matter what type of operating condition (normal, alert,
Emergency) exists. The transition from normal to Emergency operation can be sudden and
indistinguishable until recognized, often after the damage is done. There are multiple human
factors during communication that occur naturally and contribute to unclear communication,
which increases the risk to reliable operation of the BES.
The electric power industry widely deploys communication protocols such as three-part
communications for all BES Operating Communications. The uniform deployment of these
protocols in the three Interconnections is in part due to Requirement 2 in the mandatory and
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Chapter 8— Performance of the Electric Utility Industry
enforceable Reliability Standard COM-002-2a. Industry’s widespread utilization of three-part
communications for BES Operating Communication is a confirmation of the reliability value of
the protocol.
The official results of the 2003 Blackout Report cites unclear communications as a major factor
in the cause, spread, and impedance of restoration of major BES failures. Other industries have
successfully implemented universal communication protocols, which have resulted in fewer
accidents and fatalities caused by miscommunications. Preventable blackouts or widespread
loss of generation or load continues to be politically, socially and economically unacceptable in
North America.
Co n clu s io n
The critical nature of BES configuration and its impact on reliability demands, that any action
planned to alter the System under any condition should be systematically and clearly conveyed.
Given the extent of human involvement in the process, the risk of miscommunication increases
based on our own human tendencies and perceptions.
COM 003-1 takes communication protocols for the BES to the next level of reliability by
requiring protocols that will reduce the risk of miscommunication. It clarifies when to use threepart communication. It provides a superior requirement structure that properly assigns the
elements of three-part communication to the “issuer” (sender) and “receiver” and requires
additional communication protocols that provide greater clarity when engaged in operating
communication on the BES. Based on the facts listed above, communication protocols, as
contained in proposed Standard COM-003-1, will provide a strong and much improved
reliability benefit to address existing communication reliability gaps that continue to negatively
impact the reliable operation of the BES.
The proposed communication protocols in COM 003-1 have been successfully developed and
proven in other organizations’ processes. The use of repeat backs and the added layer of value
they provide to BES reliability make them essential to all “Operating Communications.” The
OPCP SDT endorses the use of these protocols.
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Standard COM-001-2 — Telecommunications
A. Introduction
Requirement R4 was assigned to
Project 2007-02. All other
requirements were assigned to Project
2006-06 and are being revised or
retired under Project 2006-06.
1.
Title:
Telecommunications
2.
Number:
COM-001-2
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
(Proposed) Effective Date: First day of the first calendar quarter, six calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter a year from the date of Board of
Trustee adoption.
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
written operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilities.
R5.
Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM001, “NERCNet Security Policy.”
C. Measures
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Standard COM-001-2 — Telecommunications
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy, that will be used to confirm that it meets Requirement 4.
M3. The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to, documented procedures, operator logs, voice recordings or
transcripts of voice recordings, electronic communications, etc., that will be used to determine
if it adhered to the (User Accountability and Compliance) requirements in Attachment 1-COM001. (Requirement 5)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 4.
For Measure 3, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
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Standard COM-001-2 — Telecommunications
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance for every one of the following
requirements that is in violation:
2.3.1
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities, as
specified in R4.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed, as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
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Standard COM-001-2 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
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Standard COM-001-2 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
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Standard COM-001-1.12 — Telecommunications
A. Introduction
Requirement R4 was assigned to
Project 2007-02. All other
requirements were assigned to Project
2006-06 and are being revised or
retired under Project 2006-06.
1.
Title:
Telecommunications
2.
Number:
COM-001-1.12
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
(Proposed) Effective Date: First day of the first calendar quarter, six calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter a year from the date of Board of
Trustee adoption.May 13, 2009
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all communications between and among operating
personnel responsible for the real-time generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing Authorities may use an alternate language
for internal operations.
R5.R4.
Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall have written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunications facilities.
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Standard COM-001-1.12 — Telecommunications
R6.R5.
Each NERCNet User Organization shall adhere to the requirements in
Attachment 1-COM-001, “NERCNet Security Policy.”
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy, that will be used to confirm that it meets Requirement 4.The Reliability Coordinator,
Transmission Operator or Balancing Authority shall have and provide upon request evidence
that could include, but is not limited to operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or equivalent, that will be used to determine
compliance to Requirement 4.
M3.Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have
and provide upon request its current operating instructions and procedures, either electronic or
hard copy that will be used to confirm that it meets Requirement 5.
M4.M3.
The NERCnet User Organization shall have and provide upon request
evidence that could include, but is not limited to, documented procedures, operator logs, voice
recordings or transcripts of voice recordings, electronic communications, etc., that will be used
to determine if it adhered to the (User Accountability and Compliance) requirements in
Attachment 1-COM-001. (Requirement 65)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
Page 2 of 6
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Standard COM-001-1.12 — Telecommunications
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2 each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall keep 90 days of historical data (evidence).
For Measure 32, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 54.
For Measure 43, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.22.3.1
There are no written operating instructions and procedures to enable
continued operation of the system during the loss of telecommunication facilities,
as specified in R5R4.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed, as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Page 3 of 6
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Standard COM-001-1.12 — Telecommunications
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
Page 4 of 6
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Standard COM-001-1.12 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Page 5 of 6
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Standard COM-001-1.12 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
Page 6 of 6
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Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Initial Ballot and Non-Binding Poll Open Through 8 p.m. Wednesday,
June 20, 2012
Now Available
An initial ballot of COM-003-1 – Operating Personnel Communications and Protocols and a non-binding
poll of the associated VRFs/VSLs is open through 8 p.m. Eastern on Wednesday, June 20, 2012.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standard and opinion in the non-binding poll of the associated VRFs and VSLs by clicking here.
Due to modifications to NERC’s balloting software, voters will no longer be able to submit comments
via the balloting software
Next Steps
The drafting team will consider all comments received during the formal comment period and initial
ballot and determine whether to make changes to the standard and associated documents. After the
standards and associated documents are revised, the drafting team will submit its work for quality
review prior to the next posting.
Background
There are two projects that have the modification of the COM family of standards in the scope of their
SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is concerned
with communication protocols for normal and emergency operations. The other project, Project 200606 – Reliability Coordination has limited the scope of its modifications to the COM family of standards
to those that address communication during emergency operations. The Project 2006-06 team has
proposed a new term, “Reliability Directive,” to specifically address those communications. The
proposed definition of Reliability Directive is “A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.” The Project 2006-06 drafting team is proposing to require
three-part communication for Reliability Directives, with a VRF of High for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols must address communication
protocols for both normal and emergency operations, the Project 2007-02 drafting team is proposing a
new term, “Operating Communication.” The proposed definition for Operating Communication is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
“Communication of instruction to change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.” Given that Reliability Directives are a subset of Operating
Communications, and to avoid any possibility of double jeopardy, the Project 2007-02 SDT is proposing
to require three-part communication for all Operating Communications other than Reliability
Directives, and has proposed a Medium VRF for these requirements. Having a High VRF for a violation
of three-part communication involving a Reliability Directive and having a Medium VRF for a violation
of three-part communication involving other Operating Communications supports the appropriate
differentiation of risk for normal and emergency communications.
Additional information is available on the project webpage.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
White Paper on Operating Communications Protocols now Posted
Now Available
A white paper on Operating Communications protocols has been posted with the clean version COM003-1 – Operating Personnel Communications Protocols that has been posted for a 45-day formal
comment period, initial ballot and non-binding poll. The drafting team prepared this white paper to
aid in the evaluation of proposed COM-003-1 and the associated proposed definition of Operating
Communication.
Background
NERC Project 2007-02 was created from the 2003 Blackout Report, Recommendation 26. In April 2004,
the “Blackout Report” was submitted to the President of the United States of America and the Prime
Minister of Canada.
The Blackout Report stated that:
“Ineffective communications contributed to a lack of situational awareness and precluded
effective actions to prevent the cascade. Consistent application of effective communications
protocols, particularly during alerts and emergencies, is essential to reliability.”
The report also recommended that industry,
“Tighten communications protocols, especially for communications during alerts and
emergencies. Upgrade communication system hardware where appropriate.”
FERC Order No. 693, Paragraph 532 directs the ERO and the industry to develop communication
protocols based on the following guidelines:
“532. While we agree with EEI that EOP-001-0, Requirement R4.1 requires communications
protocols to be used during emergencies, we believe, and the ERO agrees, that the
communications protocols need to be tightened to ensure Reliable Operation of the BulkPower System. We also believe an integral component in tightening the protocols is to
establish communication uniformity as much as practical on a continent-wide basis. This will
eliminate possible ambiguities in communications during normal, alert and emergency
conditions. This is important because the Bulk- Power System is so tightly interconnected that
System impacts often cross several operating entities’ areas.”
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The purpose of the white paper is to establish the reliability value of requiring three-part
communication for all operations on the BES described in the proposed definition of COM-003 -1
“Operating Communication.” Additionally, it addresses the reliability benefit of other communication
protocols featured in COM 003-1 that provide addition clarity for “Operating Communication.”
The requirements in COM-003-1 also support one of the eight high priority issues identified in the
NERC President’s Top Priority Issues for BPS Reliability Issued January 7, 2011:
Ambiguous or incomplete voice communications – Out of longstanding tradition, system
operators and reliability coordinators are comfortable with informal communications with field
and power plant personnel and neighboring systems. Experience from analyzing various events
indicates there is often a sense of awkwardness when personnel transition from conversational
discussion to issuing reliability instructions. It is also human nature to be uncomfortable in
applying formal communication procedures after personnel have developed informal styles
over many years. Confusion in making the transition from normal conversation to formal
communications can introduce misunderstandings and possibly even incorrect actions or
assumptions. Further, once the need to transition to more formal structure is recognized, the
transition is often not complete or effective. Results can include unclear instructions, confusion
whether an instruction is a suggestion or a directive, whether specific action is required or a set
of alternative actions are permissible, and confusion over what elements of the system are
being addressed.
The drafting team is in the process of preparing for a webinar on the proposed COM-003-1. The
webinar is scheduled to be held on Thursday June 7, 2012 from 1:30—3:30 p.m. Eastern Daylight Time.
An announcement for the webinar with additional details is forthcoming.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Ballot Pools Forming: May 7 – June 5, 2012
Formal Comment Period Open: May 7 – June 20, 2012
Ballot Windows Open for Initial Ballot and Non-Binding Poll:
June 11 – June 20, 2012
Now Available
A clean version COM-003-1 – Operating Personnel Communications Protocols has been posted for a
45-day formal comment period, initial ballot and non-binding poll. The drafting team has also posted
its implementation plan, mapping document, justification for Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) and proposed changes to COM-001. The drafting team has not posted
a redline of COM-003-1 because the changes to the last posted version of COM-003-1 are so extensive
that a redline is not useful.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join the ballot pools to be eligible to vote in the upcoming ballot
of Project 2007-02 Operating Personnel Communications Protocols by clicking here for the Initial ballot
and the non-binding poll of the associated Violation Risk Factors and Violation Severity Levels.
During the pre-ballot windows, members of the ballot pools may communicate with one another by
using their “ballot pool list servers.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for the ballot pools are:
Initial ballot: [email protected]
Non-binding poll: [email protected]
The ballot pools are open through 8 a.m. Eastern on Tuesday, June 5, 2012.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Wednesday, June 20, 2012. Please use
this electronic comment form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at [email protected]. An off-line, unofficial
copy of the comment form is posted on the project page.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Commenters and voters must submit comments through the electronic comment form. Due to
modifications to NERC’s balloting software, voters are no longer able to submit comments via the
balloting software.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a recirculation ballot.
Background
There are two projects that have the modification of the COM family of standards in the scope of their
SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is concerned
with communication protocols for normal and emergency operations. The other project, Project 200606 – Reliability Coordination has limited the scope of its modifications to the COM family of standards
to those that address communication during emergency operations. The Project 2006-06 team has
proposed a new term, “Reliability Directive,” to specifically address those communications. The
proposed definition of Reliability Directive is “A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.” The Project 2006-06 drafting team is proposing to require
three part communication for Reliability Directives, with a VRF of High for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols must address communication
protocols for normal and emergency operations, the Project 2007-02 drafting team is proposing a new
term, “Operating Communication.” The proposed definition for Operating Communication is
“Communication of instruction to change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.” Given that Reliability Directives are a subset of Operating
Communications, and to avoid any possibility of double jeopardy, the Project 2007-02 SDT is proposing
to require three part communication for all Operating Communications other than Reliability
Directives, and has proposed a Medium VRF for these requirements. Having a High VRF for a violation
of three part communication involving a Reliability Directive and having a Medium VRF for a violation
of three part communication involving other Operating Communications supports the appropriate
differentiation of risk for normal and emergency communications.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
Standards Announcement: Project 2007-02
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Ballot Pools Forming: May 7 – June 5, 2012
Formal Comment Period Open: May 7 – June 20, 2012
Ballot Windows Open for Initial Ballot and Non-Binding Poll:
June 11 – June 20, 2012
Now Available
A clean version COM-003-1 – Operating Personnel Communications Protocols has been posted for a
45-day formal comment period, initial ballot and non-binding poll. The drafting team has also posted
its implementation plan, mapping document, justification for Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) and proposed changes to COM-001. The drafting team has not posted
a redline of COM-003-1 because the changes to the last posted version of COM-003-1 are so extensive
that a redline is not useful.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join the ballot pools to be eligible to vote in the upcoming ballot
of Project 2007-02 Operating Personnel Communications Protocols by clicking here for the Initial ballot
and the non-binding poll of the associated Violation Risk Factors and Violation Severity Levels.
During the pre-ballot windows, members of the ballot pools may communicate with one another by
using their “ballot pool list servers.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for the ballot pools are:
Initial ballot: [email protected]
Non-binding poll: [email protected]
The ballot pools are open through 8 a.m. Eastern on Tuesday, June 5, 2012.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Wednesday, June 20, 2012. Please use
this electronic comment form to submit comments. If you experience any difficulties in using the
electronic form, please contact Monica Benson at [email protected]. An off-line, unofficial
copy of the comment form is posted on the project page.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Commenters and voters must submit comments through the electronic comment form. Due to
modifications to NERC’s balloting software, voters are no longer able to submit comments via the
balloting software.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a recirculation ballot.
Background
There are two projects that have the modification of the COM family of standards in the scope of their
SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is concerned
with communication protocols for normal and emergency operations. The other project, Project 200606 – Reliability Coordination has limited the scope of its modifications to the COM family of standards
to those that address communication during emergency operations. The Project 2006-06 team has
proposed a new term, “Reliability Directive,” to specifically address those communications. The
proposed definition of Reliability Directive is “A communication initiated by a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.” The Project 2006-06 drafting team is proposing to require
three part communication for Reliability Directives, with a VRF of High for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols must address communication
protocols for normal and emergency operations, the Project 2007-02 drafting team is proposing a new
term, “Operating Communication.” The proposed definition for Operating Communication is
“Communication of instruction to change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.” Given that Reliability Directives are a subset of Operating
Communications, and to avoid any possibility of double jeopardy, the Project 2007-02 SDT is proposing
to require three part communication for all Operating Communications other than Reliability
Directives, and has proposed a Medium VRF for these requirements. Having a High VRF for a violation
of three part communication involving a Reliability Directive and having a Medium VRF for a violation
of three part communication involving other Operating Communications supports the appropriate
differentiation of risk for normal and emergency communications.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate. For more information or assistance, please contact Monica Benson
at [email protected].
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
Standards Announcement: Project 2007-02
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Initial Ballot and Non-Binding Poll Results
Now Available
An initial ballot of COM-003-1 – Operating Personnel Communications Protocols and non-binding polls
of the associated VRFs and VSLs concluded Wednesday, June 20, 2012.
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Approval
Non-binding Poll Results
Quorum: 84.14%
Quorum:
81.01%
Approval: 21.11 %
Supportive Opinions: 28.78%
Next Steps
The drafting team will consider all comments submitted, and based on the comments will determine
whether to make additional changes. If the drafting team decides to make substantive revisions, the
drafting team will submit the revised standard and consideration of comments received for a quality
review prior to posting for a parallel formal 30-day comment period and successive ballot.
Background
There are two projects that have the modification of the COM family of standards in the scope of their
SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is concerned
with communication protocols for normal and emergency operations. Project 2006-06 – Reliability
Coordination has limited the scope of its modifications to the COM family of standards to those that
address communication during emergency operations. The Project 2006-06 team has proposed a new
term, “Reliability Directive,” to specifically address those communications. The proposed definition of
a Reliability Directive is “A communication initiated by a Reliability Coordinator, Transmission Operator
or Balancing Authority where action by the recipient is necessary to address an Emergency or Adverse
Reliability Impact.” The Project 2006-06 drafting team is proposing to require three-part
communication for Reliability Directives, with a VRF of High for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols must address communication
protocols for normal and emergency operations, the Project 2007-02 drafting team is proposing a new
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
term, “Operating Communication.” The proposed definition for Operating Communication is
“Communication of instruction to change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System.” Given that Reliability Directives are a subset of Operating
Communications, and to avoid any possibility of double jeopardy, the Project 2007-02 SDT is proposing
to require three-part communication for all Operating Communications other than Reliability
Directives, and has proposed a Medium VRF for these requirements. Having a High VRF for a violation
of three-part communication involving a Reliability Directive, and having a Medium VRF for a violation
of three-part communication involving other Operating Communications, supports the appropriate
differentiation of risk for normal and emergency communications.
Additional information is available on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Ballot Results – Project 2007-02 | COM-003-1
2
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007 -02 COM-003-1
Password
Ballot Period: 6/11/2012 - 6/20/2012
Ballot Type: Initial
Log in
Total # Votes: 366
Register
Total Ballot Pool: 435
Quorum: 84.14 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
21.11 %
Vote:
Ballot Results: The drafting team will consider comments received.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
110
11
103
39
93
53
0
12
5
9
435
#
Votes
1
1
1
1
1
1
0
0.9
0.1
0.6
7.6
#
Votes
Fraction
20
1
15
12
14
10
0
2
0
1
75
Negative
Fraction
0.233
0.1
0.165
0.387
0.197
0.222
0
0.2
0
0.1
1.604
Abstain
No
# Votes Vote
66
9
76
19
57
35
0
7
1
5
275
0.767
0.9
0.835
0.613
0.803
0.778
0
0.7
0.1
0.5
5.996
3
1
3
0
5
1
0
0
1
2
16
21
0
9
8
17
7
0
3
3
1
69
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Ballot
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Comments
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Negative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Negative
Negative
Affirmative
Michael Moltane
Negative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
1
3
3
3
3
3
3
3
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Rod Noteboom
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Negative
Negative
Negative
Negative
Negative
Affirmative
Dave Markham
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
NW Electric Power Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
David McDowell
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Rick Paschall
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Turlock Irrigation District
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Steve Eldrige
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Affirmative
Tim Beyrle
Affirmative
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
Keith Morisette
Steven C Hill
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
ICF International
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Brent B Hebert
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
David Gordon
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
matt E jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Michiko Sell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Abstain
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
APX
INTELLIBIND
JDRJC Associates
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Lujuanna Medina
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Negative
Negative
Peter H Kinney
David F. Lemmons
Edward C Stein
Roger C Zaklukiewicz
James A Maenner
Michael Johnson
Kevin Conway
Jim Cyrulewski
Frederick R Plett
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Donald Nelson
Negative
Diane J. Barney
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=284bd79e-135c-4405-b611-df0f6b9af3c0[6/26/2012 8:48:02 AM]
Abstain
Negative
Negative
Negative
Affirmative
Negative
Abstain
Negative
Abstain
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
Project 2007-02 COM-003-1
Non-binding Poll Results
Ballot Name: Project 2007-02 Non-binding Poll COM-003-1
Ballot Period: 6/11/2012 - 6/20/2012
Total # Opinions: 320
Total Ballot Pool: 395
81.01% of those who registered to participate provided an opinion or
Summary Results: abstention; 28.30% of those who provided an opinion indicated support
for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
1
1
1
1
1
1
1
1
1
1
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
1
1
1
1
1
1
1
1
1
1
1
Project 2007-02 Non-binding Poll Results
Member
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
Kevin Smith
Opinions
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Abstain
Affirmative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
Project 2007-02 Non-binding Poll Results
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Negative
Abstain
Affirmative
Michael Moltane
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
Negative
Negative
Affirmative
Negative
Affirmative
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Affirmative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Kevin White
Negative
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore
Negative
Negative
Abstain
Abstain
Negative
Negative
Negative
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
3
3
3
3
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Abstain
Abstain
Rod Noteboom
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
Negative
Abstain
Negative
Negative
Negative
Affirmative
John Shaver
Noman Lee Williams
Beth Young
Larry Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Independent Electricity System Operator Barbara Constantinescu
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Southwest Power Pool, Inc.
Charles H. Yeung
Alabama Power Company
Richard J. Mandes
Alameda Municipal Power
Douglas Draeger
Ameren Services
Mark Peters
APS
Steven Norris
Project 2007-02 Non-binding Poll Results
Abstain
Negative
Negative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
Abstain
Negative
Abstain
Abstain
Abstain
Abstain
Negative
Negative
Affirmative
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Project 2007-02 Non-binding Poll Results
Chris W Bolick
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Kent Kujala
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Negative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Daniel D Kurowski
Negative
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Project 2007-02 Non-binding Poll Results
Tony Eddleman
David R Rivera
Negative
Negative
Michael Schiavone
Negative
Skyler Wiegmann
Negative
William SeDoris
David McDowell
David Burke
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Negative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Project 2007-02 Non-binding Poll Results
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Negative
Affirmative
Henry E. LuBean
Affirmative
John D Martinsen
Negative
Mike Ramirez
Hao Li
Steven R Wallace
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Steven McElhaney
Keith Morisette
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Project 2007-02 Non-binding Poll Results
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Affirmative
Negative
Negative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Kenneth Silver
Negative
Mike Laney
S N Fernando
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
matt E jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Abstain
Steven Grega
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
Project 2007-02 Non-binding Poll Results
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Negative
Negative
Negative
Negative
Affirmative
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Negative
Negative
Abstain
Negative
Abstain
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
8
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10
10
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
APX
JDRJC Associates
Massachusetts Attorney General
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Project 2007-02 Non-binding Poll Results
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Negative
Negative
Abstain
Negative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Peter H Kinney
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Michael Johnson
Jim Cyrulewski
Frederick R Plett
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Donald Nelson
Negative
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Negative
Negative
Negative
Negative
Abstain
Abstain
Abstain
Abstain
9
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Individual or group. (94 Responses)
Name (64 Responses)
Organization (64 Responses)
Group Name (30 Responses)
Question 1 (74 Responses)
Question 1 Comments (94 Responses)
Question 2 (76 Responses)
Question 2 Comments (94 Responses)
Question 3 (66 Responses)
Question 3 Comments (94 Responses)
Question 4 (78 Responses)
Question 4 Comments (94 Responses)
Question 5 (75 Responses)
Question 5 Comments (94 Responses)
Question 6 (77 Responses)
Question 6 Comments (94 Responses)
Question 7 (76 Responses)
Question 7 Comments (94 Responses)
Question 8 (74 Responses)
Question 8 Comments (94 Responses)
Question 9 (59 Responses)
Question 9 Comments (94 Responses)
Question 10 (0 Responses)
Question 10 Comments (94 Responses)
Lead Contact (30 Responses)
Group
Northeast Power Coordinating Council
No
The proposed Operating Communication term is not markedly different from the originally proposed
term (Interoperability Communication). The proposal continues to expand the scope of the SAR from
the concept of tightening the protocols associated with Emergencies by now applying to all
communications. The text box in the draft standard indicates that Reliability Directives are a type of
Operating Communications, to the extent they change or maintain the state, status, output, or input
of an Element or Facility of the Bulk Electric System. There is little difference between the two terms
despite the SDT’s assessment that Reliability Directive is a type (or a subset) of Operating
Communication. If the intent is to use the proposed new term to require three-part communication
(as suggested in R2 and R3), then that intent can be accomplished by using the term Reliability
Directive as it covers not only the emergency state but also instructions needed to address Adverse
Reliability Impacts. Both the Blackout Report and the FERC directive deal with tightening protocols for
Emergencies. The proposed requirements completely fail to address emergencies and focus solely on
developing non-emergency protocols.
No
An alternative approach would be to introduce communications protocols as a mandatory nonstandard (e.g. as a requirement for certification) that would center on a corporate communications
manual that encourages three-part communications; and that includes how monitoring would be
audited internally. Such an alternative would change the requirement from monitoring personnel
mistakes to a requirement monitoring corporate culture.
No
A general suggestion for all reliability standards that has been made is that standards’ requirements
be eliminated that do not address reliability problems. No available information indicates that
language is causing reliability problems. In the absence of such evidence that this is a reliability
problem, consideration should be given to eliminating this requirement.
No
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This requirement is outside the scope of the approved SAR which proposes responding to the Blackout
Recommendation to tighten communications protocols especially during emergencies. This proposed
requirement is both procedural and does not address tightening communications of situational
awareness. As an alternative a standard could require the Functional Entities to have a
communications protocol that could indeed include this, but it should not be a requirement on
personnel. By adopting an alternative category (i.e. not making this a standard) a Reliability Entity
could adopt a progressive best practice approach without concern for violating the strictest features of
the proposed best practice.
No
There are a number of references appearing that state “excluding Reliability Directives”. If Reliability
Directive is going to be defined in a separate project (Project 2006-06), how will stakeholders
understand what is really being excluded for the purposes of this Standard’s scope? It also needs to
be made clear when an action is a Reliability Directive. Will each entity be required to define what is
to be included as a Reliability Directive? With the definition of Operating Communication, three-part
communications is expanded to include communications beyond directives, communications that
might not warrant governance by this Standard. The proposed exception (specifically Reliability
Directives used during emergencies) does not support the reason the SAR was proposed--to improve
protocols during emergencies. The term Operating Communications is not significantly different from
the term Reliability Directives (see comments to Q1). Using the term Reliability Directives to support
the requirements for 3-part communication can avoid (a) any confusion with the requirement in COM002-3, (b) potential double jeopardy of violating both COM-002 and COM-003, and (c) the need to
exercise 3-part communication for routine operating instructions. Suggest consider removing the term
Operating Communications. Are Requirements R2 and R3 needed if Reliability Directives already cover
non-emergency conditions (instructions/actions that are needed to address potential Adverse
Reliability Impact)? The requirement to exercise three-part communication to handle Reliability
Directives is thus duly addressed in COM-002-3. It hasn’t been shown that three-part communication
is necessary for routine operating instructions. Realistically the definition of Operating
Communications covers all communications. Only Reliability Directives should require three-part
communications, and should be enforceable if a miscommunication results in an error on the BES.
No
What determines whether a clarifier used is an “accurate alpha-numeric clarifier”? What dictates noncompliance? This is a procedural issue. The Standard should require the Functional Entities to have a
communications protocol that could include this, but it should not be a standard on personnel.
Complexity is being added to communications, not improvement. There are equipment designations
that are commonly used and understood, and to force the use of clarifiers will disrupt operating
communications.
No
The applicability of this Standard is unclear in the case of Distribution Providers. The definition of
Operating Communication includes “Elements” that could impact the BES. The NERC Glossary
definition for Elements includes non-BES devices and equipment. Additionally, the Purpose section of
the Standard states "harmful to the reliability of the BES." Since non-BES Elements could affect the
BES this Standard could be deemed applicable to non-BES devices. If it is the intent of the SDT to
apply this Standard to All Operating Communications concerning both BES and non-BES Facilities this
should be explicitly stated in the applicability section for transparency. Otherwise clarifying language
should be added to exclude non-BES Facilities. This is a procedural issue. Suggest that the Standard
should require the Functional Entities to have a communications protocol that could indeed include
this suggestion, but it should not be a standard on personnel.
No
The white paper discusses many non-utility industries use of the three-part communication. However,
they are not out of compliance if they fail to use three-part communications. Only the Reliability
Directives should require three-part communications (and dictate compliance). This should be
enforceable only if the miscommunication results in an error on the BES. We support the use of threepart communications with limitations. There is concern over the potential for being out of compliance
when there is no BES impact. Failure to meet Requirement R2, part 2.2 bullets 1 or 3 is either a
Moderate or High. Failure to meet bullet 2 is a Severe VSL. It is not clear why this differentiation was
adopted. The White Paper reflects on Human Performance, and how miscommunications can cause a
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BES error resulting in an outage, or possible cascading effects. Then the Standard (and the associated
out of compliance) should apply when, and to the extent that communications lapse (e.g., when there
is an impactful violation of bullets 1, 2 and/or 3) results in an impactful error on the BES. Otherwise,
an out of compliance is inappropriate. Non-impactful violations should be rated “Lower VSL.”
The three-part communications in COM-003-1 are expanded beyond reliability directives which
unnecessarily forces the inclusion of conversations which may be impractical or unnecessary. Good
practice dictates that three part communication be used as a tool, but it should not be a requirement.
The Standard is specifying how to accomplish, not just what is required. “1.1.4 When referring to a
Transmission interface Element or a Transmission interface Facility, use the name specified by the
owner(s) for that Transmission interface Element or Transmission interface Facility” may create a
detriment to reliability. Oftentimes, for switching, TOs have very detailed names for individual
elements, devices, equipment which may not translate into the TOP/RC systems. However, it is
known what equipment is being talked about. The requirement is unnecessary, unreasonable and
burdensome. The communications protocol to be followed in the event that there is a situation that
requires the removal of BES (or any other power system equipment for that matter) from service on
an immediate and emergency basis to protect the health and safety of the public and/or an
employee/s needs to be addressed. The instructions issued to meet this condition fall under the
definition of Operating Communication, but in an emergency situation the time taken for the required
repetition could be catastrophic. This also applies to BES (or any other power system) equipment that
is in imminent danger of failure, phase angle regulator or transformer tap changer runaway, or other
emergency conditions. This is also true of situations where the BES response to a disturbance results
in a facility or facilities being overloaded real time over their STE and LTE ratings, and those facility
loadings have to be reduced below their STE and LTE ratings within five and fifteen minutes
respectively. The time spent for the necessary three part communication could mean the difference
between maintaining continuity of service, or having to shed load. Suggest that wording be added to
address the emergency situations described by recognizing the possibility that an operator might have
to respond to a situation by issuing a “one way” order, then have a requirement for after the fact
communications which would be informational as to what emergency actions were taken, and then
resume normal communications protocols for subsequent actions. Regarding the wording for the
issuer in R2 “…that issues an oral, two-party, person-to-person Operating Communication”, and the
wording for the receiver in R3 “…that receives an oral two-party, person-to-person Operating
Communication”, what is the significance of the use of the comma after “oral” in R2? What is the
difference between two-party and person-to-person communication? Also regarding R2, the Generator
Operator should be included as an authority to issue an Operating Communication. It is not necessary
to separate normal and emergency communications into two standards (COM-003, COM-002). One
standard should encompass both. But having two Standards, the communication protocols in COM003 R1 should be incorporated in COM-002. The proposals expand the scope of the SAR by ignoring
communications protocols used during emergencies and focusing on procedures imposed on
personnel during normal situations. This standard overreaches into routine operations by requiring
three-part communication for all instructions that change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System. Because of the real-time frequency of use
these instructions, requiring operating personnel to apply a three-part communication procedure for
these instructions is unnecessary and can in fact adversely affect reliability. Any requirement for
three-part communication for routine operating instructions should be removed.
Guy Zito
Individual
Hertzel Shamash
The Dayton Power and Light Company
No
We have concerns with the true scope and depth of this standard. How far does this standard reach?
A tie line utility wants us to utilize three part communication for tie line check outs, which we assume
is not part of ‘operating communications’. Not sure this is the intent of the standard, but seems to be
a coverall by them. One could argue the tie line data (which is up to 23 hours old by the time we
check out, is an output from the BES) How do resolve this? Operating Communications is a very
broad term that could be interpreted differently by the many individuals we interact with leading to
‘overuse’ of three part communication when in doubt. This may counteract the importance of its use
for the conditions we truly need to utilize this protocol.
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No
This standard specifically excludes “Reliability Directives” which is a term that does not currently exist
in the list of definitions, rather it is proposed in a separate standard (COM-002-3) which is currently in
the approval process. Not sure how you can reference a term from a pending standard.
No
This requires using a 'correct’ alpha numeric clarifier, while the proposed standard is written as
‘accurate’. It would be great if there were consistency between the proposed standard and the
comment form. Not sure how one can define accurate or correct. The standard indicates that NATO
has one, but there are others as well. The moniker for “A” in the LAPD definition is ADAM, while NATO
is ALPHA. Both are ‘accurate and/or correct’ but if I use one version and the person I’m talking to
uses another, is this a violation of the standard? The language in this proposed version is better than
the last (where they required the use of the NATO language) but I’m still not comfortable this
proposal fixes the problem.
Individual
D Mason
HHWP
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Recommend that R1.1.4 incorporate use of the term Uniform Line Identifiers, in conformance with
R18 of TOP-002.
No
VSL should provide for a Lower Violation Severity Level for first occurances of the violation. For the
most part violation of this standard should be addressable through FFT process.
Group
ACES Power Marketing Standards Collaborators
No
1. We do not agree with the need to use three-part communication for all operations on the BES.
Requiring entities to employ three-part communication for routine operating instructions is excessive
and burdensome. The 2003 Blackout Report recommended that industry, “Tighten communications
protocols, especially for communications during alerts and emergencies.” We strongly support using
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
three-part communication for the execution of Reliability Directives as defined in the proposed COM002-3 draft standard in Project 2006-06 but not for routine operating instructions. 2. The COM-003-1
Operating Communications Protocols White Paper states three reliability benefits of using three-part
communication as follows: a. “The removal of any doubt that communication protocols will be used
and when they will be used. This will reduce the opportunity for confusion and misunderstanding
among entities that may have different doctrine.” We don’t agree with the premise that implementing
three-part communications for all operating instructions will reduce confusion. If there is a standard
such as draft COM-002-3 that requires the use of three-part communication for Reliability Directives
and the issuer is required to state that a Reliability Directive is being issued, then there should be no
confusion. The example provided in this bullet where “one entity uses three-part for emergencies, and
the other uses it for all operating conditions” is used to support the premise. However, Table 1-A of
the White Paper only lists 11 entities that currently use three-part communication during both
emergencies and non-emergencies. Eleven out of how many entities? The paragraph immediately
following Table 1-A states, “The fact that the majority of BES entities already employ three-part (or
repeat back) communications for routine…operations…” Eleven entities do not make a majority. We
don’t believe the actions of a few should dictate the actions of all. Much stronger evidence to support
this “fact” is needed. b. “There will be no mental “transition” when operating conditions shift from
normal to Emergency.” Once again, if there is a standard such as COM-002-3 that requires three-part
communication for Reliability Directives and the issuer is required to state that a Reliability Directive
is being issued, then there should be no confusion. System Operators are trained to make mental
transitions every day. It is an inherent characteristic of the job. Operators should be able to mentally
“transition” when a Reliability Directive is issued. c. “The formal requirement for three-part
communication will create a heightened sense of awareness in operators that the task they are about
to execute is critical…” Not all operating instructions are “critical” so this premise is flawed. This bullet
makes perfect sense for Reliability Directives because the actions taken to address those would be
considered critical based on the proposed definition of Reliability Directive in COM-002-3. It does not
make sense for routine operating instructions. 3. Based on the above, we do not agree with the
definition of Operating Communication as proposed in this draft standard since we do not support the
use of three-part communication for all operations on the BES.
Yes
Yes
Yes
No
1. The SDT should consider clarifying that use of relative times will not be subject to this requirement.
For example, if a System Operator communicates that they will begin switching in 10 minutes, no 24
hour clock requirement is necessary.
No
1. We do not agree that excluding Reliability Directives is a good idea. We would prefer to see COM003-1 and COM-002-3 combined and have the requirements only apply to Reliability Directives. If
these protocols should be used for any type of communication, we believe they should be used for
Reliability Directives as we’ve stated in our comments in Question 1. The definition of a Reliability
Directive as proposed in COM-002-3 is “where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.” There is no type of communication more important than a
Reliability Directive, therefore, the protocols outlined in R2 and R3 of COM-003-1 should be applicable
to them. During the webinar on June 7, 2012, it was said that the only distinctions between COM002-3 and COM-003-1 are the VRF/VSL levels and that a Reliability Directive must be stated as such
when issued. There is no reason both standards can’t be combined into a single standard and simply
split out the VRF/VSL levels for Reliability Directives while keeping the requirement where the RC,
TOP and BA shall identify the action as a Reliability Directive when one is issued. We suggest that the
SDTs consider combining their efforts in this manner. 2. However, if both projects are to continue
along separate paths, we’d like to see the requirements in both mirror one another so entities aren’t
wondering what the distinction is between the two descriptions of three-part communication. COM003-1 is more detailed in outlining the steps that should be taken when using three-part
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
communication than COM-002-3. COM-002-3 R2 states that the recipient “shall repeat, restate,
rephrase or recapitulate…” COM-003-1 doesn’t use these words. It simply states that the receiver
shall “repeat” or “request the issuer reissue…” 3. We do agree with splitting the single requirement
into two requirements: one for the issuer and one for the receiver. However, we suggest the SDT
develop a flow chart that demonstrates the communication paths and the loop flow of the steps to
further clarify what needs to be done and when. For example, in R2 Part 2.2, after an Operating
Communication is reissued at the request of the receiver (bullet 3), the receiver should repeat the
information to make sure they received it correctly (R3 bullet 1) and the issuer should confirm the
receiver’s response (Part 2.2 bullet 1). As the parts are written currently, the loop flow of the steps
isn’t clear. It may seem intuitive but a literal reading doesn’t capture the loop flow as intended. R3
even has a gap in that the recipient can choose to repeat the Operating Communication or they can
request it be reissued. Thus, if they request it is reissued, they don’t have to repeat it back. 4. In R3,
we suggest adding the words, “before taking action” to the end of the first bullet to further emphasize
the importance of receiving confirmation from the issuer. If action is taken prior to confirmation, a
critical mistake could be made if the instruction was heard and repeated back incorrectly.
No
1. First the requirement uses the word “accurate” instead of “correct” as stated in this question. 2.
What is meant by the term “accurate alpha-numeric clarifiers?” Can someone make up their own
alpha-numeric clarifiers in the heat of the moment and expect the other party to mentally “transition”
and understand what they mean? Or does it have to be another established and recognized alphanumeric clarifier? A made up alpha-numeric clarifier could be confusing to someone who isn’t familiar
with the clarifiers being used. This is more of a mental “transition” than determining the difference
between an Emergency (which will be stated up front as a Reliability Directive as proposed in draft
COM-002-3) and a normal operating instruction. We suggest that only established alpha-numeric
clarifiers be used.
No
1. We don’t believe this requirement is necessary. A similar requirement was removed from TOP-0022 Project 2007-03. From the Project 2007-03 mapping document: “R18. Neighboring Balancing
Authorities, Transmission Operators, Generator Operators, Transmission Service Providers and Load
Serving Entities shall use uniform line identifiers when referring to transmission facilities of an
interconnected network.” Project 2007-03 SDT’s reason for deletion of R18 from TOP-002-2: “This
requirement adds no reliability benefit. Entities have existing processes that handle this issue. There
has never been a documented case of the lack of uniform line identifiers contributing to a System
reliability issue. The bottom line is that this situation is handled by the operators as part of their
normal responsibilities, and no one is aware of a switching error caused by confusion over line
identifiers.” We agree with these reasons and believe they should apply to R1 Part 1.1.4 in COM-0031. 2. Another issue we have with the requirement is that this draft standard is not applicable to TOs
or GOs yet the requirement calls for the use of “the name specified by the owner(s) for that
Transmission interface Element or Transmission interface Facility.” Are the auditors going to ask the
TOs and GOs for their list of named Elements or Facilities when they audit the applicable entities in
this standard?
No
1. The first Severe VSL listed for R1 says, “…did not correctly implement any of the parts…” What is
the definition of the word “any” in this VSL? We’ve interpreted the VSL to mean that none of the parts
of R1 were implemented. If this is the intent of the SDT, then we suggest removing this VSL since the
next Severe VSL listed says, “…did not correctly implement three (3) or more of the four (4) parts…”
Three or more would include all of the parts (4 of 4) not being implemented correctly. Not
implementing 1 of the 4 parts is a Moderate VSL while not implementing 2 of the 4 parts is a High
VSL. So, not implementing 3 or more of the parts would be a Severe VSL. 2. The second Moderate
VSL for R1 says, “The responsible entity did not correctly implement Part 1.2 of the requirement.”
Corresponding with our comments in Question 7 above, we don’t know how this requirement will be
measured since the term “accurate” in the requirement is not defined. If an entity can make up their
own clarifiers, who determines if they were “accurate” and whether they were correctly implemented?
Measure M1 doesn’t specify a measurement for Part 1.2 of R1. 3. The High VSL for R3 should be
clarified to align with our suggestion of adding the words, “before taking action” in Question 6 above.
1. It is not clear that COM-003-1 R1 applies to COM-002-3. The latest draft of COM-002-3 doesn’t
reference the communications protocols listed in COM-003-1 R1 and the definition of Reliability
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Directive does not state that it is a type of Operating Communication. The only place that describes
the relationship between a Reliability Directive and Operating Communications is the text box under
the definition of Operating Communication in COM-003-1. There should be a better connection
between the two standards to emphasize this fact. We recommend the SDTs work together to bridge
this gap. 2. Bullet 2 of the Implementation Plan Effective Dates is missing a word or words (section in
question in parentheses): “If the version of COM-001-2 revised under Project 2006-06 is not
approved before COM-003-1 is approved, then COM-001-1.1 shall expire midnight of the day
(immediately the) version of COM-001-2 developed under Project 2007-02 …” In addition, this bullet
is simply too wordy and difficult to comprehend. We suggest re-wording or splitting into separate
sentences for easier comprehension. 3. Because all three Measures include voice recordings as
evidence, the Data Retention section inappropriately and without justification raises the bar on
retention of voice recordings. The section requires 365 days of voice recordings for R1 and 180 days
for R2 and R3. Many registered entities keep no more than 90 days of voice recordings. Keeping more
than 90 days would require unnecessary additional storage. Furthermore, it is not consistent with any
other NERC standard (including COM-002) that compels, at most, 90 days. Thus, many registered
entities probably have evidence retention policies that actually require destruction of such recordings
after 90 days. 4. While we do not agree with all parts of the Whitepaper, we believe one major point
of clarification is needed. On page 3, in the first bullet regarding a general description of how threepart communications is conducted, the face-to-face communication needs to be clarified or removed.
Including face-to-face communications is not necessary for two primary reasons. First, the major
reason that three-part is necessary for telephonic communications is because you cannot see the
receiver and really tell if they comprehend the message. Second, this could draw in communications
between operators within the control center. Since these conversations are not easily recordable, how
does a registered entity prove compliance?
Jean Nitz
Individual
Mace Hunter
Lakeland Electric
Yes
Would modify R1 as noted below to remove the implication that a Distribution would have to provide
evidence that all Distribution Provider communications used the required protocols. R1. Each
Reliability Coordinator, Transmission Operator, Balancing Authority[, and] Generator Operator, and
Distribution Provider [receiving a Operating Communications,] shall use the following communications
protocols:
Yes
Yes
Yes
Yes
No
I do not understand why Reliability Directives would be excluded! Reliability Directives are capitalized
in the box on the Development Roadmap and in this question but I cannot find the term in the
February 8, 2012 NERC Glossary. So where is Reliability Directives defined? I am concerned that the
exclusion will cause problems especially if the clarifying box is omitted from the final standard. The
split is OK.
Yes
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
John D. Brockhan
CenterPoint Energy Houston Electric, LLC.
No
Question 1 Comments: Instead of adding the proposed new definition of “Operating Communication”
to the NERC Glossary, the definition should be used to define the industry known terminology
“Directive”, as “an instruction to change or maintain the state, status, output, or input of an Element
or Facility of the Bulk Electric System”. Aligning this definition with Project 2006-006 Reliability
Coordination and a new proposed definition of “Reliability Directive” to be “A communication initiated
by a Reliability Coordinator, transmission operator or Balancing Authority to change or maintain the
state, status, output, or input of an Element or Facility of the Bulk Electric System where action by
the recipient is necessary to address an emergency or adverse Reliability Impact”.
Yes
Question 3 Comments: CenterPoint Energy believes the SDT should only use exisiting defined alert
levels, rather than implementing new alert levels or categories.
No
Question 6 Comments: The proposed language in this requirement can be omitted and incorporated in
COM-002-2 R2, where language has already been written and is currently in force regarding 3-part
communications. The industry is well aware and versed in the method of communicating using 3-part
communications. The elaboration of performing a three part communication is a “how to” and not
necessary and can be omitted altogether. The term “3-Part Communication” could be defined and
added to the NERC Glossary to suffice the elaboration of the definition proposed in this requirement.
The idea of requiring all communications (Operating Communications) to be made as 3-part
communications is not practical and should be left up to the communicating entities. Requiring
ongoing administration of “3-part” communications will impede rather than improve timely
communications consequently affecting the reliability of the BES.
No
Question 7 Comments: The use of correct alpha numeric clarifiers represents a “how to” and although
it may be an example of a good utility practice, it should not be a requirement to the extent of not
only just having to use the alpha numeric clarifiers, but required to use them correctly or “accurate”
as it is currently worded in the language of proposed COM-003-1 R 1.2 draft 2. The requirement is
unclear as to whether the accurate use of alpha –numeric clarifiers is required only when the clarifiers
are used, or whether accurate use of alpha-numeric clarifiers are required for all oral Operating
Communications. The use of any alpha- numeric clarifiers should be left up to the discretion of the
communicating entities during their exchange, acknowledgement, and agreement of information of
any such communication.
No
Question 8 Comments: The language in requirement 1.1.4 will require the limitation to a single
identifier for an interface element or facility between neighboring entities which will require the
neighboring entities to agree upon a specified single identifier. This may possibly require entities to
make changes to their EMS system and their model and incur a cost to complete such tasks. Similar
language is currently enforced in TOP-002-2 R18, where Entities are required to use uniform line
identifiers when referring to transmission facilities of an interconnected network, making this
requirement language redundant.
No
Question 9 Comments: No. VRFs and VSLs for requirements R1, R2, and R3 should not be high or
severe unless Adverse Reliability Impact has occurred.
Question 10 Comments: It appears that the SDT is using an undefined definition of Reliability
Directive to propose the new definition of Operating Communication. Is the intent of the SDT to also
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introduce this definition for Reliability Directive with this project? The purpose is not consistent with
language in other currently enforced standards. The words “could” and “possibility” needs to be
removed from the language. The purpose needs to be concrete. An alternative purpose would be “To
specify clear, formal, and universally-applied communication protocols for the operation of BES
facilities, that reduce miscommunication, which will have a negative influence on the reliability of the
Bulk Electric System. The six month effective date following approval is too short and should be
extended to 12 months to allow adequate time for training and implementation.
Individual
Michael Falvo
IESO
No
The IESO agrees with the removal of the 3 terms proposed in the previous draft. However, the IESO
does not agree with the introduction of a new term Operating Communication. This term is not
materially different than the originally proposed term Interoperability Communication. The text box in
the draft standard indicates that Reliability Directives are a type of Operating Communications, to the
extent they change or maintain the state, status, output, or input of an Element or Facility of the Bulk
Electric System. We see insufficient difference between the two terms despite the SDT’s assessment
that Reliability Directives are a type (or a subset) of Operating Communication. If the intent is to use
the proposed new term to require 3-part communication (as suggested in R2 and R3), the intent can
be accomplished by using the term Reliability Directives as it covers not only emergency state but
also instructions needed to address Adverse Reliability Impacts. Please also see our comments under
Q6 on using the proposed term to support the requirements for 3-part communication.
Yes
We agree that Attachment 1 should not form part of COM-003-1 and support suppressing any
requirements in this standard that stipulate the Alert Levels. We need more details on the specific
proposal to re-locate Attachment 1 before we can comment on the merit of the transfer.
Yes
We have no preference one way or the other as long as the personnel understand each other.
However, if the option to use daylight saving time or standard time is allowed (to be agreed by the
personnel), it begs the question as to why the 24-hour clock hours must be followed, and why the 12hour clock with am and pm specified is not allowed.
No
The IESO disagrees with using the term Operating Communications as it is not much different from
the term Reliability Directives (see our comments under Q1). Using the term Reliability Directives to
support the requirements for 3-part communication can avoid (a) any confusion with the requirement
in COM-002-3, (b) potential double jeopardy of violating both COM-002 and COM-003, and (c) the
need to exercise 3-part communication for routine operating instructions. However, if the SDT’s intent
is to require 3-part communication for any and all operating instructions (as the proposed term
suggest), then this intent will result in unnecessary 3-part communication burdens for simple actions
such as when requests for the removal of a line, or switching, or generation output changes are
issued. We suggest the SDT to remove the term Operating Communications. With respect to
Requirements R2 and R3, we question the need for having these requirements if Reliability Directives
also cover non-emergency conditions (instructions/actions that are needed to address potential
Adverse Reliability Impact). The requirement to exercise 3-part communication to handle Reliability
Directives is thus duly addressed in COM-002-3. Other than emergency conditions and potential
Adverse Reliability Impact conditions, we do not see a need to exercise 3-part communication for
routine operating instructions.
Yes
While we agree with allowing appropriate alpha numeric qualifiers other than the NATO phonetic
alphabet, we do not support the mandatory use of these qualifiers for each and every instruction.
They should only be required when clarification by either party is requested.
Yes
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No
We do not agree with Requirements R2 and R3 to begin with. We therefore do not agree with the
VRFs and VSLs for these two requirements.
1. This standard is over-reaching into routine operations as it requires 3-part communication for all
instructions that change or maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System. This type of instructions occurs every hour, if not every minute. Requiring
operating personnel to apply a 3-part communication procedure for each and all of these instructions
is absolutely unnecessary and overburdening, and can in fact adversely affect reliability. We strongly
suggest that any requirement for 3-part communication for routine operating instructions be
removed. 2. 2. The proposed implementation plan conflicts with Ontario regulatory practice respecting
the effective date of the standard. It is suggested that this conflict be removed by appending to the
implementation plan wording, after “applicable regulatory approval” in the Effective Dates Section A5
on P. 4 of the draft standard COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s
Implementation Plan and P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following
effect: “, or as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.”
Individual
Thad Ness
American Electric Power
Our efforts in this regard should first be focused solely on Reliability Directives before expanding this
work, and creating similar requirements for all other Operating Communications. Requiring three part
communications for every scenario might be considered a best practice by some, but making it a
mandatory practice for routine operations seems to emphasize the manner of communications rather
than the operations themselves. In addition, requiring three part communications for Reliability
Directives will likely result in more widespread usage for more routine operating communications,
without making it a requirement. AEP believes that there should not be multiple project teams
proposing concurrent changes to COM-001, COM-002, and COM-003. Unless there are overwhelming
reasons for not doing so, these efforts should be consolidated and managed by a single project team.
In addition, current efforts on COM-003 need to be co-located with the proposed changes to COM-002
within a single standard. Having multiple project teams proposing concurrent changes results in
problems such as this, where a) changes are proposed to the same standard or b) similar changes are
proposed to separate standards. AEP cannot support revisions on these matters until they are
managed by a single project team.
Individual
Ronnie C. Hoeinghaus
City of Garland
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Requirement 1.2 should be removed from the standard. The number of directives and switching
orders that have been issued in North America over time probably number in the billions. If one could
determine the percentage of issues caused by miscommunications out of that large number, it would
be extremely small. The reason that miscommunication issues exist is because the communication is
between two human beings and where people are involved, issues will happen. A requirement for
three part communications is more than sufficient to address the issue of miscommunications. Adding
a requirement to use alpha-numeric clarifiers such as the NATO Spelling Alphabet is not going to
prevent miscommunications. The only thing that adding this requirement will accomplish is to require
auditors to listen to recorded conversations trying to verify that operators used alpha-numeric
clarifiers and then penalizing a company if an operator does not even though the directive or
switching order was followed correctly.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
No
Believe the additional definition is not necessary and it is not clear what value it would have to small
Distribution Providers other then additional compliance complexity.
Yes
No
Don't understand this change, but wonder why seperate alert levels are necessary to incorporate in
this set of standards.
Yes
No
Not sure this is necessary for small entities.
Yes
Yes
No
Think this requirement is duplicative of TOP-002a, R18
No
We believe there should be a distinction in the “Applicability” section of the standard between
“Scheduling Distribution Provider” and “Non-scheduling Distribution Provider”. Many small WECC
entities re small rural cooperatives and PUDs are Full service customers. This means that the TO/TOP
is the power supplier and scheduling agent and therefore handles all reliability directives, scheduling,
tagging, dispatching of resources and curtailments of load from breakers on the BES system.
According to a letter from the WECC Reliability Coordinator (VRCC and LRCC) none of the smaller
entities in the Pacific Northwest will ever receive a “Reliability Directive” directly from teh RC. Such a
Directive would be sent to either a Balancing Authority (BA), or a Transmission Operator (TOP). We
estimate there are over 100 entities that are BPA Full Service customers that are in a similar position
and making this standard applicable to them does nothing to enhance reliability. A simple declarative
statement in the Applicability section of the standard could focus the intent of the SDT on those
entities that need it while lessening the compliance risk and clerical burden for other entities that the
standard should not apply to. We suggest: 4. Applicability: 4.1. Functional Entities 4.1.1 Reliability
Coordinator 4.1.2 Transmission Operator 4.1.3 Balancing Authority 4.1.4 Generator Operator 4.1.5
Distribution Provider: With Real-time Operations and Scheduling desk We believe the above change
will lessen the compliance burden on small, non-scheduling entities while still meeting the SDT’s
intent with regard to Operating Personnel Communications. We also note that FERC and NERC, on
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multiple occasions and in multiple filings, have indicated their openness to lessening unnecessary
compliance requirements for small entities.
Individual
Joe O'Brien
NIPSCO
Yes
Yes
Yes
Yes
Yes
Yes
There was a COM-002 NOP issued in January 2011, a COM-002 interpretation recently approved by
NERC, and presently there is a draft of both a COM-002 and a COM-003 out for vote. These projects
appear to address 3 part communication requirements in a non-consistent manner. Why not combine
these efforts into a single project that the industry can review and understand? The VRF/VSL
difference between routine and emergency does not warrant having two standards. A suggested plan
of attack could be to withdraw the NERC approved COM-002 interpretation from FERC and combine
the COM002-COM003 drafting efforts into one project resulting in a new version of COM-002; we
already have enough standards. The content of the two new drafts is good, the webinar was
informative, and the work of the SDTs is appreciated.
Individual
Joe Tarantino
SMUD
Yes
Yes
Yes
No
We believe the requirement to only speak English is detrimental to reliability. Entities who have
predominantly speaking Spanish personnel would be inhibited with ineffective communications
mandated by the English only requirement. Further, this particular requirement is in direct conflict
with COM0-001 R4 which states “…Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.”
Mandating use of a 24-hour clock reference provides no improvement to reliability. This is an auditing
function only, there is no reliability benefit to differentiate 0800 and 8 am.
No
Requirements R2 and R3 are over prescriptive and included as a business practice in the entities’
training program.
No
Communication should not be restricted to only use of the phonetic alphabet. Referencing a “103-C”
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switch versus a “103-Charley” does not enhance reliability and has the potential of hindering reliable
operation of the BPS by forcing the Operator Communications personnel to focus on being compliant
with the correct phonetics rather than the actual instruction.
No
First, this requirement is redundant to Requirement R18 in the TOP-002 standard. It also put an
administrative burden on the RC to know each “correct” name specified by the respective entity’s line
segment causing a hindering timely operation of BPS elements.
No
Individual
Daniel Duff
Liberty Electric Power LLC
No
Routine market communications between entities are not a valid area of regulation under the NERC
Standards.
Yes
Yes
Yes
No
No. Communications which do not involve Directives are not the proper subject of NERC standards.
No
Three part communication is a best business practice. Three part communication should be required
during a declared Emergency. But there is no reason to create a standard, and the massive
monitoring requirements and records obligations which go along with a standard, to cover business
communications.
No
Again, this is beyond the proper scope of reliability standards.
No
This requirement is already covered under TOP-002 R18, and opens double-jeopardy for entities by
including it in a second standard.
No
Yes. The regulation of market communications between entities is not the proper subject for NERC
standards. The STD proposes placing entities into the realm of zero tolerance for thousands of routine
communications. This assures failure. Further, this will force entities to reallocate precious resources
away from more critical reliability functions to assure compliance and allow for self-certification. As
such, the proposed standard weakens the reliability of the BES. The proposed standard should be
withdrawn and the SAR closed.
Individual
Jennifer Wright
San Diego Gas & Electric
No
San Diego Gas & Electric (“SDG&E”) agrees with the proposed exemption from the requirement to use
English language where the use of another language is mandated by law or regulation. However,
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SDG&E recommends including the following language as an additional exemption: “or a formal
agreement has been established between the functional entities to use an alternative language,” so
that R1.1.1. states: “Use the English language when communicating between functional entities,
unless another language is mandated by law or regulation or a formal agreement has been
established between the functional entities to use an alternative language.”
No
SDG&E recommends removing the language, “When the communication is between entities in
different time zones” in R1, Part 1.1.3, and replacing it with “Communication is to…”, so that R1.1.3
states: “Communication is to include the time and time zone and indicate whether the time is daylight
saving time or standard time.” The proposed requirement for the communicator to determine if an
entity is in a different time zone appears to be an unintended impact of the wording proposed in
R1.1.3, and may prove to cause inefficiencies in complying with this requirement. Communicators
SHOULD NOT NEED to determine whether or not an entity is in the same time zone as they are, but
should simply state the time zone where they are calling from or the KNOWN element of their
operations. Though a majority of communication will occur within the same time zones, System
Operators and others affected by the requirement will be assured that the timing of ANY event will be
KNOWN and never assumed.
No
The boxed note in the draft of COM-003-1 states that “Reliability Directives are a type of Operating
Communications…” and the process described in R2 and R3 is 3 way communication. Why is the SDT
segregating this as if it is a “separate process” that needs to be followed by operating personnel? The
two do not appear to be separate communication processes. SDG&E recommends removing the word,
“excluding,” and replacing it with the word “including,” so that R2 states: “Each Reliability
Coordinator, Transmission Operator and Balancing Authority that issues an oral, two-party, person-toperson Operating Communication, including Reliability Directives shall:” SDG&E also recommends that
the following language be added in a bullet to R2.2: • Request that the receiver repeat the Operating
Communication if the receiver does not issue a response (not necessarily verbatim). R3 notes that the
Registered Entity who receives the Operating Communication needs to repeat the Operating
Communication provided. In order to promote compliance and proper communications, this bullet
point should be added.
Individual
Stephen J. Berger
PPL Generation, LLC on behalf of its Supply NERC Registered Entities
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does not agree with the addition
of “Operating Communication” as a proposed definition because it imposes three part communication
on the industry for routine communications of changes of output in generation. Also the language as
written does not specify if these changes include communication of future planning to change the
status of generation in instances of future planned outages. The standard should specify if
communication of real time operations is what falls under the definition of “Operation Protocol.” This
ensures that communication which would be considered a compliance event and require the scrutiny
of an audit.
Yes
Yes
Yes
Yes
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No
Three part communication should not be required for routine operating communications.
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does not believe that this sub
requirement is appropriate when applied with the new definition “Operating Communication.”
Common operating communications should not be considered a compliance event that requires the
use of correct alpha numeric clarifiers. Under the current language, it could be interpreted that
according to “Operating Communication” that every change in generation output must be stated in
alpha numeric clarifiers in every instance of communication. This requirement shifts operators focus
from communicating proper information to a focus on communicating using the specified terms in all
instances of communication, where in everyday normal business activities and operation should not
require such scrutiny.
Yes
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does believe that this sub
requirement R1.2 should be considered a moderate violation when alpha numeric clarifiers are not
used in general communication.
The statement, “Evidence may include, but is not limited to, voice recordings, transcripts of voice
recordings, on-site observations, or other equivalent evidence,” in the Measures section of COM-003
is impractical. Any comprehensive body of evidence would be unreasonably voluminous as well as
requiring far more effort to compile than could be justified. The only evidence required for Generation
Owners should be a procedure on the subject and a record showing that all applicable personnel have
been trained.
Individual
Cristina Papuc
TransAlta Centralia Generation LLC
The current effective date only gives the registered entities 6 calendar months to be compliant with
the requirements. We do not think this will be achievable. A longer implementation time is required,
such as 12 months. In order to comply with standard requirements, the registered entities need to
develop the internal controls, such as the procedures/operator training documents, and then provides
the training to the operators. The 6 calendar months are not long enough to complete these tasks. In
the white paper, Table 1-A shows only the three-part communication are currently used in the
registered entities. However, for all other requirements, such as using alpha-numeric clarifiers, the
white paper does not show that these are currently used in the registered entities. Thus, there is no
base to justify that 6 months is reasonable to achieve the compliance.
Group
Imperial Irrigation District
Yes
Yes
Yes
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Yes
Yes
Yes
Yes
Yes
Yes
Jesus Sammy Alcaraz
Group
Midwest Reliability Organization NERC Standards Review Forum
No
The MRO NSRF recommends the following comments for consideration by the SDT: 1. The sentence
structure of this definition is incorrect. It is unclear whether the prepositional phrase “of the Bulk
Electric System” applies to both Facility and Element or only to a Facility. Recommend this be
rewritten to read “… Bulk Electric System Elements and Facilities”. 2. The definition should be for only
actionable commands (to accomplish an actionable item). Status of does necessitate 3 part
communication. 3. The inclusion of a Reliability Directive as a subset of the Operating Communication
definition adds confusion as to what is a Reliability Directive. This confusion is compounded by having
Reliability Directives in a different standard with different descriptions for three part communication.
4. The 2003 Blackout Report recommended that industry, “Tighten communications protocols,
especially for communications during alerts and emergencies.” We strongly support using three-part
communication for the execution of Reliability Directives as defined in the proposed COM-002-3 draft
standard in Project 2006-06 but not for routine operating instructions. 5. Table 1-A of the White Paper
lists 11 entities that currently use three-part communication during both emergencies and nonemergencies. We agree that this can be an utility ‘best practice’, however, there is a major difference
between good utility practice and a no-fault, no exception Reliability Standard.
Yes
Yes
Yes
No
There are two time zones in the eastern interconnection and two time zones in the western
interconnect with Arizona not utilizing daylight savings time. The Reliability Coordinator and entities
can agree on what time zone to use. The NSRF does not understand if the ‘time zone” issue has
caused any past performance issues? Please clarify with a basis of time zone inclusion.
No
The MRO NSRF recommends the following comments for consideration by the SDT: 1. The NSRF does
not understand how three part communication is not applicable to Reliability Directives, when COM002-3 states that three part communication shall be used when issuing a Reliability Directive. This
adds confusion and is further evidence that there should only be one communication standard. 2. How
are group calls going address three part communication? Many entities use blast calls to forward
system wide information in a very short period of time. The intent of a blast call is to speed up the
dispersing of information from one to many. Please clarify. 3. Currently there are 1681 entities (BA,
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TOP, RC, GOP, and DP) registered with NERC. Assume that each entity has one phone call every 10
minutes in a 12 hour day shift and half during a night shift (being conservative). A single entity will
have 72 per day on an average. Note that both parties (sender and receiver) will need to use COM003 requirements. There will be about 120,000 calls per day within NERC where COM-003 will need to
be applied. That equates to 44,176,680 calls per year that require COM-003 requirements to be used.
While all these communications will not necessarily be an Operating Communication, but the NSRF
believes that at least 75% will be Operating Communications. This alone will slow down the reliability
of our system. Is this the intent of the SDT? Please consider all industry comments and upon
development of “consideration of comments”, run the number of instances where COM-003 will need
to be applied. The question should be, does this hamper our system reliability or not.
No
The MRO NSRF recommends the following comments for consideration by the SDT: As written, if an
operator simply states “open switch c138”, they would be found non compliant. The SDT has not
given any justification (reference to a FERC Directive) to why they are mandating the use of alphanumeric clarifiers within this requirement. It is not needed to be written within this (or any other
standard). It is agreed that it may be a good practice in some cases, but when written within a
standard, it is driving for a zero tolerance. Entities will make a mistake and this non compliance issue
will be forward via the CEA as an FFT. Section 81 of the Commission’s March 15th, 2012 order
questions if a violation is forwarded in an FFT format, is it really needed for reliability. This
requirement needs to be deleted. If an entity wishes to use an alpha-numeric format, they can as part
of their internal controls to reduce their risk of violating a different standard or for safety reasons. The
requirement of using alpha-numeric as a standard will be administratively burdensome and punitive.
For example: An operator states, “open switch fifteen twenty six” instead of “open switch one, five,
two, six” is now subject to a potentially significant fine for no reliability benefit. Suggest dropping the
Alpha Numeric clarifier requirement from the standard.
No
The MRO NSRF recommends the following comments for consideration by the SDT: 1. This
requirement is too closely associated with TOP-002-2b, R18. As written, a BA, TOP, and GOP will be in
double jeopardy of non compliance if either TOP-002-2b, R18 or COM-003, R1.1.4 is violated. 2. A
similar requirement was removed from TOP-002-2 Project 2007-03. From the Project 2007-03
mapping document: “R18. Neighboring Balancing Authorities, Transmission Operators, Generator
Operators,Transmission Service Providers and Load Serving Entities shall use uniform line identifiers
when referring to transmission facilities of an interconnected network.” Project 2007-03 SDT’s reason
for deletion of R18 from TOP-002-2: “This requirement adds no reliability benefit. Entities have
existing processes that handle this issue. There has never been a documented case of the lack of
uniform line identifiers contributing to a System reliability issue. The bottom line is that this situation
is handled by the operators as part of their normal responsibilities, and no one is aware of a switching
error caused by confusion over line identifiers.” The standard is not applicable to TOs or GOs yet the
requirement calls for the use of “the name specified by the owner(s) for that Transmission interface
Element or Transmission interface Facility.” Suggest deleting this requirement.
No
The MRO NSRF recommends the following comments for consideration by the SDT: System Operators
receive and issue many Operating Communications a day. The VSL for one Operating Communication
is Moderate. That is too high. While improving communications is a laudable goal, the zero tolerance
VSL is unacceptable and will lead to a preponderance of self-reports and compliance and
administrative overhead. Also overlooked is the added stress that every time a System Operator
speaks they may be in violation.
The MRO NSRF recommends the following comments for consideration by the SDT: 1. Concerning the
“Purpose”: Recommend rewrite to state: “To specify universally-applied communication protocols that
reduce the possibility of miscommunication which could impact the reliability of BES”. This shorter and
to the point purpose clearly defines the intent of the Standard. 2. R1.1.3, An entity will be found non
compliant if it merely has a written BES switching order that does not contain a time, time zone or
whether it is daylight savings time or standard time. The Requirement states nothing about
implementing the written communication, just that it is written. The NSRF does not believe that this is
the intent of the SDT. 3. This also applies to oral communications. If two operators are
communicating between each other while in different time zones and executing a BES switching
order, they would need to establish what time it is in both time zones, indicate whether it is daylight
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saving time or standard time. So, since a Reliability Directive is a component of an Operating
Communication, prior to receiving an oral Reliability Directive senders and receivers would need to
establish what time it is in both time zones, indicate whether it is daylight saving time or standard
time and then give and receive the Reliability Directive. The NSRF does not believe that this is the
intent of the SDT. 4. The SAR for this standard incorrectly addresses the blackout recommendation
number 26. Recommendation 26 states: “26. Tighten communications protocols, especially for
communications during alerts and emergencies. Upgrade communication system hardware where
appropriate”. “ NERC should work with reliability coordinators and control area operators to improve
the effectiveness of internal and external communications during alerts, emergencies, or other critical
situations, and ensure that all key parties, including state and local officials, receive timely and
accurate information.” “NERC should task the regional councils to work together to develop
communications protocols by December 31, 2004, and to assess and report on the adequacy of
emergency communications systems within their regions against the protocols by that date.” 5. Order
No. 693 clearly says that the tightened protocols are primarily intended for actions during alerts and
emergencies. This was partially addressed in the interpretation on COM-002 and is being addressed in
Project 2006-06. Below is the summary determination in the Order on this issue. "535, Accordingly,
we direct the ERO to either modify COM-002 or develop a new Reliability Standard that requires
tightened communication protocols, especially for communications during alerts and emergencies." 6.
It is not clear that COM-003-1 R1 applies to COM-002-3. The latest draft of COM-002-3 doesn’t
reference the communications protocols listed in COM-003-1 R1 and the definition of Reliability
Directive does not state that it is a type of Operating Communication. Suggest combining the two
standards into a single communication standard. 7. The white paper states “Significant events have
occurred on the BES when unclear communication created or exacerbated misunderstandings that led
to instability and separation.” However, no specific examples were identified. During the June 7
webinar when this question was brought up, it was stated that three part communication was used
during these events. This begs the question as to why this standard is needed for normal operations.
8. In order to assign the same level of responsibility as COM-002-2, R2, the RC, TOP, and BA should
be the only applicable entities since a Reliability Directive is a sub component of Operating
Communications. The RC, TOP, and BA clearly understand clear, concise and definitive
communications. They are the only required entities to be NERC Certified and should be held to the
highest standards. They can establish other controls to mitigate their risk by training and informing
DPs and GOPs that are within their control. DPs and GOPs do not need to be included in R3.
William Smith
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
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1.Inconsistency between the sentences in R2 of COM-003 "that issues an oral, two-party, person-toperson Operating Communications" and R3 "that receives an oral two-party, person-to-person
Operating Communication". The sentence in R2 has a comma after the word oral, the sentence in R3
does not. Furthermore, what is the difference between two-party and person-to-person
communication? 2.For R2 of COM-003, should the Generator Operator be involved in this requirement
as an authority able to issue an oral Operating Communication? 3.It's not clear when an action is
defined as a Reliability Directive. Does each utility define the instruction to be included in the Reliabity
Directive? Our current practice is that 3 ways communication is always directive. We still don't see the
need to separate the COM-002 (emergency) and COM-003 (normal operating). 4.The requirement R1
of COM-003 should also be reflected in the COM-002 standard. Specially during the Emergency
situation, the Operation Communication should be followed.
Group
Progress Energy
Yes
Yes
Yes
Yes
No
To prevent unintended use of “standard time” or “daylight time” Progress Energy is requesting using
“prevailing time.” Instructions issued at or near the time change could have individuals inadvertently
use the wrong time reference further confusing the issue.
Yes
Yes
No
Progress Energy does not agree with having "Severe VSL" for all of R1
Jim Eckelkamp
Individual
Brad Chase
Orlando Utilities Commission
Yes
Yes
Yes
Yes
Yes
Yes
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No
Use a phonetic alphabet only when further clarification is needed.
No
For example, the (OUC)Indian River to (FPL)Cape Canaveral #1 230kv line is equivalent to the
(FPL)Cape Canaveral to (OUC)Indian River #1 230kv line. Either description is accurate and
acceptable.
Yes
Individual
Jack Stamper
Clark Public Utilities
Yes
Yes
Yes
Yes
Yes
Yes
No
This requirement is still overly prescriptive. Practically all switches, breakers, and transformers have
alpha-numeric identifiers and the proposed Requirement R1.2 will require the use of some form of
alpha-numeric clarifier (either NATO or some other accurate clarifier). However, many alpha-numeric
identities need no clarifier to be accurately understood. Additionally, any such mis-understandings
would become obvious during the three-way communication process. The SDT needs to modify this
requirement to allow the judgment of the system operator to be used in the determination of whether
an alpha-numeric clarifier is needed. This judgment would be based on (1) common sense in
understanding that some letters or numbers may sound similar when broadcast over communications
equipment, (2) past experience with certain letters or numbers requiring clarification, (3) an
understanding by each individual system operator (as supplemented by managerial oversight) of that
system operator’s ability to correctly pronounce letters and numbers (in the English language, unless
another language is mandated by law or regulation), and (4) confidence derived from the accurate
and understandable repetition of the alpha-numeric identifiers in the three way communication
process. Clark believes that Requirement R1.2 needs to rely on the determination by the system
operator as to whether the use of an alpha-numeric clarifier is needed or not. These system operators
are required to obtain certifications and ongoing training and the operating process needs to defer to
the judgment of trained and certified system operators to resolve this potential communication issue.
Yes
No
Failure to implement R1.2 is not necessarily a reliability problem. As stated in our previous
comments, not all alpha-numeric identifiers need clarification. However, the current proposed
standard would deem a failure to use a clarifier in any Operating Communication that uses alphanumeric identifiers as a violation.
Group
Detroit Edison
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No
The definition of Operating Communication is overly broad, increasing the scope of the standard. It
should be limited to actionable items. Suggested rewording of the definition: "Communication of
instruction to perform an action relating to a physical change or a control system data change
affecting an Element or Facility of the Bulk Electric System."
Yes
Yes
Yes
No
In 1.1.3 "When the communication is between entities in different time zones..." should read "When
the communication is between entities in operating in different time zones...". Two entities may be
physically located in the same time zone but one may operate in standard time and the other in
daylight time. When commmunication is between entities operating in different time zones, clarify
which time zone takes precedence.
Yes
No
"use accurate alpha-numeric clarifiers" is vague. Suggest re-wording and adding verbiage: "use
defined (or standard or specified) alpha-numeric clarifiers as specified in Registered Entities
communication protocols." Concern with requirement 1.2- alpha-numeric clarifiers. Would like
clarification if any alpha clarifier can be used or must the phonetic alphabet listed in the white paper
(military Communication protocol)be used. example: for "R", is it required to use "Romeo" or can
"Robert" be used? Concern with VSL table for R1. Current format shows that an entity must be 100%
compliant. The break down from medium to severe is based on how many elements of R1 was not
followed. Suggest changing the format to how many times it was not followed rather than the number
of elements.
Yes
No
VSL table for R1. Current format shows that an entity must be 100% compliant. The break down from
medium to severe is based on how many elements of R1 was not followed. Suggest changing the
format to how many times it was not followed rather than the number of elements.
There is a significant amount of redundancy between COM-002-3 and COM-003-1. These two
standards should be combined and one of them eliminated. COM-002 purpose states "To ensure
communications by operating personnel are effective." COM-003 could be sub-requirements under R2
of COM-002. The blue box on page 2 does not clarify Reliability Directives. Suggest using the same
language as the proposed definition of Reliability Directive from COM-002-3.
Kent Kujala
Individual
Jonathan Appelbaum
The United illuminating Company
No
The intent of Recommendation 26 was to improve the communications around situational awareness.
The SAR sates the purpose is to “efficiently convey and mutually understood for all operating
conditions.” Paragraph 532 seeks to establish communication uniformity as much as practical on a
continent-wide basis. This will eliminate possible ambiguities in communications during normal, alert
and emergency conditions The new definition limits the communication to taking actions during nonEmergencies, and ignores the finding that poor communication occurred in the events leading up to
the 2003 Blackout.
Yes
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Te CPOP was overly administrative.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
UI disagrees with the necessity for this Standard. The intent of Recommendation 26 was to improve
the communications around situational awareness. The SAR states the purpose is to “efficiently
convey and mutually understood for all operating conditions.” This Draft does not address the concern
and a Reliability Standard will not resolve the problem. It will create a compliance burden. The White
Paper does not provide justification for imposing a compliance burden of recording, reviewing and
tagging every conversation in a control center for the applicability of COM-003. There is no correlation
between non-emergency communication and BES reliability. There is no study to demonstrate that
the cause of awkwardness when transitioning from non-emergency to emergency communication will
be resolved by any of the requirements in this Standard. Awkwardness has been resolved by Com002 Requirement to explicitly identify an action as a Directive.
Individual
Scott Berry
Indiana Municipal Power Agency
No
On page 2 of 10 (blue box), the SDT has a blue box that defines Reliability Directives as a “type” of
Operating Communications. This gives the appearance that Reliability Directives are part of Operating
Communications and this could be a double-jeopardy issue. If an entity is found with a potential noncompliance finding on the communication of a Reliability Directive (COM-002), then it is very likely
that the entity could have a potential non-compliance finding on COM-003 (proper communication of
an Operating Communication).
Yes
No
IMPA agrees with the splitting of a single requirement into two requirements. However, the blue box
on page 2 of 10 makes the statement “Reliability Directives are a type of Operating Communications,
to the extent they change or maintain the state, status output, or input of an Element or Facility of
the Bulk Electric System” which seems to include Reliability Directives by simply referencing
Operating Communications in each requirement (R2 and R3). By excluding Reliability Directives, the
requirement is now very confusing and can be interpreted two different ways. Requirement 2 does not
include the Generator Operator as a potential entity that could issue an Operating Communication.
Within its organization or company, a Generator Operator could issue an Operating Communication,
such as one location calling and telling another location to start its generating unit. IMPA believes the
Generator Operator should be included in R2.
No
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The question uses the word “correct” and the requirement uses the word “accurate”. The use of either
word adds ambiguity to the requirement, and an entity being found compliant or non-compliant
depends on how the entity and the auditor interprets the meaning of “use of an accurate alphanumeric clarifier”. The SDT should allow the entity to pick the alpha-numeric clarifier that its company
wants to use or the same clarifier that was used when the Operating Communication was given, and
not give an auditor the chance to say it is not an “accurate” alpha-numeric clarifier.
No
The requirement that requires entities to use uniform line identifiers when referring to transmission
facilities of an interconnected network is in the TOP-002-2b standard (R18). Requirement R1.1.4 of
COM-003-1 draft is not needed and should be deleted.
IMPA believes that each organization should follow its internal communication protocol up to the point
where a Reliability Directive is issued. IMPA does not see why NERC is stating the “how” in this
standard (sub-requirements 1.1, 1.1.1 thru 1.1.4) when its common practice has been to stay away
from telling the entities “how” to do a standard requirement. Therefore, IMPA believes that COM-003
should just state that an entity needs to have a communication protocol in place for issuing and
receiving instructions. In addition, an entity should only have to do training on its communication
protocol in order to prove compliance that it is following or using it. The record keeping or data
retention of phone recordings will become very burdensome on entities, especially if they have to
keep five or six years worth (back to its last audit date).
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
No
Ingleside Cogeneration LP believes that the definition of “Operating Communication” widely expands
the scope of COM-003-1 beyond entity-to-entity or multiple-entity communications. Instead, all
conversations conducted by System Operators, field personnel, engineers, or vendors that may refer
to the status of a BES component are applicable – even those discussed face-to-face. We believe the
original intent to bound the communications to those which can be captured in control room
recordings and/or logbooks is manageable; not so every side conversation or email that takes place
during the natural course of the operating day. The original term, “Interoperability Communication”,
captured this concept. It seems like the Draft 1 definition could be easily modified to read as follows:
Interoperability Communication: Communication of instruction to
change or maintain the state, status, output, or input of an Element or Facility of the Bulk Electric
System. Ingleside Cogeneration LP is in full agreement with the removal of the definitions for
“Communication Protocol,” and “Three part Communications”. Neither term helps address an
ambiguity in the body of NERC Standards that we are aware of.
Yes
Ingleside Cogeneration LP agrees that a communication procedure is unnecessary for routine
operations. In our view, the remaining requirements in COM-003-1 will drive entities to continually
reinforce communications protocols without it.
Yes
There are already other project teams addressing the handling of incidents related to transmission,
physical, and cyber security. It is appropriate in our view to separate emergency operations
communications from normal ones – as done in the second draft of COM-003-1.
Yes
Yes
Yes
Ingleside Cogeneration LP agrees that Reliability Directives must be handled in a more prescriptive
manner. Since Reliability Directives are also an important piece of Project 2006-06, it makes sense to
move the developmental responsibility to them – and avoid unnecessary overlap between the two
projects.
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Yes
No
Ingleside Cogeneration LP agrees with restricting the applicability of COM-003-1 R1.2 to Transmission
interface Elements/Facilities. These are the most likely to carry more than one identifier, as each
entity may use different numbering conventions. However, we see two separate types of identifiers
which may need to be addressed separately. First, those provided on control room monitors often
come from a centrally managed Regional database. It is not reasonable to expect System Operators
to refer to a Facility owner’s one-line diagram to reference these interconnections – and may reduce
reliability. Conversely, field personnel and engineers may rely on the one-line for their identifiers. The
use of the owner’s documentation is more appropriate in these cases. We will further point out that
COM-003-1 does not apply to Facility owners, so it seems as though they could decline to provide
identifiers if they so choose.
Yes
With the transition of emergency communications to other projects, it is appropriate to downgrade
COM-003-1’s VRFs from “High” to “Medium”.
Ingleside Cogeneration LP agrees in principle with the need for Operators and Field Personnel to
express and validate their intent before taking actions that may pose a risk to the BES. However, we
have serious reservations with the use of the audit methodology to drive consistent behavior. Perhaps
most significant is the assessment of violations for a single instance where an operator does not use
alphanumeric identifiers or a 24 hour clock during the course of an Operating Communication. We
believe that even in an extremely well managed organization that 100% adherence is statistically
impossible. In our view, this flies in the face of fairness – and raises serious questions about the
“public/private partnership” that is supposed to be the foundation of NERC standards. This points to
the “bean counting” type of Standards that NERC is trying to get away from, rather than focusing on
reliability of the BES. Furthermore, entities will be assessed violations if they cannot prove that every
side conversation did not take place in accordance with COM-003-1. In order to comply, we estimate
it will take two or three times the time to document a non-recorded communication than it will be to
actually conduct one. This is not an appropriate use of our front-line resources available time – nor
does the documentation serve a reliability purpose in our view. In addition, COM-003-1 is silent as to
multiparty calls that are typical in some regions, where an entity at random is elected for the three
part response for the group on conference calls, and not all parties are required to respond, but
rather only participate on the call.
Individual
Roger C. Zaklukiewicz
Roger Zaklukiewicz Consulting
No
The proposed standard introduces a new term "Operating Communications" which in my opinion is
unnecessary and which I believe will cause confusion with the term "Reliability Directives". The
standard proposes to establish a three part communcations for what I would describe as routing
operating instructions. This aspect of the standard would require/mandate the use of an unnnecessary
and burdensome operating practice that in a number of cases may impede or jeopardize system
reliability rather than improve the reliability of system operations.
No
See previous comment(s) regarding the necessity for a Communications Protocol Operating
Procedure.
No
Yes
Yes
No
See previous comment to Question 1.
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Not certain as I do not know the specifics of the NATO phonetic alphabet.
No
We should always use the identifer adopted by the RTO, not one developed by the Element/Facility's
owner.
No
The standard should not be mandating the "HOW".
Group
Duke Energy
No
The definition of Operating Communication is vague, general and overly broad. We don’t believe the
Blackout Report recommendations and Order 693 directives require 3-part communications for
routine communications. Communications protocols can be tightened, and more effective
communications can be achieved without this extreme approach. See our comments under question
#2.
No
We believe that having a reliability standard requirement to develop a Communications Protocol
Operating Procedure, to address items similar to those under R1.1 would be an appropriate method to
address the Blackout Report recommendations and Order 693 directives to tighten communications
protocols. An entity’s CPOP could address the language to be used between functional entities, what
clock format is to be used, how time zone/Daylight Savings Time will be addressed, and transmission
equipment identifiers. The CPOP should have a required review frequency, and personnel should be
trained on the CPOP. This approach, unlike the draft standard could be audited and certified. We see
no way to reasonably audit or certify compliance with the draft standard in its current form. Duke
suggests this approach to COM-003: Rather than specifying the solutions to achieving effective
communication, COM-003 should instead focus on developing and training on an approach that is
designed appropriately for each RE. For instance, another approach to COM-003 might be along the
lines of: Requirement R1 could be written in a manner to require the appropriate registered entities to
develop a communications protocol that is appropriate for each RE. This communications protocol
should address how the RE is handling: Time Zone Designations – for both internal and external
communications Language Alpha-numeric identifiers 3–part communications – when is it required,
etc. Use of defined terminology Use of common transmission equipment identifiers Other items
deemed important for the communications protocol to address – again, this would not define HOW
these items are addressed. This approach would require the RE to specify how it is addressing these
issues, without prescribing solutions. For instance, a RE could include a section in its protocol to deal
with time zone designation. In this section the RE could explain that it, and its neighbors, all are in
and use the same time zone. As a result, the RE has determined that requiring the identification of
time zone reference in communication is not necessary. Requirement 2 could be written in a manner
to require the training of operators on the communication protocol. Requirement 3 could be written in
a manner to require the RE to define its internal controls it uses to review that its protocol is being
followed. The compliance approach would be to: 1) assess whether the RE has developed a written
protocol and whether the protocol addresses each item – this does not mean there is an assessment
of HOW each item is assessed; 2) assess whether the RE has trained its operators on the
communications protocol 3) assess whether the RE is following its internal controls
Yes
No
We think mandating English is over-reaching (As currently written, the Standard erroneously focuses
on “how” an entity can be compliant, rather than describing “what” an entity needs to achieve to be
compliant). Let the entity that develops the CPOP and its neighbors decide on language, clock format,
etc.
No
We think mandating the 24 hour clock is over-reaching (As currently written, the Standard
erroneously focuses on “how” an entity can be compliant, rather than describing “what” an entity
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needs to achieve to be compliant). Let the entity that develops the CPOP and its neighbors decide on
clock format, how time zone differences will be addressed, etc.
No
We don’t believe that 3-part communications are needed for ALL routine communications, and that R2
and R3 should be deleted. Also, there should only be one standard for communications protocols. The
communications efforts in Projects 2007-02, 2006-06 and 2007-03 should be combined.
No
We think that this is over-reaching (As currently written, the Standard erroneously focuses on “how”
an entity can be compliant, rather than describing “what” an entity needs to achieve to be compliant),
and creating a requirement that can’t reasonably be audited or certified.
No
We don’t believe that this requirement is consistent with the TOP requirement to use common line
identifiers. This is more restrictive, in that it mandates the use of a name specified by the asset
owner, while TOP simply requires the development of common identifiers without dictating what party
defines the names. We understand the issue of identifying common terms for equipment, but believe
the development and use of “common identifiers” is already covered in the TOP Standard and should
be eliminated altogether from COM-003.
No
The VRF’s should all be “Low”. For example, there will be thousands of routine communications per
year, and each instance of missing one alpha numeric identifier (ex. “balloon” versus “baker”) would
be a violation. As written, this standard would drive allocation of resources for little reliability benefit.
We believe that having effective communications is an important goal; and there are instances where
the use of 3-part communication is appropriate. We also believe that the industry is maturing, and
the use of 3-part communication as a tool to achieve effective communication has grown (as
evidenced by Table 1-A in the May 2012 COM-003-1 Whitepaper. This maturity and expanded use of
3-part communication has occurred without a Standard in place; and that we do not believe a
Standard is needed that focuses on one way of establishing effective communication.
Greg Rowland
Individual
Michael Moltane
ITC Holdings
Yes
Yes
COM-003-1 and COM-002-3 cannot be processed separately since they are inextricably inter-related.
In fact, they are so inter-related that there is no compelling reason provided that suggests they
should be separate standards. The comment form for COM-003-1 even indicates that Reliability
Directives are a subset of Operational Communication which further indicates that all of the
requirements surrounding how communication is performed regardless of the nature of the content
should be addressed in one standard. Further, 3 part communication is being cited as ensuring
reliable operation of the BES. It is not the act of 3 part communication that ensures reliable
operation. Rather, it is the effective transfer of information that does. Requiring 3 part communication
for all communication will reduce the effectiveness of the communication as the novelty factor wears
off and individuals only go through the motions. Active listening and truly understanding the
communication is what accomplishes the intent. Use of 3 part communication for situations that the
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initiator determines it is warranted based on their knowledge and training is the most appropriate
approach to ensure reliable operation of the BES.
Group
BC Hydro
No
BC Hydro does not support limiting operating communications to instructions. We believe this should
account for notification or reporting and that in these cases three part communication should be used
to ensure understanding. For example, if an element is out of service and that is being reported to an
operating entity, the receiver of that communication should show confirmation of understanding by
repeating their understanding and receiving confirmation. Example: 1) TOP Call to RC: Our
transmission Line XX is currently out of service and is expected to remain out until field crews
respond. 2) RC to TOP : OK, I understand that Line XX is out of service and will remain out until
further notice. 3) TOP to RC: That’s correct. I’ll call you when I have some more information.
Yes
Yes
Yes
Yes
Yes
No
BC Hydro does not support the full time use of alpha numeric clarifiers for all Operating
Communication. In some cases we believe it detracts from the instruction being delivered. In our
system, devices are identified by a combination of alpha and numeric. For example, to call
transmission line 5L98, ‘5-Line-98’ or a circuit breaker 5CB11, ‘5-circuit breaker-11’ does not add
value. This may help in some areas depending on their naming conventions. BC Hydro does not think
the use of the term ‘accurate’ effectively describes what is permissible to be used as an alpha numeric
clarifier.
No
BC Hydro supports this in most cases, especially when dealing with the RC, but in many cases there
may be lack of clarity around ownership. We believe this needs to be reworded to account for
designation that is agreed to by the parties that are communicating.
Yes
Patricia Robertson
Individual
Joe Tarantino
Sacramento Municipal Utility District
No
See response in #10
No
See response in #10
No
See response in #10
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No
See response in #10
No
See response in #10
No
We have a problem with the standard and therefore we inherently don't agree with VRFs and VSLs.
Recommendation: Not-Approve We feel that the direction for this communications standard is grossly
in error. Focus should be on ensuring proper training programs are in place that emphasize and best
prepare the System Operator for effective communication. The idea that effective communication can
be scripted is entirely mis-guided and that a regulatory body might subject an entity to financial
penalties for communication standards that attempt to script the language spoken, how time is
referenced, naming conventions and alpha-numeric clarifiers has no precedence in industry that we
are aware of. The United States’ Air Traffic Control protocols for communications between controllers
and commercial airline pilots are very tested, well trained and effective. Controllers and pilots are
trained in effective communication and the situations and pronunciation types that may lead to
confusion. But they are not fined for any instance of not following them. From the Air Traffic
Controllers Handbook, http://avstop.com/ac/atc/2-4-1.html#2-4-1 2-4-3 Pilot Acknowledgment /
Readback a. When issuing clearances or instructions ensure acknowledgment by the pilot. NOTE Pilots may acknowledge clearances, instructions, or other information by using "Wilco," "Roger,"
"Affirmative," or other words or remarks. REFERENCE - AIM, Contact Procedures, paragraph 4-2-3. b.
If altitude, heading, or other items are read back by the pilot, ensure the readback is correct. If
incorrect or incomplete, make corrections as appropriate. Mandating the use of the English language
in all communications is not in the best interest of reliability. We are not aware of any issue that has
been raised of significance with the current requirement contained within COM-001-1.1, R4
Individual
Ed Davis
Entergy Services
No
Due to these extensive comments and desire for these comments to be formatted for the SDT we
have also sent these comments to Monica Benson in a Word document. While we agree with the
definition, we do not agree with R1, R2 and R3. While we are not enamored of having a Requirement
to have a procedure, in this instance, the exception seems to be necessary. Below is suggested
language to replace all of the Requirements and sub-Requirements in COM-003: Proposed new text:
“R1. Each Reliability Coordinator, Transmission Operator, Balancing Authority, Generator Operator,
and Distribution Provider shall develop a written communications procedure for Operating
Communications among personnel responsible for Real-time generation control and Real-time
operation of the interconnected Bulk Electric System. The procedure shall address at minimum:
[Violation Risk Factor: Low][Time Horizon: Long Term Planning] 1.1 When communicating between
functional entities 1.1.1. Establish the language to be used. 1.1.2. Time format to be used. 1.1.3.
Establish treatment for time zones when multiple time zones are crossed. 1.1.4. Identify naming
convention for Transmission interface Element or a Transmission interface Facility. 1.1.5. For oral
Operating Communications, establish the treatment for the circumstances in which alpha-numeric
identifiers must be used.” The SDT has not listened to the industry comments given in previous
ballots. It also appears to be focused on imposing three part communications on the industry for
routine communications despite the fact that neither the blackout report nor the SAR on which these
standards are based emphasize that issue.
No
We believe that this version of COM-003 actually embeds a “CPOP” within the Requirements. This is
inappropriate intrusion beyond identification of with “what” an entity must comply into “how” that
entity must comply. Our suggested R1 provides replacement language that would require a
communications procedure. We see no reliability value in having a defined term for “Communications
Protocol Operating Procedure”, as the term “communications procedure” is completely understandable
using the normally accepted meanings of the words.
No
We disagree – this concept more properly belongs in the NERC Rules of Procedure and should be
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designed to address Recommendation 26 of the NERC 2003 Blackout Report. This is an expectation of
NERC itself, not of the industry (and NERC can’t write Requirements for the ERO). Also, this team
should take the time to become familiar with recent NERC Operating Reliability Subcommittee (ORS)
discussions and recommendations regarding the elimination of the Transmission Alert Levels. Even
the DHS has found that Alert Levels has diminished value.
No
We disagree with all of the Requirements and sub-Requirements in this standard, due to the fact that
they embody a procedure into the Requirements. There is no reliability need being fulfilled by taking
this approach. See our suggested replacement R1 in our response to Q1. This would replace R1, R2
and R3 and their associated sub-Requirements.
No
See our response to Q1, Q2 and Q4.
No
Three part communications should not be required for routine operating communications. See the
definition of Reliability Directive in COM-002, which addresses the actual reliability issues associated
with communications. This team once had coordinated with the RC SDT (Project 2006-06), and the
RTO SDT (Project 2007-03), with a different approach for routine communications resulting from a
meeting between the chairs of the three SDTs on November 17, 2009 in the SERC offices in Charlotte,
NC. Quoting from the meeting setup email: “On the basis that the SC members are the key drivers of
the joint effort to finalize “Directives and Three-Part Communications”, […] and […] indicated a
preference for Tuesday 1-3PM ET November 17. Some members of the RTOSDT and RCSDT will be
attending the meeting in person….” At that meeting it was agreed that RC SDT (Project 2006-06)
would develop the definition for “Reliability Directives”, and require 3-way communication for
Reliability Directives by the RC. Conversely, it was decided that OPCP (Project 2007-02) would handle
ordinary communications, but would not require 3-way communications for routine communications.
RTO SDT (Project 2007-03) only agreed to this course of action (in effect, backing out of writing
ordinary communications standards as part of Project 2007-03) because OPCP SDT (Project 2007-02)
had committed to this approach during that meeting. It should be noted that “COM-001-1
Telecommunications” and “COM-002-2 Communications and Coordination” are included in the SAR for
RTO SDT (Project 2007-02) and its coordination with RC SDT and OPCP SDT was conditioned upon RC
SDT and OPCP SDT following the course of action agreed-to in the November 17, 2009 Charlotte, NC
meeting. OPCD SDT (Project 2007-02) should honor the intent of that meeting in Charlotte and
remove R2 and R3 from this standard. We suggest that R2 and R3 should be eliminated, since neither
one will result in increased reliability.
No
See our responses to Questions #1, 2 and 4.
No
See our responses to Questions #1, 2 and 4.
No
We disagree only in the sense that we disagree with the requirements, therefore, the VRFs and VSLs
are not relevant. We suggest deletion of all three requirements, and the insertion of one new
requirement. See Response to Questions 1, 2 and 4.
NERC standards are not procedures and this standard attempts to impose a single procedure on the
industry. Tightening of communications protocols between entities does not equate to a procedural
requirement to use 3-part communications between personnel at various registered entities. The
actual impact to reliability of routine communications between entities is minimal and further
diminished by the Reliability Directive construct espoused by RC SDT (Project 2006-06), which fully
addresses the reliability implications of communications. While most of the industry practices threeway communications routinely, this is not necessary to assure reliable operations. Rather, in many
cases, entities are viewing this as a “best practice”, that helps to formalize communications so that
Operators will develop good communications habits. The work by the RC SDT (Project 2006-06) on
Reliability Directives is all that is necessary to assure BES reliability, and the approach currently
espoused by OPCP SDT (Project 2007-02) in this COM-003 standard is massively redundant to that
effort while not helping reliability. We agree with SERC in suggesting another approach to COM-003.
Rather than to specify the solutions to achieving effective communication, COM-003 should instead
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focus on developing and training on an approach that is designed appropriately for each RE. For
instance, another approach to COM-003 might be along the lines of: Requirement 1 (See our
suggested alternate language in our response to Question 1) could be written in a manner to require
the appropriate registered entities to develop a communication protocol that is appropriate for each
RE. This communications protocol should address how the RE is handling: Time Zone Designations –
for both internal and external communications Language Alpha-numeric identifiers Three – part
communications – circumstances in which is it required, etc Use of defined terminology This approach
would require the RE to address how it is addressing these issues, without prescribing solutions. For
instance, a RE could include in its protocol a section dealing with time zone designation. In this
section the RE could explain that it, and its neighbors, all are in and use the same time zone. As a
result, the RE has determined that requiring the identification of time zone reference in
communication is not necessary Procedures should address the training of operators on the
communication protocol Procedures should address the internal controls that the RE uses to review
that its protocol is being followed. The compliance approach would be to: Assess whether the RE has
developed a written protocol and whether the protocol addresses each item – this does not mean
there is an assessment of HOW each item is assessed; assess whether the RE has trained its
operators on the communications protocol and assess whether the RE is following its internal controls.
Compliance with this requirement should not require 100% accuracy in compliance with the entities
communication procedure by real-time operations staff. That would cause misdirection of resources
and training time from issues more important to BES reliability. Any data retention requirements
should be consistent with the COM-002 reliability standard. What is the role of the Operating
Communications Protocols White paper? Is it a position of the STD? Was there a minority opinion?
Why was it not vetted with a wide spectrum of industry stakeholders (we are unaware of any effort to
circulate this white paper even as far as to the standing Technical Committees of NERC ). Does the
industry agree that we need a standard on three part communications for normal operations? We
have seen no evidence to support this contention. This revision to COM-003 seems to have sprung
into existence without any substantive industry comments indicating that the industry would benefit
from having a procedure memorialized as a set of Requirements.
Individual
Anthony Jablonski
ReliabilityFirst
No
ReliabilityFirst votes in the Affirmative for this standard because the standard further enhances
reliability by providing communication protocols when participating in Operating Communications
(specifically three way communication). Clear, formal and universally-applied communication
protocols will help reduce the possibility of miscommunication which could lead to action or inaction
harmful to the reliability of BES. Even though ReliabilityFirst votes in the Affirmative standard,
ReliabilityFirs votes in the negative for the VSLS and offer the following comments for consideration:
1. VSL for Requirement R2 a. When referencing “Part” numbers within the VSL, a consistent format
(e.g. Requirement R2, Part 2.2 first bullet) should be used. 2. VSL for Requirement R3 a. The VSLs
should state “oral … Operating Communication” rather than “verbal … Operating Communication” to
be consistent with the language in the requirement. b. For consistency with the first part of the first
bullet in Requirement R3, RFC recommends the following language be considered for the “High” VSL:
“The responsible entity received and repeated an oral two-party, person-to-person Operating
Communication but did not wait for confirmation that the repetition was correct. (Requirement R3,
first bullet)”
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Individual
Brian Evans-Mongeon
Utility Services, Inc.
No
Though we agree with the addition of “Operating Communication” definition and the elimination of
“Communication Protocol”, “Interoperability Communication” and “Three part Communications”
definitions, the use of a “blue box” around the example of a Reliability Directive (Reliability Directive
are a type of Operating Communications, to the extent they change or maintain the state, status,
output, or input of an Element of Facility of the Bulk Electric System.) implies this is also a definition.
We suggest removing this “blue box” from COM-003-1 and leave the definition of Reliability Directive
to Project 2006-06 which has been charged with developing this definition. An alternative would be a
footnote to the other Project and/or the NERC Glossary of Terms if the other standard is approved
prior to COM-003-1.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
The applicability of this standard is unclear in the case of Distribution Providers. The definition of
Operating Communication includes “Elements” that could impact the BES. The NERC Glossary
definition for Elements includes non-BES devices and equipment. Additionally, the Purpose section of
the standard states "harmful to the reliability of the BES." Since non-BES Elements could affect the
BES this standard could be deemed applicable to non-BES devices. If it is the intent of the SDT to
apply this standard to All Operating Communications concerning both BES and non-BES Facilities this
should be explicitly stated in the applicability section for transparency. Otherwise clarifying language
should be added to exclude non-BES Facilities.
Individual
Wayne Sipperly
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
NYPA supports the comments submitted by the NPCC Regional Standards Committee (RSC).
Group
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Dominion
No
Dominion agrees with the elimination of Communication Protocol, Interoperability Communication and
Three part Communications proposed in the first draft. Each standard requirement (R1, R2 & R3)
specifically excludes Reliability Directives, further adding confusion to the issue of what is a reliability
directive. The Reliability Directive should stand on its own and if the SDT does not agree then the
relationship between Reliability Directives and Operating Communications should be clarified in the
Standard. When the standard is implemented, the text box (on page 2 of the clean standard) will be
removed, therefore losing any tieback to a Reliability Directive as a type of operating communication.
Yes
Yes
Yes
No
Dominion currently views this requirement as being too prescriptive, the standard should be written
to allow a 24 hour clock and time zone designation or 12 clock with an AM or PM and time zone
designation.
No
The current version of this standard expands the use of three-part communication to all Operating
Communications, not just Reliability Directives as specified in draft standard COM-002-3, Project
2006-06. Also, given the definition of Operating Communication (i.e., communication of instruction to
change…an Element or Facility…) and the use of “two-party, person-to-person” in the Requirements,
communications between two members of the same organization (e.g., two Generator Operators, two
Transmission Operators) would be subject to this standard. This seems impractical, requiring
organizations to document, as evidence, internal communications. Dominion suggests the language
be clarified to eliminate this issue. The requirement as written could also be interpreted to mean that
three-part communications are not necessary for communicating Reliability Directives. If the protocol
for Reliability Directives must be covered by a different standard, then that standard should be
referenced in this requirement in order to clarify the intent of the exclusion and remove the
implication that three-part communications do not apply to Reliability Directives. COM-003-1 R2 could
be rewritten to add clarification for Reliability Directives only as “Each Reliability Coordinator,
Transmission Operator and Balancing Authority that issues an oral, two-party, person-to-person
Operating Communication, excluding Reliability Directive (as referenced in COM-002-3 R2 and R3)
shall:”
No
Dominion suggests that Requirement R1, Part 1.2 is ambiguous in that the use of alpha-numeric
identifiers appears optional (but if they are used, they must be accurate). If the purpose of Part 1.2 is
to USE alpha-numeric identifiers, then this statement needs to be modified to state that more directly
and to give that clarity.
No
The requirement as written is superior to Requirement R18 of TOP-002b which requires the use of “. .
. uniform line identifiers when referring to transmission facilities of an interconnected network.”
However, the industry can’t have two different standards with different requirements for identifying
transmission facilities.
Dominion acknowledges the term Reliability Directive is proposed for inclusion in the draft of COM002-3, but we also prefer a notation be added, to clarify this is not an existing term in the current
version of the NERC Glossary of Terms. As mentioned in response to Question #1; When the standard
is implemented, the text box (on page 2 of the clean standard) will be removed, therefore losing any
tieback to a Reliability Directive as a type of operating communication. The data retention period for
this standard for normal operating communications is extensively longer than the COM-002-3
standard for emergency communications as discussed in Project 2006-06. Dominion suggests the
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same data retention period as COM-002-3 for Requirements 1, 2 and 3 of this standard, which is for
the most recent 3 months. Dominion also questions why the proposed standard is applicable to
Distribution Providers since changing the state of BES elements is not what they do. Therefore, they
would never receive an Operating Communication instructing them to do anything to a BES element,
so it would not be practical or useful for a DP to include this standard in its compliance program. DP is
included as an applicable Registered Entity in COM-002. Other than a load shed Reliability Directive
(during emergencies), what other Operating Communication would a DP receive?
Connie Lowe
Individual
Andrew Gallo
City of Austin dba Autin Energy
No
To clarify that Operating Communications occur in real-time, AE offers the following change to the
definition: “Real-time communication of instruction to change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System.”
Yes
No
AE believes the SDT should carefully review existing alert levels (e.g. EEA levels, threat levels). AE
requests that the SDT use only the Alert Levels in Attachment 1 if they enhance existing levels or fill a
gap. AE’s preference is for the SDT to build upon existing alert levels instead of imposing a new
category.
No
There is not enough evidence to support the need for these types of specifics. Recommendation 26
encourages NERC “to ensure that all key parties … receive timely and accurate information.” COM003-1 seems to interpret the recommendation by telling entities “how” to ensure information is
accurate (e.g., use English, 24-hour clock, time zones, alpha-numeric identifiers, etc.). This standard
reaches too far into the “how” instead of focusing on the “what,” which is “timely and accurate
information.” Registered entities should decide the best methods to ensure accurate information for
themselves (through three-part communication, use of the 24-hour clock or otherwise).
No
It makes sense to separate R2 from R3; however, AE respectfully objects to mandating three-part
communication for normal operating communications. The fact that most registered entities already
use three-part communications for normal operating communications makes it a best practice; it does
not mean a NERC Reliability Standard should require it.
No
There is not enough evidence to support the need for these types of specifics. Recommendation 26
encourages NERC “to ensure that all key parties … receive timely and accurate information.” COM003-1 seems to interpret the recommendation by telling entities “how” to ensure information is
accurate (e.g., use English, 24-hour clock, time zones, alpha-numeric identifiers, etc.). This standard
reaches too far into the “how” instead of focusing on the “what,” which is accurate information.
Registered entities should decide the best methods to ensure accurate information for themselves
(through three-part communication, use of the 24-hour clock or otherwise).
Yes
No
AE respectfully objects to the contents of COM-003-1 as described in these comments. If, however,
AE were to assume agreement with the requirements, we offer the following comments regarding the
VSLs: AE does not believe the R1 VSLs provide for a fair application in practice. Risk to the BES is not
increased when fewer communication protocols apply to an entity. As proposed, missing 1 of 4 parts
when 4 parts are required is a Moderate VSL. Missing 1 of 4 when 3 are required is a High VSL (and it
never has an opportunity for a lower severity level because Moderate VSL applies only when 4 parts
are required). Similarly, if an entity misses 1 of 4 when 2 are required, it should not be penalized with
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a Severe VSL. AE suggests the solution to this issue is to assign Moderate VSL to missing 1 of 4, High
VSL to missing 2 of 4 and Severe VSL to missing 3 or more of 4, in all instances regardless of how
many parts are required. If the structure suggested above is not adopted, AE offers the following
comments for consideration: Within the Severe VSL column for R1, the first paragraph (missing all of
the parts when four are required) duplicates the second paragraph (missing three or more when four
are required.) Within the Severe VSL column for R1, the third and final paragraphs should say “two
(2) or more” and “one (1) or more,” respectively, to account for all possible situations. Doing so
aligns with the second paragraph which already says “three (3) or more.” Finally, with respect to the
VSLs for R2 and R3, all instances of “verbal” should be changed to “oral” to match the language of the
requirement.
Austin Energy (AE) respectfully disagrees with COM-003-1 because it: (1) reaches beyond the SAR
and (2) requires “how” communication should take place instead of “what” and “when.” The scope of
COM-003-1 reaches beyond the SAR by imposing protocols on normal communications when the
focus of the 2003 Blackout Report, Recommendation 26 and Order 693, Paragraph 532 is on timely
and accurate EMERGENCY communication. Recommendation 26 does not recommend tightened
communication protocols under normal operating conditions. It recommends that NERC “work with
reliability coordinators and control area operators to improve the effectiveness of internal and
external communications during alerts, emergencies, or other critical situations....” AE believes
Project 2006-06 (COM-002-3) sufficiently addresses this recommendation by requiring three-part
communication for Reliability Directives. If used correctly, the say-repeat-confirm method improves
effectiveness of communications during alerts, emergencies and other critical time periods. The other
source for COM-003-1 (Paragraph 532) references communications during normal conditions, but only
in response to an EEI comment. The actual directive is in paragraph 535, where FERC states,
“Accordingly, we direct the ERO to either modify COM-002-2 or develop a new Reliability Standard
that requires tightened communications protocols, especially for communications during alerts and
emergencies.” AE notes that the directive focuses on communications during alerts and emergencies,
similar to Recommendation 26. AE recognizes that the SDT reads Paragraph 532 to indicate a need
for communication protocols even under normal operating conditions. However, AE believes that a
NERC Reliability Standard is not the appropriate place to address the “how” of communication
protocols under normal conditions. Industry stakeholders are justifiably concerned that deviations
from the requirements during normal operating conditions will inevitably occur (human performance
factor) without a risk to reliability. The potential number of self-reports industry-wide carries an
overly burdensome cost without an associated benefit to the BES. AE believes that efforts at the
regional level (e.g., training, guidelines, etc.) would be more effective and relevant. In summary, AE
believes the focus of COM-003-1 should be on achieving accurate and timely information (the “what”
and “when”), not prescribing exactly “how” registered entities achieve it. As written, COM-003-1 goes
too far into the realm of mandating best practices and claiming it is necessary for reliability.
Individual
J. S. Stonecipher, PE
City of Jacksonville Beach dba/Beaches Energy Services
Yes
None
Yes
Yes, it would be administrative in nature and would not add value.
Yes
None.
Yes
None.
Yes
Yes
None.
Yes
None.
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Yes
None.
Yes
None.
None.
Individual
Warren Rust
Colorado Springs Utilities
Yes
Yes
Yes
better option would be to retire the concept
Yes
"Use the English language when communicating between functional entities, unless another language
is mandated by law or regulation." If two or more functional entities (say BA & TOP) reside within the
same utility (perhaps even co-located in the same control center) and are communicating solely with
each other, mayn't they speak their native language to each other - with or without the aid of law?
Yes
the use of "prevailing time" should be allowed, when appropriate, along with daylight and standard.
Yes
No
the term "correct alpha-numeric clarifier" is itself unclear. Searching on Google, I can find no other
use of this term outside of this Standard. Therefore, this does not appear to be a standard term or
concept. Did the SDT mean to require the use of a phonetic alphabet (NATO's or any other)? If so,
please just state so. If the intent was to permit means other than phonetic alphabets to ensure clear
communication of alpha-numeric identifiers, then I suggest clarifying the Standard's language.
Perhaps, "When participating in oral Operating Communications and using alpha-numeric identifiers,
use a phonetic alphabet or similar means to ensure clear understanding."
Yes
The possibility exists for an element/facility to be co-owned and for each owner to have a different
name.
Yes
Individual
Patrick Brown
Essential Power, LLC
No
Defining the new term ‘Operating Communication’, and including the approved definition of ‘Reliability
Directive’ under this newly defined term and then requiring the use of three part communications for
all ‘Operating Communications’ is redundant and unnecessary. There is no reason to have two
separate Standards governing the use of three-part communications.
No
The use of English should be mandated for communications between entities in separate regions
where the common language in one of the regions may not be English. Allowing an entity to use a
language other than English when communicating with regions where English is the required language
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is counter to the purpose of the Standard and could in fact jeopardize reliability through
miscommunication.
No
This provides minimal real-time benefits to the Operators, but only serves to make it easier to
conduct an after the fact analysis. As such, this is an administrative requirement that should not be
included in the Standard.
No
Although I agree with the requirement making the receiver responsible for repeating the message,
this should be included in COM-002. Again, having two separate Standards on this topic is redundant
and unnecessary.
No
If the purpose of this Standard is to improve and standardize communications, than all entities should
use the same alpha numeric clarifiers.
Group
JEA
No
Yes
No
Yes
Yes
No
The two standards (COM002&COM003) should be merged into one standard. Three part
communications should be considered a best practice and only requried during emergency directives.
Yes
R1.2 is unclear. The term “alpha-numeric identifiers” is not defined. We believe examples would help.
For example we assume that if we say the Northside 1, this would not be alpha-numeric but what if
we used logical letters such as NS1 in internal communications. Is it all alpha-numeric
communications or just illogical meaningless letters and numbers. We believe we should be able to
use logical alpha numeric things like MS for motor-switch and not have to use alpha-numeric
clarifiers. Also please specify if this is for both internal and external communications. Again we believe
that this should be for external communications using illogical meaningless letters and numbers not
for internal normal nomenclature.
Yes
R1.1.4 is unclear. Does this apply to both internal and external communications? JEA believes that
this should only apply to external communications only. Many entities have internal numbering
systems that have been in place without incident for decades and should be able to continue to use
these internal systems when performing internal communications.
No
R2 & R3 should be removed from the standard. They are a best practice and do not substantially
affect reliability when a simple command such as increase load by 100MW for a new purchase
agreement.
Combine COM002 & COM003.
Thomas McElhinney
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Group
Associated Electric Cooperative JRO00088
No
Although the intent appears to be only for oral communications of NERC Certified System Operators,
and those directly aimed at affecting the altered or continued state of BES elements of Facilities, the
wording is insufficiently bounded. For instance, it could include any communications between a unit or
plant operator and internal plant personnel, were the net output of the plant to change, significantly
or insignificantly, current or future (status), its injection to the BES. The same would be true of loads,
and so communication of Distribution providers with any manufacturing plant managers would
necessarily become subject to this standard (extractions from the BES – significant or insignificant).
Taken to one extreme, purchasing personnel could also be responsible for whatever part their
telephone conversations play in altering the future status of plant real or reactive power production or
consumption. AECI agrees with the SERC OC STANDARDS REVIEW GROUP consensus comment, that
COM-002 should be sufficient in addressing any industry deficiencies in this area and if not, the
deficiencies addressed there.
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s comments pertaining to question 2.
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s comments pertaining to question 3.
No
Although this qualification appears to now be accommodating of regional government mandates, it
fails to address decorum where a non-English bounded Entity is communicating externally with
entities who are unbounded by the same mandates or vice-versa. Best to let the Regional Entities
work this out among themselves and document the agreements, where applicable.
No
There are remaining issues where Entities deal with those few areas who swap time-zones dependent
upon SDT, and they could be unfairly ensnared by non-compliance, in their not realizing that nuance.
In addition, given the unbounded scope of this standard, it would seem best to allow operator
discretion or this clause is a PV magnet.
No
AECI appreciates the SDT’s desire to add flexibility and yet clarity for what is expected, but we
absolutely disagree with a split into two requirements. Such a split unnecessarily increases the
industry’s risk, of a single three-part communication failure, being assessed in violation of two
separate requirements, yet with no added value to BES reliability. Given today’s environment, PVs will
be written although the intended content was accurately conveyed and the system properly operated,
should these requirements exist. So AECI agrees with SERC OC STANDARDS REVIEW GROUP’s
assessment that R2 and R3 should be entirely removed.
No
AECI appreciates the SDT’s desire to afford flexibility to the industry, and yet we still view this level of
prescription as unnecessarily burdensome, given the current broad scope of this particular standard.
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s response to Question 8.
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s response to question 9.
AECI remains unconvinced that COM-003-1 adds sufficient value to our industry reliability, for the
degree of non-compliance risk it imposes. There are several issues with the supporting white paper:
1) this paper appears void of citations supporting its assertions, 2) it also fails to differentiate cited
industry failures in communication, between; situations where somebody failed to communicate a
field-change that significantly affected BES situational awareness, situations where the change was
clearly understood and yet its situational impact was not, and situations where the affected objects
were misunderstood. All of these failures are critical to our industry’s assessing true value in
introducing and enforcing broad-scope three-part communication, because COM-003-1 can only
improve the last of those three miscommunications, 3) its citation, of 12 Entity’s broadly adopting
three-point communication, seems hardly a majority practice within our industry, 4) while Entities
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may internally adopt similar policies, that does not mean we should risk being subject to Federal law
in support of conceptual theories, 5) citations of similar adoptions by other industries or cultures, fail
to provide useful differentiation between their critical and casual operational communications, except
in the case of military, where COM-003’s proposed broad scope of communication appears to be
inconsistent, while COM-002’s narrowed scope appears in alignment with the military’s adopted
practices as described.
David Dockery
Individual
Bob Steiger
Salt River Project
Yes
The definition of "Operating Communication" is vague and needs clarification.
Yes
Yes
No
In the real time environment we deal in current hour or next hour terms. Including the time zones in
these conversations would further muddy the waters.
No
This combination for R2 and R3 would open some vertical entities to be being fined multiple times for
the same communication.
Yes
No
The interface names that should be used are the names that are registered in the TSIN.
No
Individual
Robert L Dintelman
Utility System Efficiencies, InC.
Yes
No
Even though this is administrative, due to the vital importance of proper operating communications a
Communications Operating Procedure is necessary to ensure that the Registered Entity has
established its own communications procedures in compliance with the standard to use in training its
operations personnel in proper communications protocols.
Yes
Yes
Yes
Yes
Yes
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Yes
No
We agree with the classification of VRF as medium for Requirements R1, R2, and R3; however,
hopefully this will not detract from the vital importance of using three-part communications in ALL
operations communications relevant to the Bulk Electric System (BES). We disagree with the VSLs for
Requirements R1, R2, and R3. For R1 we don't believe it is valid to claim that various combinations of
not using the 24-hour clock, or alphanumeric definitions, etc. will make any difference in the outcome
of poor communications. We recommend the following approach: For R1, failure to use any of the
required elements of this requirement should be documented for each incident during the audit
period. Greater than three failures but less than or equal to 5 would be considered "moderate;"
greater than 5 but less than or equal to 8 would be considered "high;" greater than 8 would be
considered "severe." Any failure to use the required elements of this Requirement R1 which results in
a reportable incident on the BES should be considered "severe." For Requirements R2 and R3, all
failures to use the required three-part communications should be documented by the Registered
Entity for the audit period. Greater than three failures but less than or equal to 5 would be considered
"moderate;" greater than 5 but less than or equal to 8 would be considered "high;" greater than 8
would be considered "severe." Any failure to use three-part communication which results in a
reportable incident on the BES should be considered "severe."
Regarding Measure 1, the "on-site observation" aspect should be expanded upon and clarified. This
concept would be very important to identify and document "failures" to properly follow Requirements
R1, R2, and R3, during the audit period. Registered Entities should be encouraged to use such
observations to coach employees and reinforce their following proper communications
protocols/procedures and complying with this standard.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
SCE&G supports the comments submitted by the SERC OC standards Review Group.
No
No
No
No
No
No
No
No
Group
PNGC Small Entity Comment Group
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The PNGC comment group believes there should be a distinction in the “Applicability” section of the
standard between “Scheduling Distribution Provider” and “Non-scheduling Distribution Provider”.
PNGC members are small rural cooperatives that are “Full service BPA customers.” This means that
BPA is our power supplier and scheduling agent and therefore handles all reliability directives,
scheduling, tagging, dispatching of resources and curtailments of load from breakers on BPA’s system
for PNGC members. According to a letter from the WECC Reliability Coordinator (VRCC and LRCC)
none of PNGC’s members will ever receive a “Reliability Directive”. Such a Directive would be sent to
either a Balancing Authority (BA), or a Transmission Operator (TOP). We estimate there are over 100
entities that are BPA Full Service customers that are in a similar position and making this standard
applicable to them does nothing to enhance reliability. A simple declarative statement in the
Applicability section of the standard could focus the intent of the SDT on those entities that need it
while lessening the compliance risk and clerical burden for other entities that the standard should not
apply to. We suggest: 4. Applicability: 4.1. Functional Entities 4.1.1 Reliability Coordinator 4.1.2
Transmission Operator 4.1.3 Balancing Authority 4.1.4 Generator Operator 4.1.5 Distribution
Provider: With Real-time Operations desk The PNGC comment group believes the above change will
lessen the compliance burden on small, non-scheduling entities while still meeting the SDT’s intent
with regard to Operating Personnel Communications. We also note that FERC and NERC, on multiple
occasions and in multiple filings, have indicated their openness to lessening unnecessary compliance
requirements for small entities.
Ron Sporseen
Group
LG&E and KU Services
No
LG&E and KU Services do not agree with the proposed definition of Operating Communication and
agree with eliminating the other three definitions. The standard appears to be focused on imposing
three part communications on the industry for routine communications despite the fact that neither
the blackout report nor the SAR on which these standards are based emphasize that issue. The blue
text box that mentions Reliability Directives seems to be a back door attempt to change COM-002 and
should be clarified or eliminated. Splitting communications requirements across different standards
creates unnecessary confusion
No
The SDT did not eliminate a communications procedure requirement. It turned the former
requirement into R1 and its sub-parts, forcing a single communication procedure on the industry. This
goes far too deeply into the “HOW” of communication as opposed to the “WHAT”.
No
LG&E and KU Services disagree. This concept more properly belongs in the NERC Rules of Procedure
and should be designed to address Recommendation 26 of the NERC 2003 Blackout Report. This is an
expectation of NERC and not of the industry. Also, see recent NERC Operating Reliability
Subcommittee (ORS) discussions and recommendations regarding the elimination of the Transmission
Alert Levels.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
Three part communications should not be required for routine operating communications. See the
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definition of Reliability Directive in COM-002, which addresses reliability issues. We suggest that R2
and R3 be eliminated, since neither one will increase reliability.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”. Requirement 1.1.4 does
not need to be in this standard as the requirement for unique line identifiers is stipulated in TOP-0022 R18.
No
LG&E and KU Services suggest deletion of all three requirements
Does the industry agree that we need a standard on three part communications for normal
operations? Has a lack of a standard on three part communications for normal operations created any
reliability issues? If so, what are they? LG&E and KU Services believes that the concerns expressed by
the Blackout Report and cited as the reason for creating this NERC Project are already addressed
through EOP and TOP Standards that specify what information is to be communicated, instead of how
information is to be communicated. “Lack of situational awareness” (2003 Blackout Report,
Recommendation 26) cannot be overcome by dictating “how” communication takes place, but instead,
can be overcome by responsible individuals (NERC certified operators) ensuring that proper
information is communicated. LG&E and KU Services believes that the concerns expressed by the
Blackout Report and FERC Order 693, Paragraph 532 are not (and need not be) addressed by this or
any other NERC RS Project. First, the recommendation for “tightened communication protocols” (FERC
Order 693, Paragraph 531) is within the context of “alerts and emergencies.” Second, FERC’s Order
693, Paragraph 532 calls for “communication uniformity as much as practical on a continent-wide
basis.” This is calling for uniformity in emergency communications, which was the context within
which FERC was speaking, as evidenced by the previous sentence (“during emergencies”). By
establishing emergency communication uniformity, “ambiguities in communications during normal,
alert and emergency conditions” will be eliminated. Nothing in the Commission’s Determination was
calling for establishing communication uniformity for all communications. LG&E and KU Services
suggest removing requirements R2 and R3. These requirements do not improve reliability, but instead
shift Operator focus from communicating proper information (“what”) to communicating in a
compliant manner (“how”). System Operator need to be wholly concerned with the information they
are communicating, not making sure they “say things the right way” so they will not be noncompliant. Every communication should not be a compliance event. While LG&E and KU Services
supports the addition of using the 24-hour clock format, subpart 1.1.4 is already addressed in TOP002-2b R18. Including such a similar requirement here simply provides entities with a double
jeopardy opportunity to be non-compliant. We suggest subpart 1.1.4 be removed, along with subpart
1.2, which again goes too far in dictating “how” and simply creates another compliance event. We
suggest subpart 1.1.3 be rewritten to explicitly allow for entities to agree upon using a particular
format for communicating time. With these suggestions in mind, it would be more appropriate to put
the remaining requirements into COM-001. We also suggest removing the definition for Operating
Communication since this also unnecessarily creates opportunities for non-compliance. LG&E and KU
Services have concerns about the white paper posted on the project page. Some assertions made in
the white paper are not defensible, and some are not technically sound. This should not be used as
support for the existing draft of COM-003.
Brent Ingebrigtson
Group
Pepco Holdings Inc & Affiliates
No
The distinction between Operating Communication definition and the Reliability Directive being a type
of Operating Communication is confusing.
Yes
Yes
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Yes
Yes
No
This modification for use of 3 part communications for Operating Communications is confusing and
should not be required for Normal conditions, non reliability communications.
Yes
However not sure if it is applicable to Reliability Directives.
Yes
COM-002 and COM-003 must be combined into one standard. COM-002 dealing with emergency,
reliability situations requires 3 part communication as specified. COM-003 dealing with normal
conditions, non reliability issues should not require 3 part communications.
David Thorne
Group
PNGC Small Entity Comment Group
Modified PNGC Small Entity Group Comments: The PNGC comment group believes there should be a
distinction in the “Applicability” section of the standard between “Scheduling Distribution Provider”
and “Non-scheduling Distribution Provider”. PNGC members are small rural cooperatives that are “Full
service BPA customers.” This means that BPA is our power supplier and scheduling agent and
therefore handles all reliability directives, scheduling, tagging, dispatching of resources and
curtailments of load from breakers on BPA’s system for PNGC members. According to a letter from the
WECC Reliability Coordinator (VRCC and LRCC) none of PNGC’s members will ever receive a
“Reliability Directive”. Such a Directive would be sent to either a Balancing Authority (BA), or a
Transmission Operator (TOP). We estimate there are over 100 entities that are BPA Full Service
customers that are in a similar position and making this standard applicable to them does nothing to
enhance reliability. A simple declarative statement in the Applicability section of the standard could
focus the intent of the SDT on those entities that need it while lessening the compliance risk and
clerical burden for other entities that the standard should not apply to. We suggest: 4. Applicability:
4.1. Functional Entities 4.1.1 Reliability Coordinator 4.1.2 Transmission Operator 4.1.3 Balancing
Authority 4.1.4 Generator Operator 4.1.5 Distribution Provider: With Real-time Operations and
Scheduling desk The PNGC comment group believes the above change will lessen the compliance
burden on small, non-scheduling entities while still meeting the SDT’s intent with regard to Operating
Personnel Communications. We also note that FERC and NERC, on multiple occasions and in multiple
filings, have indicated their openness to lessening unnecessary compliance requirements for small
entities.
Ron Sporseen
Individual
Howard Rulf
Wisconsin Electric dba We Energies
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Yes
Yes
No
This is too similar to but different than what is required for a directive. Since 99.9% or more
communications will not be directives, we will be conditioning operators to use this for directives also.
If I reissue an Operating communication because the other party does not respond soon enough for
me for whatever reason, the other party has violated R3 of this standard. R3 in general would not
apply to a DP except for loads connected at transmission voltages.
No
Use of “accurate” accurate alpha-numeric clarifiers is subjective. What are they? Who decides what is
“accurate”? An auditor? The NATO phonetic alphabet is really still being mandated. What if I use the
NATO version and another entity uses a different one. Can we talk to each other? We will now also
have to specify what phonetic alphabet we are using before any communication.
No
See the Mapping Document for Project 2007-03 Real-time Operations, TOP-002 R18: “This
requirement adds no reliability benefit. Entities have existing processes that handle this issue. There
has never been a documented case of the lack of uniform line identifiers contributing to a System
reliability issue. This is an administrative item, as seen in the measure, which simply requires a list of
line identifiers. The true reliability issue is not the name of a line but what is happening to it, pointing
out the difficulty in assigning compliance responsibility for such a requirement, as well as the near
impossibility of coming up with truly unique identifiers on a nation-wide basis. The bottom line is that
this situation is handled by the operators as part of their normal responsibilities, and no one is aware
of a switching error caused by confusion over line identifiers.”
We agree that accurate communication is necessary and we must strive to eliminate mistakes due to
miscommunications. In the White Paper, other industries are cited that use three-part
communication. Which of these industries also imposes sanctions and penalties on a company if an
operator says ”for” instead of “fow-er”? In order to verify compliance with this standard, there will be
entities that will need to listen to thousands of hours of voice recordings (8760 hours in a year, and
multiple operators). Listening to 10% of the voice recordings will be a full time job for one or more
persons. What is the reliability benefit of this cost? Unless it is tempered with some reasonableness,
this standard as written will be detrimental to reliability because it will slow down communications
considerably with innumerable repeats because of fear of violating the standard.
Individual
Eric Scott
City of Palo Alto
Palo Alto supports the comments submitted by PNGC Power regarding limiting the applicability of the
standard to a certain subset of Distribution Providers. Palo Alto is similiarly situated as PNGC.
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Group
MEAG Power, Danny Dees, Steven Grego, Steve Jackson
No
Operating communication is not necessarily three part communication. If three part communication is
being required, then it should be defined as three part communication.
Yes
It is best for NERC to evaluate risk and performance and prescribe methods.
No
The language, intent and purpose is not sufficiently defined. Needs better documentation and
explanation.
No
Too prescriptive. NERC should be addressing risk and performance.
No
Overly prescriptive. NERC should deal with risk and performance. This level of prescriptive standard
language is not appropriate.
No
Overly prescriptive. NERC should deal with risk and performance.
No
Too perscriptive. The industry has performed for many decades, successfully. NERC should focus on
risk and performance.
No
Too perscriptive.
No
VRFs and VSLs should be eliminated across the board.
Scott Miller
Group
ISO/RTO Standards Review Committee
No
The SRC agrees with the elimination of the three terms but not with the addition of “Operating
Communication”. The SRC does not believe that the proposed term (Operating Communication) is
sufficiently different from the originally proposed term (Interoperability Communication) to warrant
adoption. The SDT’s proposal continues to expand the scope of the SAR from the concept of
tightening the protocols associated with Emergencies or Adverse Reliability Impact to now applying to
all communications. The text box in the draft standard indicates that Reliability Directives are a type
of Operating Communications, to the extent they change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System. We see little difference between the two
terms despite the SDT’s assessment that Reliability Directives is a type (or a subset) of Operating
Communication. If the SDT intent is to use the proposed new term to require 3-part communication
(as suggested in R2 and R3), then that intent can be accomplished by using the term Reliability
Directives as it covers not only emergency state but also instructions needed to address Adverse
Reliability Impacts. Please also see our comments under Q6 regarding the use of the proposed term
to support the requirements for 3-part communication. The SRC would note that both the Blackout
Report and the FERC directive deal with tightening protocols for Emergencies, whereas the proposed
SDT requirements completely fail to address emergencies and focuses solely on developing nonemergency protocols. SRC Note: there is no mention in the Blackout Report of “operational
communications breakdowns re: changing states of equipment; most of the documentation points to:
(1) emergencies/alerts; and (2) notification OUTSIDE of the entity experiencing the problem. The SRC
requests that in the next posting the SDT provide real examples (without naming the registered
entities) where reliability was jeopardized by the failure of 3-part communications under routine
operational situations. Effectiveness of Communications “Under normal conditions, parties with
reliability responsibility need to communicate important and prioritized information to each other in a
timely way, TO HELP PRESERVE THE INTEGRITY OF THE GRID. THIS IS ESPECIALLY IMPORTANT IN
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EMERGENCIES. DURING EMERGENCIES, OPERATORS SHOULD BE RELIEVED OF DUTIES UNRELATED
TO PRESERVING THE GRID. A COMMON FACTOR IN SEVERAL OF THE EVENTS DESCRIBED ABOVE
WAS THAT INFORMATION ABOUT OUTAGES OCCURRING IN ONE SYSTEM WAS NOT PROVIDED TO
NEIGHBORING SYSTEMS.” (2003 Blackout Report, page 108) 26. “Tighten communications protocols,
ESPECIALLY FOR COMMUNICATIONS DURING ALERTS AND EMERGENCIES. UPGRADE
COMMUNICATION SYSTEM HARDWARE WHERE APPROPRIATE. NERC should work with reliability
coordinators and control area operators to improve the EFFECTIVENESS OF INTERNAL AND EXTERNAL
COMMUNICATIONS DURING ALERTS, EMERGENCIES, OR OTHER CRITICAL SITUATIONS, AND
ENSURE THAT ALL KEY PARTIES, INCLUDING STATE AND LOCAL OFFICIALS, RECEIVE TIMELY AND
ACCURATE INFORMATION.” (2003 Blackout Report, page 108) SRC note – Nowhere in the above
quoted Recommendation 26 is there a reference to person-to-person communications of required
actions; rather it references communication of the state of the operating system itself. SRC Note:
there is no mention in FERC Order 693 of “operational communications breakdowns re: changing
states of equipment; the Order does state: 532. “While we agree with EEI that EOP-001-0,
Requirement R4.1 requires communications protocols to be used during emergencies, we believe, and
the ERO agrees, that the communications protocols need to be tightened to ensure Reliable Operation
of the Bulk-Power System. We also believe an integral component in tightening the protocols is to
establish communication uniformity as much as practical on a continent-wide basis. This will eliminate
possible ambiguities in communications during normal, alert and emergency conditions. This is
important because the Bulk-Power System is so tightly interconnected that system impacts often
cross several operating entities’ areas.” SRC note – The above section concerns “ineffective
communications” not “incorrect communications”. The key to the above is “communication
uniformity” not 3 part communications. The SRC believes the both the FERC Order’s directives and
the Blackout Report Recommendation 26 are clear in their respective requests to address general
protocols; and that neither request suggests a need for mandating a specific procedure let alone 3
part communications for all operational communications.
No
The question is structured as an “either” “or” question about one requirement and does not include a
“neither” option relating to the other requirements. The SDT has replaced one procedure with another
set of procedures. Neither is an appropriate requirement. The SRC believes that this and other
detailed procedural requirements on personnel are not valid applications for NERC reliability
standards. The SRC believes that standards must mandate outcomes and that standards such as this
one on 3 part communication procedures are better left to the registered entities. If the Industry were
to support the SDT’s proposed requirement, the SRC would urge the SDT to turn away from the “zero
defect” standard that it is proposing and to replace it with a requirement that allows for reasonable
number of deviations. The proposed requirement will be prohibitively expensive to implement with
little improvement in reliability (also see “whitepaper” included in response to Question 10). The
requirement will require all communications channels to not just be recorded (which is done today)
but will require each recording to be reviewed by a compliance person for self-reporting purposes.
The proposed requirement would actually reduce reliability by taking the above required compliance
personnel away from reliability related standards and placing them on these procedural requirements
; and (2) distracting operators from their core responsibility of reliability due to concerns with
meeting compliance obligations. A more acceptable alternative approach would be to introduce
communications protocols as a mandatory non-standard (e.g. as a requirement for certification) that
would center on a corporate communications manual that encourages three-part communications;
and that includes how monitoring would be audited internally. Such an alternative would change the
requirement from monitoring personnel mistakes to a requirement for monitoring corporate culture.
Moreover, the use of a non-standard alternative would encourage the creation of innovative Best
Practices; as opposed to a mandatory fixed procedure which would limit innovation.
No
FERC has made it clear that it would be amenable to eliminating requirements that are not reliability
problems. A requirement regarding language comes under that category. There are no reports
indicating that language is causing reliability problems. The SRC does not believe this issue rises to
the level of a mandatory standard. The SRC would ask if the SDT has any evidence that language is a
problem causing reliability impacts. In the absence of such evidence that it is a reliability problem, the
SDT should eliminate this requirement.
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No
This requirement is outside the scope of the approved SAR which proposes responding to the Blackout
Recommendation to tighten communications protocols especially during emergencies. This proposed
requirement is both procedural and does not address tightening communications of situational
awareness. The SRC would suggest that as an alternative a standard could require the Functional
Entities to have a communications protocol that could indeed include this suggestion, but it should not
be a standard on personnel. By adopting an alternative category (i.e. not making this a standard) a
Reliability Entity could adopt a progressive best practice approach without concern for violating the
strictest features of the “proposed” best practice.
No
The SRC agrees that if there is a requirement for 3 part communications as proposed, then the
proposed exception is needed to avoid double jeopardy, and the differentiation between issuer and
receiver is needed. The SRC however does not agree with the need for the requirement itself. By
introducing the proposed exception (i.e. of Reliability Directives used during emergencies) the SDT
has invalidated the very reason that its SAR was proposed (i.e. to improve protocols DURING
emergencies). The SRC disagrees with using the term Operating Communications because the term is
not significantly different from the term Reliability Directives (see our comments under Q1). Using the
term Reliability Directives to support the requirements for 3-part communication can avoid (a) any
confusion with the requirement in COM-002-3, (b) potential double jeopardy of violating both COM002 and COM-003, and (c) the need to exercise 3-part communication for routine operating
instructions. If the SDT’s intent is to require 3-part communication for any and all operating
instructions (as the proposed term suggests), then this intent will result in unnecessary 3-part
communication burdens for simple actions such as requesting the removal of a line, or switching, or
raising generation, or even to “maintain” its current state. We suggest the SDT remove the term
Operating Communications. With respect to Requirements R2 and R3, we question the need for
having these requirements if Reliability Directives already cover non-emergency conditions
(instructions/actions that are needed to address potential Adverse Reliability Impact). The
requirement to exercise 3-part communication to handle Reliability Directives is thus duly addressed
in COM-002-3. Other than emergency conditions and potential Adverse Reliability Impact conditions,
we do not see, nor has the SDT proven a need to exercise 3-part communication for routine operating
instructions.
No
This requirement is a procedural issue and is outside the scope of the approved SAR which proposes
responding to the Blackout Recommendation to tighten communications protocols especially during
emergencies. This proposed requirement is both procedural and does not address tightening
communications of situational awareness. The SRC would suggest that the standard should require
the Functional Entities to have a communications protocol that could indeed include this suggestion,
but it should not be a standard on personnel.
No
This requirement is a procedural issue and is outside the scope of the approved SAR which proposes
responding to the Blackout Recommendation to tighten communications protocols especially during
emergencies. This proposed requirement is both procedural and does not address tightening
communications of situational awareness.
The SDT’s proposals do not conform to the Standards Process because those proposals do not reflect
the public comments that were submitted. The Process requires the SDT to use the Industry’s
comments to drive the requirements and as such the requirements should not be mandating three
part communications procedures for all “changes in status” much less the maintaining of such status.
Such a request was not made by any of the commenters let alone a majority of the commenters. It
would be more appropriate if the SDT asked who favored the approach being used, as opposed to
asking if an “adjustment” to the requirement were acceptable. Many of the adjustments are better
than if they were not there, but that ignores the fact that the requirement itself is not supported by
the majority of commenters. The SDT’s proposals expand the scope of the SAR by totally ignoring
communications protocols used during emergencies and simply focusing on procedures imposed on
personnel during normal situations. This standard over-reaches into routine operations by requiring 3part communication for all instructions that change or maintain the state, status, output, or input of
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an Element or Facility of the Bulk Electric System. This type of instructions occurs every hour, if not
minute. Requiring operating personnel to apply a 3-part communication procedure for these
instructions is absolutely unnecessary and overburdening, and can in fact adversely affect reliability.
We strongly suggest that any requirement for 3-part communication for routine operating instructions
be removed. **** FERC Order 693 510. “The Commission proposed… (4) requires tightened
communications protocols, especially for communications during alerts and emergencies. “ SRC Note
– The above language while allowing for a requirement to go beyond emergencies, it states that the
primary intent is “during alerts and emergencies”. The SDT has no requirement for “alerts and
emergencies” and focuses solely on normal operations. 532. While we agree with EEI that EOP-001-0,
Requirement R4.1 requires communications protocols to be used during emergencies, we believe, and
the ERO agrees, that the communications protocols need to be tightened to ensure Reliable Operation
of the Bulk-Power System. We also believe an integral component in tightening the protocols is to
establish communication uniformity as much as practical on a continent-wide basis. This will eliminate
possible ambiguities in communications during normal, alert and emergency conditions. This is
important because the Bulk-Power System is so tightly interconnected that system impacts often
cross several operating entities’ areas. 230 EOP-001-0, Requirement R4 provides, in relevant part,
that: “[e]ach Transmission Operator and Balancing Authority shall have emergency plans that will
enable it to mitigate operating emergencies. At a minimum, Transmission Operator and Balancing
Authority emergency plan shall include [c]ommunication protocols to be used during emergencies.”
SRC Note – the communications ambiguities noted above do not refer to issues with interpersonal
communications but rather refer to situational ambiguities. 540. “While the Commission identified
concerns regarding COM-002-2, the proposed Reliability Standard serves an important purpose by
requiring users, owners and operators to implement the necessary communications and coordination
among ENTITIES. SRC Note – the above does not say “among OPERATING PERSONNEL” it says
“among ENTITIES”. 540. (continued) ALTERNATIVELY, with respect to this final issue, the ERO may
develop a new Reliability Standard that responds to Blackout Report Recommendation No. 26 in the
manner described above. “ SRC note – The above is a key directive. It states tightened
communications protocols [it does not say three part communications for normal actions]’ Also note
that the Blackout report recommendation is “an alternative” solution and not necessarily a part of the
FERC proposed solution. The SDT is also asked to identify the role of the posted White Paper. Is the
White paper to be retained as part of the support documentation? If so, then the paper must be
vetted by the Industry. The SDT did not afford the opportunity to respond to the paper. There was no
indication if the paper was a unanimous SDT position or if there were any minority opinions. The SRC
would offer the following “whitepaper” to help in deciding whether or not a requirement for 3 part
communications for all operational communications rises to the level of requiring a mandatory
standard. The “whitepaper” frames the communications issues generically providing an alternative to
a zero defects standard. ******** The strides NERC is making in the areas of Events Analysis and
Human Factors will likely lead to useful practices and value-added standards. A fact-based approach
to standards will lead to improved reliability. This paper attempts to quantify the problem that COM003 is trying to address. While human error is often the first theory to explain major accidents, the
follow-on investigation typically finds many factors beyond the front-line operator’s control. There is
an axiom in the field of quality control that attributes 80% of manufacturing defects are controllable
by management rather than the cause of the front-line workers . Many people make errors that
contribute to outages. Manufacturers have equipment defects, planners make incorrect design
decisions, technicians draw maps incorrectly, managers cut budgets (plant maintenance, vegetation
management), etc. A study of errors at nuclear power plants sheds light on the causes behind the
scenes. Although 92% of all root causes were man-made, only a small number of these were initiated
by front-line operators. Most originated in either maintenance-related activities or in bad decisions
within the organization. In another study, a review of summaries of three major industrial events
(Three Mile Island, Bhopal, and Chernobyl) identified operators as committing less than 10% of the
missteps that led to the disasters. Table 1 Contributors to Major Accidents To be conservative, this
paper assumes that 30% of all major human errors that impact the BPS are attributed to front-line
workers (dispatchers, field operators, technicians and maintenance personnel). With regard to which
front-line workers commit errors, a study of electrical system incidents at nuclear plants were
generally evenly distributed between operators, maintenance personnel and technicians. As to
communications problems causing trouble, an EPRI study reviewed nearly 400 switching mishaps by
electric utilities and found that roughly 19% of errors (generally classified as loss of load, breach of
safety, or equipment damage) were due to communication failures. This was nearly identical to
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another study of dispatchers from 18 utilities representing nearly 2000 years of operating experience
that found that 18% of the operators’ errors were due to communication problems. Figure 1 EPRI
Study Results on Operating Errors Bringing the pieces of this discussion together, the following
assumptions are used to estimate the percent of human errors on the BPS caused by operator
communication breakdowns: • 30% of human failures impacting the BPS are due to front line
workers. • Front line errors were generally evenly split into 3 groups o Dispatchers o Field Personnel o
Maintenance and Relaying Technicians • 18% of dispatcher errors are due to communication
problems. The net result is that using estimates of existing research shows that dispatcher
communications represent roughly 2% of the human failure on the BPS. Figure 2 Summary Human
Failure Estimate While it has been stated that communication problems are found during the review of
all system events, this is similar to saying that gravity is involved in all trips and falls. The statements
are true, but the solutions to the problems are multidimensional. During a system event, there are
hundreds, if not thousands of communications among different operators, often on situations never
seen by the participants. Many of the communications are troubleshooting and information sharing
that requires give and take and must be done quickly. If every communication during a disturbance
needed to be 3-way, system restoration times for those disturbances would increase. NERC has built
a solid foundation to make informed decisions in the future. The Events Analysis process, GADS and
TADS should yield data on the impacts and contributors to BPS failures. NERC’s Human Factors efforts
can be used to develop good practices for all front line personnel. NERC should build on the research
similar to that outlined in this paper via industry-wide surveys of operators to collect additional data,
lessons-learned and tips for improvement. ***************** A quick estimate of the workload
associated with COM-003, for the number of registered entities under the standard’s applicability list.
If we assume 1 call each 10 minutes for a BA, TOP and RC and ¼ this amount for GOP and DP, you
get the totals below. Each of these are an auditable and sanctionable event. The review and self
report on all of these is incompatible with the reliability impacts realized? BA TOP RC GOP DP Total
132 181 22 795 551 # of Entities 19008 26064 3168 28620 19836 96,696 Calls per Day 35,294,040
Calls per year ***************** Lastly, the SRC requests that in the next posting that the SDT
include the question: Does the Industry: • Support continued development of a standard on personnel
discussions during non-emergency conditions? • Support withdrawal of the standard? • Support the
creation of an alternative non-standard (e.g. certification) that addresses the corporate protocols on
communications?
Albert DiCaprio
Group
City Water Light and Power
No
Definition is overly broad and should at least be tailored to indicate the operating time frame is the
relevant concern.
Yes
No
This requirement should certainly not be a part of this standard, but should be eliminated entirely. It
specifices a process, not a result - the requirement should be based on resultant functionality, not the
process by which the entitiy achieves it.
Yes
No
Entities who have an agreed upon protocol which includes the time zone to be used for system
operations should not be required to repeat the time zone for every communication. For instance, if
Entity A and Entity B are in different time zones but both have an operating policy that states all
communication between the two is in Eastern Standard Time and all operating personnel are trained
on this policy, this should be sufficient. This achieves the same functional goal. The requirement to
restate the time zone in this case only serves to set up a situation where a simple single-instance
omission would have no effect on reliability but still be noncompliant.
No
Three part communications should not be required for routine operating communications. See the
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definition of Reliability Directive in COM-002, which addresses reliability issues.
No
Again, this requirement attempts to dictate process as opposed to being a standard. The standard
should only dictate the result, not how it is achieved.
No
This is already addressed in TOP-002 R18. Even if moved, the requirement should be focused on
agreed upon identifiers and the process for coordination shoudl be left to the entities.
No
These requirements should be eliminated entirely
CWLP generally echoes the SERC Operating Committee comments. Additional comments have been
provided to suggest better functionality if the standard moves forward in its current form.
Shaun Anders
Individual
Joe Petaski
Manitoba Hydro
No
Manitoba Hydro disagrees with the term “Operating Communication” as we do not feel there should
be a distinction between Reliability Directive and “Operating Communications”. We suggest that the
term “Operating Communication” be replaced with the term Reliability Directive as any instruction to
change the status or function of the BES must be clear and concise and confirmed with three way
communication to ensure system reliability and personnel safety.
Yes
Yes
Yes
No
Manitoba Hydro agrees with R1.1.2 but disagrees with R1.1.3. R1.1.3 is unnecessary and should be
modified to “1.1.3 - When communication is between entities in different time zones, clarify the
difference in time to ensure mutual understanding”. Making R1.1.3 more generic gives operators the
opportunity to determine the best method for them to ensure mutual understanding and clarify the
time difference.
Yes
Manitoba Hydro agrees with splitting the single requirement into (R2) issuer and (R3) receiver, but as
stated in our response to Question 1, we do not agree with the term “Operating Communications”.
No
Manitoba Hydro agrees with the use ‘accurate alpha-numeric identifiers’ and feels that they should
also be required when referring to a Transmission interface Element or a Transmission interface
Facility in R1.1.4
Yes
See question 7 comments
Yes
Manitoba Hydro is voting negative on COM-003-1 based on our comments in the previous questions in
addition to the following: (M1/M2/M3)– it is unclear what specifically is meant by ‘on site
observations’ or how ‘on site observations’ can be an effective measure of compliance with the
standard’s requirements.
Individual
John Seelke
Public Service Enterprise Group
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See #10.
See #10.
Yes
See #10.
See #10.
See #10.
See #10.
See #10.
See #10.
This standard (COM-003-1) should be combined with COM-002-3 and issued as one standard to
require ONE 3-part communications protocol for both Reliability Directives and non-Reliability
Directives. Both require 3-part communications; however, COM-003-1 sets ADDITIONAL
communications protocols and introduces a new definition (Operating Communication) that is not
contained in COM-002-3. In addition, the text box on page 2 appears to redefine “Reliability Directive”
inappropriately. While the sentence confusion is the text box may be unintended, its needs to be
clarified.
Individual
John T. Walker
Portland General Electric - Transmission & Reliability Services
Yes
Yes
Yes
Yes
No
Requirement 1.2 requiring the use of alpha-numeric clarifiers would unnecessarily complicate operator
communications, especially inter-company communications where transmission facilities have
historically and are commonly identified by alpha-numeric characters. The use of three-way
communications ensures accurate communications without the complications of alpha-numeric
clarifiers.
Group
Hydro One Networks Inc.
No
The proposed Operating Communication term is not sufficiently different from the originally proposed
term (Interoperability Communication). The proposal continues to expand the scope of the SAR from
the concept of tightening the protocols associated with Emergencies to now applying to all
communications. The text box in the draft standard indicates that Reliability Directives are a type of
Operating Communications, to the extent they change or maintain the state, status, output, or input
of an Element or Facility of the Bulk Electric System. There is little difference between the two terms
despite the SDT’s assessment that Reliability Directive is a type (or a subset) of Operating
Communication. If the intent is to use the proposed new term to require 3-part communication (as
suggested in R2 and R3), then that intent can be accomplished by using the term Reliability Directive
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as it covers not only the emergency state but also instructions needed to address Adverse Reliability
Impacts. Both the Blackout Report and the FERC directive deal with tightening protocols for
Emergencies. The proposed requirements completely fail to address emergencies and focus solely on
developing non-emergency protocols.
Yes
No
In the past there was a lot of confusion regarding the use and applicability of three-part
communication. We believe that all communication protocol related requirements and information
should be contained within one standard. This should include Alert Levels and their definitions.
No
We believe that this requirement should be eliminated. As a general rule, standards’ requirements
that do not address reliability problems should be eliminated. No available information indicates that
language is causing reliability problems and there. In addition to this, there are some jurisdictions
where this requirement might cause decrease in reliability (i.e. Quebec)
Yes
No
The term Operating Communications is not significantly different from the term Reliability Directives.
Using the term Reliability Directives to support the requirements for 3-part communication can avoid
(a) any confusion with the requirement in COM-002-3, (b) potential double jeopardy of violating both
COM-002 and COM-003, and (c) the need to exercise 3-part communication for routine operating
instructions. Realistically, the definition of Operating Communications covers all communications. We
believe that only Reliability Directives should require 3-part communications, and should be
enforceable if a miscommunication results in an error on the BES.
No
This requirement adds added complexity to communications, not improvement. There are equipment
designations that are commonly used and understood, and to force the use of clarifiers will disrupt
operating communications.
Yes
No
The white paper discusses many non-utility industries use of the three-part communication. However,
they are not out of compliance if they fail to use three-point communications. Only the Reliability
Directives should require three-part communications (and dictate compliance). This should be
enforceable only if the miscommunication results in an error on the BES. We support the use of threepart communications. There is concern over the potential for being out of compliance when there is
no BES impact. Failure to meet Requirement R2, part 2.2 bullets 1 or 3 is either a Moderate or High.
Failure to meet bullet 2 is a Severe VSL. It is not clear why this differentiation was adopted. The
White Paper reflects on Human Performance, and how miscommunications can cause a BES error
resulting in an outage, or possible cascading effects. Then the Standard (and the associated out of
compliance) should apply when, and to the extent that communications lapse (e.g., when there is an
impactful violation of bullets 1, 2 and/or 3) results in an impactful error on the BES. Otherwise, an out
of compliance is inappropriate. Non-impactful violations should be rated “Lower VSL.”
- Hydro One strongly believes that three-part communication should be limited to Reliability
Directives only. It application to virtually all communications will prove to be an additional burden for
operators, burden that is not justified and would not increase the reliability of the BES. - While we
don’t agree with inclusion of the three part communication for Operating Communication (as stated
above), we believe that the communication protocol related requirements from both existing COM
standards should be merged into COM-003 to improve clarity. In the current draft, COM-003 does this
only partially by including COM-001 R4.In addition to already mentioned Alert Levels and their
definitions (already mentioned in our reply to Q3), we believe that COM-002 R2 should be moved into
this standard as well for clarity purposes.
Sasa Maljukan
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Individual
Denise Lietz
Puget Sound Energy
Yes
Yes
Yes
Yes
Yes
Yes
No
No. The current language addressing alpha-numeric clarifiers is a significant improvement over the
formulation addressing the same issue in the previous draft. However, this requirement remains
overly-prescriptive, especially with respect to numeric clarifiers. Even with the NATO clarifiers, not all
numbers have clarifiers. As a result, it not clear when a numeric clarifier would be required and when
it is acceptable not to use such a clarifier. The requirement to use alpha-numeric clarifiers should be
removed from the proposed standard entirely. If the requirement is not removed in its entirety, the
requirement should be modified to exclude numeric clarification.
Yes
Group
SPP Standards Review Group
No
The definition is fine but it may not be necessary based on the comments provided to the remaining
questions below. It’s not so much what’s contained in the definition, it’s more about what the
standard requires the industry to do with that definition. We believe eliminating the other three
definitions was a positive move by the SDT.
Yes
Eliminating the requirement to have the procedure (documentation) was a move in the right direction.
We are glad it was eliminated because that’s one less piece of paper we have to keep track of.
Yes
We agree with the Alert Levels being removed from COM-003-1 and question the need to move them
somewhere else. During its May, 2012 meeting, the Operating Reliability Subcommittee (ORS)
approved a motion to ‘…terminate the pilot program using Alert Levels and to discontinue any efforts
to include the guidelines in reliability standards projects.’ This was based on the inability of the ORS
to demonstrate any reliability improvements during the six years that the Alert Level pilot program
had been in existence. That being the case, there is no need to create a SAR and transfer this to
another SDT.
Yes
While we concur with the inclusion of the exemption, we question how the industry can ensure
effective communications in a situation where the exemption comes into play.
No
Requiring time zone notifications at times other than those around the time of the transition from
standard to daylight savings and back again is excessive. For a brief period of time around this
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transition, ensuring the correct times are communicated would probably require including standard or
daylight savings designations. Some consideration for this issue needs to be incorporated into the
requirement. That said, trying to be overly prescriptive with the requirement creates an unnecessary
burden on operating personnel without significantly improving BES reliability. A one-size fits all
requirement may not be appropriate. Entities whose geographical area is located in multiple time
zones probably have internal procedures detailing how they handle time differences within their area.
Most often this entails selecting one time zone as the entity’s reference. As written, the requirement
overrides any internal procedures which may unnecessarily complicate internal communications.
Allowances should be made for internal procedures which cover this situation. Requirement 1.1.3
requires that time and time zone, including standard or daylight savings time designations, must be
communicated at all times. Yet Requirement 1.1.2 includes a provision that requires use to the 24hour clock only when clock times are referenced. This needs to be included in Requirement 1.1.3 as
shown below: When the communication is between entities in different time zones and refers to clock
times, include the time and time zone and indicate whether the time is daylight saving time or
standard time.
No
The format of the requirement is an improvement. However, we have concerns about the standard
being overly prescriptive. All actions ‘…to change or maintain the state, status, output or input of an
Element or Facility…’ of the BES do not have a significant impact on the reliability of the BES. The
draft standard mandates that they do. Applying 3-part communications to all Operating
Communications places an overly burdensome task on the industry in monitoring and tracking
compliance. Additionally, a zero-tolerance interpretation of this requirement places an unjustified risk
on the industry without making an appreciable improvement in BES reliability.
Yes
We concur with the elimination of the NATO phonetic alphabet and thank the SDT for making this
change. This is an excellent example of backing away from being overly prescriptive by requiring the
NATO alphabet and allowing the industry to use any of several other options to ensure effective
communications. We do have concerns with the use of ‘correct’ or ‘accurate’, depending on which
document you refer to. What is correct? What is accurate? How does one measure compliance with
these terms? We would propose to delete the word ‘accurate’ altogether. The requirement would then
read: When participating in oral Operating Communications and using alpha-numeric identifiers, use
alpha-numeric clarifiers.1
Yes
While the industry probably understands what is meant by ‘Transmission interface Element or
Facility’, the terms are somewhat cumbersome. Additionally, for situations where there may be an
agreement between owners designating multiple names for an Element or Facility, we propose adding
an ‘(s)’ to ‘name’. For example, if one owner calls a line A-B and the other owner calls the line B-A
and they agree to use both names interchangeably, then either would be correct. Requirement 1.1.4
would then read: When referring to an Element or Facility that is part of an interconnection between
entities, use the name(s) specified by the owner(s) for that Element or Facility.
No
With the additional burden of monitoring and tracking compliance and the increased risk of the zerotolerance VSLs without a subsequent improvement in reliability of the BES, the VRFs should be
changed to Low. The VSLs should be reduced to Lower. We suggest modifying the second part of the
existing Moderate VSL for Requirement 1 to include specific reference to Requirement 1 as is done in
the first part of that VSL. The VSL would then read: The responsible entity did not correctly
implement Requirement R1, Part 1.2. Likewise, we also suggest modifying the second part of the
existing High VSL for Requirement 1 to include specific reference to Requirement 1. The VSL would
then read: The responsible entity did not correctly implement one (1) of the four (4) parts of
Requirement R1 when it was appropriate to use three of the four parts.
We believe the standard is too prescriptive as written. The purpose of the standard is to ensure
effective communications. The standard has given us a very specific listing of items that must be done
in a specific manner in order to accomplish this goal. What the industry needs is flexibility in how it
achieves the goal of effective communications. The standard does not recognize that flexibility. The
Measures for Requirements 1, 2 and 3 do not contain specific references to the requirements they are
associated with. There is a parenthetical following the measure that does include that reference but
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including the reference specifically in the measure is a stronger statement and eliminates any
possibility for confusion. The section of M1 to be modified would then read: ‘…that the communication
protocols specified by Requirement 1 were implemented…’ The section of M2 to be modified would
then read: ‘…that the communication protocol specified by Requirement 2 was implemented.’ The
section of M3 to be modified would then read: ‘…that the communication protocol specified by
Requirement 3 was implemented.’
Robert Rhodes
Group
Avista
No
Yes
This standard as drafted is very prescriptive and will not ensure improved reliability. A better
approach would be to require applicable entities to; develop and implement an internal
communication plan that takes into consideration recommendations discussed in the proposed NERC
OC System Operator Verbal Communications Guideline, implement internal controls and monitoring to
ensure adherence to the communication plan, and implement an adequate communication training
program.
Scott Kinney
Individual
Brenda Truhe
PPL Electric Utilities
No
Suggest the definition be clarified to scope to ‘real-time’ operating instructions to eliminate discussion
of future outages.
Yes
Yes
Yes
No
Since Reliability Directives are a subset of Operating Communications, if this was done to lower the
VRF for Operating Communications that are not Reliability Directives, this modification makes sense.
However, having two stds/rqmts address 3-part communication (even if not in same words) is not as
clear as it could be. One standard requiring 3-part comm for Real-time operating communications
which includes Reliability Directives would be more straight-forward, with a higher VRF for Reliability
Directives.
Yes
No
This requirement seems duplicative of TOP-002-2 R18.
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Regarding R1.1.3: I request the SDT consider allowing for the Applicable Functional Entity to develop
an Operating Procedure such that if all parties in the communication are in the same time zone that
the time zone does NOT need to be used in the Operating Instruction. Regarding the VSL/VRF: I
request the SDT consider adjusting the std or VSLs to allow for compliance with a 95% confidence.
Such that 1 incomplete 3-part Operating Communication could be considered low or not a PV. If
sampling of voice recordings provides a 95% confidence, this should be sufficient. E.g. If one sample
of 30 voice recordings results in 1 incomplete 3 part and a second sample of 30 finds no issues, the
audit result should be no PV. This is a standard sampling techniques. We thank the SDT for their
efforts. PPL EU supports the value added by using 3-part communications and a phonetic alphabet as
both are included in our current communications operating instructions. Even with the many Human
Performance tools we use, our concern with the standard is being found non-compliant if one of
hundreds/thousands of operating communications in a year is not perfect 3-part comm.
Individual
Bob Thomas
Illinois Municipal Electric Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Group
Arizona Public Service Company
Yes
Yes
Intentionally left blank
Yes
Yes
Yes
Yes
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Yes
Yes
Equipment identifiers at individual locations (generating stations as an example) have the same alpha
preceding the unique device numeric. It is unnecessary, redundant and confusing to the operator to
repeat the station location with an alpha clarifier.
Janet Smith, Regulatory Affairs Supervisor
Individual
Alice Ireland
Xcel Energy
No
We do not agree that this definition should include “or maintain”, and recommend that be struck. The
scope should only include instructions that would require an action by the recipient.
Yes
Yes
Yes
No
Is there any evidence of an actual event where there was confusion in the time zone, which led or
contributed to an event? We are not aware of any. If the drafting team has no basis for mandating
the use of a time zone and daylight/standard time reference, then we suggest this requirement be
struck because we do not believe it would increase reliability. In fact, we think it may have the
opposite effect of reducing reliability. If the SDT decides to retain the sub-requirement, please clarify
which entity’s time zone should be used. As written, this sub-requirement may create confusion for
field personnel if they are to repeat the order back in their own time zone. We are concerned this will
actually increase the likelihood of human error, and therefore potentially reduce reliability. As a
company that has field personnel in different time zones, company procedures dictate that CPT be
used as that is the time zone the control center is in. Adding additional oral verification for time zones
will promote human error.
Yes
No
1) “Accurate alpha-numeric identifier” needs to be clarified. Could each entity (or even each operator)
create their own alpha-numeric identifiers? Further would it be a violation if an operator used
“Charlie” in one conversation and “chalk” in another? Or, is it an expectation that the entity/operator
adopts an existing list of alpha-numeric identifiers, which is published publicly? 2) We recommend
that device names be excluded from the requirement to use alpha-numeric identifiers when both
parties are working off of written instructions. We do not feel requiring this would improve reliability.
Instead, it could actually slow down the recovery of the system. For example, we have devices in the
field that may be labeled 12B34-W gang switches and it makes no senses to say, “Open and tag the
one, two, B as in Bravo, three, four W as in Whiskey gang switch, when both parties have “12B34-W”
written in the instructions they are both working from. Three-way communications are occurring and
if there is any question as to the device name, it can be caught and clarified during that process.
Yes
No
The Moderate VSL for missing one part of the sub-requirements in R1.1.1 thru R1.1.4 is too harsh
with a six month effective date. We suggest a phased in VSL or a twelve month effective date, as
further explained under question 10.
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(1) Requirement R1.1 refers to both written and oral Operating Communications. It was our
understanding that COM-003-1 was to be focused solely on oral communications. If that was the
SDT’s intent, then we suggest striking the word “written” from this sub-requirement. (2) Six month
Effective Date is not likely to be enough time to develop, implement, and test a new communication
program. We need enough time to train the field personnel, plant control room operators and system
operators to use alpha-numeric identifiers, 24-hr clock, time zone, etc. before the standard becomes
effective. A twelve month implementation period would be more appropriate.
Individual
John D. Martinsen
Public Utility District No. 1 of Snohomish County
No
Yes
Yes
No
SNPD takes issue with the specification of “English” only communications and the Alpha-Numeric
identifiers. There is no precedence established for the use of English, Alpha-Numeric or the use of a
24-hour clock format that warrant a sever VSL and the associated penalties that could be imposed by
the Compliance Enforcement Agency
No
SNPD takes issue with the specification of “English” only communications and the Alpha-Numeric
identifiers. There is no precedence established for the use of English, Alpha-Numeric or the use of a
24-hour clock format that warrant a sever VSL and the associated penalties that could be imposed by
the Compliance Enforcement Agency
Individual
Kirit Shah
Ameren
No
We recommend that the SDT eliminate the words “…or maintain…” in the definition. We believe that
inclusion of these words would drastically reduce side conversations that continuously occur between
different entities. These side conversations provide additional information and perspectives to realtime operators that ensure they understand the real-time status of the BES. In other words, due to
fear of possible non-compliance consequences for failure to properly converse in a three-part protocol
at all times, entities will drastically curtail side discussions and deprive all BES operators of this
pertinent and useful real-time information.
Yes
No
We recommend the Alert Levels be used by the SDT to define a workable time period when three-part
communications is mandatory.
Yes
Yes
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No
From our perspective, use of such a split for all Operating Communications (not directives) would add
to the confusion.
No
We recommend to the SDT that one industry-wide alpha-numeric clarifying system should be used.
Multiple systems may add confusion by use of clarifying words that some Operators may not be
familiar with. We agree with use of the NATO Spelling Alphabet.
No
We suggest the SDT to provide clarification and guidance on precisely what Elements and Facilities
are included in these terms. Since the word “interface” is not capitalized or defined in the NERC
Glossary or this Standard, it will be difficult for TO, TOP, GO, GOP and DP entities to precisely identify
the equipment associated with these terms. We also recommend that the SDT consider use of the
term “Interconnected Facilities” as defined by Project 2007-06 System Protection Coordination for use
in the new Standard PRC-027-1. Multiple definitions in multiple Standards for the same BES Elements
and Facilities create unnecessary risk and uncertainty for both Auditors and Functional Entities.
No
We believe that the VSLs in this draft Standard create the potential for a violation or self-report for
almost every single individual conversation about the BES by real-time operators. In this regard, we
are concerned that the Functional Entities will greatly decrease their oral communications to minimize
the risk of a self-report or violation which ultimately would undermine necessary discussions between
operating entities.
We believe that multiple communication standards (COM-002, COM-003) are not necessary and
suggest that SDT work with the NERC Operating Committee members to appropriately address what
requirements are necessary from operating/reliability perspective as well as any related FERC
directives.
Individual
Greg Travis
Idaho Power Company
Yes
Yes
Yes
Threat Alert Levels does not seem to fit this Standard.
Yes
Yes
No
I'm not sure I understand the separation of Directives and these Operating Instructions. They seem
very similar and could be incorporated into the same standard. The split between Issuer and Receiver
seems to add some clarity.
No
They should specify the alphabet to use for consistency.
Yes
Yes
At least I don't have a good reason not to agree.
I believe the requirements for Directive should be included in this standard and removed from COM002.
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
Yes
Yes
No
The prescriptive requirements currently in R2, and R3, tell how, not what, an entity is obligated to do.
To address the fact that most Operating entities engage in “Operating Communications”, one
requirement(combining R2 and R3) is all that is needed, and ATC recommends that Requirement 2 be
restated as follows: R2 Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider that issues, or receives an Operating Communication,
excluding Reliability Directives, shall use Three-part Communications. Furthermore, ATC recommends
that the SDT reconsider adding the “three-part communication” as a defined term properly vetted
through the appropriate process, and added to the NERC Glossary of Terms. The definition as
previously noted in Draft #1 is below. Three-part Communication — A Communications Protocol
where information is verbally stated by a party initiating a communication, the information is
repeated back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be correct by the
party who initiated the communication.
Yes
No
Entities will face double jeopardy with existing Reliability Standard TOP-002-2b R18. Requirement 18
of TOP-002-2b is proposed to be removed from NERC Standards by the respective SDT because it
adds no reliability benefit.
No
System Operators receive and issue many Operating Communications each day. The VSL for “one”
Operating Communication is Moderate, which is considered too high. While improving communications
is a laudable goal, the zero tolerance VSL is unacceptable and will lead to a preponderance of selfreports and compliance and administrative overhead. Also overlooked is the added stress that every
time a System Operator speaks, they may be in violation.
When a situation necessitating alpha-numeric clarifiers in an Operational Communication arises, per
the standard requirement, it becomes mandatory. There are many instances when marginally defined
elements such as a carrier grounding switch, may need to be operated or changed state. If these
devices can’t be clearly defined as an element or facility, yet have alpha-numeric identifiers, the use
of clarifiers should be discretionary. FERC Orders and recommendations point to “Tightening
communications protocols, especially for communications during alerts and emergencies.” The NERC
standards addressing this issue are not approved yet. When they are approved by FERC,
subsequently implemented, and allowed to mature, the concept of tighter protocols for normal
operations may be developed.
Individual
Marie Knox
MISO
No
We do not agree with the proposed definition of Operating communication and agree with the
elimination of the other three definitions. The SDT does not appear to respond positively to the
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majority of industry comments submitted along with ballots. It also appears to be focused on
imposing three part communications on the industry for routine communications despite the fact that
neither the blackout report nor the SAR on which these standards are based emphasize that issue.
The blue text box that mentions Reliability Directives seems to be a back door attempt to change
COM-002 and should be clarified or eliminated. Splitting communications requirements across
different standards creates unnecessary confusion.
No
The SDT did not eliminate a communications procedure requirement! It turned the former
requirement into R1 and its sub-parts, forcing a single communication procedure on the industry. This
goes far too deeply into the “HOW” of communication as opposed to the “WHAT”.
No
We disagree – this concept more properly belongs in the NERC Rules of Procedure and should be
designed to address Recommendation 26 of the NERC 2003 Blackout Report. This is an expectation of
NERC and not of the industry. Also, see recent NERC Operating Reliability Subcommittee (ORS)
discussions and recommendations regarding the elimination of the Transmission Alert Levels.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
Three part communications should not be required for routine operating communications. See the
definition of Reliability Directive in COM-002, which addresses reliability issues. We suggest that R2
and R3 should be eliminated, since neither one will increase reliability.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”. Requirement 1.1.4 does
not need to be in this standard as the requirement for unique line identifiers is stipulated in TOP-0022 R18.
No
We suggest deletion of all three requirements.
We support the need to strive for good communications among users, owners and operators of the
grid, but believe the standard as drafted is misdirected. Review of research done by EPRI and others
shows that dispatcher communications cause on the order of 1-2% of human failure impacting the
BPS. It is well less than 1% of all failures of the BPS. We also estimate there are millions of
conversations annually that self-inspecting entities would need to review. Recommendation 26 of the
Blackout Report, on which the SAR for this standard is based, was not focused on operator
communications. Rather it suggested a mechanism by the Regions to keep regulators and
government officials informed during emergencies. We would not be opposed to a requirement for
entities to have a procedure for communication expectations of operators and that the entities have a
process for periodic (no less than quarterly) sampling of operator communication for use in training
and counseling. The requirement would need to be framed such that it does not become a “fill in the
blank” standard, such that an investigator can ask for tapes of hundreds of conversations looking to
find any kinks in communications. As drafted, this standard can actually impede reliability as there
are at times better ways to communication when group action is needed and there are times when
speed or “give and take” are needed. The standard also fails to acknowledge that SCADA forms part
of the feedback process in communications. For example, ACE recovery and generation movement
during a DCS event are better confirmation that the message was received and understood than just
parroting back a phone call.
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Eric Salsbury
Consumers Energy
No
As there is no definition of what alpha – numeric clarifiers must be used, this leaves too much room
for interpretation for audit staff.
We believe this standard attempts to redefine “Reliability Directive” and should not do so. Specifics of
communication for this standard should be centered on emergency operations and not a blanket
protocol for almost all operations communications.
Individual
Karen Webb
City of Tallahassee
Yes
The City of Tallahassee Electric Utility (TAL) agrees with the addition of this proposed new definition;
however, TAL is not clear on the scope of the phrase "input of an Element or Facility of the Bulk
Electric System".
Yes
Yes
Yes
No
TAL is concerned with any unnecessary complication of communications. If more than one Time Zone
is entailed in a communication, it is reasonable to require clarification of such. However, if both the
sender and receiver observe the same prevailing time (e.g. Eastern Standard Time versus Eastern
Daylight Time), it does not facilitate communication to require this clarification.
Yes
TAL agrees with this split into two requirements for the protection of each party in the event of noncompliance by the opposing party. TAL seeks clarification on the application of this requirement in an
instance where a receiver never acknowledges the issuer.
Yes
Yes
TAL is concerned that the proposed standard focuses too heavily on the communications method
without consideration of a successful result. While the administrative approach/focus of this proposed
language appears to be crafted with the intent of standardizing communications and thereby
improving communications, it does not appear to place sufficient value on results-based performance.
Should an entity take proper action on a communication that is not delivered precisely in accordance
with this language, consideration of such at the Enforcement level would be warranted.
Group
Florida Municipal Power Agency
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Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Frank Gaffney
Individual
Brian Murphy
NextEra Energy, Inc
Yes
Yes
Yes
Yes
No
NextEra believes the current language in R 1.1.2 unnecessarily limits two other forms of clear
communications on the implementation of an Operating Communication. Specifically, NextEra also
believes it is appropriate to use “AM” or “PM,” or “effective immediately” for the timing of
implementing an Operating Communication, instead of the 24 hour clock. To add these items,
NextEra requests that R 1.1.2 be revised to read as follows: Use one of the following: (a) the 24-hour
clock; (b) “AM/PM” or (c) “effective immediately,” when referring to the time an Operating
Communication shall be implemented.
No
NextEra does not agree with R2 or R3, as drafted. COM-002-2, which applies to three-way
communications for Reliability Directives, is not mirrored by the proposed COM-003-1, thus creating
two different three-way communication protocols. This disconnect between the two three-way
communication Standards is counterproductive for System Operators, who we want focused on the
reliable operation of the system, rather than memorizing multiple three-way communication
protocols. As a member of the Standards Committee, NextEra has expressed its concern that
Standard Drafting Teams (SDTs) are not sufficiently communicating and coordinating in a manner
that promotes clear and effective Reliability Standards. It appears that the COM-002 and COM-003
SDTs have not coordinated their efforts, because COM-003-1 proposes to implement a more
restrictive three-way communication protocol via R1, R2 and R3 than proposed for COM-002-3.
NextEra believes that the easiest way to make COM-003-1 consistent with COM-002-3 is to
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implement the same three-part communication language contained in COM-002-3. Specifically, COM003-1 R1, R2 and R3 would be replaced with the following language that mirrors COM-002-3: “R1.
When a Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be
executed as an Operating Communication, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as an Operating Communication to the recipient. R2. Each
Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the
recipient of an Operating Communication shall repeat, restate, rephrase or recapitulate the Reliability
Directive. R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues
an Operating Communication shall either: • Confirm that the response from the recipient of the
Operating Communication (in accordance with Requirement R2) was accurate, or • Reissue the
Operating Communication to resolve any misunderstandings.” Although NextEra prefers that the SDT
use the above language, in the event the SDT chooses not to mirror COM-002-3, NextEra requests
the SDT implement the proposed modifications to R1 and R2 as set forth in response to questions 5, 7
and 10.
No
Similar to the 24 clock, it appears that R1.2 does not fully consider how communications and naming
conventions are used in the industry. Specifically, alpha-numeric identifiers are used when there is an
uncommon naming convention. Examples of common naming conventions include AM/PM, breaker
names such as (8W15), etc. As written, the requirement could be interpreted to require alphanumeric identifiers for all alpha applications even though the industry has never had a need to use
such identifiers. This will likely lead to unnecessary confusion, and, therefore, will likely not promote
reliability. Moreover, the R1.2 and COM-003-1 technical paper suggest there is only one set of alphanumeric clarifiers that are “accurate.” NextEra does not agree with this perspective, and believes it is
counterproductive to narrowing a System Operator’s discretion on which alpha-numeric clarifiers he or
she may use. To address these matters, NextEra recommends that R1.2 be revised to read: “When an
oral Operating Communication does not use a common naming convention, alpha-numeric identifiers
shall be used.”
No
See comments in response to question 7.
NextEra has the following additional recommended changes to increase the clarity of COM-003-1: 1. A
new provision on written Operating Communications that requires that the sender to receive a
notification that the recipient has received and read the communication. As currently written, there is
no read receipt requirement for written Operating Communications. This appears to create a possible
reliability gap, given that the sender will not know that its instructions were received and read, which
leaves the system in a state of limbo as to what actions will or will not be taken. Accordingly, NextEra
recommends that a requirement be added that reads as follows: “When a Reliability Coordinator,
Transmission Operator and Balancing Authority sends a written Operating Communication it shall
include a “read receipt” requirement or similar mechanism to ensure the sender has received and
read the Operating Communication. If a “read receipt” is not received by the sender, the sender shall
call the intended recipient or rescind the Operating Communication.” 2. R2.1 is confusing because it
attempts to mix what occurs when a response is received and when no response is received during a
oral communication. To ensure no confusion occurs, as well as providing for additional practical
discretion when a response is not received, NextEra recommends that R2.1 be separated into two
distinct sections and be rewritten to read as follows: R2.2. After the response is received, do the
following: • Confirm the receiver’s response is correct (not necessarily verbatim). • Reissue the
Operating Communication if the repeated information is incorrect or if the receiver does not issue a
response. • Reissue the Operating Communication, if requested by the receiver. R2.3 If no response
is received, do one of the following: • Ask the receiver if the Operating Communication was received.
If receiver confirms receipt of the Operating Communication, then proceed through R2.2. If the
receiver, however, does not confirm receipt or no response is received, the sender of the Operating
Communication shall either reissue or rescind the Operating Communication. 3. Unlike language on
Reliability Directives in IRO-001-3 – “unless compliance with the direction cannot be physically
implemented or unless such actions would violate safety, equipment, regulatory or statutory
requirements” – there is no similar qualifier for Operating Communications. To provide the recipient of
an Operating Communication the same rights as a Reliability Directive, NextEra requests that a new
section be added: “The recipient of an Operating Communication is required to implement the
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instruction, unless compliance with the instruction cannot be physically implemented or unless such
actions would violate safety, equipment, regulatory or statutory requirements. In the event the
recipient is unable to carry out the instruction, it shall communicate this situation to the sender of the
Operating Communication.” This last recommended addition should be added in both cases: (a) if
NextEra’s response to question 6 is adopted, or (b) if NextEra’s response to question 6 is not adopted.
4. To provide clarity to COM-003-1, NextEra recommends that the purpose stated in the white paper
be transferred to the purpose statement of COM-003-1. The white paper states that “[t]he purpose of
the proposed standard is to: ‘Require that real time System Operators use standardized
communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.’” NextEra recommends that this purpose statement replace the draft
purpose statement in COM-003-1, so COM-003-1 is not misinterpreted to require three way
communications outside of real-time system operations.
Individual
Randall McCamish
City of Vero Beach
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
NONE
Individual
Don Jones
Texas Relibility Entity
Yes
We agree, in view of the additional comments we provide below.
Yes
Yes
Yes
Yes
Yes
Yes
Consider removing the word “accurate” from part 1.2. We do not believe it adds anything to the
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requirement, and it may cause confusion.
No
The name specified by the operators of the equipment should be used, rather than the name given by
the owner, and it should be jointly agreed to as the identifier for the equipment. For example, an
owner name could be the “Lyndon Baines Johnson East Johnson City Substation Line 3” but the
Transmission Operator refers to it as “East Johnson City 3” or “EJC3” or “Johnson 3”. The Planning
Authority/Coordinator may dictate a naming convention to be used in Operations systems that are
used by the System Operators (i.e. RTCA, outage scheduler, etc.). The name to be used should be
clearly identifiable, concise, and easily understood by all parties involved in the Operating
Communication. We suggest re-wording R1.1.4 to “When referring to a Transmission interface
Element or a Transmission interface Facility, each responsible entity shall use a pre-determined,
uniform identifier for each Element or Facility.”
1. The use of exploder or hotline calls, where a single oral communication is used to alert a multitude
of entities simultaneously to issues and directions affecting the BES, should be addressed by this
Standard. The use of these types of calls is economic, efficient, and should be recognized for the
purpose of providing Operating Communications, including Reliability Directives. Not addressing this
issue will have a serious impact on System Operators during times, normal or emergency, when clear,
concise, and effective communications are needed. The 2003 Blackout Recommendation #26 includes
the following text: “Standing hotline networks, or a functional equivalent, should be established for
use in alerts and emergencies (as opposed to one-on-one phone calls) to ensure that all key parties
are able to give and receive timely and accurate information.” This proposed Standard should address
the issue of what communication protocols should be applied to exploder or hotline calls. 2. There is a
disconnect between COM-003-1 and COM-002-3 that will create confusion within the industry
regarding communications. COM-002-3 has limited applicability, restricted to use of Reliability
Directives ONLY in an Emergency or Adverse Reliability Impact. COM-003-1 is limited to oral two
party communications, but it applies outside of Emergency situations. With proposed IRO-001-3
contained in Project 2006-06, a Reliability Coordinator or other entity may not be certain of whether
to give a directive, a Reliability Directive, or an Operating Communication, and a recipient may
dispute whether the correct communication type was used. What is the intended compliance impact of
using the wrong type of communication, for both the initiating entity and the receiving entity? 3.
COM-003-1 and COM-002-3 will cause substantial confusion as drafted because they both require
three-part communication, but they use different language to describe it. That suggests that the
communication protocols that are required must be different, and as an entity moves from nonEmergency into Emergency operations, its communication protocol will be expected to change. We
strongly suggest that a single three-part-communication protocol be set forth in one place only, and
that any differences between Emergency and non-Emergency communication requirements be clearly
identified.
Group
FirstEnergy
No
The requirement for line identifiers should not be included and is unnecessary. This type of
requirement was also removed from standard TOP-002 in recently board approved project 2007-03.
The drafting team position for the removal was the following: “This requirement adds no reliability
benefit. Entities have existing processes that handle this issue. There has never been a documented
case of the lack of uniform line identifiers contributing to a System reliability issue. This is an
administrative item, as seen in the measure, which simply requires a list of line identifiers. The true
reliability issue is not the name of a line but what is happening to it, pointing out the difficulty in
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assigning compliance responsibility for such a requirement, as well as the near impossibility of coming
up with truly unique identifiers on a nation-wide basis. The bottom line is that this situation is handled
by the operators as part of their normal responsibilities, and no one is aware of a switching error
caused by confusion over line identifiers.” Therefore we suggest the removal of R1.1.4 for the same
reason.
Although we believe the team made significant improvements to the standard, and would support a 3part communication standard, we believe the introduction of both COM-002-2 which utilizes Reliability
Directives and COM-003-1 which utilizes Operating Communications cause confusion for system
operators and may in fact be detrimental to reliability. We do not support two standards on three-part
communication. We suggest, as we have in the past, that the subject of three-part communication be
addressed in a single standard, and that the requirements be developed for simplicity. The industry is,
and has been, using three-part communication for decades and although we agree it should be more
consistently practiced and standardized, the required communications protocols should be simple
while meeting the goal of BES reliabilty. Introducing complicated requirements and standards that
have different definitions such as Reliability Directive and Operating Communication may cause the
operator to hesitate when issuing directives in real-time and every second counts when a potential
system emergency must be mitigated. Therefore, FE does not support the creation of both COM-0031 nor COM-002-2 (see project 2006-06 vote and comments) and ask NERC to reevaluate the need to
have two separate standards for three-part communication.
Sam Ciccone
Individual
Kenneth A Goldsmith
Alliant Energy
Yes
Yes
Yes
No
We believe that adding the mandate to use a 24 hr clock and list the time zone and Daylisght Savings
Time or not is going too far. We agree that it could be considered a best practice, but to require it and
have a violation every time it is not used will result in multiple frivolous violations and clog the system
with violations that have no impact on the reliability of the BES. With a zero-deffect philosophy, which
currently exists in the regulatory model, this is unworkable.
No
We do not believe there is a need for COM-003 at all and recommend it be deleted. COM-002 covers
Reliability Directives very well. For three-part communications in a non-Reliability Directive situation
we beleive it should be considered an industry best-practice. By requring three-part communications
as dictated in this standard, there will be requests for interpretations, CAN's produced for the CEA,
and numerous violations written for what the industry considers a non-problem. In our opinion this
standards goes against the concept of risk-based standard making and reinforces a zero-defect
operation, which opposite of how the industry works.
Individual
Kathleen Goodman
ISO New England Inc
No
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We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
These Alert Levels have been and should continue to remain a product of the NERC OC and not a
Standards issue.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
No
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
We agree with, support and have signed onto the ISO/RTO Standards Review Committee comments.
Lastly, we do not believe this rises to the level of a Standard.
Group
SERC OC Standards Review Group
No
GENERAL COMMENT: While SERC does not agree that the mandatory procedure for three part
communications will improve reliability of the BES, SERC offers the following comments: We do not
agree with the proposed definition of Operating communication and agree with the elimination of the
other three definitions. The SDT has not listened to the industry comments given in the previous
commenting periods. It also appears to be focused on imposing three part communications on the
industry for routine communications despite the fact that neither the blackout report nor the SAR on
which these standards are based emphasize that issue. The blue text box that mentions Reliability
Directives seems to be a back door attempt to change COM-002 and should be clarified or eliminated.
Splitting communications requirements across different standards creates unnecessary confusion.
No
The SDT did not eliminate a communications procedure requirement! It turned the former
requirement into R1 and its sub-parts, forcing a single communication procedure on the industry. This
goes far too deeply into the “HOW” of communication as opposed to the “WHAT”.
No
We disagree – this concept more properly belongs in the NERC Rules of Procedure and should be
designed to address Recommendation 26 of the NERC 2003 Blackout Report. This is an expectation of
NERC and not of the industry. Also, see recent NERC Operating Reliability Subcommittee (ORS)
discussions and recommendations regarding the elimination of the Transmission Alert Levels.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
Three part communications should not be required for routine operating communications. See the
definition of Reliability Directive in COM-002, which addresses reliability issues. We suggest that R2
and R3 should be eliminated, since neither one will increase reliability.
No
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This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”.
No
This sub-part is part of the SDT forcing a single communication procedure on the industry. This goes
far too deeply into the HOW” of communication as opposed to the “WHAT”. Requirement 1.1.4 does
not need to be in this standard as the requirement for unique line identifiers is stipulated in TOP-0022 R18.
No
We suggest deletion of all three requirements.
Where is the demonstrated need for such a Standard? Has communications, especially during periods
of normal operations, been shown to be the root cause of many, if any, events? While there is easy
agreement for the need of clear and concise communication between entities, we must avoid creating
a system that is unmanageable and quite possibly results in less reliability. FERC Order 693 directs
the ERO to ‘‘and (3) requires tightened communications protocols, especially for communications
during alerts and emergencies.”, in paragraph 532. The proposed standard goes too far, especially for
communications outside of alerts and emergencies. NERC standards are not procedures and this
standard attempts to impose a single procedure on the industry. SERC suggests another approach to
COM-003. Rather than to specify the solutions to achieving effective communication, COM-003 should
instead focus on developing and training on an approach that is designed appropriately for each RE.
For instance, another approach to COM-003 might be along the lines of: Requirement 1 could be
written in a manner to require the appropriate registered entities to develop a communication
protocol that is appropriate for each RE. This communications protocol should address how the RE is
handling the following: Time Zone Designations – for both internal and external communications
language comm Alpha-numeric identifiers Three – part communications – when is it required, etc. Use
of defined terminology Other items deemed important for the communications protocol to address –
again, this would not define HOW these items are addressed This approach would require the RE to
address how it is addressing these issues, without prescribing solutions. For instance, a RE could
include in its protocol a section dealing with time zone designation. In this section the RE could
explain that it, and its neighbors, all are in and use the same time zone. As a result, the RE has
determined that requiring the identification of time zone reference in communication is not necessary
Procedures should address the training of operators on the communication protocol Procedures should
address the internal controls that the RE uses to review that its protocol is being followed. The
compliance approach would be to: Assess whether the RE has developed a written protocol and
whether the protocol addresses each item – this does not mean there is an assessment of HOW each
item is assessed; assess whether the RE has trained its operators on the communications protocol
and assess whether the RE is following its internal controls. Any data retention requirements should
be consistent with the COM-002 reliability standard. What is the role of the Operating
Communications Protocols White paper? Is it a position of the STD? If not, was there a minority
opinion? Will it be part of the standard? Does the industry agree that we need a standard on three
part communications for normal operations? Yes or No? Has a lack of a standard on three part
communications for normal operations created any reliability issues? If so, what are they? “The
comments expressed herein represent a consensus of the views of the above named members of the
SERC OC Standards Review group only and should not be construed as the position of SERC Reliability
Corporation, its board or its officers.”
Gerald Beckerle
Individual
Steven Wallace
Seminole Electric Cooperative
Yes
No
While ee absolutely support the promotion and use of 3-part oral communication protocol, the failure
of individual persons to use "proper" and "correct" oral operational communications should NOT
constitute a Standard violation. It is reasonable to require the responsible entities to have written
procedures requiring such use; to have evidence of applicable personnel training on such; and to have
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a program for internal monitoring and enforcement of such. As written, a subjective review of many
oral operational communications will arguably be identified by Compliance Auditors as medium, high
or even severe levels.
Yes
Yes
No
Splitting the requirement is okay but the exclusion of reliability directives and the structure of R2 and
R3 to take one of the following actions based on the other party's action is ambiguous.
Yes
Yes
No
See previous comments
While we absolutely support the promotion and use of 3-part oral communication protocol and the
other features identified, the failure of individual persons to use "proper" and "correct" oral
operational communications should NOT constitute a Standard violation. It is reasonable to require
the responsible entity to have written procedures requiring such use; to have evidence of applicable
personnel training on such; and to have a program for internal monitoring and enforcement of such.
As written, a subjective review of many oral operational communications will arguably be identified by
Compliance Auditors as medium, high or even severe levels.
Group
Western Electricity Coordinating Council
How are facilities that might affect the opearion of the BES treated? Would the changing of an LTC or
the low voltage taps on a 230/92 kV transformer be suject to this standard?
Yes
Yes
Yes
Any thoughts given to including a provision for agreement between specific entities to use a language
other than English for areas that another language may be common, but not mandated by law or
regulation?
Yes
Is the exclusion of Reliability Directives becasue they are covered under COM-002? Since all COM-002
covers is Reliability Directives, why not include it in this standard? Operators should use the same
protocol for all Operating Communications. We agree with the split for the issuer and the receiver.
From an enforcement perspective, this could be problematic. As drafted this will allow virtually any
appha numeric clarifier. Who is to detrmine if the identifies is "correct?" This will put the auditor in the
positoin of determining wheter or not a clarifier was correct or accurate. For auditing purposes there
should be clear direction on what is acceptable.
No
We question the need for this part of the requirement based on the fact that it appears to be
redundant with TOP-002-2b, R18.
As noted in our response to question 6, there is still a concern about having two standards for
communications on changes to elements of the BES. Bifucations may lead to the misues of one
protocol in place of another for the two standards.
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Steve Rueckert
Individual
Martin Bauer
U.S. Bureau of Reclamation
Yes
Yes
Yes
Yes
Yes
Yes
No
By using the term "correct" alpha numeric clarifier, it implies that an incorrect alpha numeric clarifier
can exist. In reality as long as an alpha numeric clarifier is used to verify the letters or numbers are
conveyed the intent is made. The standard language should be revised to state that "When
participating in oral Operating Communications and using alpha-numeric identifiers, use alphanumeric clarifiers for the letters and numbers to convey the correct numbers and letters in the
Operating Communication."
Yes
Yes
The standard should clarify what is evidence is considered acceptable to demonstrate compliance with
R 1.2. The requirement 3 appears to require the use of voice recording to demonstrate compliance
with repeating the operating communication requirement. Not all facilities in which operating
instruction may be received have voice recording capability. The requirement/measure should clarify
an alternative evidence when such a means is not present.
Group
Southern Company
No
Southern agrees with the elimination of “Communication Protocol,” “Interoperability Communication”
and “Three part Communications” proposed in the first draft of COM-003-1; however, Southern does
not agree with the proposed new definition for “Operating Communication”. The definition of
Operating Communications is too broad. The SDT appears to be focused on imposing 3-part
communication on the industry for routine communications even though the August 2003 Blackout
Report and the direction in FERC Order 693 Paragraph do not require such. The word “maintain”
should be removed. Three part communication is not needed to keep things as they are in real time
unless the communication is meant to be a Directive issued by the RC or TOP and identified as such.
From a real time operations standpoint, only communications that are meant to initiate a change
(e.g., open, close, enable, disable, increase, decrease) should require 3 part communications. In
addition, any instruction to change or maintain the state, status, output, or input of an Element or
Facility of the BES should not be considered a Reliability Directive. A more appropriate definition of
Reliability Directive has been included in Project 2006-06 (Reliability Coordination) for COM-002-3. As
such, the definition of Reliability Directive developed in Project 2006-06 should be used here as part
of this Project 2007-02. Further, this capitalized term should have one definition and should not be
defined differently in different standards. Otherwise, there will be ambiguity and unnecessary
confusion.
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No
It appears as though the SDT did remove the term Communications Protocol Operating Procedure,
but replaced it with very prescriptive requirements and subrequirements in R1 of this revised
standard. This newly revised standard focuses on the “HOW” of communication when it should be
more focused on the “WHAT”.
No
Southern suggests that this concept more properly belongs in the NERC Rules of Procedure and
should be designed to address Recommendation 26 of the NERC 2003 Blackout Report. This
suggestion of placing Alert Levels in the reliability standards is an expectation of NERC, but it is not
an expectation of the industry. Also, see recent NERC Operating Reliability Subcommittee (ORS)
discussions and recommendations regarding the elimination of the Transmission Alert Levels.
No
While Southern agrees with the concept of allowing the use of another language when mandated by
law or regulation, Southern does not agree with R1 and its subrequirements as they are focused on
the “HOW” of communication when they should be more focused on the “WHAT”.
No
Southern suggests that this requirement of a common time zone is overly prescriptive. The
requirement should be that entities operating in different time zones agree on how to best eliminate
any confusion regarding the time difference. Entities who have an agreed upon protocol which
includes the time zone to be used for system operations should not be required to repeat the time
zone for every communication. For instance, if Entity A and Entity B are in different time zones but
both have an operating policy that states all communication between the two is in Eastern Standard
Time and all operating personnel are trained on this policy, this should be sufficient. This achieves the
same functional goal. The requirement to restate the time zone in this case only serves to set up a
situation where a simple single-instance omission would have no effect on reliability but still be
noncompliant.
No
Southern disagrees that three part communications should be required for routine operating
communications. A more appropriate definition of Reliability Directive has been included in Project
2006-06 (Reliability Coordination) for COM-002-3. As such, the definition of Reliability Directive
developed in Project 2006-06 should be used here as part of this Project 2007-02. Further, this
capitalized term should have one definition and should not be defined differently in different
standards. Otherwise, there will be ambiguity and unnecessary confusion. Southern suggests that R2
and R3 should be eliminated, since neither one will increase reliability.
No
Southern does not agree with R1 and its sub-requirements as they appear to force a single
communications procedure on the industry and are focused on the “HOW” of communication when
they should be more focused on the “WHAT”. Also, the word "accurate" should be removed from R1.2,
as it is not needed.
No
Southern does not agree with R1 and its subrequirements as they appear to force a single
communications procedure on the industry and are focused on the “HOW” of communication when
they should be more focused on the “WHAT”. Furthermore, requirement 1.1.4 does not need to be in
this standard as the requirement for unique line identifiers is stipulated in TOP-002-2 R18. Also, is it
certain that both parties in the communication will know the name for the element/facility that is
specified by the element/facility's owner(s)?
No
As mentioned in the previous comments, Southern does not agree with R1 as it is imposing a single
communications procedure on the industry and is focused on the “HOW” as opposed to the “WHAT”,
and does not agree with R2 and R3 as they imply that that 3-part communications are needed for all
communications, not just during Reliability Directives, emergencies, or alerts. As such, Southern
disagrees with the VRFs and VSLs.
NERC standards are not procedures and this standard attempts to impose a single procedure on the
industry. Where is the demonstrated need for such a standard? Have communications, especially
during periods of normal operations, been shown to be the root cause of many, if any, events?
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Registered Entities agree that there is a need of clear and concise communication between entities;
however, we must avoid creating a system that is unmanageable and quite possibly results in less
reliability. FERC Order 693 directs the ERO to ‘‘and (3) requires tightened communications protocols,
especially for communications during alerts and emergencies”, in paragraph 532. The proposed
standard goes too far, especially for communications outside of alerts and emergencies.
Antonio Grayson
Individual
Rich Salgo
NV Energy
Yes
Yes
This was a much warranted improvement.
Yes
Yes
No
We believe that the requirement to specify "daylight" versus "standard" is unwarranted and may lead
to confusion among the parties. All time is understood to be "prevailing time" without this
clarification. Requiring such will only serve to confuse rather than clarify.
No
I have not seen the parallel requirement that pertains to Reliability Directives, but I can imagine no
reason why the communication protocols for Operating Communications would ever differ from those
for Reliability Directives. Making the distinction here in this requirement adds unnecessary confusion.
Yes
Agree that it ought not to be restricted to NATO only, but we are confused about what "correct"
means. Perhaps it means any spoken word that begins with the subject alpha character?
Yes
Agree, however, we suggest that there be more clarity provided about what constitutes a
Transmission interface Element/Facility. Is it a connection between BA's or between TOP's within a
BA?
Individual
Maggy Powell
Exelon Corporation and its affiliates
No
Exelon believes it is not necessary to create a new defined term “Operating Communication.” Please
see response to Q10 with alternate standard language that avoids the need for a new term.
No
Exelon agrees with the elimination of the requirement to have a Communications Protocol Operating
Procedure and we also believe the basic approach as proposed is wrong. The burden for
demonstrating compliance for non-emergency, non-directive communications, including retention and
review of 180-365 days worth of evidence to be able to demonstrate 100% compliance presents
significant burden potentially detracting from the work of reliability. Auditing, whether by a NERC CEA
or by entities conducting internal self assessments for self-certifications, would potentially involve
listening to thousands of hours of tapes to review. This is an overly prescriptive, burdensome
approach. We believe that a more effective approach would be for the standard to mandate reliability
based outcomes and require entities to design practices to achieve the desired outcome. See
response to Q10.
No
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While Exelon agrees with deleting the Alert Levels in Attachment 1 from COM-003-1, Exelon does not
agree with transferring the requirement to use Alert Levels to any other standard or the creation of a
separate new standard. As stated by many of the commenters to the previous draft, the addition of
"Alert Levels" with defined colors have been used by DHS and may be misinterpreted. In response to
these comments the SDT removed the requirement to Attachment 1 as falling outside the scope of a
"communication protocol." Exelon reiterates that the concept of adding colored "Alert Levels" not only
be deleted from COM-003-1, but also not be transferred to another SAR in the future.
No
Exelon finds it unnecessary for the standard to include a requirement that discusses specifics
concerning language requirements. If discussion of language is important to clarify within a
Registered Entity’s protocol, then the standard could suggest it as an attribute to be included in an
entity developed protocol. See alternate standard language proposal in response to Q10.
No
It’s not clear that this addresses a reliability problem. We are not aware of instances where failure to
specify the time zone and daylight saving time resulted in communication failures between entities
leading to a condition that threatened an outage or a cascading outage. Further, specifically creating
a requirement is overly prescriptive. If it is justified as important to reliability, then the standard could
suggest it as an attribute to be included in an entity developed protocol. See alternate standard
language proposal in response to Q10.
No
Please see response to Q10.
No
While Exelon agrees with the modification to allow the use of another alpha numeric clarifier, Exelon
does not agree with the designation of "correct" related to alpha numeric communication. Requiring
"accurate" alpha-numeric clarifiers is overly prescriptive and unclear. An entity should not be held
accountable for 100% adherence to a set phonetic alphabet. For example, if a communicator and
receiver use the phonetic nomenclature "motor operated disconnect one foxtrot" but in a later
communication the equipment is referenced as "motor operated disconnect one fox" by the Standard
as written this could be considered a violation. It should be an expectation but not a requirement as
long as the transmitter and receiver use three way communications effectively. Again, the standard
should emphasis entity practice for effective communication not impose an overly prescriptive set of
requirements that pose compliance challenges.
No
Exelon is concerned with the requirement to use “the name” for the Element/Facility specified by the
Element/Facility's owner(s). By dictating “the name” this requirement may become overly
prescriptive. An entity should not be held accountable for 100% adherence to a set "specified name"
for an Element/Facility. It is reasonable for entities to fully understand what Element/Facility is
communicated; however, verbatim use of a "specified name" should not in itself be a requirement.
For instance, if the formal name of a generating unit is "ABC Fossil Generating Station Unit 1" and an
entity communicates "ABC Station Unit 1" or "ABC Generating Station 1" by the Standard as written
this could be considered a violation even though it can effectively communicate the needed
information. As in other sub-requirements to R1, the use of "specified name" should be an
expectation but not a requirement as long as the transmitter and receiver use three way
communications effectively. Further, this appears as an internal inconsistency in the standard
between R1 and R2. For example, an entity owner specifies a unique name for an interface element.
R1.1.4 requires the use of that unique identifier but R2 does not require verbatim response. It is not
clear which part of the repeated information three part response in R2 is allowed to be non-verbatim.
No
Exelon does not agree with the VRFs and VSLs for Requirements R1, R2 and R3. Requirement R1 The Violation Severity Levels imply that if the responsible entity did not correctly implement any one
(1) of the four (4) parts of R1 at any time that that entity would be non-compliant. It is not
reasonable to hold an entity responsible to verify that every communication be in accordance with R1
at all times. It should be an expectation, but not a requirement. Requirements R2 and R3 – Similar to
R1 it is not reasonable to hold an entity responsible to verify that every communication meet the
requirement of R2 or R3 in all instances. Exelon suggests that this requirement be revised to address
those instances where an actual event occurred due to improper communication or be limited to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
communication of a stated Reliability Directive. In general, the current VSLs for the current draft of
COM-003-1 do not seem commensurate to the risk to the BES. See the response to Q10 for a
reasonable approach to implementation of the intent of this requirement.
Exelon believes that the proposed COM-003-1 exceeds what is necessary for reliability and creates
other problems such that the proposed standard may in fact result in a decrease in reliability. In
particular the language is overly prescriptive and presents significant compliance questions both in
terms of creating a credible compliance measure and a reasonable way for entities to demonstrate
compliance or conduct internal self-assessment. Exelon believes that an alternative approach to COM003 is needed. The standard should set desired outcomes and leave the specific implementation of
communication protocols to registered entities. Standards should not impede use of best practices
and should encourage effective innovation. An alternate approach is worth consideration:
Requirements: 1. Entities must have a protocol addressing communications for operating personnel.
1.1. The protocol should address; three part communication, English language usage (include
footnote for requirement to use legislatively prescribed language), time zone, entity unique
identifiers, 24 hour clock and alpha numeric identifiers. 1.2. All control center operating personnel
should be trained on the use of the protocol. Measure: In an audit, a company would be expected to
demonstrate that they had such a protocol and that they trained their operators on its use. This
proposal would satisfy the Directives and Blackout Recommendation #26 which were to “tighten
communication protocols, especially for… emergencies”. Stakeholders and the NERC BOT approved
COM-002-2 which addressed communications capabilities being staffed and available for addressing a
real-time emergency condition. An associated interpretation of COM-002 clarified whether routine
operating instructions are “directives” or whether “directives” are limited to actual and anticipated
emergency operating conditions. Our proposed changes to COM-003 are responsive to the FERC
recommendation to tighten operating protocols. Other possible responses to this recommendation
would be to conduct an assessment of NERC certification requirements and if found lacking in this
area, strengthen them. For the reasons stated above, we urge NERC to change the focus of COM-003
from a prescriptive what to do approach and allow entities to develop and implement protocols in
keeping with NERC and ISO/RTO operator certification requirements and best practices within the
industry. Thank you for the opportunity to comment.
Individual
Tony Kroskey
Brazos Electric Power Cooperative
No
Please see formal comments provided by APM.
Yes
Yes
Yes
No
Please see formal
No
Please see formal
No
Please see formal
No
Please see formal
No
Please see formal
Please see formal
Individual
Darryl Curtis
comments provided by APM.
comments provided by APM.
comments provided by APM.
comments provided by APM.
comments provided by APM.
comments provided by APM.
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Oncor Electric Delivery Company LLC
No
Oncor is in general agreement with the elimination of the three terms. Furthermore, Oncor takes the
position that the proposed new definition for the NERC Glossary, “Operating Communication” is not
needed because “person to person” communication is not cited or listed as a contributor to the events
summarized in the 2003 Blackout Report. Oncor takes the position that improvements should
emphasize communicating the state of the operating system as a whole during an emergency.
No
Oncor takes the position that elimination of the Communications Protocol Operating Procedure does
not constitute the introduction of another set of procedures (i.e. 3 - Part Communication, or alphanumeric clarifiers). Furthermore Oncor takes the position that a more productive approach would be
to encourage the creation of innovative Best Practices; as opposed to a mandatory fixed procedure
which would limit innovation.
No
Oncor takes the position that the introduction of new alert levels or categories simply introduces more
complexity to what could be better addressed through a closer examination of existing alert levels.
This includes EEA levels and threat levels.
No
Oncor takes the position that this requirement is unnecessary in that it is not aware of any evidence
supporting the notion that failure to use the English language has been a significant contributor to
reduction in reliability. Furthermore, FERC has made it known that it is in favor of eliminating
requirements that do not contribute to reliability. Oncor recommends that this requirement be
eliminated.
No
Oncor takes the position that more productive approach would be to encourage the creation of
innovative Best Practices; as opposed to a mandatory fixed procedure which would limit innovation.
Oncor believes that requiring registered entities to have its own internal communication protocols
would encourage the adaption of best practices that could be shared, modified and implemented as a
“best fit” and could potentially enhance reliability as opposed to a mandated “procedural specific”
requirement
No
Oncor believes that the application of three part communication as prescribed in the proposed
reliability standard COM-002-3 is appropriate as prescribed for emergencies. Any additional
requirements, including those for routine operations goes well beyond what is called for in the 2003
Blackout Report which focused on emergencies. As such, Oncor also takes the position that the term
Operating Communications should also be removed.
No
Oncor take the position that this requirement is far too much detail and goes well beyond the 2003
Blackout recommendations. Furthermore, Oncor take the position that a more appropriate approach
would be to require internal procedures that address internal communication protocols.
No
Again, Oncor take the position that this requirement contains far too much detail and goes well
beyond the 2003 Blackout recommendations. Furthermore, Oncor take the position that a more
appropriate approach would be to require internal procedures that address internal communication
protocols.
Group
Bonneville Power Administration
Yes
Yes
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Yes
No
BPA believes that the existing language format should remain solely English and recognizes that this
is the case with International & US air traffic controllers.
Yes
Yes
No
BPA disagrees with both clarifiers (NATO phonetic alphabet and alpha numeric) and believes the
communication should be left to the discretion of each utility. This modification causes an undue
burden when relaying communication; especially in a time of an emergency and dramatically
increases the risk of human error. BPA recommends that the drafting team remove any and all
language of NATO phonetic and alpha numeric identification of any device, (Alpha and especially
numeric phonetic requirements). R2 and R3 clearly ensure that all parties are already properly
communicating clearly and concisely. Should the drafting team remove the NATO phonetic and alpha
numeric language, BPA would change its negative position to affirmative.
No
BPA believes that the uniform line identifiers between utilities should be identified by mutual consent
and suggests the drafting team use the language from COM-003-1 R7, “Each Reliability Coordinator,
Balancing Authority, Transmission Owner, Transmission Operator, Generator Operator, Transmission
Service Provider, Load Serving Entity and Distribution Provider shall use pre-determined, mutually
agreed upon line and equipment identifiers for verbal and written Interoperability Communications”.
BPA also recognizes that uniform line identifiers are already addressed in TOP-002-2b.
No
BPA believes the VSLs for R3 are too extreme as written. The SDT needs to add emphasis and clarity
to the second *AND*. The requirement only asks for one of the two bullets; the VSL could be
incorrectly interpreted by and auditor that both bullets are needed. Compliance is met if: (a) the
receiver repeats back the Operating Communication and waits for confirmation, or (b) requests it to
be repeated because it may not have been heard correctly. Compliance is not met if neither is done.
So if the entity received a communication but did not repeat it AND did not request it to be repeated,
that violation would be severe. For severity levels add impact to the Bulk Electric System as a
qualifier. IF Cascading outage or 1000 MW of load is lost due to failure to repeat information back
*AND* wait for confirmation ( equals SEVERE). If equipment is damaged as a result (equals
Moderate). If fails to repeat *AND* fails to wait for confirmation (equals LOW). BPA would change its
position if categorizing a level of impact to the BES beginning with an equivalent to the severity of the
violation.
Chris Higgins
Individual
Steve Alexanderson P.E.
Central Lincoln
No
The change from “Interoperability Communications” to “Operating Communication” greatly expands
the standard to include all internal communications regarding > 100 kV equipment. Central Lincoln
does not consider the extra burden to be worth the negligible benefit.
Yes
Yes
Yes
but please see Q 10.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
We appreciate the change from requiring Central Time, but believe that 12 hour designations with AM
or PM qualifiers to be just as clear as 24 hour clock time. In addition, we suggest that the DT or ST
designation should only be required when deviating from the prevailing time in effect.
Yes
but please see Q 10.
Yes
but please see Q 10.
Yes
but please see Q 10.
1) Central Lincoln supports the comments provided by PNGC. We have a similar situation, and believe
the redirection of resources needed for compliance can only have a negative effect on our local level
of service. 2) Central Lincoln is greatly concerned regarding how this standard will be audited. We
expect the Compliance Enforcement Authority, in order to avoid a data dump in the form of a six year
audit period’s worth of radio recordings consisting of mainly distribution related instructions, will
request searchable transcripts with pointers to the relevant >100 kV parts. This will represent a huge
amount of time to transcribe the recordings and provide the pointers. This administrative burden in
proving compliance after the fact will not result in any improvement in reliability.
Group
GP Strategies
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
We disagree that all DP’s should be subject to this Standard. For many small entities, it is the TOP
who will control the equipment to shed load. These DP’s do not operate a 24x7 control center for
receiving such instructions. During non-business hours calls are forwarded to an answering service or
an on-call technician. We recommend the drafting team modify the applicability as follows:
Applicability: 4.1. Functional Entities 4.1.1 Reliability Coordinator 4.1.2 Transmission Operator 4.1.3
Balancing Authority 4.1.4 Generator Operator 4.1.5 Distribution Provider who is the 24 x 7 entity that
operates their load shedding equipment when instructed by the RC, TOP, or BA. The TOP should be
the repsonsible entity unless the Distribution Provider has agreed on the responsibility for taking the
action.
Mary Jo Cooper
Individual
Richard Vine
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California Independent System Operator
Yes
No
While the objective of minimizing ambiguities in communications between functional entities is
commendable, the standard as currently written goes too far by requiring “…English when
communicating between functional entities, unless another language is mandated by law or
regulation.” (R1.1.1) To begin, requirement 1.1.1 is completely silent on who’s law or regulation
would satisfy this requirement if a functional entity wanted/needed to speak a different language. For
example, it’s unclear which of the following would satisfy this requirement: 1. A Canadian or Mexican
law or regulation provided as evidence to WECC auditors? 2. An American law or regulation? 3.
Perhaps both an American and a neighboring country’s law/regulation would be required? Since the
proposed standard is silent on what constitutes satisfactory evidence, both numbers 1 and 2 seem
like potentially harmful unilateral moves that could be detrimental to reliability but may be allowable
in COM-003-1 as currently proposed. So if functional entities would like/need to speak a different
language, the requirement looks like it’s attempting to set a high bar without specifying how high that
bar is. I also think the requirement pre-supposes a level of English fluency by all North American
citizens that simply does not exist and mandates a very high and very vague threshold for compliance
while not allowing for exceptions. So ultimately, R1.1.1. is a vague, unnecessary and inflexible
requirement that would be detrimental to real-time operators in a contingent status. It would deny
operators that are fluent in other languages the ability to assist non-native English speakers
experiencing difficulties in communications by using a language they are fluent in to mitigate a
potentially serious issue. The requirement could also potentially require U.S. states, Canadian
provinces and/or Mexican states to write laws and/or regulations to satisfy a requirement in a
standard which seems like an unrealistic threshold. The bottom line is if an entity enters a contingent
state and there is no legislation or regulation in place at the time of a contingency event, system
operators may be forced to decide between two very difficult positions. Either adhere to COM-003 and
run the risk of putting the grid at risk or violating COM-003 to ensure grid integrity is not
compromised.
Yes
Yes
Individual
Jennifer Flandermeyer
Kansas City Power & Light
No
The requirements in this standard specifically state “how” to meet the goal of this standard. This
standard needs to be written such that it allows for entity flexibility. Many entities already have COM
protocols that are used. The proposed standard is too prescriptive and is more effort than necessary
to ensure reliability and security of the BES. Overall – this standard is going to cost the registered
entities much more than the realized benefits.
Yes
No
Create one standard for all operating conditions and retire the balance of those places where levels
are referenced. We support a new or separate requirement speaking to all alert levels for operating
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
conditions but not combination with another unique standard losing the efficiencies of a combined set
of operating condition alert levels.
Yes
Yes
No
Do we lose the “speciality” of only using 3-part communication during times of issuing
directives/emergencies?
Yes
Yes
No
VRFs and VSLs should be low.
This standard needs to be written such that it allows for entity flexibility. Many entities already have
COM protocols that are used. To prove compliance in an audit, entities will we need to provide 3 years
worth of voice recordings to the auditors. It would take a full-time position to review the daily voice
recordings for submission and what value does this add to the reliability or security of the BES. This
standard is “overkill” from what is existing standard already dictates. Overall – this standard is going
to cost the registered entities way more than the realized benefits.
Group
NERC Operating Committee
No
See Response 10
No
See Response 10
See Response 10
See Response 10
No
Overly prescriptive
No
See Response 10 - the OC sees these differing concepts for communications as overly prescriptive
and complex.
See Response 10
No
See Response 10
No
See Response 10
NERC Operating Committee (OC) comments on COM-003 (Operating Personnel Communications
Protocols) The current draft of COM-003 is proscriptive and is in fact a procedure or rather a set of
discrete tasks / actions that are not focused to support the reliability intent. The NERC OC
recommends that the SDT develop a purpose that speaks to operators and their responsibility to
maintain reliability not a process or set of protocols that cannot account for every nuance and variable
in the realm of communications and human interaction. Restated Purpose: To provide system
operators a holistic communications program that reduces the possibility of miscommunication that
could lead to action or inaction harmful to the reliability of BES. The OC just approved a guideline for
System Operator Verbal Communications. The OC feels this could be used as a basis for a new
approach for COM-003-1. The OC proposes that the SDT changes the draft of COM-003 to the
following three requirements: R1: Each RC, TOP, GOP, BA, DP shall develop a written communications
procedure to address the following: • Protocols • Training and education • Internal controls
(Preventive, Detective and Corrective) that demonstrates a process that will find, fix, track, trend,
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analyze and continuously improve R2: Each RC, TOP, GOP, BA, DP shall train applicable personnel on
the communication procedure developed for R1 R3: Each RC, TOP, GOP, BA, DP shall take appropriate
actions to address deficiencies revealed by internal controls. Data retention must be rethought to
focus less on significant data and evidence archiving (backwards looking) and more on the internal
program to continuously improve (forward looking). Individual instances of not following the
company’s procedure should not be the basis of violation but instead – a demonstration of internal
assessment and refinement. The VRF/VSL should be based on an entity either not having a program,
not demonstrating their assessment and corrective action process or egregious / systemic problems
with the implementation of their program.
Tom Bowe - OC Chair
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Consideration of Comments
Operating Personnel Communications Protocols: Project 2007-02
The Operating Personnel Communications Protocols Drafting Team thanks all commenters who
submitted comments on the proposed draft COM-003-1 Operating Personnel Communications
Protocols standard. These standards were posted for a 45-day public comment period from May 7,
2012 through June 20, 2012. Stakeholders were asked to provide feedback on the standards and
associated documents through a special electronic comment form. There were 94 sets of comments,
including comments from approximately 292 people from approximately 166 companies representing
all 10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President of Standards and Training, Herb Schrayshuen, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration:
A common theme among many entities is that the approach to COM-003-1 should be changed.
Most agreed with the comments submitted by the NERC Operating Committee that applicable
entities should be required to
a) develop written communication protocols that address the elements in draft 2 of COM-003-1,
b) train on those protocols, and
c) develop internal controls to find and correct deviances from those protocols.
After discussion, the SDT agreed with the commenters and modified its approach to closely align with
the proposal. In addition, the SDT felt that it would be beneficial to develop the RSAW for this standard
in conjunction with NERC Compliance staff, and has posted the draft RSAW for comment along with
draft 3 of COM-003-1.
1
The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_Rev%201_20110825.pdf
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Another prevalent theme was questioning the necessity of the standard, specifically one that requires
three part communication for routine operations.
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in
its approval the expedited development of a comprehensive communications program, which would
address necessary communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is necessary and what is
required) during normal operations was a necessary step in addressing the BOT’s concern.
Another theme was the concern that the work of the SDT was overreaching the scope of the SAR.
The purpose of the SAR for this project is “Require that real time system operators use standardized
communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.” Additionally, the SAR is very specific in that it also includes the term
“normal” operating conditions under Applicability: “Clear and mutually established communications
protocols used during real time operations under normal and emergency conditions ensure universal
understanding of terms and reduce errors.”
Another theme was that the use of three part communications should be limited to Reliability
Directives only.
A Reliability Directive, by definition, is limited to instances where action by the recipient is necessary to
address an Emergency or Adverse Reliability Impact. The SDT believes that it is necessary to specify 3
part communication as a necessary communications protocol for all Operating Instructions, not just
emergency situations. The OPCPSDT believes that the potential for risk to the reliability of the BES exists
for all Operating Instructions.
Other commenters expressed a desire to combine COM-002-3 and COM-003-1 into a single standard.
The purpose of the SAR for this project is “Require that real time system operators use standardized
communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.” This is a broader scope for communications than that for Project 2006-06.
Another concern was that this standard addressed “how” to communicate instead of “what” to
communicate.
When defining common communication protocols to be used for communication between entities, it is
necessary to be specific on what must be communicated and how it must be communicated.
Many commenters also questioned the purpose of the whitepaper that was posted by the SDT during
draft 2.
The whitepaper was intended to assist industry stakeholders understand the rationale behind the
content in the standard. For further information on communication guidelines, please refer to the
paper developed by the NERC Operating Committee titled “Reliability Guideline: System Operator
Verbal Communication – Current Industry Practices” located at http://www.nerc.com/filez/oc.html.
2
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
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Definitions: (Question 1)
Most commenters agreed with removing all three definitions (Communications Protocol, Three-part
Communication, and Interoperability Communication) in draft 1 of COM-003-1. However, most
commenters also disagreed with the new proposed term Operating Communications, introduced in
Draft 2 and defined as: “Communication of instruction to change or maintain the state, status, output,
or input of an Element or Facility of the Bulk Electric System.” Commenters stated:
•
The proposed term Operating Communication is still confusing and the large extent of
operations it applies to would create an overwhelming compliance exposure due to the large
number of communications described in the definition.
•
The term, Operating Communication, and its relation to the proposed term “Reliability
Directive” from COM-002-3 is unclear.
•
The meaning of the word “maintain” in the definition is unclear. The OPCP SDT changed
“maintain” to “preserve” to differentiate this term from maintenance activities.
To eliminate the confusion expressed by commenters; and to clarify the scope and intent of an
Operating Instruction, the SDT has revised the definition to read:
Operating Communication Instruction — Communication of instruction Command from a System
Operator to change or maintain preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System.
Requirements:
Requirement R1 (required entities to use the English Language (Question 4), 24 Hour Clock and Time
Zone reference (Question 5), Common interface identifiers (Question 7), and alpha-numeric clarifiers
(Question 8) during oral and written Operating Communication):
•
The majority of the commenters agreed with the SDT’s decision to remove a Communications
Protocol Operating Procedure (CPOP) because it would be administrative in nature and would
not satisfy the criterion of enhancing the reliable operation of the BES.
Many commenters supported the development of internal communication protocols and
internal controls to correct deficiencies in lieu of a zero defect standard. (Question 2)
•
The majority of commenters agreed with the SDT’s decision to remove the Alert Level Guide
from the standard but did not want it in another standard because it added no value to
reliability. (Question 3)
•
In response to Questions 4, 5, 7 and 8 dealing with the English language, 24 hour clock and time
zone reference, common interface identifiers, and alpha-numeric clarifiers, a large majority of
the commenters believe that all of subparts are too prescriptive and focus on the “how to”
instead of the “what.” The SDT acknowledges this and has defended it as necessary for this
3
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
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standard in drafts 1 and 2. When defining common communication protocols to be used for
communication between entities, it is necessary to be specific on what must be communicated
and how it must be communicated.
•
There was a lack of agreement on requiring the use of the English language as part of a
communication protocol. Some commenters support requiring the use of English, and indicated
that communicating in a language other than English would cause confusion, while others
contested requiring English exclusively, stating in some areas the use of other languages in a
localized environment may be effective. The SDT believes that English should prevail in almost
all cases and those situations where another language would be required by law would be a rare
exception. Furthermore, this requirement only applies to communication initiated by a System
Operator at one functional entity to another functional entity. The SDT added “Transmission
Operators and Balancing Authorities may use an alternate language for internal operations.” to
provide some flexibility in areas where another language is commonly used.
•
Commenters were also divided on the use the 24 hour clock and time zone references as part of
a communication protocol. Those who indicated support stated they felt it added clarity to
communications. Other commenters stated that the 24 hour clock and time zone references
are too prescriptive and should be eliminated. The SDT believes use of the 24 hour clock and
time zone references clarifies the time element of communications, which will enhance reliability
by avoiding time mistakes that could affect the reliability of the BES.
•
Commenters were confused over the meaning of the word “accurate” to modify the phrase
“alpha-numeric clarifier.” Other commenters felt the NATO requirement was too restrictive, but
indicated that the phrase “alpha-numeric clarifiers” was too vague. The SDT has chosen to
retain the inclusion of alpha-numeric clarifiers as an alternative to a strict requirement to
include the use of the NATO alphabet, but has removed the word “accurate.”
•
Many commenters stated that Requirement R1 is not necessary, stating that it is covered by
standard TOP-002 R18. The SDT is aware that Requirement R18 is being eliminated by the
RTOSDT as part of project 2007-03. Project 2007-03 chose to eliminate TOP-002-2a Requirement
R18 on the basis that “This requirement adds no reliability benefit. Entities have existing
processes that handle this issue. There has never been a documented case of the lack of uniform
line identifiers contributing to a System reliability issue. This is an administrative item, as seen in
the measure, which simply requires a list of line identifiers. The true reliability issue is not the
name of a line but what is happening to it, pointing out the difficulty in assigning compliance
responsibility for such a requirement, as well as the near impossibility of coming up with truly
unique identifiers on a nation-wide basis. The bottom line is that this situation is handled by the
operators as part of their normal responsibilities, and no one is aware of a switching error
caused by confusion over line identifiers.” COM-003-1, while reintroducing the concept of line
identifiers, limits the scope to only Transmission interface Elements or Transmission interface
4
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Requirement R2 (required entities that send Operating Communications to use three part
communication)
and
Requirement R3 (required entities that receive Operating Communications to use three part
communication)
•
Many commenters indicated that the scope of Operating Communications and the requirement
was too broad and that the sheer numbers of Operating Communications would overwhelm the
entities in terms of monitoring and evidence retention. They also are concerned that under
these Requirements, operators would be distracted to focus more on complying with the
specifications for three part communication rather than effectively responding to incidents,
thereby reducing reliability. The SDT believes universal communication protocols are critical to
avoid mistakes that would result in reduced reliability on the BES, which is within the scope of
the SDT’s SAR. After consideration of comments in these questions, as well as question 10, the
SDT has modified its approach in COM-003-1, draft 3 to address the concerns expressed by
commenters.
•
Several stakeholders continue to identify potential conflicts between COM-003-1 and work
underway on COM-002-3 by the Project 2006-06 – Reliability Coordination SDT (RCSDT), which
also addresses the use of three-part communications. Some stated that the applicability of the
two standards was confusing and called for one communication standard to reduce the
confusion. A few commenters stress this should be limited to COM-002-3 (which has been
approved by its ballot pool and is pending NERC Board approval). In COM-002-3 the proposed
requirements focus on the use of three part communication when issuing and receiving
“Reliability Directives.” As proposed in COM-002-3, a Reliability Directive is a directive issued to
address an Emergency or an Adverse Reliability Impact. The OPCP SDT believes the scope of
their SAR extends beyond communications during emergency situations, thereby necessitating a
new standard such as the proposed COM-003-1. The OPCP SDT proposes use of three-part
communication for all Operating Instructions, under normal and emergency conditions, and has
worked with the RCSDT to ensure that COM-002-3 and COM-003-1 are complementary to
achieve this objective.
•
In addition, a number of commenters pointed out that R2 and R3 of each standard dictate three
part communication but the language in each standard is different, which may create confusion.
The SDT has changed the language referring to three part communication in COM-003-1 to
match that of COM-002-3, R2 and R3.
5
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
VRFs and VSLs
The SDT acknowledges there were many comments on draft 2 regarding VSLs and VRFs and we
appreciate the contributions. The SDT has dramatically changed draft 3 and all of the VRFs and VSLs
have been changed to reflect those changes.
Additional Issues addressed by the SDT:
Small numbers of commenters raised issues around:
•
The standard’s 6 calendar month implementation time frame. The SDT has extended the
implementation period to 12 calendar months to provide an adequate amount of time for
training and implementation.
•
Whether the standard should address “all call” types of communications. The SDT has added
language to Requirements R1 and R2to clarify how these Requirements apply when all calls are
used to communicate,
•
Re writing the Purpose Statement, – The SDT modified the purpose statement in response to
comments,
•
Adding language to identify Transmission Interface "……., unless otherwise mutually agreed,”The SDT added the commenters’ recommended language.
•
Clarifying the time horizon of draft 2; real time applicability; - The SDT confirmed that draft 2
was in the real time horizon.
Outstanding Unresolved Issues:
•
Whether read receipts for written Operating Communications should be addressed in the
Measures. - This is in reference to R2 and R3 which is applicable only to oral Operating
Communication, so the SDT made no change,
•
Exclusion of R2 and R3 for Face to Face Operating Communication in a control room, - The SDT
clarified that COM-003-1 only applies to communication between functional entities. For
example, if a TOP System Operator is issuing an Operating Instruction to an individual that is
internal to that TOP, three part communication is not required by this standard. If a TOP System
Operator is issuing an Operating Instruction to an individual in another TOP or another
functional entity (e.g. Distribution Provider, Generator Operator), then three part
communication is required by this standard. If a TOP System Operator is issuing an Operating
Instruction to an individual that is not in a functional entity, then three part communication is
not required by this standard.
6
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Index to Questions, Comments, and Responses
_Toc333408803
1.
Do you agree with the addition of “Operating Communication” as a proposed new definition for
the NERC Glossary and the elimination of “Communication Protocol,” “Interoperability
Communication” and “Three part Communications” proposed in the first draft of COM-003-1?
Operating Communication: Communication of instruction to change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System. If not, please
explain in the comment area. ........................................................................................ 22
2.
The SDT eliminated the requirement to have a Communications Protocol Operating Procedure
from the proposed standard because it is administrative in nature. Do you agree with this
modification? If not, please explain in the comment area. .................................................63
3.
The SDT has proposed to transfer the requirement to use Alert Levels in Attachment 1 to
another more closely aligned standard or to a separate new standard. Do you agree with this
transfer? If not, please explain in the comment area. ....................................................... 76
4.
The SDT modified the standard to allow an exemption from the requirement to use English
language where the use of another language is mandated by law or regulation. (See
Requirement R1, Part 1.1.1) Do you agree with this modification? If not, please explain in the
comment area. ............................................................................................................87
5.
The SDT modified the standard to mandate utilization of a 24 hour clock for all times and to
mandate the use of a time zone and indicate whether the time is daylight saving time or
standard time reference when Operating Communications occur between different time zones.
(See Requirement R1, Part 1.1.3) Do you agree with this modification? If not, please explain in
the comment area. ..................................................................................................... 103
6.
The SDT modified the requirement for use of three-part communications for Operating
Communications to clarify that this is not applicable for Reliability Directives and split the
single requirement into two requirements: one for the issuer (R2) and anothr for the receiver
(R3). Do you agree with this modification? .................................................................... 121
7.
The SDT modified the requirement for use of the NATO phonetic alphabet to allow use of
another correct alpha numeric clarifier. (See Requirement R1, Part 1.2.) Do you agree with this
modification? ............................................................................................................. 154
8.
The SDT modified the requirement for use of identifiers to limit the applicability to operating
communications involving Transmission interface Elements/Facilities and to require use of the
name for that Element/Facilities specified by the Element/Facility’s owner(s). Do you agree
with this modification? ................................................................................................ 175
9.
Do you agree with the VRFs and VSLs for Requirements R1, R2 and R3? ........................... 194
10. If you have any other comments or suggestions to improve the draft standard that you have
not already provided in response to the previous questions please provide them here. ....... 210
7
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
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8
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Greg Campoli
New York Independent System Operator
NPCC 2
3.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
4.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
5.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
6.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
7.
Kathleen Goodman
ISO - New England
NPCC 2
8.
Michael Jones
National Grid
NPCC 1
9.
David Kiguel
Hydro One Networks Inc.
NPCC 1
Northeast Utilities
NPCC 1
10. Michael Lombardi
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Randy MacDonald
New Brunswick
NPCC 5
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
15. Robert Pellegrini
The United Illuminating Company
NPCC 1
16. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
17. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
18. Brian Robinson
Utility Services
NPCC 8
19. Michael Schiavone
National Grid
NPCC 1
20. Wayne Sipperly
New York Power Authority
NPCC 5
21. Tina Teng
Independent Electricity System Operator
NPCC 2
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
Group
ACES Power Marketing Standards
Collaborators
Jean Nitz
Additional Member
Additional Organization
Shari Heino
Brazos Electric Power Cooperative, Inc.
2.
Robert Thomasson Big Rivers Electric Corporation
3.
Scott Brame
North Carolina Electric Membership Corporation RFC
3, 4, 5, 1
4.
Clem Cassmeyer
Western Farmers Electric Cooperative
SPP
1, 5
5.
Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
6.
John Shaver
Arizona Electric Power Cooperative
WECC 4, 5
7.
John Shaver
Southwest Transmission Cooperative, Inc.
WECC 1
8.
Chad Wasinger
Sunflower Electric Power Corporation
SPP
Group
4
5
6
7
8
9
10
Jesus Sammy Alcaraz
X
X
X
X
X
X
X
X
X
X
Region Segment Selection
1.
3.
3
NPCC 9
12. Silvia Parada Mitchell NextEra Energy, LLC
2.
2
ERCOT 1
SERC
1
1
Imperial Irrigation District
Additional Member Additional Organization Region Segment Selection
1. Alfonso Juarez
IID
WECC 1, 3, 4, 5, 6
2. Joel Fugett
IID
WECC 1, 3, 4, 5, 6
3. Marc Printy
IID
WECC 4, 5, 6, 1, 3
4. Christopher Reyes
IID
WECC 1, 3, 4, 5, 6
10
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
Group
Midwest Reliability Organization NERC
Standards Review Forum
William Smith
X
2
3
4
5
X
X
X
X
X
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Tom Webb
WPS
MRO
3, 4, 5, 6
4.
Jodi Jenson
WAPA
MRO
1, 6
5.
Ken Goldsmith
ALTW
MRO
4
6.
Alice Ireland
XCEL (NSP)
MRO
1, 3, 5, 6
7.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
8.
Eric Ruskamp
LES
MRO
1, 3, 5, 6
9.
Joseph DePoorter
MGE
MRO
3, 4, 5, 6
10. Scott Nickels
RPU
MRO
4
11. Terry Harbour
MEC
MRO
6, 1, 3, 5
12. Marie Knox
MISO
MRO
2
13. Lee Kittelson
OTP
MRO
1, 3, 5, 6
14. Scott Bos
MPW
MRO
1, 3, 5, 6
15. Tony Eddleman
NPPD
MRO
1, 3, 5
16. Mike Brytowski
GRE
MRO
1, 3, 5, 6
17. Dan Inman
MPC
MRO
1, 3, 5, 6
5.
Kent Kujala
Group
Detroit Edison
Additional Member Additional Organization Region Segment Selection
1. Barbara Holland
DECo
RFC
3, 4, 5
2. Jeffrey DePriest
DECo
RFC
3, 4, 5
3. Alexander Eizans
DECo
RFC
3, 4, 5
6.
Group
Greg Rowland
Duke Energy
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Ed Ernst
Duke Energy
SERC
3
3. Dale Goodwine
Duke Energy
SERC
5
11
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Greg Cecil
7.
Duke Energy
Group
RFC
Patricia Robertson
Additional Member
4
5
6
7
8
9
10
BC Hydro
X
Additional Organization Region Segment Selection
WECC 2
2. Pat G. Harrington
BC Hydro
WECC 3
3. Clement Ma
BC Hydro
WECC 5
Group
3
6
1. Venkataramakrishnan Vinnakota BC Hydro
8.
2
Connie Lowe
Dominion
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
Michael Crowley
SERC
1, 3, 5, 6
2.
Louis Slade
RFC
5, 6
3.
Mike Garton
NPCC 5, 6
4.
Lou Oberski
MRO
9.
Group
Thomas McElhinney
5, 6
JEA
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
JEA
FRCC
1
2. Garry Baker
JEA
FRCC
3
3. John Babik
JEA
FRCC
5
10.
Group
David Dockery
Additional Member
Associated Electric Cooperative JRO00088
1.
Central Electic Power Cooperative
SERC
1, 3
2.
KAMO Electric Cooperative
SERC
1, 3
3.
M & A Electric Power Cooperative
SERC
1, 3
4.
Northeast Missouri Electric Power Cooperative
SERC
1, 3
5.
N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6.
Sho-Me Power Electric Cooperative
SERC
1, 3
7.
Associated Electric Cooperative, Inc.
SERC
1, 3, 5, 6
11.
Group
Ron Sporseen
Additional Member
1.
Joe Jarvis
X
Additional Organization Region Segment Selection
Additional Organization
PNGC Small Entity Comment Group
X
X
Region Segment Selection
Blachly-Lane Electric Cooperative WECC 3
12
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power Company
WECC 3
4.
Roman Gillen
Consumers Power Inc.
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Bryan Case
Fall River Electric Cooperative
WECC 3
7.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
8.
Annie Terracciano
Northern Lights Inc.
WECC 3
9.
Aleka Scott
PNGC Power
WECC 4
10. Heber Carpenter
Raft River Electric Cooperative
WECC 3
11. Steve Eldrige
Umatilla Electric Cooperative
WECC 1, 3
12. Marc Farmer
West Oregon Electric Cooperative WECC 4
13. Margaret Ryan
PNGC Power
WECC 8
14. Rick Paschall
PNGC Power
WECC 3
12.
2
3
Group
Brent Ingebrigtson
No additional members listed.
LG&E and KU Services
X
X
13.
Pepco Holdings Inc & Affiliates
X
X
X
X
Group
David Thorne
4
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Mark Jones
Pepco
RFC
3
2. Mike Mayer
DPL
RFC
3
3. Nicole Buckman
ACE
RFC
3
4. David Thorne
Pepco
RFC
1
14.
Group
Ron Sporseen
Additional Member
PNGC Small Entity Comment Group
Additional Organization
X
X
Region Segment Selection
1.
Joe Jarvis
Blachly-Lane Electric Cooperative WECC 3
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power Company
WECC 3
4.
Roman Gillen
Consumers Power Inc.
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Bryan Case
Fall River Electric Cooperative
WECC 3
7.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
13
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
8.
Annie Terracciano
Northern Lights Inc.
WECC 3
9.
Aleka Scott
PNGC Power
WECC 4
10. Heber Carpenter
Raft River Electric Cooperative
WECC 3
11. Steve Eldrige
Umatilla Electric Cooperative
WECC 1, 3
12. Marc Farmer
West Oregon Electric Cooperative WECC 4
13. Margaret Ryan
PNGC Power
14. Rick Paschall
PNGC Power
4
5
6
7
8
9
10
WECC 3
MEAG Power, Danny Dees, Steven Grego,
Steve Jackson
Group
Scott Miller
No additional members listed.
Group
3
WECC 8
15.
16.
2
Albert DiCaprio
X
X
X
X
X
X
ISO/RTO Standards Review Committee
Additional Member Additional Organization Region Segment Selection
1.
Greg Campoli
NYISO
NPCC
2.
Gary DeShazo
CAISO
WECC 2
3.
Matt Goldberg
ISONE
NPCC
2
4.
Ben Li
IESO
NPCC
2
5.
Stephanie Monzon
PJM
RFC
2
6.
Steve Myers
ERCOT
ERCOT 2
7.
Bill Phillips
MISO
RFC
8.
Mark Thompsoon
AESO
WECC 2
9.
Don Weaver
NBSO
NPCC
2
SPP
10. Charles Yeung
2
2
SPP
2
11. Kathleen Goodman ISONE
NPCC
2
12. Terry Bilke
MISO
RFC
2
17.
Shaun Anders
Group
City Water Light and Power
X
Additional Member Additional Organization Region Segment Selection
1. Roger Powers
CWLP
SERC
2. Steve Rose
CWLP
SERC
18.
Group
Sasa Maljukan
Hydro One Networks Inc.
X
Additional Member Additional Organization Region Segment Selection
14
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1. David Kiguel
19.
3
4
5
6
7
8
9
10
Hydro One Networks Inc. NPCC 1
Group
Robert Rhodes
Additional Member
X
SPP Standards Review Group
Additional Organization
Region Segment Selection
1.
John Allen
City Utilities of Springfield
SPP
1, 4
2.
Michelle Corley
CLECO
SPP
1, 3, 5
3.
Gary Cox
Southwestern Power Adminstration
SPP
1, 5
4.
John Geil
Sunflower Electric Power Corporation
SPP
1
5.
Allan George
Sunflower Electric Power Corporation
SPP
1
6.
Ron Gunderson
Nebraska Public Power District
MRO
1, 3, 5
7.
Ed Hammons
Grand River Dam Authority
SPP
1, 3, 5
8.
Jonathan Hayes
Southwest Power Pool
SPP
2
9.
Bo Jones
Westar Energy
SPP
1, 3, 5, 6
10. Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
11. Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
12. Paul Lampe
City of Independence, Power & Light Department SPP
3
13. Tara Lightner
Sunflower Electric Power Corporation
SPP
1
14. Julie Lux
Westar Energy
SPP
1, 3, 5, 6
15. Greg McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
16. Stephen McGie
City of Coffeyville
SPP
17. Jerry McVey
Sunflower Electric Power Corporation
SPP
1
18. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
19. Randy Root
Grand River Dam Authority
SPP
1, 3, 5
20. Sean Simpson
Board of Public Utilities of Kansas City, KS
SPP
21. Ashley Stringer
Oklahoma Municipal Power Authority
SPP
4
22. Jim Useldinger
Kansas City Power & Light
SPP
1, 3, 5, 4
23. Chad Wasinger
Sunflower Electric Power Corporation
SPP
1
20.
Scott Kinney
Group
2
Avista
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Scott Kinney
Avista
WECC 1
2. Ed Groce
Avista
WECC 5
3. Bob Lafferty
Avista
WECC 3
15
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
21.
Group
Frank Gaffney
Florida Municipal Power Agency
2
3
X
X
X
X
X
X
4
5
6
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
22.
Group
FRCC
Sam Ciccone
FirstEnergy
X
Additional Member Additional Organization Region Segment Selection
1. J. Reed
FE
RFC
2. M. Klohanatz
FE
RFC
3. L. Raczkowski
FE
RFC
4. B. Orians
FE
RFC
5. J. Anderson
FE
RFC
6. R. Loy
FE
RFC
7. B. Duge
FE
RFC
23.
Group
Gerald Beckerle
SERC OC Standards Review Group
Additional Member Additional Organization Region Segment Selection
1.
Stuart Goza
TVA
SERC
2.
Mike Hirst
Cogentrix
SERC
3.
Phil Whitmer
Southern
SERC
4.
Eugene Warnecke
Ameren
SERC
5.
Jeff Harrison
AECI
SERC
6.
Terry Bilke
MISO
SERC
7.
Mike Hardy
Southern
SERC
8.
Chris McNeil
Santee Cooper
SERC
9.
Jake Miller
Dynegy
SERC
Entergy
SERC
10. Jim Case
16
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Albert DiCaprio
PJM
SERC
12. William Berry
OMU
SERC
13. Joel Wise
TVA
SERC
14. Greg Stone
Duke
SERC
15. John Rembold
SIPC
SERC
16. Scott Brame
NCEMC
SERC
17. Merrit Castello
Southern
SERC
18. Chris Bolick
AECI
SERC
19. Tom Hanzlik
SCE&G
SERC
20. Brad Young
LGE-KU
SERC
21. Greg Matejka
CWLP
SERC
22. Timmy Lejeune
NRG Energy
SERC
23. Wayne Van Liere
LGE-KU
SERC
24. Dale Walters
CWLP
SERC
25. Ed Davis
Entergy
SERC
24.
Steve Rueckert
Group
2
3
4
5
6
7
8
9
10
X
Western Electricity Coordinating Council
Additional Member Additional Organization Region Segment Selection
1. John McGhee
WECC
WECC 10
2. Phil O'Donnell
WECC
WECC 10
25.
Group
Chris Higgins
Bonneville Power Administration
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Jim
Burns
WECC 1
2. Tim
Loepker
WECC 1
3. Dick
Winters
WECC 1
4. Rodney
Krause
WECC 1
5. Erika
Doot
WECC 3, 5, 6
6. Tedd
Snodgrass
WECC 1
26.
Group
Mary Jo Cooper
Additional Member
1. City of Lodi
GP Strategies
Additional Organization Region Segment Selection
WECC 3
17
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. City of Ukiah
WECC 3
3. Alameda Municipal Power
WECC 3
4. Pasadena Water and Power
WECC 1, 3
5. Salmon River Electric Co-op
WECC 1, 3
6. California Pacific Electric Company
WECC 3
Group
Tom Bowe - OC Chair
NERC Operating Committee Members
NERC Operating Committee
X
28.
Progress Energy
X
Individual
Jim Eckelkamp
Janet Smith, Regulatory
Affairs Supervisor
30.
Individual
Antonio Grayson
31.
Individual
32.
2
6
X
X
X
X
X
X
X
Southern Company
X
X
X
X
Hertzel Shamash
The Dayton Power and Light Company
X
X
X
Individual
D Mason
HHWP
X
33.
Individual
Mace Hunter
Lakeland Electric
X
34.
Individual
John D. Brockhan
CenterPoint Energy Houston Electric, LLC.
X
35.
Individual
Michael Falvo
IESO
36.
Individual
Thad Ness
American Electric Power
37.
Individual
Ronnie C. Hoeinghaus
City of Garland
X
Individual
39. Individual
Russ Schneider
Joe O'Brien
Flathead Electric Cooperative, Inc.
NIPSCO
X
X
X
40.
Individual
Joe Tarantino
SMUD
X
X
41.
Individual
Daniel Duff
Liberty Electric Power LLC
42.
Individual
Jennifer Wright
X
X
Individual
Stephen J. Berger
San Diego Gas & Electric
PPL Generation, LLC on behalf of its Supply
NERC Registered Entities
44.
Individual
Cristina Papuc
TransAlta Centralia Generation LLC
45.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
29.
38.
43.
X
5
X
Individual
X
4
X
27.
X
3
7
X
8
X
9
10
X
Arizona Public Service Company
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
18
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
Brad Chase
Orlando Utilities Commission
X
Individual
48. Individual
Jack Stamper
Jonathan Appelbaum
Clark Public Utilities
The United illuminating Company
X
49.
Individual
Scott Berry
Indiana Municipal Power Agency
50.
Individual
Michelle D'Antuono
Ingleside Cogeneration LP
51.
Individual
Roger C. Zaklukiewicz
Roger Zaklukiewicz Consulting
52.
Individual
Michael Moltane
ITC Holdings
X
53.
Individual
Joe Tarantino
Sacramento Municipal Utility District
X
X
54.
Individual
Ed Davis
Entergy Services
X
X
55.
Individual
Anthony Jablonski
ReliabilityFirst
56.
Individual
Brian Evans-Mongeon
Utility Services, Inc.
57.
Individual
Wayne Sipperly
New York Power Authority
X
X
58.
Individual
Andrew Gallo
X
X
Individual
J. S. Stonecipher, PE
City of Austin dba Autin Energy
City of Jacksonville Beach dba/Beaches
Energy Services
60.
Individual
Warren Rust
Colorado Springs Utilities
X
61.
Individual
Patrick Brown
Essential Power, LLC
62.
Individual
Bob Steiger
Salt River Project
63.
Individual
Robert L Dintelman
Utility System Efficiencies, InC.
64.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
65.
Individual
Howard Rulf
Wisconsin Electric dba We Energies
X
66.
Individual
Eric Scott
City of Palo Alto
67.
Individual
Joe Petaski
Manitoba Hydro
X
X
X
X
X
68.
Individual
John Seelke
Public Service Enterprise Group
Portland General Electric - Transmission &
Reliability Services
X
X
X
X
46.
Individual
47.
59.
69.
Individual
John T. Walker
X
6
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
19
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
Denise Lietz
Puget Sound Energy
X
Individual
72. Individual
Brenda Truhe
Bob Thomas
PPL Electric Utilities
Illinois Municipal Electric Agency
X
73.
Alice Ireland
X
X
X
X
70.
Individual
71.
X
5
X
X
X
X
X
X
John D. Martinsen
75.
Individual
Kirit Shah
Ameren
X
X
76.
Individual
Greg Travis
Idaho Power Company
X
X
77.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
X
78.
Individual
Marie Knox
MISO
79.
Individual
Eric Salsbury
Consumers Energy
80.
Individual
Karen Webb
City of Tallahassee
81.
Individual
Brian Murphy
NextEra Energy, Inc
X
X
82.
Individual
Randall McCamish
City of Vero Beach
X
X
83.
Individual
Don Jones
Texas Relibility Entity
84.
Individual
Kenneth A Goldsmith
Alliant Energy
85.
Individual
Kathleen Goodman
ISO New England Inc
86.
Individual
Steven Wallace
Seminole Electric Cooperative
87.
Individual
Martin Bauer
U.S. Bureau of Reclamation
88.
Individual
Rich Salgo
NV Energy
X
X
X
89.
Individual
Maggy Powell
Exelon Corporation and its affiliates
X
X
X
90.
Individual
Tony Kroskey
Brazos Electric Power Cooperative
91.
Individual
Oncor Electric Delivery Company LLC
Individual
Darryl Curtis
Steve Alexanderson
P.E.
X
X
Individual
Richard Vine
California Independent System Operator
93.
7
8
9
10
X
Individual
92.
6
X
Xcel Energy
Public Utility District No. 1 of Snohomish
County
74.
Individual
4
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Central Lincoln
X
20
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
94.
Individual
Jennifer Flandermeyer
Kansas City Power & Light
X
2
3
X
4
5
X
6
7
8
9
10
X
21
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
1.
Do you agree with the addition of “Operating Communication” as a proposed new definition for the NERC Glossary and the
elimination of “Communication Protocol,” “Interoperability Communication” and “Three part Communications” proposed in
the first draft of COM-003-1? Operating Communication: Communication of instruction to change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System. If not, please explain in the comment area.
Summary Consideration: Major Issues
The majority of commenters agreed with eliminating the three original definitions in draft 1; however the same majority had
concerns about the proposed definition of Operating Communications. The concern is that the definition and the manner in which it
was used in the requirements in COM-003-1 were potentially over reaching. Most commenters indicated that the evidence
requirements would also strain an entity’s resources and would not improve reliability. The SDT believes that the use of the
protocols, many of which are now in use by industry stakeholders, should be a required part of BES operations and communication.
The SDT also believes that use of these protocols enhance reliability by providing a structure for communication that clarifies intent
and meaning. This in turn provides a layer of defense in the reliable operation of the BES.
Many commenters indicated that they do not agree that the term Operating Communication is needed and believe that Reliability
Directive, as defined in COM-002-3 is the only term needed to clarify the type of communications that should require three part
communications. Some comments indicate that the scope of communications that would be considered Operating Communications
was not sufficiently clear, and could include casual control room conversations and discussion over potential alternatives. The SDT
believes the scope of the SAR extends beyond communications during emergency situations, thereby necessitating a term that
involves communications during all situations, both normal and emergency. To clarify the intent and scope of the term, the SDT
renamed the term Operating Communications to Operating Instruction, and modified the definition to “Command from a System
Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System.”
Commenters also stated the SDT has exceeded the scope of the SAR, the 2003 Blackout Report recommendations, and FERC Order
693. The SDT is confident that the concepts in COM-003-1 appropriately address the Blackout Report recommendations, FERC Order
693 and the SAR. The SDT also believes that the concepts in COM-003-1 address a reliability gap that exists because the vast
numbers of Operating Communications that affect the state of BES Elements or BES Facilities are not currently subject to consistent
protocols that clarify content and intent. This increases the risk of mistakes that could degrade the reliability of the BES.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
A few commenters questioned the purpose and the standing of the White Paper the SDT drafted. The SDT responded that the
Standards Committee requested that the team develop the White Paper to provide its justification for the application of
Communication protocols. The White Paper was posted for information, not for industry approval.
A number of stakeholders agreed with the changes to replace the previous three defined terms with a single defined term,
Operating Communication.
Organization
Northeast Power Coordinating
Council
Yes or No
No
Question 1 Comment
The proposed Operating Communication term is not markedly different
from the originally proposed term (Interoperability Communication).
Response: The SDT believes the term Operating Communication focuses on
very specific actions that affect the reliability of the BES, making it more
specific than Interoperability Communication. Based on comments
received about the scope and intent of an Operating Communication, the
SDT has revised the term to be Operating Instruction and changed the
definition to be “command from a System Operator to change or preserve
the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System.”
The proposal continues to expand the scope of the SAR from the concept of
tightening the protocols associated with Emergencies by now applying to all
communications. The text box in the draft standard indicates that Reliability
Directives are a type of Operating Communications, to the extent they
change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. There is little difference between the
two terms despite the SDT’s assessment that Reliability Directive is a type
(or a subset) of Operating Communication. If the intent is to use the
proposed new term to require three-part communication (as suggested in
R2 and R3), then that intent can be accomplished by using the term
Reliability Directive as it covers not only the emergency state but also
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
instructions needed to address Adverse Reliability Impacts.
Response: The purpose of the SAR for this project is “Require that real
time system operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and
shorten response time.” The SDT does not believe that it has expanded
the scope of this SAR. Reliability Directive, as defined in COM-002-3, is
specifically focused on Emergencies or Adverse Reliability Impacts. The
scope of COM-003-1 is to require the use of common communication
protocols for all BES operations that affect the state of the BES.
Both the Blackout Report and the FERC directive deal with tightening
protocols for Emergencies. The proposed requirements completely fail to
address emergencies and focus solely on developing non-emergency
protocols.
Response: The OPCPSDT disagrees that both the Blackout Report (and
FERC Order 693 and the SAR) only addresses the need to tighten protocols
for Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating situations and used this language to amplify the
importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
Response: Thank you for your comments. Please see the responses above.
ACES Power Marketing Standards
No
1. We do not agree with the need to use three-part communication for all
operations on the BES. Requiring entities to employ three-part
24
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Collaborators
Yes or No
Question 1 Comment
communication for routine operating instructions is excessive and
burdensome. The 2003 Blackout Report recommended that industry,
“Tighten communications protocols, especially for communications during
alerts and emergencies.” We strongly support using three-part
communication for the execution of Reliability Directives as defined in the
proposed COM-002-3 draft standard in Project 2006-06 but not for routine
operating instructions.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
2. The COM-003-1 Operating Communications Protocols White Paper states
three reliability benefits of using three-part communication as follows:
a. “The removal of any doubt that communication protocols will be used
and when they will be used. This will reduce the opportunity for confusion
and misunderstanding among entities that may have different doctrine.”
We don’t agree with the premise that implementing three-part
communications for all operating instructions will reduce confusion. If
there is a standard such as draft COM-002-3 that requires the use of threepart communication for Reliability Directives and the issuer is required to
state that a Reliability Directive is being issued, then there should be no
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
confusion.
Response: The Blackout study cites a scenario where communication was
unprofessional and confused. Communication protocols should used
before, during, and after emergency conditions.
The example provided in this bullet where “one entity uses three-part for
emergencies, and the other uses it for all operating conditions” is used to
support the premise. However, Table 1-A of the White Paper only lists 11
entities that currently use three-part communication during both
emergencies and non-emergencies. Eleven out of how many entities? The
paragraph immediately following Table 1-A states, “The fact that the
majority of BES entities already employs three-part (or repeat back)
communications for routine...operations...” Eleven entities do not make a
majority. We don’t believe the actions of a few should dictate the actions of
all. Much stronger evidence to support this “fact” is needed.
Response: The SDT sampled major entities that manage significant
amounts of load and serve large numbers of customers to capture the
magnitude of impact of the sample on the BES. The SDT is confident that it
would have achieved the same results if it sampled 100 additional entities
based on the overwhelming consistency in the results provided in Table 1A.
b. “There will be no mental “transition” when operating conditions shift
from normal to Emergency.” Once again, if there is a standard such as COM002-3 that requires three-part communication for Reliability Directives and
the issuer is required to state that a Reliability Directive is being issued, then
there should be no confusion. System Operators are trained to make mental
transitions every day. It is an inherent characteristic of the job. Operators
should be able to mentally “transition” when a Reliability Directive is issued.
Response: The SDT agrees that most System Operators are highly trained
26
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
and experienced, but it is risky to discount the human factor in
communications. Low frequency, high impact events such as the 2003
Blackout are of such speed and magnitude that it is only natural to
anticipate a potential inaccurate mental “transition.”
c. “The formal requirement for three-part communication will create a
heightened sense of awareness in operators that the task they are about to
execute is critical...” Not all operating instructions are “critical” so this
premise is flawed. This bullet makes perfect sense for Reliability Directives
because the actions taken to address those would be considered critical
based on the proposed definition of Reliability Directive in COM-002-3. It
does not make sense for routine operating instructions.
Response: The SDT believes that every instruction for a change to the BES
carries some risk. If unclear communication causes an operator to open the
wrong switch on an already compromised system the results could lead to
an undesirable event.
3. Based on the above, we do not agree with the definition of Operating
Communication as proposed in this draft standard since we do not support
the use of three-part communication for all operations on the BES.
Response: Thank you for your comments. Please see the responses above.
Midwest Reliability Organization
NERC Standards Review Forum
No
The MRO NSRF recommends the following comments for consideration by
the SDT:
1. The sentence structure of this definition is incorrect. It is unclear
whether the prepositional phrase “of the Bulk Electric System” applies to
both Facility and Element or only to a Facility. Recommend this be rewritten
to read “... Bulk Electric System Elements and Facilities”.
Response: The SDT has reworded the definition in response to your
27
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
comment.
2. The definition should be for only actionable commands (to accomplish an
actionable item). Status of does necessitate 3 part communication.
Response: The context was “maintain the status” which is an actionable
command. The intent was related to commands to preserve the stability of
a normally operating system. The SDT has proposed “preserve” as an
alternative to “maintain” in draft 3.
3. The inclusion of a Reliability Directive as a subset of the Operating
Communication definition adds confusion as to what is a Reliability
Directive. This confusion is compounded by having Reliability Directives in a
different standard with different descriptions for three part communication.
Response: The SDT has adopted the language in COM-002-3, R2 and R3 for
three part communication. This change to make the two standards
consistent is intended to reduce any potential for confusion.
4. The 2003 Blackout Report recommended that industry, “Tighten
communications protocols, especially for communications during alerts and
emergencies.” We strongly support using three-part communication for the
execution of Reliability Directives as defined in the proposed COM-002-3
draft standard in Project 2006-06 but not for routine operating instructions.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
28
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
5. Table 1-A of the White Paper lists 11 entities that currently use three-part
communication during both emergencies and non-emergencies. We agree
that this can be an utility ‘best practice’, however, there is a major
difference between good utility practice and a no-fault, no exception
Reliability Standard.
Response: The SDT acknowledges your position and has developed an
alternative form of the standard that addresses your comment.
Response: The OPCPSDT appreciates your comments.
Detroit Edison
No
The definition of Operating Communication is overly broad, increasing the
scope of the standard. It should be limited to actionable items. Suggested
rewording of the definition: "Communication of instruction to perform an
action relating to a physical change or a control system data change
affecting an Element or Facility of the Bulk Electric System."
Response: The OPCPSDT appreciates your comments. It was not the intent to include control system data change in the scope
of Operating Communication. In response to your comment and other similar comments, the definition has been modified to
“Command from a System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric
System or Facility of the Bulk Electric System.”
Duke Energy
No
The definition of Operating Communication is vague, general and overly
broad.
Response: The definition has been modified to “Command from a System
Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
29
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
We don’t believe the Blackout Report recommendations and Order 693
directives require 3-part communications for routine communications.
Communications protocols can be tightened, and more effective
communications can be achieved without this extreme approach. See our
comments under question #2.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
Response: Thank you for your comments. Please see the responses above.
BC Hydro
No
BC Hydro does not support limiting operating communications to
instructions. We believe this should account for notification or reporting
and that in these cases three part communication should be used to ensure
understanding. For example, if an element is out of service and that is being
reported to an operating entity, the receiver of that communication should
show confirmation of understanding by repeating their understanding and
receiving confirmation.
Example:
1) TOP Call to RC: Our transmission Line XX is currently out of service and is
30
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
expected to remain out until field crews respond.
2) RC to TOP: OK, I understand that Line XX is out of service and will remain
out until further notice.
3) TOP to RC: That’s correct. I’ll call you when I have some more
information.
Response: Thank you for your comments. The SDT applauds your use of three part communication beyond our proposal and
believes it adds clarity and enhances reliability. The SDT is not inclined at this point to broaden the scope of communications
that would require the use of three part communications, but does not discourage entities who wish to employ three-part
communication more broadly.
Dominion
No
Dominion agrees with the elimination of Communication Protocol,
Interoperability Communication and Three part Communications proposed
in the first draft.
Each standard requirement (R1, R2 & R3) specifically excludes Reliability
Directives; further adding confusion to the issue of what is a reliability
directive.
Response: COM-003-1, draft 2, R1 does apply to Reliability Directives. R2
and R3 had exclusion language to preclude potential double jeopardy with
the requirements of COM-002-3, R2 and R3. The SDT has modified it
approach in the latest draft, which should eliminate the confusion.
The Reliability Directive should stand on its own and if the SDT does not
agree then the relationship between Reliability Directives and Operating
Communications should be clarified in the Standard. When the standard is
implemented, the text box (on page 2 of the clean standard) will be
removed, therefore losing any tieback to a Reliability Directive as a type of
operating communication.
Response: The SDT acknowledges this confusion and has been working
31
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
with RCSDT to address it. The June 7th Webinar (Posted under Project
2007-02) addressed this issue and may provide additional clarification.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_200702_June_7_2012_final.pdf
Response: Thank you for your comments. Please see the responses above.
Associated Electric Cooperative
JRO00088
No
Although the intent appears to be only for oral communications of NERC
Certified System Operators, and those directly aimed at affecting the altered
or continued state of BES elements of Facilities, the wording is insufficiently
bounded. For instance, it could include any communications between a unit
or plant operator and internal plant personnel, were the net output of the
plant to change, significantly or insignificantly, current or future (status), its
injection to the BES. The same would be true of loads, and so
communication of Distribution providers with any manufacturing plant
managers would necessarily become subject to this standard (extractions
from the BES - significant or insignificant). Taken to one extreme,
purchasing personnel could also be responsible for whatever part their
telephone conversations play in altering the future status of plant real or
reactive power production or consumption. AECI agrees with the SERC OC
STANDARDS REVIEW GROUP consensus comment, that COM-002 should be
sufficient in addressing any industry deficiencies in this area and if not, the
deficiencies addressed there.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
32
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
LG&E and KU Services
Yes or No
No
Question 1 Comment
LG&E and KU Services do not agree with the proposed definition of
Operating Communication and agree with eliminating the other three
definitions. The standard appears to be focused on imposing three part
communications on the industry for routine communications despite the
fact that neither the blackout report nor the SAR on which these standards
are based emphasize that issue.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
The blue text box that mentions Reliability Directives seems to be a back
door attempt to change COM-002 and should be clarified or eliminated.
Splitting communications requirements across different standards creates
unnecessary confusion
Response: The blue text box and the exclusionary language regarding
Reliability Directives in COM-003-1, R2 and R3 were added to address
concerns over potential double jeopardy. The SDT has modified its
approach in the latest draft.
Response: Thank you for your comments. Please see the responses above.
33
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Pepco Holdings Inc & Affiliates
Yes or No
No
Question 1 Comment
The distinction between Operating Communication definition and the
Reliability Directive being a type of Operating Communication is confusing.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
MEAG Power, Danny Dees, Steven
Grego, Steve Jackson
No
Operating communication is not necessarily three part communication. If
three part communication is being required, then it should be defined as
three part communication.
Response: Thank you for your comments. Operating Communication is a definition to categorize any instruction that directly
orders reconfiguration of the BES. The SDT developed requirements to utilize three part communication when issuing or
receiving an Operating Communication to reduce the potential for a miscommunication that could reduce BES reliability.
ISO/RTO Standards Review
Committee
No
The SRC agrees with the elimination of the three terms but not with the
addition of “Operating Communication”.
Thank you for your comments.
The SRC does not believe that the proposed term (Operating
Communication) is sufficiently different from the originally proposed term
(Interoperability Communication) to warrant adoption.
Response: The SDT believes the term Operating Communication is more
distinct than Interoperability Communication because it focuses on very
specific actions that affect reliability on the BES. Based on comments
received about the scope and intent of an Operating Communication, the
SDT has revised the term to be Operating Instruction and changed the
definition to be “command from a System Operator to change or preserve
the state, status, output, or input of an Element of the Bulk Electric System
34
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
or Facility of the Bulk Electric System.”
The SDT’s proposal continues to expand the scope of the SAR from the
concept of tightening the protocols associated with Emergencies or Adverse
Reliability Impact to now applying to all communications. The text box in
the draft standard indicates that Reliability Directives are a type of
Operating Communications, to the extent they change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System.
We see little difference between the two terms despite the SDT’s
assessment that Reliability Directives is a type (or a subset) of Operating
Communication. If the SDT intent is to use the proposed new term to require
3-part communication (as suggested in R2 and R3), then that intent can be
accomplished by using the term Reliability Directives as it covers not only
emergency state but also instructions needed to address Adverse Reliability
Impacts.
Response: The purpose of the SAR for this project is “Require that real
time system operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and
shorten response time.” The SDT does not believe that it has expanded
the scope of this SAR. Reliability Directive, as defined in COM-002-3, is
specifically focused on Emergencies or Adverse Reliability Impacts. The
scope of COM-003-1 is to require the use of common communication
protocols for all BES operations that affect the state of the BES.
Please also see our comments under Q6 regarding the use of the proposed
term to support the requirements for 3-part communication. The SRC would
note that both the Blackout Report and the FERC directive deal with
tightening protocols for Emergencies, whereas the proposed SDT
requirements completely fail to address emergencies and focuses solely on
developing non-emergency protocols.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
SRC Note: there is no mention in the Blackout Report of “operational
communications breakdowns re: changing states of equipment; most of the
documentation points to:
(1) emergencies/alerts; and
(2) notification OUTSIDE of the entity experiencing the problem. The SRC
requests that in the next posting the SDT provide real examples (without
naming the registered entities) where reliability was jeopardized by the
failure of 3-part communications under routine operational situations.
Effectiveness of Communications “Under normal conditions, parties with
reliability responsibility need to communicate important and prioritized
information to each other in a timely way, TO HELP PRESERVE THE
INTEGRITY OF THE GRID. THIS IS ESPECIALLY IMPORTANT IN EMERGENCIES.
DURING EMERGENCIES, OPERATORS SHOULD BE RELIEVED OF DUTIES
UNRELATED TO PRESERVING THE GRID. A COMMON FACTOR IN SEVERAL OF
THE EVENTS DESCRIBED ABOVE WAS THAT INFORMATION ABOUT OUTAGES
OCCURRING IN ONE SYSTEM WAS NOT PROVIDED TO NEIGHBORING
SYSTEMS.” (2003 Blackout Report, page 108)26. “Tighten communications
protocols, ESPECIALLY FOR COMMUNICATIONS DURING ALERTS AND
EMERGENCIES. UPGRADE COMMUNICATION SYSTEM HARDWARE WHERE
APPROPRIATE. NERC should work with reliability coordinators and control
area operators to improve the EFFECTIVENESS OF INTERNAL AND EXTERNAL
COMMUNICATIONS DURING ALERTS, EMERGENCIES, OR OTHER CRITICAL
SITUATIONS, AND ENSURE THAT ALL KEY PARTIES, INCLUDING STATE AND
LOCAL OFFICIALS, and RECEIVE TIMELY AND ACCURATE INFORMATION.”
(2003 Blackout Report, page 108)SRC note - Nowhere in the above quoted
Recommendation 26 is there a reference to person-to-person
communications of required actions; rather it references communication of
the state of the operating system itself.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
SRC Note: there is no mention in FERC Order 693 of “operational
communications breakdowns re: changing states of equipment; the Order
does state:
532. “While we agree with EEI that EOP-001-0, Requirement R4.1 requires
communications protocols to be used during emergencies, we believe, and
the ERO agrees, that the communications protocols need to be tightened to
ensure Reliable Operation of the Bulk-Power System. We also believe an
integral component in tightening the protocols is to establish
communication uniformity as much as practical on a continent-wide basis.
This will eliminate possible ambiguities in communications during normal,
alert and emergency conditions. This is important because the Bulk-Power
System is so tightly interconnected that system impacts often cross several
operating entities’ areas.”SRC note - The above section concerns “ineffective
communications” not “incorrect communications”. The key to the above is
“communication uniformity” not 3 part communications. The SRC believes
the both the FERC Order’s directives and the Blackout Report
Recommendation 26 are clear in their respective requests to address
general protocols; and that neither request suggests a need for mandating a
specific procedure let alone 3 part communications for all operational
communications.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions.
FERC Order 693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
SAR are very specific in that both include the term “normal” operating
conditions.
Response: Thank you for your comments. Please see the responses above.
City Water Light and Power
No
Definition is overly broad and should at least be tailored to indicate the
operating time frame is the relevant concern.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
Hydro One Networks Inc.
No
The proposed Operating Communication term is not sufficiently different
from the originally proposed term (Interoperability Communication). The
proposal continues to expand the scope of the SAR from the concept of
tightening the protocols associated with Emergencies to now applying to all
communications. The text box in the draft standard indicates that Reliability
Directives are a type of Operating Communications, to the extent they
change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System. There is little difference between the
two terms despite the SDT’s assessment that Reliability Directive is a type
(or a subset) of Operating Communication. If the intent is to use the
proposed new term to require 3-part communication (as suggested in R2
and R3), then that intent can be accomplished by using the term Reliability
Directive as it covers not only the emergency state but also instructions
needed to address Adverse Reliability Impacts.
Response: The purpose of the SAR for this project is “Require that real
time system operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
shorten response time.” The SDT does not believe that it has expanded
the scope of this SAR. Reliability Directive, as defined in COM-002-3, is
specifically focused on Emergencies or Adverse Reliability Impacts. The
scope of COM-003-1 is to require the use of common communication
protocols for all BES operations that affect the state of the BES.
Both the Blackout Report and the FERC directive deal with tightening
protocols for Emergencies. The proposed requirements completely fail to
address emergencies and focus solely on developing non-emergency
protocols.
Response: The OPCPSDT disagrees that the Blackout Report and FERC
Order 693 only address the need to tighten protocols for Emergencies. The
Blackout Report uses the phrase “especially for emergencies” which the
SDT interprets to mean the authors were recommending applicability of
communication protocols for the total population of operating
communication and used this language to amplify the importance of such
protocols during emergency conditions. FERC Order 693 paragraph 532
(“This will eliminate possible ambiguities in communications during
normal, alert and emergency conditions”) and the SAR are very specific in
that both include the term “normal” operating conditions.
COM-003-1 applies to communications in both emergency and nonemergency situations. R2 and R3 had exclusion language to preclude
potential double jeopardy with the requirements of COM-002-3, R2 and
R3.
Response: Thank you for your comments. Please see the responses above.
SPP Standards Review Group
No
The definition is fine but it may not be necessary based on the comments
provided to the remaining questions below. It’s not so much what’s
contained in the definition; it’s more about what the standard requires the
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
industry to do with that definition. We believe eliminating the other three
definitions was a positive move by the SDT.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
SERC OC Standards Review Group
No
GENERAL COMMENT: While SERC does not agree that the mandatory
procedure for three part communications will improve reliability of the BES,
SERC offers the following comments: We do not agree with the proposed
definition of Operating communication and agree with the elimination of the
other three definitions.
Response: Thank you for your comments. Based on comments received
about the scope and intent of an Operating Communication, the SDT has
revised the term to be Operating Instruction and changed the definition to
be “command from a System Operator to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System.”
The SDT has not listened to the industry comments given in the previous
commenting periods. It also appears to be focused on imposing three part
communications on the industry for routine communications despite the
fact that neither the blackout report nor the SAR on which these standards
are based emphasize that issue.
Response: The OPCPSDT firmly believes it has listened to industry
comment based on the sweeping changes to draft 2 compared to draft 1
(the original posting) and the new approach provided in draft 3.
The SDT is focused on requiring three-part communication for Operating
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Instructions (Communication) because it provides a proven means of
clarifying communication which prevents mistakes that impact the
reliability of the BES. During its discussion of the approval of the
Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval
the expedited development of a comprehensive communications program,
which would address necessary communication protocols for use in the
operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is
required) during normal operations was a necessary step in addressing the
BOT’s concern.
The blue text box that mentions Reliability Directives seems to be a back
door attempt to change COM-002 and should be clarified or eliminated.
Splitting communications requirements across different standards creates
unnecessary confusion.
Response: The blue text box and the exclusionary language regarding
Reliability Directives in COM-003-1, R2 and R3 were added to address
concerns over potential double jeopardy. The SDT has modified it
approach in the latest draft.
Response: Thank you for your comments. Please see the responses above.
NERC Operating Committee
No
See Response 10
Response: Thank you for your comments. Please see the responses for Question 10.
Southern Company
No
Southern agrees with the elimination of “Communication Protocol,”
“Interoperability Communication” and “Three part Communications”
proposed in the first draft of COM-003-1; however, Southern does not agree
with the proposed new definition for “Operating Communication”. The
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
definition of Operating Communications is too broad.
Response: Based on comments received about the scope and intent of an
Operating Communication, the SDT has revised the term to be Operating
Instruction and changed the definition to be “command from a System
Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
The SDT appears to be focused on imposing 3-part communication on the
industry for routine communications even though the August 2003 Blackout
Report and the direction in FERC Order 693 Paragraph do not require such.
Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for
emergencies” which the SDT interprets to mean the authors were
recommending applicability of communication protocols for the total
population of operating communication and used this language to amplify
the importance of such protocols during emergency conditions. FERC Order
693 paragraph 532 (“This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions”) and the
SAR are very specific in that both include the term “normal” operating
conditions.
The word “maintain” should be removed. Three part communication is not
needed to keep things as they are in real time unless the communication is
meant to be a Directive issued by the RC or TOP and identified as such.
From a real time operations standpoint, only communications that are
meant to initiate a change (e.g., open, close, enable, disable, increase,
decrease) should require 3 part communications.
Response: The context was “maintain the status” which is an actionable
command. The SDT has proposed “preserve” as an alternative to
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
“maintain” in draft 3.
In addition, any instruction to change or maintain the state, status, output,
or input of an Element or Facility of the BES should not be considered a
Reliability Directive. A more appropriate definition of Reliability Directive
has been included in Project 2006-06 (Reliability Coordination) for COM-0023. As such, the definition of Reliability Directive developed in Project 200606 should be used here as part of this Project 2007-02. Further, this
capitalized term should have one definition and should not be defined
differently in different standards. Otherwise, there will be ambiguity and
unnecessary confusion.
Response: The OPCPSDT is aware of the definition of Reliability Directive
and has collaborated with the RCSDT. The protocols of COM-003-1 cover all
operating conditions and are in force during normal or routine operations.
Response: Thank you for your comments. Please see the responses above.
The Dayton Power and Light
Company
No
We have concerns with the true scope and depth of this standard. How far
does this standard reach? A tie line utility wants us to utilize three part
communication for tie line check outs, which we assume is not part of
‘operating communications’. Not sure this is the intent of the standard, but
seems to be a coverall by them. One could argue the tie line data (which is
up to 23 hours old by the time we check out, is an output from the BES)
How do resolve this? Operating Communications is a very broad term that
could be interpreted differently by the many individuals we interact with
leading to ‘overuse’ of three part communication when in doubt. This may
counteract the importance of its use for the conditions we truly need to
utilize this protocol.
Response: Thank you for your comments. The SDT agrees that the tie line check out as specified is not an Operating
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Communication. Based on comments received about the scope and intent of an Operating Communication, the SDT has revised
the term to be Operating Instruction and changed the definition to be “command from a System Operator to change or preserve
the state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
Center Point Energy Houston
Electric, LLC.
No
Question 1 Comments: Instead of adding the proposed new definition of
“Operating Communication” to the NERC Glossary, the definition should be
used to define the industry known terminology “Directive”, as “an
instruction to change or maintain the state, status, output, or input of an
Element or Facility of the Bulk Electric System”. Aligning this definition with
Project 2006-006 Reliability Coordination and a new proposed definition of
“Reliability Directive” to be “A communication initiated by a Reliability
Coordinator, transmission operator or Balancing Authority to change or
maintain the state, status, output, or input of an Element or Facility of the
Bulk Electric System where action by the recipient is necessary to address an
emergency or adverse Reliability Impact”.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.” The SDT has specifically chosen to not define “directive,” as it is used in other standards and the
implications of the definitions would be far reaching.
IESO
No
The IESO agrees with the removal of the 3 terms proposed in the previous
draft. However, the IESO does not agree with the introduction of a new term
Operating Communication. This term is not materially different than the
originally proposed term Interoperability Communication.
Response: Based on comments received about the scope and intent of an
Operating Communication, the SDT has revised the term to be Operating
Instruction and changed the definition to be “command from a System
Operator to change or preserve the state, status, output, or input of an
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
The text box in the draft standard indicates that Reliability Directives are a
type of Operating Communications, to the extent they change or maintain
the state, status, output, or input of an Element or Facility of the Bulk
Electric System. We see insufficient difference between the two terms
despite the SDT’s assessment that Reliability Directives are a type (or a
subset) of Operating Communication. If the intent is to use the proposed
new term to require 3-part communication (as suggested in R2 and R3), the
intent can be accomplished by using the term Reliability Directives as it
covers not only emergency state but also instructions needed to address
Adverse Reliability Impacts.
Response: Reliability Directive, in the context of COM-002-3, is specifically
for Emergency operating conditions. The intent of the OPCPSDT is to
require the use of 3 part communication in COM-003-1 for all BES
operations that are specified in the definition of Operating Instruction.
Please also see our comments under Q6 on using the proposed term to
support the requirements for 3-part communication.
Response: Please refer to the response to your comments in Question 6.
Response: Thank you for your comments. Please see the responses above.
Flathead Electric Cooperative, Inc.
No
Believe the additional definition is not necessary and it is not clear what
value it would have to small Distribution Providers other then additional
compliance complexity.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.” DPs that operate BES Facilities or BES Elements and receive Operating Instructions are subject to the
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
need for clear communication to avoid misunderstandings that could impact the BES.
Liberty Electric Power LLC
No
Routine market communications between entities are not a valid area of
regulation under the NERC Standards.
Response: Thank you for your comments. The standard does not address market communication. Based on comments received
about the scope and intent of an Operating Communication, the SDT has revised the term to be Operating Instruction and
changed the definition to be “command from a System Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
PPL Generation, LLC on behalf of its
Supply NERC Registered Entities
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does
not agree with the addition of “Operating Communication” as a proposed
definition because it imposes three part communication on the industry for
routine communications of changes of output in generation.
Response: Based on comments received about the scope and intent of an
Operating Communication, the SDT has revised the term to be Operating
Instruction and changed the definition to be “command from a System
Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric
System.”The SDT believes that routine operations pose a risk of a
communication error. Three-part communication is a proven method of
reducing operating errors.
Also the language as written does not specify if these changes include
communication of future planning to change the status of generation in
instances of future planned outages. The standard should specify if
communication of real time operations is what falls under the definition of
“Operation Protocol.” This ensures that communication which would be
considered a compliance event and require the scrutiny of an audit.
Response: The SDT is not proposing a new term “Operation Protocol.”
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. Please see the responses above.
The United illuminating Company
No
The intent of Recommendation 26 was to improve the communications
around situational awareness.
Response: The Blackout Report, Recommendation 26, states Tighten
communications protocols, especially for communications during alerts and
emergencies.” The SDT interprets that to mean the authors were
recommending applicability of communication protocols for the total
population of operating conditions and wanted to amplify the added
importance of using protocols during emergency conditions.
The SAR states the purpose is to “efficiently convey and mutually
understood for all operating conditions.”
Response: The purpose of the SAR for this project is “Require that real
time system operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and
shorten response time.”
Paragraph 532 seeks to establish communication uniformity as much as
practical on a continent-wide basis. This will eliminate possible ambiguities
in communications during normal, alert and emergency conditions.
Response: FERC Order 693 paragraph 532 (This will eliminate possible
ambiguities in communications during normal, alert and emergency
conditions”) is very specific. Please reference the term “normal” operating
conditions.
The new definition limits the communication to taking actions during nonEmergencies, and ignores the finding that poor communication occurred in
the events leading up to the 2003 Blackout.
Response: Based on comments received about the scope and intent of an
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Operating Communication, the SDT has revised the term to be Operating
Instruction and changed the definition to be “command from a System
Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
COM-003-1 deals specifically with “tightening communications” as
recommended in the 2003 Blackout Report, Recommendation 26. Please
read the following excerpt from Recommendation 26:
“On August 14, 2003, reliability coordinator and control area
communications regarding conditions in northeastern Ohio were in
some cases ineffective, unprofessional, and confusing. Ineffective
communications contributed to a lack of situational awareness and
precluded effective actions to prevent the cascade. Consistent
application of effective communications protocols, particularly during
alerts and emergencies, is essential to reliability.”
COM-003-1 is focused on developing effective communications protocols
that are consistently applied.
Response: Thank you for your comments. Please see the responses above.
Indiana Municipal Power Agency
No
On page 2 of 10 (blue box), the SDT has a blue box that defines Reliability
Directives as a “type” of Operating Communications. This gives the
appearance that Reliability Directives are part of Operating Communications
and this could be a double-jeopardy issue. If an entity is found with a
potential non-compliance finding on the communication of a Reliability
Directive (COM-002), then it is very likely that the entity could have a
potential non-compliance finding on COM-003 (proper communication of an
Operating Communication).
Response: Thank you for your comments. COM-003-1, draft 2, R2 and R3 contain exclusionary language exempting Reliability
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Directives to preclude potential double jeopardy with the requirements of COM-002-3, R2 and R3. The SDT has modified it
approach in the latest draft.
Ingleside Cogeneration LP
No
Ingleside Cogeneration LP believes that the definition of “Operating
Communication” widely expands the scope of COM-003-1 beyond entity-toentity or multiple-entity communications. Instead, all conversations
conducted by System Operators, field personnel, engineers, or vendors that
may refer to the status of a BES component are applicable - even those
discussed face-to-face. We believe the original intent to bound the
communications to those which can be captured in control room recordings
and/or logbooks is manageable; not so every side conversation or email that
takes place during the natural course of the operating day. The original
term, “Interoperability Communication”, captured this concept.
Response: The SDT never intended to include every side conversation or
email that takes place during the natural course of the operating day as an
Operating Communication. Based on comments received about the scope
and intent of an Operating Communication, the SDT has revised the term
to be Operating Instruction and changed the definition to be “command
from a System Operator to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System.”
It seems like the Draft 1 definition could be easily modified to read as
follows:
Interoperability Communication: Communication of instruction to change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System.
Response: Based on comments received about the scope and intent of an
Operating Communication, the SDT has revised the term to be Operating
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Instruction and changed the definition to be “command from a System
Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.”
Ingleside Cogeneration LP is in full agreement with the removal of the
definitions for “Communication Protocol,” and “Three part
Communications”. Neither term helps address an ambiguity in the body of
NERC Standards that we are aware of.
Response: Thank you for your comments.
Response: Thank you for your comments. Please see the responses above.
Roger Zaklukiewicz Consulting
No
The proposed standard introduces a new term "Operating Communications"
which in my opinion is unnecessary and which I believe will cause confusion
with the term "Reliability Directives". The standard proposes to establish a
three part communications for what I would describe as routing operating
instructions. This aspect of the standard would require/mandate the use of
an unnecessary and burdensome operating practice that in a number of
cases may impede or jeopardize system reliability rather than improve the
reliability of system operations.
Response: Thank you for your comments. Even routine operations pose a risk of a communication error that could impact the
stability of the BES. Three-part communication is a proven method of clarifying the content of an order or directive, and is
already required for Emergencies and Adverse Reliability Impacts in COM-002-3. During its discussion of the approval of the
Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited development of a comprehensive
communications program, which would address necessary communication protocols for use in the operation of the Bulk Electric
System. The SDT determined that protocols concerning three part communication (when it is necessary and what is required)
during normal operations was a necessary step in addressing the BOT’s concern.
Entergy Services
No
Due to these extensive comments and desire for these comments to be
formatted for the SDT we have also sent these comments to Monica Benson
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
in a Word document. While we agree with the definition, we do not agree
with R1, R2 and R3. While we are not enamored of having a Requirement to
have a procedure, in this instance, the exception seems to be necessary.
Below is suggested language to replace all of the Requirements and subRequirements in COM-003:Proposed new text:”
R1. Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider shall develop a written
communications procedure for Operating Communications among
personnel responsible for Real-time generation control and Real-time
operation of the interconnected Bulk Electric System. The procedure shall
address at minimum: [Violation Risk Factor: Low][Time Horizon: Long Term
Planning]
1.1 When communicating between functional entities
1.1.1. Establish the language to be used.
1.1.2. Time format to be used.
1.1.3. Establish treatment for time zones when multiple time zones are
crossed.
1.1.4. Identify naming convention for Transmission interface Element or a
Transmission interface Facility.
1.1.5. For oral Operating Communications, establish the treatment for the
circumstances in which alpha-numeric identifiers must be used.”
Response: The SDT agrees and is using a similar approach for draft 3.
The SDT has not listened to the industry comments given in previous ballots.
It also appears to be focused on imposing three part communications on the
industry for routine communications despite the fact that neither the
blackout report nor the SAR on which these standards are based emphasize
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
that issue.
Response: The OPCPSDT believes it has listened to industry comment
based on the sweeping changes to draft 2 compared to draft 1 (the original
posting).
The SDT is focused on requiring three-part communication for Operating
Communication because it provides a proven means of clarifying
communication which prevents mistakes that have the potential to impact
the reliability of the BES.
The SDT believes the 2003 Blackout Report and the SAR do focus on
protocols being applied to all operating conditions.
Please note the following excerpt from recommendation 26:
On August 14, 2003, reliability coordinator and control area
communications regarding conditions in northeastern Ohio were in some
cases ineffective, unprofessional, and confusing. Ineffective
communications contributed to a lack of situational awareness and
precluded effective actions to prevent the cascade. Consistent application
of effective communications protocols, particularly during alerts and
emergencies, is essential to reliability.
Additionally, the SAR is very specific in that it also includes the term
“normal” operating conditions under Applicability: “Clear and mutually
established communications protocols used during real time operations
under normal and emergency conditions ensure universal understanding of
terms and reduce errors.”
Response: Thank you for your comments. Please see the responses above.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Utility Services, Inc.
Yes or No
Question 1 Comment
No
Though we agree with the addition of “Operating Communication”
definition and the elimination of “Communication Protocol”,
“Interoperability Communication” and “Three part Communications”
definitions, the use of a “blue box” around the example of a Reliability
Directive (Reliability Directive are a type of Operating Communications, to
the extent they change or maintain the state, status, output, or input of an
Element of Facility of the Bulk Electric System.) implies this is also a
definition. We suggest removing this “blue box” from COM-003-1 and leave
the definition of Reliability Directive to Project 2006-06 which has been
charged with developing this definition. An alternative would be a footnote
to the other Project and/or the NERC Glossary of Terms if the other standard
is approved prior to COM-003-1.
Response: Thank you for your comment. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.” This and the new approach to the standard in draft 3 eliminate the need for the textbox.
City of Austin dba Austin Energy
No
To clarify that Operating Communications occur in real-time, AE offers the
following change to the definition: “Real-time communication of instruction
to change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System.”
Response: Thank you for your comment. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
Essential Power, LLC
No
Defining the new term ‘Operating Communication’, and including the
approved definition of ‘Reliability Directive’ under this newly defined term
53
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
and then requiring the use of three part communications for all ‘Operating
Communications’ is redundant and unnecessary. There is no reason to have
two separate Standards governing the use of three-part communications.
Response: Thank you for your comments. The SDT has modified its approach in the latest draft.
South Carolina Electric and Gas
No
SCE&G supports the comments submitted by the SERC OC standards Review
Group.
Response: Thank you for your comments. Please see the responses to the SERC OC Standards Review Group.
Manitoba Hydro
No
Manitoba Hydro disagrees with the term “Operating Communication” as we
do not feel there should be a distinction between Reliability Directive and
“Operating Communications”. We suggest that the term “Operating
Communication” be replaced with the term Reliability Directive as any
instruction to change the status or function of the BES must be clear and
concise and confirmed with three way communication to ensure system
reliability and personnel safety.
Response: Thank you for your comment. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” The definition of Reliability Directive is “A communication initiated by a Reliability Coordinator, Transmission
Operator, or Balancing Authority where action by the recipient is necessary to address an Emergency or Adverse Reliability
Impact.” The SDT does not believe that Reliability Directive captures communication during normal operations. Based on
comments received about the scope and intent of an Operating Communication, the SDT has revised the term to be Operating
Instruction and changed the definition to be “command from a System Operator to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
PPL Electric Utilities
No
Suggest the definition be clarified to scope to ‘real-time’ operating
instructions to eliminate discussion of future outages.
54
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comment. It was never the SDT’s intention to include side-bar conversations that might be a
discussion of potential operating options in the scope of COM-003-1. Based on comments received about the scope and intent
of an Operating Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be
“command from a System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric
System or Facility of the Bulk Electric System.”
Illinois Municipal Electric Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review
Group.
Response: Thank you for your comments. Please see the responses to the SERC OC Standards Review Group.
Xcel Energy
No
We do not agree that this definition should include “or maintain”, and
recommend that be struck. The scope should only include instructions that
would require an action by the recipient.
Response: Thank you for your comments. The context was “maintain the status” which is an actionable command. The intent
was related to commands to preserve the integrity of a normally operating system. The SDT has proposed “preserve” as an
alternative to “maintain” in draft 3.
Ameren
No
We recommend that the SDT eliminate the words “...or maintain...” in the
definition. We believe that inclusion of these words would drastically
reduce side conversations that continuously occur between different
entities. These side conversations provide additional information and
perspectives to real-time operators that ensure they understand the realtime status of the BES. In other words, due to fear of possible noncompliance consequences for failure to properly converse in a three-part
protocol at all times, entities will drastically curtail side discussions and
deprive all BES operators of this pertinent and useful real-time information.
Response: Thank you for your comment. It was never the SDT’s intention to include side bar conversations that might be a
55
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
discussion of potential operating options in the scope of COM-003-1. Based on comments received about the scope and intent
of an Operating Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be
“command from a System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric
System or Facility of the Bulk Electric System.”
MISO
No
Although the definition of “Operating Communication” is, in itself, clear, the
relationship between an Operating Communication and a “directive,” as used
in COM-002-2, Requirement R2 is ambiguous.
Response: The SDT notes that directive is a non glossary term that would be
supplanted in the COM family of standards when COM-002-3 and COM-0031 are implemented.
In particular, although an explanatory graphic placed beneath the proposed
definition for “Operating Communication” in the draft Standard states that
“Reliability Directives are a type of Operating Communications, to the extent
they change or maintain the state, status, output, or input of an Element or
Facility of the Bulk Electric System,” “Reliability Directive” does not appear to
be defined and is not in the Glossary of Terms Used in NERC Reliability
Standards. As a result, the definition of Operating Communication and
splitting communications requirements across different standards could
result in confusion due to the unclear relationship between COM-002-2,
Requirement R2 and COM-003-1, Requirements R2 and R3.
Response: The SDT notes that Reliability Directive is not yet a NERC glossary
term, but the SDT believes it is important to clarify the relationship between
the proposed terms (Reliability Directives and Operating Communications)
before they become effective.
MISO is aware that “Reliability Directive” has been defined in COM-002-3,
which is part of Project 2006-06, but there is no reference to Project 2006-06
or to the pending definition of “Reliability Directive” in draft COM-003-1.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Response: The SDT has been collaborating with project 2006-06 and is also
aware of its status in the process. The OPCPSDT supports the development
of COM-002-3 and the proposed definition of Reliability Directive. COM-0031 does refer to Reliability Directive in a text box where it states that a
Reliability Directive is a type of Operating Communication; and in R2 and R3
where it excludes Reliability Directives to prevent double jeopardy. This
interface between these standards is the primary subject of a Webinar
presented on June 7, 2012. It is posted and may address your comments.
MISO cannot, at this time, support the current version of COM-003-1.
Response: Thank you for your comments. Please see the responses above.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the responses to those comments.
Exelon Corporation and its affiliates
No
Exelon believes it is not necessary to create a new defined term “Operating
Communication.” Please see response to Q10 with alternate standard
language that avoids the need for a new term.
Response: Thank you for your comments. Please see the responses to Question 10.
Brazos Electric Power Cooperative
No
Please see formal comments provided by APM.
Response: Thank you for your comments. Please see the responses to the comments of APM.
Oncor Electric Delivery Company LLC
No
Oncor is in general agreement with the elimination of the three terms.
Furthermore, Oncor takes the position that the proposed new definition for
57
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
the NERC Glossary, “Operating Communication” is not needed because
“person to person” communication is not cited or listed as a contributor to
the events summarized in the 2003 Blackout Report.
Oncor takes the position that improvements should emphasize
communicating the state of the operating system as a whole during an
emergency.
Response: Thank you for your comments. The SDT believes the Blackout Report, FERC Order 693 and the SAR deal with
tightening protocols. The Blackout Report uses the word “especially for emergencies” which the SDT interprets to mean the
authors were recommending applicability of communication protocols for the total population of operating levels and wanted
to amplify the importance during emergency conditions. FERC Order 693 paragraph 532 (“This will eliminate possible
ambiguities in communications during normal, alert and emergency conditions”) and the SAR are very specific in that both
include the term “normal” operating conditions.
Central Lincoln
No
The change from “Interoperability Communications” to “Operating
Communication” greatly expands the standard to include all internal
communications regarding > 100 kV equipment. Central Lincoln does not
consider the extra burden to be worth the negligible benefit.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
Kansas City Power & Light
No
The requirements in this standard specifically state “how” to meet the goal
of this standard. This standard needs to be written such that it allows for
entity flexibility. Many entities already have COM protocols that are used.
The proposed standard is too prescriptive and is more effort than necessary
to ensure reliability and security of the BES. Overall - this standard is going
to cost the registered entities much more than the realized benefits.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. The SDT acknowledges your concerns and has developed an approach to COM-003-1
to address those very issues.
JEA
No
Public Utility District No. 1 of
Snohomish County
No
Lakeland Electric
Yes
Would modify R1 as noted below to remove the implication that a
Distribution would have to provide evidence that all Distribution Provider
communications used the required protocols.R1. Each Reliability
Coordinator, Transmission Operator, Balancing Authority[, and] Generator
Operator, and Distribution Provider [receiving a Operating
Communications,] shall use the following communications protocols:
Response: Thank you for your comments. The SDT acknowledges your concerns and has developed an approach to COM-003-1
to address those very issues.
Salt River Project
Yes
The definition of "Operating Communication" is vague and needs
clarification.
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
City of Tallahassee
Yes
The City of Tallahassee Electric Utility (TAL) agrees with the addition of this
proposed new definition; however, TAL is not clear on the scope of the
phrase "input of an Element or Facility of the Bulk Electric System".
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 1 Comment
Response: Thank you for your comments. Based on comments received about the scope and intent of an Operating
Communication, the SDT has revised the term to be Operating Instruction and changed the definition to be “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.”
Texas Reliability Entity
Yes
We agree, in view of the additional comments we provide below.
Response: Thank you for your comments.
Western Electricity Coordinating
Council
How are facilities that might affect the operation of the BES treated? Would
the changing of an LTC or the low voltage taps on a 230/92 kV transformer
be subject to this standard?
Response: Thank you for your comments. If it was an oral or written command the response is yes.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards
Committee (RSC).
Response: Thank you for your comments. Please see the responses to the NPCC Regional Standards Committee
(RSC)comments.
Public Service Enterprise Group
See #10.
Response: Thank you for your comments. Please see the responses to the comments in Question 10.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
Imperial Irrigation District
Yes
None
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Florida Municipal Power Agency
Yes
Bonneville Power Administration
Yes
GP Strategies
Yes
Progress Energy
Yes
Arizona Public Service Company
Yes
HHWP
Yes
SMUD
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
Colorado Springs Utilities
Yes
Utility System Efficiencies, InC.
Yes
Puget Sound Energy
Yes
Idaho Power Company
Yes
American Transmission Company,
LLC
Yes
Question 1 Comment
61
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
NextEra Energy, Inc
Yes
City of Vero Beach
Yes
Seminole Electric Cooperative
Yes
U.S. Bureau of Reclamation
Yes
NV Energy
Yes
California Independent System
Operator
Yes
Question 1 Comment
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
2.
The SDT eliminated the requirement to have a Communications Protocol Operating Procedure from the proposed standard
because it is administrative in nature. Do you agree with this modification? If not, please explain in the comment area.
Summary Consideration:
Major Issues
The majority of commenters approved of the elimination of the Communication Protocol Operating Procedure (CPOP) in draft 1,
indicating that it was too prescriptive and administrative in nature. The SDT agreed the requirement was administrative and chose to
remove it.
Many commenters suggested retaining the CPOP and use it to develop the protocols internal to the entity. The SDT has developed
an alternate standard for the next posting. The SDT notes there is a significant amount of support for the core elements of the
standard the SDT has developed for draft 3, which is a different approach than that defined in the Communication Protocol Operating
Procedure.
Stakeholders that agreed with the change did not offer substantive comment.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 2 Comment
No
An alternative approach would be to introduce communications protocols as a
mandatory non-standard (e.g. as a requirement for certification) that would center
on a corporate communications manual that encourages three-part communications;
and that includes how monitoring would be audited internally. Such an alternative
would change the requirement from monitoring personnel mistakes to a requirement
monitoring corporate culture.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Duke Energy
No
We believe that having a reliability standard requirement to develop a
Communications Protocol Operating Procedure, to address items similar to those
under R1.1 would be an appropriate method to address the Blackout Report
recommendations and Order 693 directives to tighten communications protocols. An
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 2 Comment
entity’s CPOP could address the language to be used between functional entities,
what clock format is to be used, how time zone/Daylight Savings Time will be
addressed, and transmission equipment identifiers. The CPOP should have a required
review frequency, and personnel should be trained on the CPOP. This approach,
unlike the draft standard could be audited and certified. We see no way to
reasonably audit or certify compliance with the draft standard in its current form.
Duke suggests this approach to COM-003: Rather than specifying the solutions to
achieving effective communication, COM-003 should instead focus on developing and
training on an approach that is designed appropriately for each RE. For instance,
another approach to COM-003 might be along the lines of:
Requirement
R1 could be written in a manner to require the appropriate registered entities to
develop a communications protocol that is appropriate for each RE. This
communications protocol should address how the RE is handling:
Time Zone Designations - for both internal and external communications
Language
Alpha-numeric identifiers
3-part communications - when is it required, etc.
Use of defined terminology
Use of common transmission equipment identifiers
Other items deemed important for the communications protocol to address - again,
this would not define HOW these items are addressed.
This approach would require the RE to specify how it is addressing these issues,
without prescribing solutions. For instance, a RE could include a section in its
protocol to deal with time zone designation. In this section the RE could explain that
it, and its neighbors, all are in and use the same time zone. As a result, the RE has
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Question 2 Comment
determined that requiring the identification of time zone reference in communication
is not necessary.
Requirement 2 could be written in a manner to require the training of operators on
the communication protocol.
Requirement 3 could be written in a manner to require the RE to define its internal
controls it uses to review that its protocol is being followed.
The compliance approach would be to:
1) assess whether the RE has developed a written protocol and whether the protocol
addresses each item - this does not mean there is an assessment of HOW each item is
assessed;
2) assess whether the RE has trained its operators on the communications protocol
3) assess whether the RE is following its internal controls
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Associated Electric
Cooperative JRO00088
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s comments pertaining to
question 2.
Response: Thank you for your comments. Please see the response to the SERC OC Standards Review Group’s comments.
LG&E and KU Services
No
The SDT did not eliminate a communications procedure requirement. It turned the
former requirement into R1 and its sub-parts, forcing a single communication
procedure on the industry. This goes far too deeply into the “HOW” of
communication as opposed to the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO/RTO Standards Review
No
The question is structured as an “either” “or” question about one requirement and
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Committee
Yes or No
Question 2 Comment
does not include a “neither” option relating to the other requirements. The SDT has
replaced one procedure with another set of procedures. Neither is an appropriate
requirement. The SRC believes that this and other detailed procedural requirements
on personnel are not valid applications for NERC reliability standards. The SRC
believes that standards must mandate outcomes and those standards such as this
one on 3 part communication procedures are better left to the registered entities.
Response: The question is focused only on the elimination of the CPOP, which does
not feature an option or a choice.
If the Industry were to support the SDT’s proposed requirement, the SRC would urge
the SDT to turn away from the “zero defects” standard that it is proposing and to
replace it with a requirement that allows for reasonable number of deviations.
The proposed requirement will be prohibitively expensive to implement with little
improvement in reliability (also see “whitepaper” included in response to Question
10). The requirement will require all communications channels to not just be
recorded (which is done today) but will require each recording to be reviewed by a
compliance person for self-reporting purposes.
The proposed requirement would actually reduce reliability by taking the above
required compliance personnel away from reliability related standards and placing
them on these procedural requirements ; and
(2) distracting operators from their core responsibility of reliability due to concerns
with meeting compliance obligations.
A more acceptable alternative approach would be to introduce communications
protocols as a mandatory non-standard (e.g. as a requirement for certification) that
would center on a corporate communications manual that encourages three-part
communications; and that includes how monitoring would be audited internally. Such
an alternative would change the requirement from monitoring personnel mistakes to
a requirement for monitoring corporate culture. Moreover, the use of a non-standard
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
alternative would encourage the creation of innovative Best Practices; as opposed to
a mandatory fixed procedure which would limit innovation.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Response: Thank you for your comments. Please see the responses above.
SERC OC Standards Review
Group
No
The SDT did not eliminate a communications procedure requirement! It turned the
former requirement into R1 and its sub-parts, forcing a single communication
procedure on the industry. This goes far too deeply into the “HOW” of
communication as opposed to the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
When defining common communication protocols to be used for communication between entities, it is necessary to be specific on
what must be communicated and how it must be communicated.
NERC Operating Committee
No
See Response 10
Southern Company
No
It appears as though the SDT did remove the term Communications Protocol
Operating Procedure, but replaced it with very prescriptive requirements and sub
requirements in R1 of this revised standard. This newly revised standard focuses on
the “HOW” of communication when it should be more focused on the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
When defining common communication protocols to be used for communication between entities, it is necessary to be specific on
what must be communicated and how it must be communicated.
Roger Zaklukiewicz Consulting
No
See previous comment(s) regarding the necessity for a Communications Protocol
Operating Procedure.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
Entergy Services
No
We believe that this version of COM-003 actually embeds a “CPOP” within the
Requirements. This is inappropriate intrusion beyond identification of with “what”
an entity must comply into “how” that entity must comply. Our suggested R1
provides replacement language that would require a communications procedure. We
see no reliability value in having a defined term for “Communications Protocol
Operating Procedure”, as the term “communications procedure” is completely
understandable using the normally accepted meanings of the words.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Utility System Efficiencies, InC.
No
Even though this is administrative, due to the vital importance of proper operating
communications a Communications Operating Procedure is necessary to ensure that
the Registered Entity has established its own communications procedures in
compliance with the standard to use in training its operations personnel in proper
communications protocols.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the responses to the comments by the SERC OC Standards Review Group.
MISO
Yes
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the responses to the comments by the ISO/RTO Standards Review
68
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
Committee.
Seminole Electric Cooperative
No
While we absolutely support the promotion and use of 3-part oral communication
protocol, the failure of individual persons to use "proper" and "correct" oral
operational communications should NOT constitute a Standard violation. It is
reasonable to require the responsible entities to have written procedures requiring
such use; to have evidence of applicable personnel training on such; and to have a
program for internal monitoring and enforcement of such. As written, a subjective
review of many oral operational communications will arguably be identified by
Compliance Auditors as medium, high or even severe levels.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Exelon Corporation and its
affiliates
No
Exelon agrees with the elimination of the requirement to have a Communications
Protocol Operating Procedure and we also believe the basic approach as proposed is
wrong. The burden for demonstrating compliance for non-emergency, non-directive
communications, including retention and review of 180-365 days worth of evidence
to be able to demonstrate 100% compliance presents significant burden potentially
detracting from the work of reliability. Auditing, whether by a NERC CEA or by entities
conducting internal self assessments for self-certifications, would potentially involve
listening to thousands of hours of tapes to review. This is an overly prescriptive,
burdensome approach. We believe that a more effective approach would be for the
standard to mandate reliability based outcomes and require entities to design
practices to achieve the desired outcome. See response to Q10.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Oncor Electric Delivery
Company LLC
No
Oncor takes the position that elimination of the Communications Protocol Operating
Procedure does not constitute the introduction of another set of procedures (i.e. 3 Part Communication, or alpha-numeric clarifiers). Furthermore Oncor takes the
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
position that a more productive approach would be to encourage the creation of
innovative Best Practices; as opposed to a mandatory fixed procedure which would
limit innovation.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Avista
No
South Carolina Electric and
Gas
No
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
Yes
It is best for NERC to evaluate risk and performance and prescribe methods.
Response: Thank you for your comments.
SPP Standards Review Group
Yes
Eliminating the requirement to have the procedure (documentation) was a move in
the right direction. We are glad it was eliminated because that’s one less piece of
paper we have to keep track of.
Response: Thank you for your comments.
The United illuminating
Company
Yes
The CPOP was overly administrative.
Response: Thank you for your comments.
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP agrees that a communication procedure is unnecessary for
routine operations. In our view, the remaining requirements in COM-003-1 will drive
entities to continually reinforce communications protocols without it.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
Response: Thank you for your comments.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
Yes, it would be administrative in nature and would not add value.
Response: Thank you for your comments.
NV Energy
Yes
This was a much warranted improvement.
Response: Thank you for your comments.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Response: Thank you for your comments. Please see the responses to the comments by the NPCC Regional Standards
Committee (RSC).
Public Service Enterprise
Group
See #10.
ACES Power Marketing
Standards Collaborators
Yes
Imperial Irrigation District
Yes
Midwest Reliability
Organization NERC Standards
Review Forum
Yes
Detroit Edison
Yes
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
BC Hydro
Yes
Dominion
Yes
JEA
Yes
Pepco Holdings Inc & Affiliates
Yes
City Water Light and Power
Yes
Hydro One Networks Inc.
Yes
Florida Municipal Power
Agency
Yes
Western Electricity
Coordinating Council
Yes
Bonneville Power
Administration
Yes
GP Strategies
Yes
Progress Energy
Yes
Arizona Public Service
Company
Yes
HHWP
Yes
Question 2 Comment
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted August 21, 2012
Organization
Yes or No
Lakeland Electric
Yes
CenterPoint Energy Houston
Electric, LLC.
Yes
IESO
Yes
Flathead Electric Cooperative,
Inc.
Yes
NIPSCO
Yes
SMUD
Yes
Liberty Electric Power LLC
Yes
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
Utility Services, Inc.
Yes
City of Austin dba Autin
Energy
Yes
Question 2 Comment
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Organization
Yes or No
Colorado Springs Utilities
Yes
Salt River Project
Yes
Wisconsin Electric dba We
Energies
Yes
Manitoba Hydro
Yes
Portland General Electric Transmission & Reliability
Services
Yes
Puget Sound Energy
Yes
PPL Electric Utilities
Yes
Xcel Energy
Yes
Public Utility District No. 1 of
Snohomish County
Yes
Ameren
Yes
Idaho Power Company
Yes
American Transmission
Company, LLC
Yes
City of Tallahassee
Yes
Question 2 Comment
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Organization
Yes or No
NextEra Energy, Inc
Yes
City of Vero Beach
Yes
Texas Relibility Entity
Yes
Alliant Energy
Yes
U.S. Bureau of Reclamation
Yes
Brazos Electric Power
Cooperative
Yes
Central Lincoln
Yes
Kansas City Power & Light
Yes
Question 2 Comment
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3.
The SDT has proposed to transfer the requirement to use Alert Levels in Attachment 1 to another more closely aligned standard
or to a separate new standard. Do you agree with this transfer? If not, please explain in the comment area.
Summary Consideration:
The majority of commenters approved of moving the Alert Level guide out of COM-003-1, draft 1; however the many commenters
still addressed the question as if the ALG was still retained. Many commenters wanted the guide eliminated completely, stating it
was too prescriptive and scripted. The SDT believes the ALG did have value for creating situational awareness and believes it belongs
in another standard and will recommend that the Standards Committee assign it accordingly. The OPCPSDT stated that it does not
have the authority to determine the ultimate disposition of the ALG. The SDT has addressed each misunderstanding to clarify the
matter where appropriate.
Stakeholders that agreed with the change did not offer substantive comment.
Organization
Yes or No
Associated Electric
Cooperative JRO00088
No
Question 3 Comment
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s comments pertaining to
question 3.
Response: Response: Thank you for your comments. Please see the responses to the comments by the SERC OC Standards Review
Group.
LG&E and KU Services
No
LG&E and KU Services disagree. This concept more properly belongs in the NERC
Rules of Procedure and should be designed to address Recommendation 26 of the
NERC 2003 Blackout Report. This is an expectation of NERC and not of the industry.
Also, see recent NERC Operating Reliability Subcommittee (ORS) discussions and
recommendations regarding the elimination of the Transmission Alert Levels.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
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Organization
Yes or No
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Question 3 Comment
The language, intent and purpose is not sufficiently defined. Needs better
documentation and explanation.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
City Water Light and Power
No
This requirement should certainly not be a part of this standard, but should be
eliminated entirely. It specifies a process, not a result - the requirement should be
based on resultant functionality, not the process by which the entity achieves it.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Hydro One Networks Inc.
No
In the past there was a lot of confusion regarding the use and applicability of threepart communication. We believe that all communication protocol related
requirements and information should be contained within one standard. This should
include Alert Levels and their definitions.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
SERC OC Standards Review
Group
No
We disagree - this concept more properly belongs in the NERC Rules of Procedure
and should be designed to address Recommendation 26 of the NERC 2003 Blackout
Report. This is an expectation of NERC and not of the industry. Also, see recent NERC
Operating Reliability Subcommittee (ORS) discussions and recommendations
regarding the elimination of the Transmission Alert Levels.
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Organization
Yes or No
Question 3 Comment
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Southern Company
No
Southern suggests that this concept more properly belongs in the NERC Rules of
Procedure and should be designed to address Recommendation 26 of the NERC 2003
Blackout Report. This suggestion of placing Alert Levels in the reliability standards is
an expectation of NERC, but it is not an expectation of the industry. Also, see recent
NERC Operating Reliability Subcommittee (ORS) discussions and recommendations
regarding the elimination of the Transmission Alert Levels.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Flathead Electric Cooperative,
Inc.
No
Don't understand this change, but wonder why separate alert levels are necessary to
incorporate in this set of standards.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Entergy Services
No
We disagree - this concept more properly belongs in the NERC Rules of Procedure
and should be designed to address Recommendation 26 of the NERC 2003 Blackout
Report. This is an expectation of NERC itself, not of the industry (and NERC can’t
write Requirements for the ERO). Also, this team should take the time to become
familiar with recent NERC Operating Reliability Subcommittee (ORS) discussions and
recommendations regarding the elimination of the Transmission Alert Levels. Even
the DHS has found that Alert Levels has diminished value.
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Organization
Yes or No
Question 3 Comment
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
City of Austin dba Austin
Energy
No
AE believes the SDT should carefully review existing alert levels (e.g. EEA levels,
threat levels). AE requests that the SDT use only the Alert Levels in Attachment 1 if
they enhance existing levels or fill a gap. AE’s preference is for the SDT to build upon
existing alert levels instead of imposing a new category.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the responses to the comments by the SERC OC Standards Review Group.
Ameren
No
We recommend the Alert Levels be used by the SDT to define a workable time period
when three-part communications is mandatory.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
MISO
No
This concept more properly belongs in the NERC Rules of Procedure and should be
designed to address Recommendation 26 of the NERC 2003 Blackout Report. See
recent NERC Operating Reliability Subcommittee (ORS) discussions and
recommendations regarding the elimination of the Transmission Alert Levels.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
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Organization
Yes or No
Question 3 Comment
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
ISO New England Inc
No
These Alert Levels have been and should continue to remain a product of the NERC
OC and not a Standards issue.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Exelon Corporation and its
affiliates
No
While Exelon agrees with deleting the Alert Levels in Attachment 1 from COM-003-1,
Exelon does not agree with transferring the requirement to use Alert Levels to any
other standard or the creation of a separate new standard. As stated by many of the
commenters to the previous draft, the addition of "Alert Levels" with defined colors
have been used by DHS and may be misinterpreted. In response to these comments
the SDT removed the requirement to Attachment 1 as falling outside the scope of a
"communication protocol." Exelon reiterates that the concept of adding colored
"Alert Levels" not only be deleted from COM-003-1, but also not be transferred to
another SAR in the future.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
Oncor Electric Delivery
Company LLC
No
Oncor takes the position that the introduction of new alert levels or categories simply
introduces more complexity to what could be better addressed through a closer
examination of existing alert levels. This includes EEA levels and threat levels.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
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Organization
Yes or No
Question 3 Comment
No
Create one standard for all operating conditions and retire the balance of those
places where levels are referenced. We support a new or separate requirement
speaking to all alert levels for operating conditions but not combination with another
unique standard losing the efficiencies of a combined set of operating condition alert
levels.
its disposition.
Kansas City Power & Light
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
its disposition.
JEA
No
Roger Zaklukiewicz Consulting
No
South Carolina Electric and
Gas
No
SPP Standards Review Group
Yes
We agree with the Alert Levels being removed from COM-003-1 and question the
need to move them somewhere else. During its May, 2012 meeting, the Operating
Reliability Subcommittee (ORS) approved a motion to ‘...terminate the pilot program
using Alert Levels and to discontinue any efforts to include the guidelines in reliability
standards projects.’ This was based on the inability of the ORS to demonstrate any
reliability improvements during the six years that the Alert Level pilot program had
been in existence. That being the case, there is no need to create a SAR and transfer
this to another SDT.
Response: Thank you for your comments. The Standards Committee has approved the removal and will determine its disposition.
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Organization
Ingleside Cogeneration LP
Yes or No
Question 3 Comment
Yes
There are already other project teams addressing the handling of incidents related to
transmission, physical, and cyber security. It is appropriate in our view to separate
emergency operations communications from normal ones - as done in the second
draft of COM-003-1.
Response: Thank you for your comments.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
None.
Colorado Springs Utilities
Yes
better option would be to retire the concept
Response: Thank you for your comments. The Standards Committee has approved the removal and will determine its disposition.
Idaho Power Company
Yes
Threat Alert Levels does not seem to fit this Standard.
Response: Thank you for your comments.
ACES Power Marketing
Standards Collaborators
Yes
Imperial Irrigation District
Yes
Midwest Reliability
Organization NERC Standards
Review Forum
Yes
Detroit Edison
Yes
Duke Energy
Yes
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Organization
Yes or No
BC Hydro
Yes
Dominion
Yes
Pepco Holdings Inc & Affiliates
Yes
Florida Municipal Power
Agency
Yes
Western Electricity
Coordinating Council
Yes
Bonneville Power
Administration
Yes
GP Strategies
Yes
Progress Energy
Yes
HHWP
Yes
Lakeland Electric
Yes
NIPSCO
Yes
SMUD
Yes
Liberty Electric Power LLC
Yes
PPL Generation, LLC on behalf
of its Supply NERC Registered
Yes
Question 3 Comment
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Organization
Yes or No
Question 3 Comment
Entities
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
The United illuminating
Company
Yes
Indiana Municipal Power
Agency
Yes
Utility Services, Inc.
Yes
Utility System Efficiencies, InC.
Yes
Manitoba Hydro
Yes
Public Service Enterprise
Group
Yes
Puget Sound Energy
Yes
Xcel Energy
Yes
Public Utility District No. 1 of
Snohomish County
Yes
American Transmission
Yes
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Organization
Yes or No
Question 3 Comment
Company, LLC
City of Tallahassee
Yes
NextEra Energy, Inc
Yes
City of Vero Beach
Yes
Texas Relibility Entity
Yes
Alliant Energy
Yes
U.S. Bureau of Reclamation
Yes
NV Energy
Yes
Brazos Electric Power
Cooperative
Yes
Central Lincoln
Yes
NERC Operating Committee
See Response 10
Arizona Public Service
Company
Intentionally left blank
CenterPoint Energy Houston
Electric, LLC.
Question 3 Comments: CenterPoint Energy believes the SDT should only use existing
defined alert levels, rather than implementing new alert levels or categories.
Response: Thank you for your comments. The SDT has removed the Alert Levels in Attachment 1 from COM-003-1 because it is a
notification requirement, not a communication protocol. The Standards Committee has approved the removal and will determine
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Yes or No
Question 3 Comment
its disposition.
IESO
We agree that Attachment 1 should not form part of COM-003-1 and support
suppressing any requirements in this standard that stipulate the Alert Levels. We
need more details on the specific proposal to re-locate Attachment 1 before we can
comment on the merit of the transfer.
Response: Thank you for your comments. The Standards Committee has approved the removal and will determine its disposition.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Thank you for your comments. Please see the responses to the comments by the NPCC Regional Standards Committee
(RSC).
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4.
The SDT modified the standard to allow an exemption from the requirement to use English language where the use of another
language is mandated by law or regulation. (See Requirement R1, Part 1.1.1) Do you agree with this modification? If not, please
explain in the comment area.
Summary Consideration: Major Issues
The majority of commenters approved of the use of the English language with the exemption from the requirement to use English
language where the use of another language is mandated by law or regulation.
Stakeholders that agreed with the change did not offer comment.
The commenters who disagreed cited the requirement was too prescriptive and too much of a “how to” requirement. The SDT
believes using a common language eliminates confusion and misunderstandings, and expedites response. These all contribute to
clarifying communication which reduces the possibility of an event that could compromise the reliability of the BES. The SDT also
believes standards should adhere to law and regulation where government jurisdiction exists.
Other commenters believe a very small number functional entities have local agreements to speak a language other than English.
These instances appear to be rare and isolated. The SDT added mutual agreement language similar to that found in COM-001-1.1, R4
to the standard.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 4 Comment
No
A general suggestion for all reliability standards that has been made is that standards’
requirements be eliminated that do not address reliability problems. No available
information indicates that language is causing reliability problems. In the absence of
such evidence that this is a reliability problem, consideration should be given to
eliminating this requirement.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT believes the use of a common
language eliminates confusion and misunderstandings, and expedites response. These all contribute to clarifying communication
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Organization
Yes or No
Question 4 Comment
which reduces the possibility of an event that could compromise the reliability of the BES.
Duke Energy
No
We think mandating English is over-reaching (As currently written, the Standard
erroneously focuses on “how” an entity can be compliant, rather than describing
“what” an entity needs to achieve to be compliant). Let the entity that develops the
CPOP and its neighbors decide on language, clock format, etc.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES.
Associated Electric
Cooperative JRO00088
No
Although this qualification appears to now be accommodating of regional
government mandates, it fails to address decorum where a non-English bounded
Entity is communicating externally with entities who are unbounded by the same
mandates or vice-versa. Best to let the Regional Entities work this out among
themselves and document the agreements, where applicable.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES.
LG&E and KU Services
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. When defining common communication protocols to be used for
communication between entities, it is necessary to be specific on what must be communicated and how it must be
communicated.
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Organization
Yes or No
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Question 4 Comment
Too prescriptive. NERC should be addressing risk and performance.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES.
ISO/RTO Standards Review
Committee
No
FERC has made it clear that it would be amenable to eliminating requirements that
are not reliability problems. A requirement regarding language comes under that
category. There are no reports indicating that language is causing reliability problems.
The SRC does not believe this issue rises to the level of a mandatory standard. The
SRC would ask if the SDT has any evidence that language is a problem causing
reliability impacts. In the absence of such evidence that it is a reliability problem, the
SDT should eliminate this requirement.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a comprehensive communications program, which
would address necessary communication protocols for use in the operation of the Bulk Electric System.
Hydro One Networks Inc.
No
We believe that this requirement should be eliminated. As a general rule, standards’
requirements that do not address reliability problems should be eliminated. No
available information indicates that language is causing reliability problems and
there. In addition to this, there are some jurisdictions where this requirement might
cause decrease in reliability (i.e. Quebec)
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT added the use of an alternate language for internal operations.
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Organization
Yes or No
Question 4 Comment
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System.
SERC OC Standards Review
Group
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
Response: The SDT appreciates your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. When defining common communication protocols to be used for
communication between entities, it is necessary to be specific on what must be communicated and how it must be
communicated.
Bonneville Power
Administration
No
BPA believes that the existing language format should remain solely English and
recognizes that this is the case with International & US air traffic controllers.
Response: Thank you for your comments.
Southern Company
No
While Southern agrees with the concept of allowing the use of another language
when mandated by law or regulation, Southern does not agree with R1 and its sub
requirements as they are focused on the “HOW” of communication when they should
be more focused on the “WHAT”.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. When defining common communication protocols to be used for communication
between entities, it is necessary to be specific on what must be communicated and how it must be communicated.
SMUD
No
We believe the requirement to only speak English is detrimental to reliability.
Entities that have predominantly speaking Spanish personnel would be inhibited with
ineffective communications mandated by the English only requirement. Further, this
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Organization
Yes or No
Question 4 Comment
particular requirement is in direct conflict with COM0-001 R4 which states
“...Transmission Operators and Balancing Authorities may use an alternate language
for internal operations.”
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT added use of an alternate language for internal operations.
San Diego Gas & Electric
No
San Diego Gas & Electric (“SDG&E”) agrees with the proposed exemption from the
requirement to use English language where the use of another language is mandated
by law or regulation. However, SDG&E recommends including the following language
as an additional exemption: “or a formal agreement has been established between
the functional entities to use an alternative language,” so that R1.1.1. states: “Use
the English language when communicating between functional entities, unless
another language is mandated by law or regulation or a formal agreement has been
established between the functional entities to use an alternative language.”
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT added use of an alternate language for internal operations.
Comments on prior postings of COM-003-1 rejected allowances for entities to agree upon particular protocols, feeling that the
documentation of those agreements would be overly burdensome and is contrary to the purpose of the SAR, which is “Require
that real time system operators use standardized communication protocols during normal and emergency operations to improve
situational awareness and shorten response time.”
Sacramento Municipal Utility
District
No
See response in #10
Entergy Services
No
We disagree with all of the Requirements and sub-Requirements in this standard, due
to the fact that they embody a procedure into the Requirements. There is no
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Organization
Yes or No
Question 4 Comment
reliability need being fulfilled by taking this approach. See our suggested
replacement R1 in our response to Q1. This would replace R1, R2 and R3 and their
associated sub-Requirements.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Essential Power, LLC
No
The use of English should be mandated for communications between entities in
separate regions where the common language in one of the regions may not be
English. Allowing an entity to use a language other than English when communicating
with regions where English is the required language is counter to the purpose of the
Standard and could in fact jeopardize reliability through miscommunication.
Response: Thank you for your comments. The SDT agrees with your comments and clarifies that is the intent of the requirement.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the responses to the comments by the SERC OC Standards Review Group.
Public Utility District No. 1 of
Snohomish County
No
SNPD takes issue with the specification of “English” only communications and the
Alpha-Numeric identifiers. There is no precedence established for the use of English,
Alpha-Numeric or the use of a 24-hour clock format that warrant a severe VSL and
the associated penalties that could be imposed by the Compliance Enforcement
Agency
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT has developed a new approach to the standard that addresses
your compliance concern.
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Organization
Yes or No
MISO
No
Question 4 Comment
Fluent comprehension of and speaking ability in the English language must be uniform
among all Reliability Coordinators, Transmission Operators, Balancing Authorities,
Generator Operators, and Distribution Providers in order to ensure the safe and
reliable operation of the Bulk Electric System. NERC must ensure that all such entities
employ operators that can speak and understand English fluently, regardless of their
primary or preferred language. The proposed exception, while well-intended, could
lead to situations where effective communication between operators is compromised
or entirely prevented due to language barriers.
MISO notes that the use of English, unless otherwise agreed, is currently required for
all communications between and among operating personnel responsible for the realtime generation control and operation of the interconnected Bulk Electric System
under COM-001-1.1, Requirement R4, but that requirement does not apply to
Generator Operators or Distribution Providers. Further, COM-001-2, which is part of
Project 2006-06 (see above), would no longer require English to be used in such
instances.
Thus, COM-003-1, Requirement 1, Part 1.1.1 should be modified to require that
Reliability Coordinator, Transmission Operator, Balancing Authority, Generator
Operator, and Distribution Provider operators can speak and understand English
fluently, even if it is not the required primary language pursuant to law or regulation
for oral or written Operating Communications.
Response: Thank you for your comments. The SDT believes the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT added use of an alternate language for internal operations. The
exception provides for adherence to existing law.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
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Organization
Yes or No
Question 4 Comment
Committee comments.
Response: Thank you for your comments. Please see the responses to the comments of the ISO/RTO Standards Review
Committee.
Exelon Corporation and its
affiliates
No
Exelon finds it unnecessary for the standard to include a requirement that discusses
specifics concerning language requirements. If discussion of language is important to
clarify within a Registered Entity’s protocol, then the standard could suggest it as an
attribute to be included in an entity developed protocol. See alternate standard
language proposal in response to Q10.
Response: Thank you for your comments. Please see the responses to the comments in Question10.
Oncor Electric Delivery
Company LLC
No
Oncor takes the position that this requirement is unnecessary in that it is not aware
of any evidence supporting the notion that failure to use the English language has
been a significant contributor to reduction in reliability. Furthermore, FERC has made
it known that it is in favor of eliminating requirements that do not contribute to
reliability. Oncor recommends that this requirement be eliminated.
Response: Thank you for your comments. The SDT believes that the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES.
California Independent
System Operator
No
While the objective of minimizing ambiguities in communications between functional
entities is commendable, the standard as currently written goes too far by requiring
“...English when communicating between functional entities, unless another language
is mandated by law or regulation.” (R1.1.1) To begin, requirement 1.1.1 is completely
silent on who’s law or regulation would satisfy this requirement if a functional entity
wanted/needed to speak a different language. For example, it’s unclear which of the
following would satisfy this requirement:
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Organization
Yes or No
Question 4 Comment
Response: The SDT means any law or regulation within a jurisdiction that would
mandate it.
1. A Canadian or Mexican law or regulation provided as evidence to WECC auditors?
Response: Yes
2. An American law or regulation?
Response: Yes
3. Perhaps both an American and a neighboring country’s law/regulation would be
required?
Response: Yes, if both are mandatory and enforceable.
Since the proposed standard is silent on what constitutes satisfactory evidence, both
numbers 1 and 2 seem like potentially harmful unilateral moves that could be
detrimental to reliability but may be allowable in COM-003-1 as currently proposed.
So if functional entities would like/need to speak a different language, the
requirement looks like it’s attempting to set a high bar without specifying how high
that bar is.
Response: The SDT believes the use of a common language contributes to clarifying
communication which reduces the possibility of an event that could compromise
the reliability of the BES.
I also think the requirement pre-supposes a level of English fluency by all North
American citizens that simply does not exist and mandates a very high and very vague
threshold for compliance while not allowing for exceptions. So ultimately, R1.1.1. Is a
vague, unnecessary and inflexible requirement that would be detrimental to realtime operators in a contingent status. It would deny operators that are fluent in other
languages the ability to assist non-native English speakers experiencing difficulties in
communications by using a language they are fluent in to mitigate a potentially
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Yes or No
Question 4 Comment
serious issue.
Response: The SDT points out that existing Standard COM-001-1.1, Requirement
R4, which is mandatory and enforceable, and stipulates use of the English language,
has been in effect for years. The fluency issue and the characterization of the
proposed Requirement R1.1.1 as described has not surfaced or does not appear to
be at issue.
The requirement could also potentially require U.S. states, Canadian provinces and/or
Mexican states to write laws and/or regulations to satisfy a requirement in a standard
which seems like an unrealistic threshold. The bottom line is if an entity enters a
contingent state and there is no legislation or regulation in place at the time of a
contingency event, system operators may be forced to decide between two very
difficult positions. Either adheres to COM-003 and run the risk of putting the grid at
risk or violating COM-003 to ensure grid integrity is not compromised.
Response: The SDT notes that existing Standard COM-001-1.1, Requirement R4, has
been in force and there has been no requirement for any governments to develop
additional legislation or regulation for the use of a specific language. COM-003-1,
R1.1.1 also does not require or warrant additional laws or regulation.
The SDT has developed a new approach to the standard that may address your
concern.
Response: Thank you for your comments. Please see the responses above.
South Carolina Electric and
Gas
No
SPP Standards Review Group
Yes
While we concur with the inclusion of the exemption, we question how the industry
can ensure effective communications in a situation where the exemption comes into
play.
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Organization
Yes or No
Question 4 Comment
Response: Thank you for your comments. The SDT notes that existing Standard COM-001-1.1, Requirement R4, has been in effect
for years without major issues. Non English speaking entities will speak English when communicating externally and will follow
their applicable laws or regulations internally.
Western Electricity
Coordinating Council
Yes
Any thoughts given to including a provision for agreement between specific entities
to use a language other than English for areas that another language may be
common, but not mandated by law or regulation?
Response: Thank you for your comments. The SDT believes that the use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. The SDT added the use of an alternate language for internal operations.
Comments on prior postings of COM-003-1 rejected allowances for entities to agree upon particular protocols, feeling that the
documentation of those agreements would be overly burdensome and is contrary to the purpose of the SAR, which is “Require
that real time system operators use standardized communication protocols during normal and emergency operations to improve
situational awareness and shorten response time.”
Colorado Springs Utilities
Yes
"Use the English language when communicating between functional entities, unless
another language is mandated by law or regulation." If two or more functional
entities (say BA & TOP) reside within the same utility (perhaps even co-located in the
same control center) and are communicating solely with each other, mayn't they
speak their native language to each other - with or without the aid of law?
Response: Thank you for your comments. The SDT believes that use of a common language eliminates confusion and
misunderstandings, and expedites response. These all contribute to clarifying communication which reduces the possibility of an
event that could compromise the reliability of the BES. While the SDT added use of an alternate language for internal operations,
the exception does not apply to communications between functional entities.
Central Lincoln
Yes
but please see Q 10.
City of Jacksonville Beach
Yes
None.
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Organization
Yes or No
Question 4 Comment
dba/Beaches Energy Services
ACES Power Marketing
Standards Collaborators
Yes
Imperial Irrigation District
Yes
Midwest Reliability
Organization NERC Standards
Review Forum
Yes
Detroit Edison
Yes
BC Hydro
Yes
Dominion
Yes
JEA
Yes
Pepco Holdings Inc & Affiliates
Yes
City Water Light and Power
Yes
Avista
Yes
Florida Municipal Power
Agency
Yes
GP Strategies
Yes
Progress Energy
Yes
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Organization
Yes or No
Arizona Public Service
Company
Yes
HHWP
Yes
Lakeland Electric
Yes
IESO
Yes
Flathead Electric Cooperative,
Inc.
Yes
NIPSCO
Yes
Liberty Electric Power LLC
Yes
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
The United illuminating
Company
Yes
Ingleside Cogeneration LP
Yes
Question 4 Comment
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Organization
Yes or No
Roger Zaklukiewicz Consulting
Yes
ITC Holdings
Yes
Utility Services, Inc.
Yes
Salt River Project
Yes
Utility System Efficiencies, InC.
Yes
Wisconsin Electric dba We
Energies
Yes
Manitoba Hydro
Yes
Portland General Electric Transmission & Reliability
Services
Yes
Puget Sound Energy
Yes
PPL Electric Utilities
Yes
Xcel Energy
Yes
Ameren
Yes
Idaho Power Company
Yes
American Transmission
Yes
Question 4 Comment
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Organization
Yes or No
Question 4 Comment
Company, LLC
City of Tallahassee
Yes
NextEra Energy, Inc
Yes
City of Vero Beach
Yes
Texas Relibility Entity
Yes
Alliant Energy
Yes
Seminole Electric Cooperative
Yes
U.S. Bureau of Reclamation
Yes
NV Energy
Yes
Brazos Electric Power
Cooperative
Yes
Kansas City Power & Light
Yes
NERC Operating Committee
See Response 10
Response: Thank you for your comments. Please see the responses to the comments in Question 10.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Thank you for your comments. Please see the responses to those comments made by the NPCC Regional Standards
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Yes or No
Question 4 Comment
Committee (RSC).
Public Service Enterprise
Group
See #10.
Response: Thank you for your comments. Please see the responses to the comments in Question 10.
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5.
The SDT modified the standard to mandate utilization of a 24 hour clock for all times and to mandate the use of a time zone and
indicate whether the time is daylight saving time or standard time reference when Operating Communications occur between
different time zones. (See Requirement R1, Part 1.1.3) Do you agree with this modification? If not, please explain in the
comment area.
Summary Consideration:
Commenters who approved of the use the 24 hour clock and time zone references did not offer much comment except to state they
felt it added clarity to communication. Those commenters who argued against the 24 hour clock and time zone references believe
the requirement is too prescriptive, reaches too far and should be eliminated. The SDT believes use of the 24 hour clock and time
zone references clarifies the time element of communications and by doing so enhances reliability by avoiding time mistakes that
could compromise the stability of the BES.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 5 Comment
No
This requirement is outside the scope of the approved SAR which proposes
responding to the Blackout Recommendation to tighten communications protocols
especially during emergencies. This proposed requirement is both procedural and
does not address tightening communications of situational awareness. As an
alternative a standard could require the Functional Entities to have a communications
protocol that could indeed include this, but it should not be a requirement on
personnel. By adopting an alternative category (i.e. not making this a standard) a
Reliability Entity could adopt a progressive best practice approach without concern
for violating the strictest features of the proposed best practice.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” Additionally, the SAR is very specific in that it also includes the term “normal” operating conditions under
Applicability: “Clear and mutually established communications protocols used during real time operations under normal and
emergency conditions ensure universal understanding of terms and reduce errors.” The SDT believes use of the 24 hour clock and
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Question 5 Comment
time zone references clarifies the time element of communications and by doing so enhances reliability by avoiding time mistakes
that could compromise the stability of the BES. The SDT has developed a new approach to the standard that addresses your
concern.
ACES Power Marketing
Standards Collaborators
No
1. The SDT should consider clarifying that use of relative times will not be subject to
this requirement. For example, if a System Operator communicates that they will
begin switching in 10 minutes, no 24 hour clock requirement is necessary.
Response: Thank you for your comments. The requirement only applies to references to clock times, not relative time.
Midwest Reliability
Organization NERC Standards
Review Forum
No
There are two time zones in the eastern interconnection and two time zones in the
western interconnect with Arizona not utilizing daylight savings time. The Reliability
Coordinator and entities can agree on what time zone to use. The NSRF does not
understand if the ‘time zone” issue has caused any past performance issues? Please
clarify with a basis of time zone inclusion.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the reliability
of the BES.
Detroit Edison
No
In 1.1.3 "When the communication is between entities in different time zones..."
should read "When the communication is between entities in operating in different
time zones...". Two entities may be physically located in the same time zone but one
may operate in standard time and the other in daylight time. When communication is
between entities operating in different time zones, clarify which time zone takes
precedence.
Response: Thank you for your comments. The SDT believes that two entities physically located in the same geographic time zone
but one operating in standard time and the other in daylight time would constitute communication “between functional entities
in different time zones.”
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Duke Energy
No
Question 5 Comment
We think mandating the 24 hour clock is over-reaching (As currently written, the
Standard erroneously focuses on “how” an entity can be compliant, rather than
describing “what” an entity needs to achieve to be compliant). Let the entity that
develops the CPOP and its neighbors decide on clock format, how time zone
differences will be addressed, etc.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Dominion
No
Dominion currently views this requirement as being too prescriptive, the standard
should be written to allow a 24 hour clock and time zone designation or 12 clock with
an AM or PM and time zone designation.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Associated Electric
Cooperative JRO00088
No
There are remaining issues where Entities deal with those few areas who swap timezones dependent upon SDT, and they could be unfairly ensnared by non-compliance,
in their not realizing that nuance. In addition, given the unbounded scope of this
standard, it would seem best to allow operator discretion or this clause is a PV
magnet.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
LG&E and KU Services
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Overly prescriptive. NERC should deal with risk and performance. This level of
prescriptive standard language is not appropriate.
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Yes or No
Question 5 Comment
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO/RTO Standards Review
Committee
No
This requirement is outside the scope of the approved SAR which proposes
responding to the Blackout Recommendation to tighten communications protocols
especially during emergencies. This proposed requirement is both procedural and
does not address tightening communications of situational awareness.
Response: The purpose of the SAR for this project is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” The SDT believes use of the 24 hour clock and time zone references does in
fact tighten communication because it clarifies the time element of
communications and by doing so enhances reliability by avoiding time mistakes
that could compromise the reliability of the BES.
The SRC would suggest that as an alternative a standard could require the
Functional Entities to have a communications protocol that could indeed include this
suggestion, but it should not be a standard on personnel. By adopting an alternative
category (i.e. not making this a standard) a Reliability Entity could adopt a progressive
best practice approach without concern for violating the strictest features of the
“proposed” best practice.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Response: Thank you for your comments. Please see the responses above.
City Water Light and Power
No
Entities who have an agreed upon protocol which includes the time zone to be used
for system operations should not be required to repeat the time zone for every
communication. For instance, if Entity A and Entity B are in different time zones but
both have an operating policy that states all communication between the two is in
Eastern Standard Time and all operating personnel are trained on this policy, this
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should be sufficient. This achieves the same functional goal. The requirement to
restate the time zone in this case only serves to set up a situation where a simple
single-instance omission would have no effect on reliability but still be noncompliant.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
SPP Standards Review Group
No
Requiring time zone notifications at times other than those around the time of the
transition from standard to daylight savings and back again is excessive. For a brief
period of time around this transition, ensuring the correct times are communicated
would probably require including standard or daylight savings designations. Some
consideration for this issue needs to be incorporated into the requirement. That said,
trying to be overly prescriptive with the requirement creates an unnecessary burden
on operating personnel without significantly improving BES reliability. A one-size fits
all requirement may not be appropriate. Entities whose geographical area is located
in multiple time zones probably have internal procedures detailing how they handle
time differences within their area. Most often this entails selecting one time zone as
the entity’s reference. As written, the requirement overrides any internal procedures
which may unnecessarily complicate internal communications. Allowances should be
made for internal procedures which cover this situation.
The SDT has developed a new approach to the standard that addresses your
concern. In addition, this stipulation only applies to communication “between
functional entities in different time zones.” If the communication is not between
functional entities in different time zones, it does not apply.
Requirement 1.1.3 requires that time and time zone, including standard or daylight
savings time designations, must be communicated at all times. Yet Requirement 1.1.2
includes a provision that requires use to the 24-hour clock only when clock times are
referenced. This needs to be included in Requirement 1.1.3 as shown below:
When the communication is between entities in different time zones and refers to
clock times, include the time and time zone and indicate whether the time is daylight
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Question 5 Comment
saving time or standard time.
Response: The SDT intentionally structured the parts of the requirement this way to
mandate the use of the 24 hour clock (Requirement 1.1.2) for all time references
and to use time zone references (Requirement 1.1.3) and indicate whether the time
is daylight saving time or standard time only for those communications among
entities operating in different time zones. The SDT has developed a new approach
to the standard that addresses your concern.
Response: Thank you for your comments. Please see the responses above.
SERC OC Standards Review
Group
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
NERC Operating Committee
No
Overly prescriptive
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Progress Energy
No
To prevent unintended use of “standard time” or “daylight time” Progress Energy is
requesting using “prevailing time.” Instructions issued at or near the time change
could have individuals inadvertently use the wrong time reference further confusing
the issue.
Response: Thank you for your comments. This stipulation only applies to communication “between functional entities in different
time zones.” If the communication is not between functional entities in different time zones, it does not apply.
Southern Company
No
Southern suggests that this requirement of a common time zone is overly
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prescriptive. The requirement should be that entities operating in different time
zones agree on how to best eliminate any confusion regarding the time difference.
Entities who have an agreed upon protocol which includes the time zone to be used
for system operations should not be required to repeat the time zone for every
communication. For instance, if Entity A and Entity B are in different time zones but
both have an operating policy that states all communication between the two is in
Eastern Standard Time and all operating personnel are trained on this policy, this
should be sufficient. This achieves the same functional goal. The requirement to
restate the time zone in this case only serves to set up a situation where a simple
single-instance omission would have no effect on reliability but still be noncompliant.
Response: Thank you for your comments. This stipulation only applies to communication “between functional entities in different
time zones.” If the communication is not between functional entities in different time zones, it does not apply. Comments on
prior postings of COM-003-1 rejected allowances for entities to agree upon particular protocols, feeling that the documentation of
those agreements would be overly burdensome and is contrary to the purpose of the SAR, which is “Require that real time system
operators use standardized communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.”
Flathead Electric Cooperative,
Inc.
No
Not sure this is necessary for small entities.
Response: Thank you for your comments. The SDT believes that all BES entities that send and receive operating instructions
should utilize protocols to ensure orders are not miscommunicated. A Distribution Provider or Generator Operator that only
receives Operating Instructions is only held accountable for receiver’s requirements in the standard.
Liberty Electric Power LLC
No
No. Communications which do not involve Directives are not the proper subject of
NERC standards.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
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Question 5 Comment
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
San Diego Gas & Electric
No
SDG&E recommends removing the language, “When the communication is between
entities in different time zones” in R1, Part 1.1.3, and replacing it with
“Communication is to...”, so that R1.1.3 states: “Communication is to include the
time and time zone and indicate whether the time is daylight saving time or standard
time.” The proposed requirement for the communicator to determine if an entity is in
a different time zone appears to be an unintended impact of the wording proposed in
R1.1.3, and may prove to cause inefficiencies in complying with this requirement.
Communicators SHOULD NOT NEED to determine whether or not an entity is in the
same time zone as they are, but should simply state the time zone where they are
calling from or the KNOWN element of their operations. Though a majority of
communication will occur within the same time zones, System Operators and others
affected by the requirement will be assured that the timing of ANY event will be
KNOWN and never assumed.
Response: Thank you for your comments. If an entity does not know the time zone of the other entity it is communicating with, it
is all the more imperative that both entities understand the time at which a certain action is to occur.
Sacramento Municipal Utility
District
No
See response in #10
Response: Thank you for your comments. Please see the response to Question 10
Entergy Services
No
See our response to Questions 1, 2 and 4.
Response: Thank you for your comments. Please see the responses to Questions 1, 2 and 4.
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Organization
City of Austin dba Austin
Energy
Yes or No
Question 5 Comment
No
There is not enough evidence to support the need for these types of specifics.
Recommendation 26 encourages NERC “to ensure that all key parties ... receive
timely and accurate information.” COM-003-1 seems to interpret the
recommendation by telling entities “how” to ensure information is accurate (e.g., use
English, 24-hour clock, time zones, alpha-numeric identifiers, etc.). This standard
reaches too far into the “how” instead of focusing on the “what,” which is “timely
and accurate information.” Registered entities should decide the best methods to
ensure accurate information for themselves (through three-part communication, use
of the 24-hour clock or otherwise).
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” When defining common communication protocols to be used for communication between entities, it is
necessary to be specific on what must be communicated and how it must be communicated.
Essential Power, LLC
No
This provides minimal real-time benefits to the Operators, but only serves to make it
easier to conduct an after the fact analysis. As such, this is an administrative
requirement that should not be included in the Standard.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Salt River Project
No
In the real time environment we deal in current hour or next hour terms. Including
the time zones in these conversations would further muddy the waters.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
This would provide the latitude to utilize relative time. In addition, this stipulation only applies to communication “between
functional entities in different time zones.” If the communication is not between functional entities in different time zones, it
does not apply.
Manitoba Hydro
No
Manitoba Hydro agrees with R1.1.2 but disagrees with R1.1.3. R1.1.3 is unnecessary
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and should be modified to “1.1.3 - When communication is between entities in
different time zones, clarify the difference in time to ensure mutual understanding”.
Making R1.1.3 more generic gives operators the opportunity to determine the best
method for them to ensure mutual understanding and clarify the time difference.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” If the protocols are not standardized, it eliminates the whole purpose behind the SAR.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the response to comments submitted by the SERC OC Standards Review
Group.
Xcel Energy
No
Is there any evidence of an actual event where there was confusion in the time zone,
which led or contributed to an event? We are not aware of any. If the drafting team
has no basis for mandating the use of a time zone and daylight/standard time
reference, then we suggest this requirement be struck because we do not believe it
would increase reliability. In fact, we think it may have the opposite effect of
reducing reliability.
Response: The SDT believes use of the 24 hour clock and time zone references
clarifies the time element of communications and by doing so enhances reliability
by avoiding time mistakes that could compromise the reliability of the BES. While
the SDT cannot immediately cite evidence of a time zone event we believe that
time zone confusion can negatively impact BES operations.
If the SDT decides to retain the sub-requirement, please clarify which entity’s time
zone should be used. As written, this sub-requirement may create confusion for field
personnel if they are to repeat the order back in their own time zone. We are
concerned this will actually increase the likelihood of human error, and therefore
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potentially reduce reliability. As a company that has field personnel in different time
zones, company procedures dictate that CPT be used as that is the time zone the
control center is in. Adding additional oral verification for time zones will promote
human error.
Response: This stipulation only applies to communication “between functional
entities in different time zones.” If the communication is not between functional
entities in different time zones (e.g. the field personnel and System Operator are in
the same functional entity, or the field personnel is not in a NERC functional entity),
it does not apply.
Response: Thank you for your comments. Please see the responses above.
Public Utility District No. 1 of
Snohomish County
No
SNPD takes issue with the specification of “English” only communications and the
Alpha-Numeric identifiers. There is no precedence established for the use of English,
Alpha-Numeric or the use of a 24-hour clock format that warrant a sever VSL and the
associated penalties that could be imposed by the Compliance Enforcement Agency
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
MISO
No
The requirement to use a 24-hour clock for all times and to indicate time zone and
Standard or Daylight Saving Time would result in the expenditure of significant time,
resources and attention by System Operators for a minimal benefit to reliability. To
date, the use of the 12-hour clock time has not been demonstrated as problematic or
as having an adverse impact on reliability. The system time characteristics should
inform the communication protocols regarding time. Finally, MISO notes that the use
of the 24-hour clock time in communication is inconsistent with the 12-hour clock time
currently utilized by most systems. Accordingly, this modification appears to place
upon operators a requirement that is not justified and onerous. MISO respectfully
requests that the SDT reconsider this requirement.
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Yes or No
Question 5 Comment
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the stability of
the BES. The SDT believes the 12 hour clock adds an element of confusion if am or pm is missing or misapplied. The SDT has
developed a new approach to the standard that addresses your concern.
City of Tallahassee
No
TAL is concerned with any unnecessary complication of communications. If more
than one Time Zone is entailed in a communication, it is reasonable to require
clarification of such. However, if both the sender and receiver observe the same
prevailing time (e.g. Eastern Standard Time versus Eastern Daylight Time), it does not
facilitate communication to require this clarification.
Response: Thank you for your comments. This stipulation only applies to communication “between functional entities in different
time zones.” If the communication is not between functional entities in different time zones, it does not apply.
NextEra Energy, Inc
No
NextEra believes the current language in R 1.1.2 unnecessarily limits two other forms
of clear communications on the implementation of an Operating Communication.
Specifically, NextEra also believes it is appropriate to use “AM” or “PM,” or “effective
immediately” for the timing of implementing an Operating Communication, instead
of the 24 hour clock. To add these items, NextEra requests that R 1.1.2 be revised to
read as follows:
Use one of the following:
(a) the 24-hour clock;
(b) “AM/PM” or
(c) “effective immediately,” when referring to the time an Operating Communication
shall be implemented.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the stability of
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Organization
Yes or No
Question 5 Comment
the BES. The SDT believes the 12 hour clock adds an element of confusion if am or pm is missing or misapplied. The SDT has
developed a new approach to the standard that addresses your concern.
Alliant Energy
No
We believe that adding the mandate to use a 24 hr clock and list the time zone and
Daylight Savings Time or not is going too far. We agree that it could be considered a
best practice, but to require it and have a violation every time it is not used will result
in multiple frivolous violations and clog the system with violations that have no
impact on the reliability of the BES. With a zero-defect philosophy, which currently
exists in the regulatory model, this is unworkable.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the response to the ISO/RTO Standards Review Committee comments.
NV Energy
No
We believe that the requirement to specify "daylight" versus "standard" is
unwarranted and may lead to confusion among the parties. All time is understood to
be "prevailing time" without this clarification. Requiring such will only serve to
confuse rather than clarify.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the stability of
the BES. The SDT has developed a new approach to the standard that addresses your concern.
Exelon Corporation and its
affiliates
No
It’s not clear that this addresses a reliability problem. We are not aware of instances
where failure to specify the time zone and daylight saving time resulted in
communication failures between entities leading to a condition that threatened an
outage or a cascading outage. Further, specifically creating a requirement is overly
prescriptive. If it is justified as important to reliability, then the standard could
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Organization
Yes or No
Question 5 Comment
suggest it as an attribute to be included in an entity developed protocol. See
alternate standard language proposal in response to Q10.
Response: Thank you for your comments. The SDT believes the use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the reliability
of the BES. The SDT has developed a new approach to the standard that addresses your concern.
Brazos Electric Power
Cooperative
No
Please see formal comments provided by APM.
Response: Thank you for your comments. Please see the response to the APM comments.
Oncor Electric Delivery
Company LLC
No
Oncor takes the position that more productive approach would be to encourage the
creation of innovative Best Practices; as opposed to a mandatory fixed procedure
which would limit innovation. Oncor believes that requiring registered entities to
have its own internal communication protocols would encourage the adaption of
best practices that could be shared, modified and implemented as a “best fit” and
could potentially enhance reliability as opposed to a mandated “procedural specific”
requirement
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System.
Central Lincoln
No
We appreciate the change from requiring Central Time, but believe that 12 hour
designations with AM or PM qualifiers to be just as clear as 24 hour clock time. In
addition, we suggest that the DT or ST designation should only be required when
deviating from the prevailing time in effect.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the reliability
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Organization
Yes or No
Question 5 Comment
of the BES. The SDT believes the 12 hour clock adds an element of confusion if am or pm is missing or misapplied. The SDT has
developed a new approach to the standard that addresses your concern..
South Carolina Electric and
Gas
No
Colorado Springs Utilities
Yes
The use of "prevailing time" should be allowed, when appropriate, along with
daylight and standard.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Imperial Irrigation District
Yes
BC Hydro
Yes
JEA
Yes
Pepco Holdings Inc & Affiliates
Yes
Hydro One Networks Inc.
Yes
Florida Municipal Power
Agency
Yes
Western Electricity
Coordinating Council
Yes
Bonneville Power
Administration
Yes
GP Strategies
Yes
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Organization
Yes or No
Arizona Public Service
Company
Yes
HHWP
Yes
Lakeland Electric
Yes
NIPSCO
Yes
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
The United illuminating
Company
Yes
Ingleside Cogeneration LP
Yes
Roger Zaklukiewicz Consulting
Yes
ITC Holdings
Yes
Utility Services, Inc.
Yes
Question 5 Comment
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Organization
Yes or No
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
Utility System Efficiencies, InC.
Yes
Portland General Electric Transmission & Reliability
Services
Yes
Puget Sound Energy
Yes
PPL Electric Utilities
Yes
Ameren
Yes
Idaho Power Company
Yes
American Transmission
Company, LLC
Yes
Texas Reliability Entity
Yes
Seminole Electric Cooperative
Yes
U.S. Bureau of Reclamation
Yes
California Independent
System Operator
Yes
Kansas City Power & Light
Yes
Question 5 Comment
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Organization
Yes or No
IESO
Question 5 Comment
We have no preference one way or the other as long as the personnel understand
each other. However, if the option to use daylight saving time or standard time is
allowed (to be agreed by the personnel), it begs the question as to why the 24-hour
clock hours must be followed, and why the 12-hour clock with am and pm specified is
not allowed.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the reliability
of the BES. The SDT believes the 12 hour clock adds an element of confusion if am or pm is missing or misapplied. The SDT has
developed a new approach to the standard that addresses your concern.
SMUD
Mandating use of a 24-hour clock reference provides no improvement to reliability.
This is an auditing function only, there is no reliability benefit to differentiate 0800
and 8 am.
Response: Thank you for your comments. The SDT believes use of the 24 hour clock and time zone references clarifies the time
element of communications and by doing so enhances reliability by avoiding time mistakes that could compromise the reliability
of the BES. The SDT believes the 12 hour clock adds an element of confusion if am or pm is missing or misapplied. The SDT has
developed a new approach to the standard that addresses your concern.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Thank you for your comments. Please see the response to the comments submitted by the NPCC Regional Standards
Committee (RSC).
Public Service Enterprise
Group
See #10.
Response: Thank you for your comments. Please see the response to Question #10.
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6.
The SDT modified the requirement for use of three-part communications for Operating Communications to clarify that this is
not applicable for Reliability Directives and split the single requirement into two requirements: one for the issuer (R2) and
another for the receiver (R3). Do you agree with this modification?
Summary Consideration:
Many of the commenters who disagreed with the changes to Requirements R2 and R3 believed, while it was appropriate to separate
sender from receiver in the standard, that there should only be one standard requiring 3 part communication. Many believed COM002-3 should be the standard that requires three part communication and only during emergencies. Many also believe that COM003-1 is too prescriptive. The SDT believes three part communication should be used for all communications that are direct
instructions to change the BES. The SDT believes three part communication is a proven protocol that improves clarity and reduces the
risks to BES reliability by reducing miscommunication. Due to the change in approach, the SDT has removed the draft 2 clarification
that this is not applicable for Reliability Directives.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 6 Comment
No
There are a number of references appearing that state “excluding Reliability
Directives”. If Reliability Directive is going to be defined in a separate project (Project
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Question 6 Comment
2006-06), how will stakeholders understand what is really being excluded for the
purposes of this Standard’s scope?
Response: The SDT has developed a new approach to the standard that addresses
your concern.
It also needs to be made clear when an action is a Reliability Directive. Will each
entity be required to define what is to be included as a Reliability Directive?
Response: Yes, COM-002-3, R1 requires that the entity “shall identify the action as a
Reliability Directive to the recipient. “
With the definition of Operating Communication, three-part communications is
expanded to include communications beyond directives, communications that might
not warrant governance by this Standard.
Response: As defined in draft 3 of COM-003-1, an Operating Instruction is a
“command from a System Operator to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System.”
The proposed exception (specifically Reliability Directives used during emergencies)
does not support the reason the SAR was proposed--to improve protocols during
emergencies.
Response: The purpose of the SAR for this project is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” The SAR is clear that normal operating state communications as well as
emergency state communications are to be addressed in the standard.
The term Operating Communications is not significantly different from the term
Reliability Directives (see comments to Q1). Using the term Reliability Directives to
support the requirements for 3-part communication can avoid
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Yes or No
Question 6 Comment
(a) any confusion with the requirement in COM-002-3,
Response: This was a concern of the SDT also. A webinar was conducted on June 7,
2012 and was posted to NERC.com to clarify the relationship between the two
standards.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_200702_June_7_2012_final.pdf
(b) potential double jeopardy of violating both COM-002 and COM-003, and
(c) the need to exercise 3-part communication for routine operating instructions.
Response: See our remarks below.
Suggest consider removing the term Operating Communications. Are Requirements
R2 and R3 needed if Reliability Directives already cover non-emergency conditions
(instructions/actions that are needed to address potential Adverse Reliability
Impact)?
The requirement to exercise three-part communication to handle Reliability
Directives is thus duly addressed in COM-002-3. It hasn’t been shown that three-part
communication is necessary for routine operating instructions. Realistically the
definition of Operating Communications covers all communications. Only Reliability
Directives should require three-part communications, and should be enforceable if a
miscommunication results in an error on the BES.
Response: The OPCPSDT respectfully disagrees. The term “Reliability Directive” in
the current draft of COM-002-3 covers a very narrow band of low frequency, high
impact events. Communication protocols must be applicable to all BES
communications to clarify content in order to prevent mistakes that could
negatively impact the BES.
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Organization
Yes or No
Question 6 Comment
Response: Thank you for your comments. Please see the responses above.
ACES Power Marketing
Standards Collaborators
No
1. We do not agree that excluding Reliability Directives is a good idea. We would
prefer to see COM-003-1 and COM-002-3 combined and have the requirements only
apply to Reliability Directives. If these protocols should be used for any type of
communication, we believe they should be used for Reliability Directives as we’ve
stated in our comments in Question 1. The definition of a Reliability Directive as
proposed in COM-002-3 is “where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact.” There is no type of communication more
important than a Reliability Directive, therefore, the protocols outlined in R2 and R3
of COM-003-1 should be applicable to them. During the webinar on June 7, 2012, it
was said that the only distinctions between COM-002-3 and COM-003-1 are the
VRF/VSL levels and that a Reliability Directive must be stated as such when issued.
There is no reason both standards can’t be combined into a single standard and
simply split out the VRF/VSL levels for Reliability Directives while keeping the
requirement where the RC, TOP and BA shall identify the action as a Reliability
Directive when one is issued. We suggest that the SDTs consider combining their
efforts in this manner.
Response: The SDT has developed a new approach to the standard that may
address your concern.
2. However, if both projects are to continue along separate paths, we’d like to see the
requirements in both mirror one another so entities aren’t wondering what the
distinction is between the two descriptions of three-part communication. COM-0031 is more detailed in outlining the steps that should be taken when using three-part
communication than COM-002-3. COM-002-3 R2 states that the recipient “shall
repeat, restate, rephrase or recapitulate...” COM-003-1 doesn’t use these words. It
simply states that the receiver shall “repeat” or “request the issuer reissue...”
Response: The SDT has changed the relevant language in COM-003-1, draft 3 to the
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Organization
Yes or No
Question 6 Comment
same language as COM-002-3, R2 and R3.
3. We do agree with splitting the single requirement into two requirements: one for
the issuer and one for the receiver. However, we suggest the SDT develop a flow
chart that demonstrates the communication paths and the loop flow of the steps to
further clarify what needs to be done and when. For example, in R2 Part 2.2, after an
Operating Communication is reissued at the request of the receiver (bullet 3), the
receiver should repeat the information to make sure they received it correctly (R3
bullet 1) and the issuer should confirm the receiver’s response (Part 2.2 bullet 1). As
the parts are written currently, the loop flow of the steps isn’t clear. It may seem
intuitive but a literal reading doesn’t capture the loop flow as intended. R3 even has
a gap in that the recipient can choose to repeat the Operating Communication or
they can request it be reissued. Thus, if they request it is reissued, they don’t have to
repeat it back.
Response: The SDT has changed the relevant language in COM-003-1, draft 3 to the
same language as COM-002-3, R2 and R3 to avoid confusion.
4. In R3, we suggest adding the words, “before taking action” to the end of the first
bullet to further emphasize the importance of receiving confirmation from the issuer.
If action is taken prior to confirmation, a critical mistake could be made if the
instruction was heard and repeated back incorrectly.
Response: The SDT believes this suggestion has merit, but has changed language in
COM-003-1, draft 3 to the same language as COM-002-3, R2 and R3.
Response: Thank you for your comments. Please see the remarks above.
Midwest Reliability
Organization NERC Standards
Review Forum
No
The MRO NSRF recommends the following comments for consideration by the SDT:
1. The NSRF does not understand how three part communication is not applicable to
Reliability Directives, when COM-002-3 states that three part communication shall be
used when issuing a Reliability Directive. This adds confusion and is further evidence
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Question 6 Comment
that there should only be one communication standard.
Response: Three part communication is applicable to Reliability Directives. If you
are referring to the exclusion of Reliability Directives from COM-003-1, R2 and R3,
that was incorporated to address double jeopardy issues. When an entity declares a
Reliability Directive under COM-002-3, R1; requirements COM-002-3, R2 and R3
apply. The SDT has developed a new approach to the standard that addresses your
concern.
2. How are group calls going address three part communication? Many entities use
blast calls to forward system wide information in a very short period of time. The
intent of a blast call is to speed up the dispersing of information from one to many.
Please clarify.
Response: Both Standard drafts did not address “blast calls.” The SDT has
addressed “blast” or “all” calls into COM-003-1, draft 3.
3. Currently there are 1681 entities (BA, TOP, RC, GOP, and DP) registered with
NERC. Assume that each entity has one phone call every 10 minutes in a 12 hour day
shift and half during a night shift (being conservative). A single entity will have 72 per
day on an average. Note that both parties (sender and receiver) will need to use
COM-003 requirements. There will be about 120,000 calls per day within NERC
where COM-003 will need to be applied. That equates to 44,176,680 calls per year
that require COM-003 requirements to be used. While all these communications will
not necessarily be an Operating Communication, but the NSRF believes that at least
75% will be Operating Communications. This alone will slow down the reliability of
our system. Is this the intent of the SDT?
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Please consider all industry comments and upon development of “consideration of
comments”, run the number of instances where COM-003 will need to be applied.
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Organization
Yes or No
Question 6 Comment
The question should be, does this hamper our system reliability or not.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Response: Thank you for your comments. Please see the remarks above.
Duke Energy
No
We don’t believe that 3-part communications are needed for ALL routine
communications, and that R2 and R3 should be deleted. Also, there should only be
one standard for communications protocols. The communications efforts in Projects
2007-02, 2006-06 and 2007-03 should be combined.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
Dominion
No
The current version of this standard expands the use of three-part communication to
all Operating Communications, not just Reliability Directives as specified in draft
standard COM-002-3, Project 2006-06. Also, given the definition of Operating
Communication (i.e., communication of instruction to change...an Element or
Facility...) and the use of “two-party, person-to-person” in the Requirements,
communications between two members of the same organization (e.g., two
Generator Operators, two Transmission Operators) would be subject to this standard.
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Organization
Yes or No
Question 6 Comment
This seems impractical, requiring organizations to document, as evidence, internal
communications. Dominion suggests the language be clarified to eliminate this issue.
Response: Requirement R1 in draft 3 of COM-003-1 only applies to Operating
Instructions between functional entities, not within a functional entity.
The requirement as written could also be interpreted to mean that three-part
communications is not necessary for communicating Reliability Directives. If the
protocol for Reliability Directives must be covered by a different standard, then that
standard should be referenced in this requirement in order to clarify the intent of the
exclusion and remove the implication that three-part communications do not apply
to Reliability Directives. COM-003-1 R2 could be rewritten to add clarification for
Reliability Directives only as “Each Reliability Coordinator, Transmission Operator and
Balancing Authority that issues an oral, two-party, person-to-person Operating
Communication, excluding Reliability Directive (as referenced in COM-002-3 R2 and
R3) shall:”
Response: Reliability Directive from COM-002-3 was excluded from that draft of
COM-003-1 to avoid double jeopardy. If we specifically referenced COM-002-3, R2
and R3 in the text of COM-003-1 and COM-002-3 was altered or eliminated in the
future COM-003-1 would have an erroneous or missing reference. The SDT has
developed a new approach to the standard that addresses your concern.
Response: Thank you for your comments. Please see the responses above.
JEA
No
The two standards (COM002&COM003) should be merged into one standard. Three
part communications should be considered a best practice and only required during
emergency directives.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
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Organization
Yes or No
Question 6 Comment
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
Associated Electric
Cooperative JRO00088
No
AECI appreciates the SDT’s desire to add flexibility and yet clarity for what is
expected, but we absolutely disagree with a split into two requirements. Such a split
unnecessarily increases the industry’s risk, of a single three-part communication
failure, being assessed in violation of two separate requirements, yet with no added
value to BES reliability. Given today’s environment, PVs will be written although the
intended content was accurately conveyed and the system properly operated, should
these requirements exist. So AECI agrees with SERC OC STANDARDS REVIEW
GROUP’s assessment that R2 and R3 should be entirely removed.
Response: The SDT appreciates your comments. The SDT believes that having the COM-003-1 three-part communication
requirements separate: one for the sender and one for the receiver, more appropriately separates the unique actions and
accountabilities for each. This is consistent with the three-part structure and language in COM-002-3. This separation also
prevents double jeopardy and prevents the sender and receiver from being cited based on the other’s action or inaction. The SDT
has developed a new approach to the standard that addresses your concern.
LG&E and KU Services
No
Three part communications should not be required for routine operating
communications. See the definition of Reliability Directive in COM-002, which
addresses reliability issues. We suggest that R2 and R3 be eliminated, since neither
one will increase reliability.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
Pepco Holdings Inc & Affiliates
No
This modification for use of 3 part communications for Operating Communications is
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Yes or No
Question 6 Comment
confusing and should not be required for Normal conditions, non reliability
communications.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Overly prescriptive. NERC should deal with risk and performance.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO/RTO Standards Review
Committee
No
The SRC agrees that if there is a requirement for 3 part communications as proposed,
then the proposed exception is needed to avoid double jeopardy, and the
differentiation between issuer and receiver is needed. The SRC however does not
agree with the need for the requirement itself. By introducing the proposed
exception (i.e. of Reliability Directives used during emergencies) the SDT has
invalidated the very reason that its SAR was proposed (i.e. to improve protocols
DURING emergencies).
Response: Reliability Directive from COM-002-3 was excluded from that draft of
COM-003-1 to avoid double jeopardy. The purpose of the SAR for this project is
“Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve situational
awareness and shorten response time.” The SDT believes that reliability risk exists
when routine changes to the configuration of the BES are ordered. Three part
communication provides additional clarity to communicating parties that helps
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Yes or No
Question 6 Comment
prevent misunderstandings that could negatively impact the BES.
The SRC disagrees with using the term Operating Communications because the term
is not significantly different from the term Reliability Directives (see our comments
under Q1). Using the term Reliability Directives to support the requirements for 3part communication can avoid
(a) any confusion with the requirement in COM-002-3,
Response: This was a concern of the SDT also. A webinar was conducted on June 7,
2012 and was posted to NERC.com to clarify the relationship between the two
standards.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_200702_June_7_2012_final.pdf
(b) potential double jeopardy of violating both COM-002 and COM-003, and
Response: See the remarks above
(c) the need to exercise 3-part communication for routine operating instructions.
Response: See the remarks below.
If the SDT’s intent is to require 3-part communication for any and all operating
instructions (as the proposed term suggests), then this intent will result in
unnecessary 3-part communication burdens for simple actions such as requesting the
removal of a line, or switching, or raising generation, or even to “maintain” its current
state. We suggest the SDT remove the term Operating Communications. With respect
to Requirements R2 and R3, we question the need for having these requirements if
Reliability Directives already cover non-emergency conditions (instructions/actions
that are needed to address potential Adverse Reliability Impact). The requirement to
exercise 3-part communication to handle Reliability Directives is thus duly addressed
in COM-002-3. Other than emergency conditions and potential Adverse Reliability
Impact conditions, we do not see, nor has the SDT proven a need to exercise 3-part
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Question 6 Comment
communication for routine operating instructions.
Response: The OPCPSDT respectfully disagrees. The term “Reliability Directive” in
the current draft of COM-002-3 covers a very narrow band of low frequency, high
impact events. The SDT believes that reliability risk exists when routine changes to
the configuration of the BES are ordered. The Communication protocols must be
applicable to all BES communications to clarify content in order to avoid mistakes
that could negatively impact the BES. During its discussion of the approval of the
Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the
expedited development of a comprehensive communications program, which
would address necessary communication protocols for use in the operation of the
Bulk Electric System. The SDT determined that protocols concerning three part
communication (when it is necessary and what is required) during normal
operations was a necessary step in addressing the BOT’s concern.
Response: Thank you for your comments. Please see the responses above.
City Water Light and Power
No
Three part communications should not be required for routine operating
communications. See the definition of Reliability Directive in COM-002, which
addresses reliability issues.
Response: Thank you for your comments. The OPCPSDT respectfully disagrees. The term “Reliability Directive” in the current draft
of COM-002-3 covers a very narrow band of low frequency, high impact events. Communication protocols must be applicable to all
BES Operating Communications to clarify content in order to avoid mistakes that could negatively impact the BES.
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
Hydro One Networks Inc.
No
The term Operating Communications is not significantly different from the term
Reliability Directives. Using the term Reliability Directives to support the
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Yes or No
Question 6 Comment
requirements for 3-part communication can avoid
(a) any confusion with the requirement in COM-002-3,
Response: This was a concern of the SDT also. A webinar was conducted on June 7,
2012 and was posted to NERC.com to clarify the relationship between the two
standards.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_200702_June_7_2012_final.pdf
(b) potential double jeopardy of violating both COM-002 and COM-003, and
Response: See the remarks above
(c) the need to exercise 3-part communication for routine operating instructions.
Response: See the remarks below.
Realistically, the definition of Operating Communications covers all communications.
We believe that only Reliability Directives should require 3-part communications, and
should be enforceable if a miscommunication results in an error on the BES.
Response: The OPCPSDT respectfully disagrees. The term “Reliability Directive” in
the current draft of COM-002-3 covers a very narrow band of low frequency, high
impact events. Communication protocols must be applicable to all BES Operating
Communications to clarify content in order to avoid mistakes that could negatively
impact the BES. During its discussion of the approval of the Interpretation of COM002-2 R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Response: Thank you for your comments. Please see the response above.
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SPP Standards Review Group
Yes or No
Question 6 Comment
No
The format of the requirement is an improvement. However, we have concerns
about the standard being overly prescriptive. All actions ‘...to change or maintain the
state, status, output or input of an Element or Facility...’ of the BES do not have a
significant impact on the reliability of the BES. The draft standard mandates that they
do. Applying 3-part communications to all Operating Communications places an
overly burdensome task on the industry in monitoring and tracking compliance.
Additionally, a zero-tolerance interpretation of this requirement places an unjustified
risk on the industry without making an appreciable improvement in BES reliability.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
SERC OC Standards Review
Group
No
Three part communications should not be required for routine operating
communications. See the definition of Reliability Directive in COM-002, which
addresses reliability issues. We suggest that R2 and R3 should be eliminated, since
neither one will increase reliability.
Response: Thank you for your comments. The OPCPSDT respectfully disagrees. The term “Reliability Directive” in the current draft
of COM-002-3 covers a very narrow band of low frequency, high impact events. Communication protocols must be applicable to all
BES Operating Communications to clarify content in order to avoid mistakes that could negatively impact the BES. During its
discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
NERC Operating Committee
No
See Response 10 - the OC sees these differing concepts for communications as overly
prescriptive and complex.
Response: Thank you for your comments. Please refer to the response to your comments in Question 10.
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Southern Company
Yes or No
Question 6 Comment
No
Southern disagrees that three part communications should be required for routine
operating communications. A more appropriate definition of Reliability Directive has
been included in Project 2006-06 (Reliability Coordination) for COM-002-3. As such,
the definition of Reliability Directive developed in Project 2006-06 should be used
here as part of this Project 2007-02. Further, this capitalized term should have one
definition and should not be defined differently in different standards. Otherwise,
there will be ambiguity and unnecessary confusion. Southern suggests that R2 and
R3 should be eliminated, since neither one will increase reliability.
Response: Thank you for your comments. The OPCPSDT respectfully disagrees. The term “Reliability Directive” in the current draft
of COM-002-3 covers a very narrow band of low frequency, high impact events. Communication protocols must be applicable to all
BES Operating Communications to clarify content in order to avoid mistakes that could negatively impact the BES. During its
discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
The Dayton Power and Light
Company
No
This standard specifically excludes “Reliability Directives” which is a term that does
not currently exist in the list of definitions, rather it is proposed in a separate
standard (COM-002-3) which is currently in the approval process. Not sure how you
can reference a term from a pending standard.
Response: Thank you for your comments. We wanted to acknowledge the term because it has an impact on the content and intent
of COM-003-1. The two SDTs have been coordinating because of the linkages between the two standards’ requirements.
Lakeland Electric
No
I do not understand why Reliability Directives would be excluded! Reliability
Directives are capitalized in the box on the Development Roadmap and in this
question but I cannot find the term in the February 8, 2012 NERC Glossary. So where
is Reliability Directives defined? I am concerned that the exclusion will cause
problems especially if the clarifying box is omitted from the final standard. The split is
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Yes or No
Question 6 Comment
OK.
Response: Thank you for your comments. Both standards, COM-003-1 and COM-002-3 are still under development so the terms in
each are not yet effective. The reason Reliability Directives are excluded from COM-003-1, R2 and R3 is to prevent double
jeopardy with requirements COM-002-3, R2 and R3 during Emergencies or Adverse Reliability Impacts. Both standards are going
through ballot and industry should be afforded clarification of the relationship between two closely related concepts.
CenterPoint Energy Houston
Electric, LLC.
No
Question 6 Comments: The proposed language in this requirement can be omitted
and incorporated in COM-002-2 R2, where language has already been written and is
currently in force regarding 3-part communications. The industry is well aware and
versed in the method of communicating using 3-part communications. The
elaboration of performing a three part communication is a “how to” and not
necessary and can be omitted altogether. The term “3-Part Communication” could
be defined and added to the NERC Glossary to suffice the elaboration of the
definition proposed in this requirement. The idea of requiring all communications
(Operating Communications) to be made as 3-part communications is not practical
and should be left up to the communicating entities. Requiring ongoing
administration of “3-part” communications will impede rather than improve timely
communications consequently affecting the reliability of the BES.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
IESO
No
The IESO disagrees with using the term Operating Communications as it is not much
different from the term Reliability Directives (see our comments under Q1). Using the
term Reliability Directives to support the requirements for 3-part communication can
avoid
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Question 6 Comment
(a) any confusion with the requirement in COM-002-3,
Response: This was a concern of the SDT also. A webinar was conducted on June 7,
2012 and was posted to NERC.com to clarify the relationship between the two
standards.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_200702_June_7_2012_final.pdf
(b) potential double jeopardy of violating both COM-002 and COM-003, and
Response: See the remarks above
(c) The need to exercise 3-part communication for routine operating instructions.
Response: See the remarks below.
However, if the SDT’s intent is to require 3-part communication for any and all
operating instructions (as the proposed term suggest), then this intent will result in
unnecessary 3-part communication burdens for simple actions such as when requests
for the removal of a line, or switching, or generation output changes are issued. We
suggest the SDT to remove the term Operating Communications. With respect to
Requirements R2 and R3, we question the need for having these requirements if
Reliability Directives also cover non-emergency conditions (instructions/actions that
are needed to address potential Adverse Reliability Impact). The requirement to
exercise 3-part communication to handle Reliability Directives is thus duly addressed
in COM-002-3. Other than emergency conditions and potential Adverse Reliability
Impact conditions, we do not see a need to exercise 3-part communication for
routine operating instructions.
Response: The OPCPSDT respectfully disagrees. The term “Reliability Directive” in
the current draft of COM-002-3 covers a very narrow band of low frequency, high
impact events. Communication protocols must be applicable to all BES Operating
Communications to clarify content in order to avoid mistakes that could negatively
impact the BES. During its discussion of the approval of the Interpretation of COM137
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Question 6 Comment
002-2 R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Response: Thank you for your comments. Please see the response to your comments above.
SMUD
No
Requirements R2 and R3 are over prescriptive and included as a business practice in
the entities’ training program.
Response: Thank you for your comments. Communication protocols must be applicable to all Operating Instructions to clarify
content in order to avoid mistakes that could negatively impact the BES. The SDT does not see three part communication as a
business practice.
Liberty Electric Power LLC
No
Three part communication is a best business practice. Three part communication
should be required during a declared Emergency. But there is no reason to create a
standard, and the massive monitoring requirements and records obligations which go
along with a standard, to cover business communications.
Response: Thank you for your comments. Communication protocols must be applicable to all Operating Instructions to clarify
content in order to avoid mistakes that could negatively impact the BES. The SDT does not see three part communication as a
business practice. The SDT has developed a new approach to the standard that addresses your concern.
San Diego Gas & Electric
No
The boxed note in the draft of COM-003-1 states that “Reliability Directives are a type
of Operating Communications...” and the process described in R2 and R3 is 3 way
communications. Why is the SDT segregating this as if it is a “separate process” that
needs to be followed by operating personnel? The two do not appear to be separate
communication processes. SDG&E recommends removing the word, “excluding,” and
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Question 6 Comment
replacing it with the word “including,” so that R2 states:
”Each Reliability Coordinator, Transmission Operator and Balancing Authority that
issues an oral, two-party, person-to-person Operating Communication, including
Reliability Directives shall:
Response: The exclusion was an effort to prevent double jeopardy from the
applicability of two standards (COM-003-1 and COM-002-3).
”SDG&E also recommends that the following language be added in a bullet to R2.2:
o Request that the receiver repeat the Operating Communication if the receiver does
not issue a response (not necessarily verbatim).
R3 notes that the Registered Entity who receives the Operating Communication
needs to repeat the Operating Communication provided.
In order to promote compliance and proper communications, this bullet point should
be added.
Response: The OPCPSDT has changed language in COM-003-1, draft 3 to the same
language as COM-002-3, R2 and R3 to address industry comments regarding the
dissimilar language in draft 2.
Response: Thank you for your comments. Please see the response to your comments above.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
No
Three part communication should not be required for routine operating
communications.
Response: Thank you for your comments. The OPCPSDT respectfully disagrees. Communication protocols must be applicable to all
BES Operating Communications to clarify content in order to avoid mistakes that could negatively impact the BES. During its
discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
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Question 6 Comment
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
Indiana Municipal Power
Agency
No
IMPA agrees with the splitting of a single requirement into two requirements.
However, the blue box on page 2 of 10 makes the statement “Reliability Directives
are a type of Operating Communications, to the extent they change or maintain the
state, status output, or input of an Element or Facility of the Bulk Electric System”
which seems to include Reliability Directives by simply referencing Operating
Communications in each requirement (R2 and R3). By excluding Reliability Directives,
the requirement is now very confusing and can be interpreted two different ways.
Requirement 2 does not include the Generator Operator as a potential entity that
could issue an Operating Communication. Within its organization or company, a
Generator Operator could issue an Operating Communication, such as one location
calling and telling another location to start its generating unit. IMPA believes the
Generator Operator should be included in R2.
Response: The SDT appreciates your comments. This was a concern of the SDT also. A webinar was conducted on June 7, 2012 and
was posted to NERC.com to clarify the relationship between the two standards.
http://www.nerc.com/docs/standards/dt/Webinar_Slides_Project_2007-02_June_7_2012_final.pdf
Based on the revised definition of Operating Instruction, a GOP can only be a receiver of an Operating Instruction.
Roger Zaklukiewicz Consulting
No
See previous comment to Question 1.
Response: Thank you for your comments.
Sacramento Municipal Utility
District
No
See response in #10
Response: Thank you for your comments.
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Organization
Entergy Services
Yes or No
Question 6 Comment
No
Three part communications should not be required for routine operating
communications. See the definition of Reliability Directive in COM-002, which
addresses the actual reliability issues associated with communications. This team
once had coordinated with the RC SDT (Project 2006-06), and the RTO SDT (Project
2007-03), with a different approach for routine communications resulting from a
meeting between the chairs of the three SDTs on November 17, 2009 in the SERC
offices in Charlotte, NC. Quoting from the meeting setup email: “On the basis that
the SC members are the key drivers of the joint effort to finalize “Directives and
Three-Part Communications”, [...] and [...] indicated a preference for Tuesday 1-3PM
ET November 17. Some members of the RTOSDT and RCSDT will be attending the
meeting in person....” At that meeting it was agreed that RC SDT (Project 2006-06)
would develop the definition for “Reliability Directives”, and require 3-way
communication for Reliability Directives by the RC. Conversely, it was decided that
OPCP (Project 2007-02) would handle ordinary communications, but would not
require 3-way communications for routine communications. RTO SDT (Project 200703) only agreed to this course of action (in effect, backing out of writing ordinary
communications standards as part of Project 2007-03) because OPCP SDT (Project
2007-02) had committed to this approach during that meeting. It should be noted
that “COM-001-1 Telecommunications” and “COM-002-2 Communications and
Coordination” are included in the SAR for RTO SDT (Project 2007-02) and its
coordination with RC SDT and OPCP SDT was conditioned upon RC SDT and OPCP SDT
following the course of action agreed-to in the November 17, 2009 Charlotte, NC
meeting. OPCD SDT (Project 2007-02) should honor the intent of that meeting in
Charlotte and remove R2 and R3 from this standard. We suggest that R2 and R3
should be eliminated, since neither one will result in increased reliability.
Response: Thank you for your comments. The OPCPSDT is aware of the meeting in Charlotte in 2009. The OPCPSDT respectfully
disagrees with your summarization of the meeting. The members of the OPCP SDT that were in attendance at the Charlotte
meeting referenced above, while agreeing that the RCSDT was going to define “Reliability Directive,” have no record that there
was an agreement to eliminate three part communication from the development of COM-003-1. During its discussion of the
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Question 6 Comment
approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary communication protocols for use in the operation of
the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is necessary and what
is required) during normal operations was a necessary step in addressing the BOT’s concern.
City of Austin dba Austin
Energy
No
It makes sense to separate R2 from R3; however, AE respectfully objects to
mandating three-part communication for normal operating communications. The fact
that most registered entities already use three-part communications for normal
operating communications makes it a best practice; it does not mean a NERC
Reliability Standard should require it.
Response: Thank you for your comments. The OPCPSDT respectfully disagrees. The term “Reliability Directive” in the current draft
of COM-002-3 covers a very narrow band of low frequency, high impact events. Communication protocols must be applicable to all
BES Operating Communications to clarify content in order to avoid mistakes that could negatively impact the BES. During its
discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited
development of a comprehensive communications program, which would address necessary communication protocols for use in
the operation of the Bulk Electric System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the BOT’s concern.
Essential Power, LLC
No
Although I agree with the requirement making the receiver responsible for repeating
the message, this should be included in COM-002. Again, having two separate
Standards on this topic is redundant and unnecessary.
Response: Thank you for your comments. The SDT respectfully disagrees that COM-002 and COM-003-1 are redundant.
Salt River Project
No
This combination for R2 and R3 would open some vertical entities to be being fined
multiple times for the same communication.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
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Yes or No
Wisconsin Electric dba We
Energies
No
Question 6 Comment
This is too similar to but different than what is required for a directive. Since 99.9%
or more communications will not be directives, we will be conditioning operators to
use this for directives also.
Response: The applicability of COM-003-1 is for instructions that change the
configuration of the BES, not for casual conversation or for discussions of potential
options among entities.
If I reissue an Operating communication because the other party does not respond
soon enough for me for whatever reason, the other party has violated R3 of this
standard. R3 in general would not apply to a DP except for loads connected at
transmission voltages.
Response: The SDT has developed a new approach to the standard that addresses your
concern.
Response: Thank you for your comments. Please see the responses above.
PPL Electric Utilities
No
Since Reliability Directives are a subset of Operating Communications, if this was
done to lower the VRF for Operating Communications that are not Reliability
Directives, this modification makes sense. However, having two stds/rqmts address
3-part communication (even if not in same words) is not as clear as it could be. One
standard requiring 3-part comm for Real-time operating communications which
includes Reliability Directives would be more straight-forward, with a higher VRF for
Reliability Directives.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope for communications than that for Project 2006-06.
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Illinois Municipal Electric
Agency
No
Question 6 Comment
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the response to comments submitted by the SERC OC Standards Review
Group.
Ameren
No
From our perspective, use of such a split for all Operating Communications (not
directives) would add to the confusion.
Response: Thank you for your comments. The SDT believes that a separate requirement for the sender and receiver is the only
reasonable manner in which to capture applicability. The SDT is using the language of COM-002-3, R2 and R3 in draft 3 of COM
003-1.
Idaho Power Company
No
I'm not sure I understand the separation of Directives and these Operating
Instructions. They seem very similar and could be incorporated into the same
standard. The split between Issuer and Receiver seems to add some clarity.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope for communications than that for Project 2006-06.
American Transmission
Company, LLC
No
The prescriptive requirements currently in R2, and R3, tell how, not what, an entity is
obligated to do. To address the fact that most Operating entities engage in
“Operating Communications”, one requirement(combining R2 and R3) is all that is
needed, and ATC recommends that Requirement 2 be restated as follows:
R2 Each Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider that issues, or receives an Operating
Communication, excluding Reliability Directives, shall use Three-part
Communications.
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Question 6 Comment
Response: The SDT believes that a separate requirement for the sender and
receiver is the only reasonable manner in which to capture applicability and to
avoid possible violations that are caused by one entity to be awarded to the other.
Furthermore, ATC recommends that the SDT reconsider adding the “three-part
communication” as a defined term properly vetted through the appropriate process,
and added to the NERC Glossary of Terms. The definition as previously noted in Draft
#1 is below.
Three-part Communication - A Communications Protocol where information is
verbally stated by a party initiating a communication, the information is repeated
back correctly to the party that initiated the communication by the second party that
received the communication, and the same information is verbally confirmed to be
correct by the party who initiated the communication.
Response: The SDT proposed that in draft 1 and was heavily criticized by
stakeholders. It was eliminated in draft 2 in response to those comments.
Response: Thank you for your comments. Please see the comments above.
MISO
No
Given the broad applicability of R2 and R3 as a result of the definition of Operating
Communication, the split of requirements may result in entities being assessed
violations for multiple requirements as a result of 1 (one) communication or operating
event. While MISO appreciates the clarity in roles and responsibilities the split
provides, it is concerned about the future application and feasibility thereof. Please
refer to MISO’s comments regarding the definition of Operating Communication for
more detail on the likely adverse impact to reliability that will result from the diversion
of time and resources the split will require.
MISO cannot, at this time, support the addition of those requirements.
Response: Thank you for your comments. The SDT has developed a different approach to the standard that addresses your
concern.
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NextEra Energy, Inc
Yes or No
Question 6 Comment
No
NextEra does not agree with R2 or R3, as drafted. COM-002-2, which applies to
three-way communications for Reliability Directives, is not mirrored by the proposed
COM-003-1, thus creating two different three-way communication protocols. This
disconnect between the two three-way communication Standards is
counterproductive for System Operators, who we want focused on the reliable
operation of the system, rather than memorizing multiple three-way communication
protocols. As a member of the Standards Committee, NextEra has expressed its
concern that Standard Drafting Teams (SDTs) are not sufficiently communicating and
coordinating in a manner that promotes clear and effective Reliability Standards. It
appears that the COM-002 and COM-003 SDTs have not coordinated their efforts,
because COM-003-1 proposes to implement a more restrictive three-way
communication protocol via R1, R2 and R3 than proposed for COM-002-3. NextEra
believes that the easiest way to make COM-003-1 consistent with COM-002-3 is to
implement the same three-part communication language contained in COM-002-3.
Specifically, COM-003-1 R1, R2 and R3 would be replaced with the following language
that mirrors COM-002-3:
“R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as an Operating Communication, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as
an Operating Communication to the recipient.
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Communication shall
repeat, restate, rephrase or recapitulate the Reliability Directive.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues an Operating Communication shall either:
o Confirm that the response from the recipient of the Operating Communication (in
accordance with Requirement R2) was accurate, or
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Yes or No
Question 6 Comment
o Reissue the Operating Communication to resolve any misunderstandings.”
Although NextEra prefers that the SDT use the above language, in the event the SDT
chooses not to mirror COM-002-3, NextEra requests the SDT implement the
proposed modifications to R1 and R2 as set forth in response to questions 5, 7 and
10.
Response: Thank you for your comments. The OPCPSDT agrees and has changed the language in COM-003-1 in draft 3 to be the
same language as stated in COM-002-3, R2 and R3.
Alliant Energy
No
We do not believe there is a need for COM-003 at all and recommend it be deleted.
COM-002 covers Reliability Directives very well. For three-part communications in a
non-Reliability Directive situation we believe it should be considered an industry
best-practice. By requiring three-part communications as dictated in this standard,
there will be requests for interpretations, CAN's produced for the CEA, and numerous
violations written for what the industry considers a non-problem. In our opinion this
standards goes against the concept of risk-based standard making and reinforces a
zero-defect operation, which opposite of how the industry works.
Response: Thank you for your comments. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC
BOT stipulated in its approval the expedited development of a comprehensive communications program, which would address
necessary communication protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols
concerning three part communication (when it is necessary and what is required) during normal operations was a necessary step
in addressing the BOT’s concern.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the response to the ISO/RTO Standards Review Committee comments.
Seminole Electric Cooperative
No
Splitting the requirement is okay but the exclusion of reliability directives and the
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Question 6 Comment
structure of R2 and R3 to take one of the following actions based on the other party's
action is ambiguous.
Response: Thank you for your comments. The exclusion of Reliability Directives from COM-003-1 was incorporated to preclude
double jeopardy.
NV Energy
No
I have not seen the parallel requirement that pertains to Reliability Directives, but I
can imagine no reason why the communication protocols for Operating
Communications would ever differ from those for Reliability Directives. Making the
distinction here in this requirement adds unnecessary confusion.
Response: Thank you for your comments. The OPCPSDT agrees and has changed the language in COM-003-1 in draft 3 to be the
same language as stated in COM-002-3, R2 and R3.
Exelon Corporation and its
affiliates
No
Please see response to Q10.
Response: Thank you for your comments. Please see the response to Question 10.
Brazos Electric Power
Cooperative
No
Please see formal comments provided by APM.
Response Thank you for your comments. Please see the response to the comments provided by APM.
Oncor Electric Delivery
Company LLC
No
Oncor believes that the application of three part communication as prescribed in the
proposed reliability standard COM-002-3 is appropriate as prescribed for
emergencies. Any additional requirements, including those for routine operations go
well beyond what is called for in the 2003 Blackout Report which focused on
emergencies. As such, Oncor also takes the position that the term Operating
Communications should also be removed.
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Organization
Yes or No
Question 6 Comment
Response: Thank you for your comments. The term “Reliability Directive” in the current draft of COM-002-3 covers a very narrow
band of low frequency, high impact events. Communication protocols must be applicable to all BES Operating Communications to
clarify content in order to avoid mistakes that could negatively impact the BES. During its discussion of the approval of the
Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the expedited development of a comprehensive
communications program, which would address necessary communication protocols for use in the operation of the Bulk Electric
System. The SDT determined that protocols concerning three part communication (when it is necessary and what is required)
during normal operations was a necessary step in addressing the BOT’s concern.
Kansas City Power & Light
No
Do we lose the “speciality” of only using 3-part communication during times of
issuing directives/emergencies?
Response: Thank you for your comments. The SDT believes we have not lost a unique feature of emergency communication by
requiring three part communication for routine operations. The SDT believes we are creating a higher level of communication
discipline designed to avoid miscommunication and prevent mistakes that would harm the stability of the BES.
South Carolina Electric and
Gas
No
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP agrees that Reliability Directives must be handled in a
more prescriptive manner. Since Reliability Directives are also an important piece of
Project 2006-06, it makes sense to move the developmental responsibility to them and avoid unnecessary overlap between the two projects.
Response: Thank you for your comments.
Manitoba Hydro
Yes
Manitoba Hydro agrees with splitting the single requirement into (R2) issuer and (R3)
receiver, but as stated in our response, we do not agree with the term “Operating
Communications”.
Response: Thank you for your comments. Please see the response to your comments to Question 1.
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Organization
Yes or No
City of Tallahassee
Yes
Question 6 Comment
TAL agrees with this split into two requirements for the protection of each party in
the event of non-compliance by the opposing party. TAL seeks clarification on the
application of this requirement in an instance where a receiver never acknowledges
the issuer.
Response: Thank you for your comments. The OPCPSDT would expect the issuer to continue to establish communication with the
receiver through multiple attempts and multiple media. If voice communication is not achieved the issuer must assume lost
communication and contemplate other alternatives.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
Imperial Irrigation District
Yes
Detroit Edison
Yes
BC Hydro
Yes
Florida Municipal Power
Agency
Yes
Bonneville Power
Administration
Yes
GP Strategies
Yes
Arizona Public Service
Company
Yes
None.
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Organization
Yes or No
HHWP
Yes
Flathead Electric Cooperative,
Inc.
Yes
NIPSCO
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
Clark Public Utilities
Yes
The United illuminating
Company
Yes
Utility Services, Inc.
Yes
Colorado Springs Utilities
Yes
Utility System Efficiencies, InC.
Yes
Portland General Electric Transmission & Reliability
Services
Yes
Puget Sound Energy
Yes
Xcel Energy
Yes
Question 6 Comment
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Yes or No
City of Vero Beach
Yes
Texas Relibility Entity
Yes
U.S. Bureau of Reclamation
Yes
Central Lincoln
Yes
Question 6 Comment
but please see Q 10.
Response: Thank you for your comments. Please see the response to your comments in Question 10.
Western Electricity
Coordinating Council
Is the exclusion of Reliability Directives because they are covered under COM-002?
Since all COM-002 covers is Reliability Directives, why not include it in this standard?
Operators should use the same protocol for all Operating Communications. We agree
with the split for the issuer and the receiver.
Response: Thank you for your comments. Yes, the SDT wanted to avoid a double jeopardy situation.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Thank you for your comments. Please see the response to the comments submitted by the NPCC Regional Standards
Committee (RSC).
Public Service Enterprise
Group
See #10.
Response: Thank you for your comments. Please see the response to the comments in Question 10.
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7.
The SDT modified the requirement for use of the NATO phonetic alphabet to allow use of another correct alpha numeric
clarifier. (See Requirement R1, Part 1.2.) Do you agree with this modification?
Summary Consideration:
Commenters were confused over the meaning of “accurate” alpha-numeric clarifier. The SDT stated these alpha-numeric clarifiers
were offered as alternatives to the NATO alphabet required in draft 1. The SDT noted other commenters who felt the NATO
specification was too restrictive but felt alpha-numeric clarifiers were vague. The SDT will sustain the requirement for the use of
alpha-numeric clarifier but has removed the word “accurate.”
Commenters who disagreed felt this requirement is still overly prescriptive and did not improve reliability. The SDT has developed
an alternate approach to COM-003-1 that will allow an entity to establish internal processes to identify, assess, and correct
communication deficiencies.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 7 Comment
No
What determines whether a clarifier used is an “accurate alpha-numeric clarifier”?
What dictates non-compliance? This is a procedural issue. The Standard should
require the Functional Entities to have a communications protocol that could include
this, but it should not be a standard on personnel.
Complexity is being added to
communications, not improvement. There are equipment designations that are
commonly used and understood, and to force the use of clarifiers will disrupt
operating communications.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ACES Power Marketing
Standards Collaborators
No
1. First the requirement uses the word “accurate” instead of “correct” as stated in
this question.
2. What is meant by the term “accurate alpha-numeric clarifiers?” Can someone
make up their own alpha-numeric clarifiers in the heat of the moment and expect the
other party to mentally “transition” and understand what they mean? Or does it
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Question 7 Comment
have to be another established and recognized alpha-numeric clarifier? A made up
alpha-numeric clarifier could be confusing to someone who isn’t familiar with the
clarifiers being used. This is more of a mental “transition” than determining the
difference between an Emergency (which will be stated up front as a Reliability
Directive as proposed in draft COM-002-3) and a normal operating instruction. We
suggest that only established alpha-numeric clarifiers be used.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to the
standard that addresses your concern.
Midwest Reliability
Organization NERC Standards
Review Forum
No
The MRO NSRF recommends the following comments for consideration by the SDT:
As written, if an operator simply states “open switch c138”, they would be found non
compliant. The SDT has not given any justification (reference to a FERC Directive) to
why they are mandating the use of alpha-numeric clarifiers within this requirement.
It is not needed to be written within this (or any other standard). It is agreed that it
may be a good practice in some cases, but when written within a standard, it is
driving for a zero tolerance. Entities will make a mistake and this non compliance
issue will be forward via the CEA as an FFT. Section 81 of the Commission’s March
15th, 2012 order questions if a violation is forwarded in an FFT format, is it really
needed for reliability. This requirement needs to be deleted. If an entity wishes to
use an alpha-numeric format, they can as part of their internal controls to reduce
their risk of violating a different standard or for safety reasons. The requirement of
using alpha-numeric as a standard will be administratively burdensome and punitive.
For example: An operator states, “open switch fifteen twenty six” instead of “open
switch one, five, two, six” is now subject to a potentially significant fine for no
reliability benefit. Suggest dropping the Alpha Numeric clarifier requirement from
the standard.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
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Question 7 Comment
Detroit Edison
No
"use accurate alpha-numeric clarifiers" is vague. Suggest re-wording and adding
verbiage: "use defined (or standard or specified) alpha-numeric clarifiers as specified
in Registered Entities communication protocols."Concern with requirement 1.2alpha-numeric clarifiers. Would like clarification if any alpha clarifier can be used or
must the phonetic alphabet listed in the white paper (military Communication
protocol)be used. example: for "R", is it required to use "Romeo" or can "Robert" be
used?
Response: The word “accurate” has been removed.
Concern with VSL table for R1. Current format shows that an entity must be 100%
compliant. The break down from medium to severe is based on how many elements
of R1 was not followed. Suggest changing the format to how many times it was not
followed rather than the number of elements.
Response: The SDT has developed a different approach to the standard that
addresses your concern.
Response: Thank you for your comments. See the response above.
Duke Energy
No
We think that this is over-reaching (As currently written, the Standard erroneously
focuses on “how” an entity can be compliant, rather than describing “what” an entity
needs to achieve to be compliant), and creating a requirement that can’t reasonably
be audited or certified.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
BC Hydro
No
BC Hydro does not support the full time use of alpha numeric clarifiers for all
Operating Communication. In some cases we believe it detracts from the instruction
being delivered. In our system, devices are identified by a combination of alpha and
numeric. For example, to call transmission line 5L98, ‘5-Line-98’ or a circuit breaker
5CB11, ‘5-circuit breaker-11’ does not add value. This may help in some areas
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Yes or No
Question 7 Comment
depending on their naming conventions. BC Hydro does not think the use of the term
‘accurate’ effectively describes what is permissible to be used as an alpha numeric
clarifier.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Dominion
No
Dominion suggests that Requirement R1, Part 1.2 is ambiguous in that the use of
alpha-numeric identifiers appears optional (but if they are used, they must be
accurate). If the purpose of Part 1.2 is to USE alpha-numeric identifiers, then this
statement needs to be modified to state that more directly and to give that clarity.
Response: Thank you for your comments. Some Operating Instructions may not involve alpha-numeric qualifiers.
Associated Electric
Cooperative JRO00088
No
AECI appreciates the SDT’s desire to afford flexibility to the industry, and yet we still
view this level of prescription as unnecessarily burdensome, given the current broad
scope of this particular standard.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
LG&E and KU Services
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Too prescriptive. The industry has performed for many decades, successfully. NERC
should focus on risk and performance.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO/RTO Standards Review
No
This requirement is a procedural issue and is outside the scope of the approved SAR
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Organization
Yes or No
Committee
Question 7 Comment
which proposes responding to the Blackout Recommendation to tighten
communications protocols especially during emergencies. This proposed requirement
is both procedural and does not address tightening communications of situational
awareness. The SRC would suggest that the standard should require the Functional
Entities to have a communications protocol that could indeed include this suggestion,
but it should not be a standard on personnel.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” Response: The OPCPSDT disagrees that the Blackout Report (and FERC Order 693 and the SAR) only addresses the
need to tighten protocols for Emergencies. The Blackout Report uses the phrase “especially for emergencies” which the SDT
interprets to mean the authors were recommending applicability of communication protocols for the total population of
operating communication and used this language to amplify the importance of such protocols during emergency conditions. FERC
Order 693 and the SAR are very specific in that both include references to “normal” operating conditions.
The SDT has developed a new approach to the standard that addresses your concern.
City Water Light and Power
No
Again, this requirement attempts to dictate process as opposed to being a standard.
The standard should only dictate the result, not how it is achieved.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Hydro One Networks Inc.
No
This requirement adds added complexity to communications, not improvement.
There are equipment designations that are commonly used and understood, and to
force the use of clarifiers will disrupt operating communications.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
SERC OC Standards Review
Group
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”.
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Organization
Yes or No
Question 7 Comment
Response: The SDT has developed a new approach to the standard that addresses your concern.
Bonneville Power
Administration
No
BPA disagrees with both clarifiers (NATO phonetic alphabet and alpha numeric) and
believes the communication should be left to the discretion of each utility. This
modification causes an undue burden when relaying communication; especially in a
time of an emergency and dramatically increases the risk of human error. BPA
recommends that the drafting team remove any and all language of NATO phonetic
and alpha numeric identification of any device, (Alpha and especially numeric
phonetic requirements). R2 and R3 clearly ensure that all parties are already
properly communicating clearly and concisely. Should the drafting team remove the
NATO phonetic and alpha numeric language, BPA would change its negative position
to affirmative.
Response: Thank you for your comments. The SDT respectfully disagrees with your assertion that the use of alpha numeric
clarifiers will “dramatically increase the risk of human error”. Use of phonetic clarifiers is a Human Performance tool designed to
reduce the rate of human error and communication problems.
The SDT has developed a new approach to the standard that addresses your concern.
Southern Company
No
Southern does not agree with R1 and its sub-requirements as they appear to force a
single communications procedure on the industry and are focused on the “HOW” of
communication when they should be more focused on the “WHAT”. Also, the word
"accurate" should be removed from R1.2, as it is not needed.
Response: The SDT has developed a new approach to the standard that addresses your concern.
The Dayton Power and Light
Company
No
This requires using a 'correct’ alpha numeric clarifier, while the proposed standard is
written as ‘accurate’. It would be great if there were consistency between the
proposed standard and the comment form. Not sure how one can define accurate or
correct. The standard indicates that NATO has one, but there are others as well. The
moniker for “A” in the LAPD definition is ADAM, while NATO is ALPHA. Both are
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Yes or No
Question 7 Comment
‘accurate and/or correct’ but if I use one version and the person I’m talking to uses
another, is this a violation of the standard? The language in this proposed version is
better than the last (where they required the use of the NATO language) but I’m still
not comfortable this proposal fixes the problem.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to the
standard that addresses your concern.
CenterPoint Energy Houston
Electric, LLC.
No
Question 7 Comments: The use of correct alpha numeric clarifiers represents a “how
to” and although it may be an example of a good utility practice, it should not be a
requirement to the extent of not only just having to use the alpha numeric clarifiers,
but required to use them correctly or “accurate” as it is currently worded in the
language of proposed COM-003-1 R 1.2 draft 2. The requirement is unclear as to
whether the accurate use of alpha -numeric clarifiers is required only when the
clarifiers are used, or whether accurate use of alpha-numeric clarifiers are required
for all oral Operating Communications. The use of any alpha- numeric clarifiers
should be left up to the discretion of the communicating entities during their
exchange, acknowledgement, and agreement of information of any such
communication.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to
the standard that addresses your concern.
SMUD
No
Communication should not be restricted to only use of the phonetic alphabet.
Referencing a “103-C” switch versus a “103-Charley” does not enhance reliability and
has the potential of hindering reliable operation of the BPS by forcing the Operator
Communications personnel to focus on being compliant with the correct phonetics
rather than the actual instruction.
Response: Thank you for your comments. The SDT respectfully disagrees with your thought that the use of alpha numeric
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Yes or No
Question 7 Comment
clarifiers has the potential to “hinder reliable operation”. Use of phonetic clarifiers is a Human Performance tool designed to
reduce the rate of human error and communication problems. The SDT has developed a new approach to the standard that
addresses your concern.
Liberty Electric Power LLC
No
Again, this is beyond the proper scope of reliability standards.
Response: Thank you for your comments. The SDT respectfully disagrees and has developed a new approach to the standard that
addresses your concern.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does not believe
that this sub requirement is appropriate when applied with the new definition
“Operating Communication.” Common operating communications should not be
considered a compliance event that requires the use of correct alpha numeric
clarifiers. Under the current language, it could be interpreted that according to
“Operating Communication” that every change in generation output must be stated
in alpha numeric clarifiers in every instance of communication. This requirement
shifts operators focus from communicating proper information to a focus on
communicating using the specified terms in all instances of communication, where in
everyday normal business activities and operation should not require such scrutiny.
Response: The SDT has developed a new approach to the standard that addresses your concern.
Orlando Utilities Commission
No
Use a phonetic alphabet only when further clarification is needed.
Response: Thank you for your comments. Use of phonetic alphabet only when further clarification is needed could be subjective.
The receiver of the communication may have thought that they clearly heard “Open breaker 13D” when what was really said was
to “Open breaker 13B”. Use of the phonetic alphabet would correct this potential error.
Clark Public Utilities
No
This requirement is still overly prescriptive. Practically all switches, breakers, and
transformers have alpha-numeric identifiers and the proposed Requirement R1.2 will
require the use of some form of alpha-numeric clarifier (either NATO or some other
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Question 7 Comment
accurate clarifier). However, many alpha-numeric identities need no clarifier to be
accurately understood. Additionally, any such mis-understandings would become
obvious during the three-way communication process. The SDT needs to modify this
requirement to allow the judgment of the system operator to be used in the
determination of whether an alpha-numeric clarifier is needed. This judgment would
be based on
(1) common sense in understanding that some letters or numbers may sound similar
when broadcast over communications equipment,
(2) past experience with certain letters or numbers requiring clarification,
(3) an understanding by each individual system operator (as supplemented by
managerial oversight) of that system operator’s ability to correctly pronounce letters
and numbers (in the English language, unless another language is mandated by law or
regulation), and
(4) confidence derived from the accurate and understandable repetition of the alphanumeric identifiers in the three way communication process.
Clark believes that Requirement R1.2 needs to rely on the determination by the
system operator as to whether the use of an alpha-numeric clarifier is needed or not.
These system operators are required to obtain certifications and ongoing training and
the operating process needs to defer to the judgment of trained and certified system
operators to resolve this potential communication issue.
Response: Thank you for your comments. The SDT believes that it would be more consistent and less confusing for the operators
to utilize alpha numeric clarifiers at all times instead of having to go through a determination if it is needed in each operating
situation.
Indiana Municipal Power
Agency
No
The question uses the word “correct” and the requirement uses the word “accurate”.
The use of either word adds ambiguity to the requirement, and an entity being found
compliant or non-compliant depends on how the entity and the auditor interprets
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Question 7 Comment
the meaning of “use of an accurate alpha-numeric clarifier”. The SDT should allow
the entity to pick the alpha-numeric clarifier that its company wants to use or the
same clarifier that was used when the Operating Communication was given, and not
give an auditor the chance to say it is not an “accurate” alpha-numeric clarifier.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to
the standard that addresses your concern.
Sacramento Municipal Utility
District
No
See response in #10
Entergy Services
No
See our responses to Questions #1, 2 and 4.
Response: Thank you for your comments. See responses to these questions.
City of Austin dba Austin
Energy
No
There is not enough evidence to support the need for these types of specifics.
Recommendation 26 encourages NERC “to ensure that all key parties ... receive
timely and accurate information.” COM-003-1 seems to interpret the
recommendation by telling entities “how” to ensure information is accurate (e.g., use
English, 24-hour clock, time zones, alpha-numeric identifiers, etc.). This standard
reaches too far into the “how” instead of focusing on the “what,” which is accurate
information. Registered entities should decide the best methods to ensure accurate
information for themselves (through three-part communication, use of the 24-hour
clock or otherwise).
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Colorado Springs Utilities
No
the term "correct alpha-numeric clarifier" is itself unclear. Searching on Google, I can
find no other use of this term outside of this Standard. Therefore, this does not
appear to be a standard term or concept. Did the SDT mean to require the use of a
phonetic alphabet (NATO's or any other)? If so, please just state so. If the intent was
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Yes or No
Question 7 Comment
to permit means other than phonetic alphabets to ensure clear communication of
alpha-numeric identifiers, then I suggest clarifying the Standard's language. Perhaps,
"When participating in oral Operating Communications and using alpha-numeric
identifiers, use a phonetic alphabet or similar means to ensure clear understanding."
Response: Thank you for your comments. The SDT used the term “alpha numeric clarifier” as a substitute for the NATO alphabet,
which generated many comments from draft 1. It gives entities freedom to use their own clarifier that conveys the correct number
or letter of equipment nomenclature they are referring to. The word “accurate” has been removed.
Essential Power, LLC
No
If the purpose of this Standard is to improve and standardize communications, than
all entities should use the same alpha numeric clarifiers.
Response: Thank you for your comments. Previous versions of this Standard required the use of the NATO phonetic alphabet.
This was seen as too prescriptive by industry. While there is nothing to prevent entities from using standardized alpha numeric
clarifiers, it is not a requirement in this version of the standard.
Wisconsin Electric dba We
Energies
No
Use of “accurate” accurate alpha-numeric clarifiers is subjective. What are they?
Who decides what is “accurate”? An auditor? The NATO phonetic alphabet is really
still being mandated. What if I use the NATO version and another entity uses a
different one. Can we talk to each other? We will now also have to specify what
phonetic alphabet we are using before any communication.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to
the standard that addresses your concern.
Manitoba Hydro
No
Manitoba Hydro agrees with the use ‘accurate alpha-numeric identifiers’ and feels
that they should also be required when referring to a Transmission interface Element
or a Transmission interface Facility in R1.1.4
Response: Thank you for your comments.
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Organization
Portland General Electric Transmission & Reliability
Services
Yes or No
Question 7 Comment
No
Requirement 1.2 requiring the use of alpha-numeric clarifiers would unnecessarily
complicate operator communications, especially inter-company communications
where transmission facilities have historically and are commonly identified by alphanumeric characters. The use of three-way communications ensures accurate
communications without the complications of alpha-numeric clarifiers.
Response: Thank you for your comments. Use of phonetic clarifiers is a Human Performance tool designed to reduce the rate of
human error and communication problems. The SDT has developed a new approach to the standard that addresses your concern.
Puget Sound Energy
No
No. The current language addressing alpha-numeric clarifiers is a significant
improvement over the formulation addressing the same issue in the previous draft.
However, this requirement remains overly-prescriptive, especially with respect to
numeric clarifiers. Even with the NATO clarifiers, not all numbers have clarifiers. As a
result, it not clear when a numeric clarifier would be required and when it is
acceptable not to use such a clarifier. The requirement to use alpha-numeric
clarifiers should be removed from the proposed standard entirely. If the requirement
is not removed in its entirety, the requirement should be modified to exclude
numeric clarification.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to the
standard that addresses your concern.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see the response for the SERC OC Standards Review Group.
Xcel Energy
No
1) “Accurate alpha-numeric identifier” needs to be clarified. Could each entity (or
even each operator) create their own alpha-numeric identifiers? Further would it be
a violation if an operator used “Charlie” in one conversation and “chalk” in another?
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Yes or No
Question 7 Comment
Or, is it an expectation that the entity/operator adopts an existing list of alphanumeric identifiers, which is published publicly?
Response: The standard does not mandate any one clarifier over another. The
word “accurate” has been removed.
2) We recommend that device names be excluded from the requirement to use
alpha-numeric identifiers when both parties are working off of written instructions.
We do not feel requiring this would improve reliability. Instead, it could actually slow
down the recovery of the system. For example, we have devices in the field that may
be labeled 12B34-W gang switches and it makes no senses to say, “Open and tag the
one, two, B as in Bravo, three, four W as in Whiskey gang switch, when both parties
have “12B34-W” written in the instructions they are both working from. Three-way
communications are occurring and if there is any question as to the device name, it
can be caught and clarified during that process.
Response: Thank you for your comments. The SDT disagrees with exempting
equipment names even when written down. This is another check that the correct
equipment is being operated. The SDT disagrees that use of alpha numeric clarifiers
would slow down recovery.
Response: Thank you for your comments. Please see the responses above.
Ameren
No
We recommend to the SDT that one industry-wide alpha-numeric clarifying system
should be used. Multiple systems may add confusion by use of clarifying words that
some Operators may not be familiar with. We agree with use of the NATO Spelling
Alphabet.
Response: Thank you for your comments. Previous versions of this Standard required the use of the NATO phonetic alphabet.
This was seen as too prescriptive by industry. While there is nothing to prevent entities from using standardized alpha numeric
clarifiers, it is not a requirement.
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Organization
Yes or No
Idaho Power Company
No
Question 7 Comment
They should specify the alphabet to use for consistency.
Response: Thank you for your comments. Previous versions of this Standard required the use of the NATO phonetic alphabet.
This was seen as too prescriptive by industry. While there is nothing to prevent entities from using standardized alpha numeric
clarifiers, it is not a requirement.
MISO
No
MISO is concerned that the phrase “accurate alpha-numeric clarifiers” is ambiguous
and could lead to unintended compliance burdens. Further, MISO notes that this
provision will have, at most, a minimally beneficial impact on reliability while requiring
Registered Entities to expend substantial additional resources and will increase the
likelihood of adverse impacts to reliability resulting from confusion caused by nonstandard alpha-numeric clarifiers.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to the
standard that addresses your concern.
Consumers Energy
No
As there is no definition of what alpha - numeric clarifiers must be used, this leaves
too much room for interpretation for audit staff.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
NextEra Energy, Inc
No
Similar to the 24 clock, it appears that R1.2 does not fully consider how
communications and naming conventions are used in the industry. Specifically,
alpha-numeric identifiers are used when there is an uncommon naming convention.
Examples of common naming conventions include AM/PM, breaker names such as
(8W15), etc. As written, the requirement could be interpreted to require alphanumeric identifiers for all alpha applications even though the industry has never had
a need to use such identifiers. This will likely lead to unnecessary confusion, and,
therefore, will likely not promote reliability. Moreover, the R1.2 and COM-003-1
technical paper suggest there is only one set of alpha-numeric clarifiers that are
“accurate.” NextEra does not agree with this perspective, and believes it is
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Yes or No
Question 7 Comment
counterproductive to narrowing a System Operator’s discretion on which alphanumeric clarifiers he or she may use. To address these matters, NextEra
recommends that R1.2 be revised to read: “When an oral Operating Communication
does not use a common naming convention, alpha-numeric identifiers shall be used.”
Response: Thank you for your comments. The standard does not mandate any one clarifier over another. The word “accurate”
has been removed. The SDT has developed a new approach to the standard that addresses your concern.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the response to ISO/RTO Standards Review Committee.
U.S. Bureau of Reclamation
No
By using the term "correct" alpha numeric clarifier, it implies that an incorrect alpha
numeric clarifier can exist. In reality as long as an alpha numeric clarifier is used to
verify the letters or numbers are conveyed the intent is made. The standard
language should be revised to state that "When participating in oral Operating
Communications and using alpha-numeric identifiers, use alpha-numeric clarifiers for
the letters and numbers to convey the correct numbers and letters in the Operating
Communication."
Response: Thank you for your comments. An example of an incorrect alpha numeric clarifier would be “k as in known”. The word
“accurate” has been removed.
Exelon Corporation and its
affiliates
No
While Exelon agrees with the modification to allow the use of another alpha numeric
clarifier, Exelon does not agree with the designation of "correct" related to alpha
numeric communication. Requiring "accurate" alpha-numeric clarifiers is overly
prescriptive and unclear. An entity should not be held accountable for 100%
adherence to a set phonetic alphabet. For example, if a communicator and receiver
use the phonetic nomenclature "motor operated disconnect one foxtrot" but in a
later communication the equipment is referenced as "motor operated disconnect
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Yes or No
Question 7 Comment
one fox" by the Standard as written this could be considered a violation. It should be
an expectation but not a requirement as long as the transmitter and receiver use
three way communications effectively. Again, the standard should emphasis entity
practice for effective communication not impose an overly prescriptive set of
requirements that pose compliance challenges.
Response: Thank you for your comments. The word “accurate” has been removed. The SDT has developed a new approach to
the standard that addresses your concern.
Brazos Electric Power
Cooperative
No
Please see formal comments provided by APM.
Response: Thank you for your comments. Please see response to APM.
Oncor Electric Delivery
Company LLC
No
Oncor take the position that this requirement is far too much detail and goes well
beyond the 2003 Blackout recommendations. Furthermore, Oncor take the position
that a more appropriate approach would be to require internal procedures that
address internal communication protocols.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
South Carolina Electric and
Gas
No
Imperial Irrigation District
Yes
JEA
Yes
R1.2 is unclear. The term “alpha-numeric identifiers” is not defined. We believe
examples would help. For example we assume that if we say the Northside 1, this
would not be alpha-numeric but what if we used logical letters such as NS1 in internal
communications. Is it all alpha-numeric communications or just illogical meaningless
letters and numbers. We believe we should be able to use logical alpha numeric
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Yes or No
Question 7 Comment
things like MS for motor-switch and not have to use alpha-numeric clarifiers. Also
please specify if this is for both internal and external communications. Again we
believe that this should be for external communications using illogical meaningless
letters and numbers not for internal normal nomenclature.
Response: Thank you for your comments. Alpha numeric clarifiers are not required for common terms like CB or MS or names like
“Northside”. They would be required for Element or Facility alpha-numeric identifiers. In addition, the definition of Operating
Instruction has been modified to provide clarity around when alpha-numeric identifiers are required.
Pepco Holdings Inc & Affiliates
Yes
However not sure if it is applicable to Reliability Directives.
Response: Thank you for your comments. Alpha numeric clarifiers are required for an Operating Instruction, which is a “command
from a System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.”
SPP Standards Review Group
Yes
We concur with the elimination of the NATO phonetic alphabet and thank the SDT for
making this change. This is an excellent example of backing away from being overly
prescriptive by requiring the NATO alphabet and allowing the industry to use any of
several other options to ensure effective communications. We do have concerns with
the use of ‘correct’ or ‘accurate’, depending on which document you refer to. What is
correct? What is accurate? How does one measure compliance with these terms? We
would propose to delete the word ‘accurate’ altogether. The requirement would then
read:
When participating in oral Operating Communications and using alpha-numeric
identifiers, use alpha-numeric clarifiers.1
Response: Thank you for your comments. An example of an incorrect alpha numeric clarifier would be “k as in known”. The word
“accurate” has been removed.
IESO
Yes
While we agree with allowing appropriate alpha numeric qualifiers other than the
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Yes or No
Question 7 Comment
NATO phonetic alphabet, we do not support the mandatory use of these qualifiers for
each and every instruction. They should only be required when clarification by either
party is requested.
Response: Thank you for your comments. Use of phonetic alphabet only when further clarification is needed could be subjective.
The receiver of the communication may have thought that they clearly heard “Open breaker 13D” when what was really said was
to “Open breaker 13B”. Use of the phonetic alphabet would correct this potential error.
Texas Relibility Entity
Yes
Consider removing the word “accurate” from part 1.2. We do not believe it adds
anything to the requirement, and it may cause confusion.
Response: Thank you for your comments. The word “accurate” has been removed.
NV Energy
Yes
Agree that it ought not to be restricted to NATO only, but we are confused about
what "correct" means. Perhaps it means any spoken word that begins with the
subject alpha character?
Response: Thank you for your comments. An example of an incorrect alpha numeric clarifier would be “k as in known”. The word
“accurate” has been removed.
Central Lincoln
Yes
but please see Q 10.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
None.
Florida Municipal Power
Agency
Yes
GP Strategies
Yes
Progress Energy
Yes
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Organization
Yes or No
Arizona Public Service
Company
Yes
HHWP
Yes
Lakeland Electric
Yes
Flathead Electric Cooperative,
Inc.
Yes
NIPSCO
Yes
Hydro-Quebec TransEnergie
Yes
The United illuminating
Company
Yes
Ingleside Cogeneration LP
Yes
Utility Services, Inc.
Yes
Salt River Project
Yes
Utility System Efficiencies, InC.
Yes
PPL Electric Utilities
Yes
American Transmission
Company, LLC
Yes
Question 7 Comment
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Organization
Yes or No
City of Tallahassee
Yes
City of Vero Beach
Yes
Seminole Electric Cooperative
Yes
California Independent
System Operator
Yes
Kansas City Power & Light
Yes
Western Electricity
Coordinating Council
Question 7 Comment
From an enforcement perspective, this could be problematic. As drafted this will
allow virtually any alpha numeric clarifier. Who is to determine if the identifies is
"correct?" This will put the auditor in the position of determining whether or not a
clarifier was correct or accurate. For auditing purposes there should be clear
direction on what is acceptable.
Response: Thank you for your comments. An example of an incorrect alpha numeric clarifier would be “k as in known”. The word
“accurate” has been removed.
NERC Operating Committee
See Response 10
Roger Zaklukiewicz Consulting
Not certain as I do not know the specifics of the NATO phonetic alphabet.
Response: Thank you for your comments.
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Public Service Enterprise
See #10.
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Yes or No
Question 7 Comment
Group
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8.
The SDT modified the requirement for use of identifiers to limit the applicability to operating communications involving
Transmission interface Elements/Facilities and to require use of the name for that Element/Facilities specified by the
Element/Facility’s owner(s). Do you agree with this modification?
Summary Consideration:
Many commenters believe this requirement is not necessary, stating that it is covered by Standard TOP-002.2a R18. The SDT is
aware that Requirement R18 is being eliminated by the RTOSDT as part of project 2007-03. Project 2007-03 chose to eliminate TOP002-2a Requirement R18 on the basis that “This requirement adds no reliability benefit. Entities have existing processes that handle
this issue. There has never been a documented case of the lack of uniform line identifiers contributing to a System reliability issue.
This is an administrative item, as seen in the measure, which simply requires a list of line identifiers. The true reliability issue is not
the name of a line but what is happening to it, pointing out the difficulty in assigning compliance responsibility for such a
requirement, as well as the near impossibility of coming up with truly unique identifiers on a nation-wide basis. The bottom line is
that this situation is handled by the operators as part of their normal responsibilities, and no one is aware of a switching error
caused by confusion over line identifiers.” COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only
Transmission interface Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both
parties are referring to the same equipment for the Operating Instruction.
Other commenters believe the requirement is too prescriptive and focuses on how instead of what. When defining common
communication protocols to be used for communication between entities, it is necessary to be specific on what must be
communicated and how it must be communicated.
A few commenters cited uncertainty over what Elements and Facilities are in scope of Requirement. The SDT intends that interface
BES Elements and BES Facilities are in the scope of this requirement. The benefit is that neighboring entities can quickly and
knowledgeably react to changing operating conditions on the BES without getting confused over which Element or Facility they are
referring to.
Organization
Yes or No
Northeast Power Coordinating
Council
No
Question 8 Comment
The applicability of this Standard is unclear in the case of Distribution Providers. The
definition of Operating Communication includes “Elements” that could impact the
BES. The NERC Glossary definition for Elements includes non-BES devices and
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Question 8 Comment
equipment. Additionally, the Purpose section of the Standard states "harmful to the
reliability of the BES." Since non-BES Elements could affect the BES this Standard
could be deemed applicable to non-BES devices. If it is the intent of the SDT to apply
this Standard to All Operating Communications concerning both BES and non-BES
Facilities this should be explicitly stated in the applicability section for transparency.
Otherwise clarifying language should be added to exclude non-BES Facilities. This is a
procedural issue. Suggest that the Standard should require the Functional Entities to
have a communications protocol that could indeed include this suggestion, but it
should not be a standard on personnel.
Response: Thank you for your comments. This requirement refers to Transmission interface Elements and Facilities. The SDT has
developed a different approach to the standard that addresses your concern.
ACES Power Marketing
Standards Collaborators
No
1. We don’t believe this requirement is necessary. A similar requirement was
removed from TOP-002-2 Project 2007-03. From the Project 2007-03 mapping
document:”R18. Neighboring Balancing Authorities, Transmission Operators,
Generator Operators, Transmission Service Providers and Load Serving Entities shall
use uniform line identifiers when referring to transmission facilities of an
interconnected network.”Project 2007-03 SDT’s reason for deletion of R18 from TOP002-2:”This requirement adds no reliability benefit. Entities have existing processes
that handle this issue. There has never been a documented case of the lack of
uniform line identifiers contributing to a System reliability issue. The bottom line is
that this situation is handled by the operators as part of their normal responsibilities,
and no one is aware of a switching error caused by confusion over line
identifiers.”We agree with these reasons and believe they should apply to R1 Part
1.1.4 in COM-003-1. 2. Another issue we have with the requirement is that this draft
standard is not applicable to TOs or GOs yet the requirement calls for the use of “the
name specified by the owner(s) for that Transmission interface Element or
Transmission interface Facility.” Are the auditors going to ask the TOs and GOs for
their list of named Elements or Facilities when they audit the applicable entities in
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Yes or No
Question 8 Comment
this standard?
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Midwest Reliability
Organization NERC Standards
Review Forum
No
The MRO NSRF recommends the following comments for consideration by the SDT:
1. This requirement is too closely associated with TOP-002-2b, R18. As written, a
BA, TOP, and GOP will be in double jeopardy of non compliance if either TOP-002-2b,
R18 or COM-003, R1.1.4 is violated.
2. A similar requirement was removed from TOP-002-2 Project 2007-03. From the
Project 2007-03 mapping document: “R18. Neighboring Balancing Authorities,
Transmission Operators, Generator Operators, Transmission Service Providers and
Load Serving Entities shall use uniform line identifiers when referring to transmission
facilities of an interconnected network.” Project 2007-03 SDT’s reason for deletion of
R18 from TOP-002-2: “This requirement adds no reliability benefit. Entities have
existing processes that handle this issue. There has never been a documented case of
the lack of uniform line identifiers contributing to a System reliability issue. The
bottom line is that this situation is handled by the operators as part of their normal
responsibilities, and no one is aware of a switching error caused by confusion over
line identifiers.” The standard is not applicable to TOs or GOs yet the requirement
calls for the use of “the name specified by the owner(s) for that Transmission
interface Element or Transmission interface Facility.” Suggest deleting this
requirement.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
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Question 8 Comment
same equipment for the Operating Instruction.
Duke Energy
No
We don’t believe that this requirement is consistent with the TOP requirement to use
common line identifiers. This is more restrictive, in that it mandates the use of a
name specified by the asset owner, while TOP simply requires the development of
common identifiers without dictating what party defines the names. We understand
the issue of identifying common terms for equipment, but believe the development
and use of “common identifiers” is already covered in the TOP Standard and should
be eliminated altogether from COM-003.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
BC Hydro
No
BC Hydro supports this in most cases, especially when dealing with the RC, but in
many cases there may be lack of clarity around ownership. We believe this needs to
be reworded to account for designation that is agreed to by the parties that are
communicating.
Response: Thank you for your comments. The SDT has developed a different approach to the standard that addresses your
concern.
Dominion
No
The requirement as written is superior to Requirement R18 of TOP-002b which
requires the use of “. . . uniform line identifiers when referring to transmission
facilities of an interconnected network.” However, the industry can’t have two
different standards with different requirements for identifying transmission facilities.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
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Question 8 Comment
same equipment for the Operating Instruction.
Associated Electric
Cooperative JRO00088
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s response to Question 8.
Response: Please see response to SERC OC Standards Review Group.
LG&E and KU Services
No
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”. Requirement 1.1.4 does not need to be in this standard as the
requirement for unique line identifiers is stipulated in TOP-002-2 R18.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
Too prescriptive.
Response: Thank you for your comments. The SDT has developed a different approach to the standard that addresses your
concern.
ISO/RTO Standards Review
Committee
No
This requirement is a procedural issue and is outside the scope of the approved SAR
which proposes responding to the Blackout Recommendation to tighten
communications protocols especially during emergencies. This proposed requirement
is both procedural and does not address tightening communications of situational
awareness.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
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Yes or No
Question 8 Comment
response time.” Additionally, the SAR is very specific in that it also includes the term “normal” operating conditions under
Applicability: “Clear and mutually established communications protocols used during real time operations under normal and
emergency conditions ensure universal understanding of terms and reduce errors.”
City Water Light and Power
No
This is already addressed in TOP-002 R18. Even if moved, the requirement should be
focused on agreed upon identifiers and the process for coordination should be left to
the entities.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. The SDT has developed a different approach to the standard that addresses your concern.
FirstEnergy
No
The requirement for line identifiers should not be included and is unnecessary. This
type of requirement was also removed from standard TOP-002 in recently board
approved project 2007-03. The drafting team position for the removal was the
following: “This requirement adds no reliability benefit. Entities have existing
processes that handle this issue. There has never been a documented case of the lack
of uniform line identifiers contributing to a System reliability issue. This is an
administrative item, as seen in the measure, which simply requires a list of line
identifiers. The true reliability issue is not the name of a line but what is happening to
it, pointing out the difficulty in assigning compliance responsibility for such a
requirement, as well as the near impossibility of coming up with truly unique
identifiers on a nation-wide basis. The bottom line is that this situation is handled by
the operators as part of their normal responsibilities, and no one is aware of a
switching error caused by confusion over line identifiers.” Therefore we suggest the
removal of R1.1.4 for the same reason.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
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Yes or No
SERC OC Standards Review
Group
No
Question 8 Comment
This sub-part is part of the SDT forcing a single communication procedure on the
industry. This goes far too deeply into the HOW” of communication as opposed to
the “WHAT”. Requirement 1.1.4 does not need to be in this standard as the
requirement for unique line identifiers is stipulated in TOP-002-2 R18.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Western Electricity
Coordinating Council
No
We question the need for this part of the requirement based on the fact that it
appears to be redundant with TOP-002-2b, R18.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Bonneville Power
Administration
No
BPA believes that the uniform line identifiers between utilities should be identified by
mutual consent and suggests the drafting team use the language from COM-003-1
R7, “Each Reliability Coordinator, Balancing Authority, Transmission Owner,
Transmission Operator, Generator Operator, Transmission Service Provider, Load
Serving Entity and Distribution Provider shall use pre-determined, mutually agreed
upon line and equipment identifiers for verbal and written Interoperability
Communications”. BPA also recognizes that uniform line identifiers are already
addressed in TOP-002-2b.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
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Question 8 Comment
same equipment for the Operating Instruction. The SDT has developed a different approach to the standard that addresses your
concern.
NERC Operating Committee
No
See Response 10
Southern Company
No
Southern does not agree with R1 and its sub requirements as they appear to force a
single communications procedure on the industry and are focused on the “HOW” of
communication when they should be more focused on the “WHAT”. Furthermore,
requirement 1.1.4 does not need to be in this standard as the requirement for unique
line identifiers is stipulated in TOP-002-2 R18.Also, is it certain that both parties in the
communication will know the name for the element/facility that is specified by the
element/facility's owner(s)?
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
HHWP
No
Recommend that R1.1.4 incorporate use of the term Uniform Line Identifiers, in
conformance with R18 of TOP-002.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
CenterPoint Energy Houston
Electric, LLC.
No
Question 8 Comments: The language in requirement 1.1.4 will require the limitation
to a single identifier for an interface element or facility between neighboring entities
which will require the neighboring entities to agree upon a specified single identifier.
This may possibly require entities to make changes to their EMS system and their
model and incur a cost to complete such tasks. Similar language is currently enforced
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Question 8 Comment
in TOP-002-2 R18, where Entities are required to use uniform line identifiers when
referring to transmission facilities of an interconnected network, making this
requirement language redundant.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction. The SDT has developed a different approach to the standard that addresses your
concern.
Flathead Electric Cooperative,
Inc.
No
Think this requirement is duplicative of TOP-002a, R18
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
SMUD
No
First, this requirement is redundant to Requirement R18 in the TOP-002 standard. It
also put an administrative burden on the RC to know each “correct” name specified
by the respective entity’s line segment causing a hindering timely operation of BPS
elements.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction. The SDT has developed a different approach to the standard that addresses your
concern.
Liberty Electric Power LLC
No
This requirement is already covered under TOP-002 R18, and opens double-jeopardy
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Question 8 Comment
for entities by including it in a second standard.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Orlando Utilities Commission
No
For example, the (OUC)Indian River to (FPL)Cape Canaveral #1 230kv line is
equivalent to the (FPL)Cape Canaveral to (OUC)Indian River #1 230kv line. Either
description is accurate and acceptable.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Indiana Municipal Power
Agency
No
The requirement that requires entities to use uniform line identifiers when referring
to transmission facilities of an interconnected network is in the TOP-002-2b standard
(R18). Requirement R1.1.4 of COM-003-1 draft is not needed and should be deleted.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Ingleside Cogeneration LP
No
Ingleside Cogeneration LP agrees with restricting the applicability of COM-003-1 R1.2
to Transmission interface Elements/Facilities. These are the most likely to carry more
than one identifier, as each entity may use different numbering conventions.
However, we see two separate types of identifiers which may need to be addressed
separately. First, those provided on control room monitors often come from a
centrally managed Regional database. It is not reasonable to expect System
Operators to refer to a Facility owner’s one-line diagram to reference these
interconnections - and may reduce reliability. Conversely, field personnel and
engineers may rely on the one-line for their identifiers. The use of the owner’s
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Yes or No
Question 8 Comment
documentation is more appropriate in these cases. We will further point out that
COM-003-1 does not apply to Facility owners, so it seems as though they could
decline to provide identifiers if they so choose.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Roger Zaklukiewicz Consulting
No
We should always use the identifier adopted by the RTO, not one developed by the
Element/Facility's owner.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Not all entities are included in an RTO.
Sacramento Municipal Utility
District
No
See response in #10
Entergy Services
No
See our responses to Questions #1, 2 and 4.
Salt River Project
No
The interface names that should be used are the names that are registered in the
TSIN.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
South Carolina Electric and
Gas
No
Wisconsin Electric dba We
Energies
No
See the Mapping Document for Project 2007-03 Real-time Operations, TOP-002 R18:
“This requirement adds no reliability benefit. Entities have existing processes that
handle this issue. There has never been a documented case of the lack of uniform line
identifiers contributing to a System reliability issue. This is an administrative item, as
seen in the measure, which simply requires a list of line identifiers. The true reliability
issue is not the name of a line but what is happening to it, pointing out the difficulty
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Yes or No
Question 8 Comment
in assigning compliance responsibility for such a requirement, as well as the near
impossibility of coming up with truly unique identifiers on a nation-wide basis. The
bottom line is that this situation is handled by the operators as part of their normal
responsibilities, and no one is aware of a switching error caused by confusion over
line identifiers.”
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
PPL Electric Utilities
No
This requirement seems duplicative of TOP-002-2 R18.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see our response to comments from SERC OC Standards Review Group
Ameren
No
We suggest the SDT to provide clarification and guidance on precisely what Elements
and Facilities are included in these terms. Since the word “interface” is not
capitalized or defined in the NERC Glossary or this Standard, it will be difficult for TO,
TOP, GO, GOP and DP entities to precisely identify the equipment associated with
these terms. We also recommend that the SDT consider use of the term
“Interconnected Facilities” as defined by Project 2007-06 System Protection
Coordination for use in the new Standard PRC-027-1. Multiple definitions in multiple
Standards for the same BES Elements and Facilities create unnecessary risk and
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Question 8 Comment
uncertainty for both Auditors and Functional Entities.
Response: Thank you for your comments. The term “interface” is used in other places without confusion. In addition, not all
interface Facilities are “electrically joined by one or more Element(s) and are owned by different functional, operating, or
corporate entities.” The SDT has developed a new approach to the standard that addresses your concern.
American Transmission
Company, LLC
No
Entities will face double jeopardy with existing Reliability Standard TOP-002-2b R18.
Requirement 18 of TOP-002-2b is proposed to be removed from NERC Standards by
the respective SDT because it adds no reliability benefit.
Response: Thank you for your comments. The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as part of
project 2007-03. COM-003-1, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface
Elements or Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are referring to the
same equipment for the Operating Instruction.
MISO
No
To date, System Operators have identified equipment by to/from station and voltage
level. Such identification has been sufficient to ensure the accurate identification of
Transmission interface Elements and Facilities. Additionally, MISO notes that internal
identifiers utilized by owners may result from internal coding or naming conventions
that would not be known by or comprehensible to external entities. Hence, MISO
cannot support this requirement based on the potential adverse impacts to reliability
that could result.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
NextEra Energy, Inc
No
See comments in response to question 7.
Texas Reliability Entity
No
The name specified by the operators of the equipment should be used, rather than
the name given by the owner, and it should be jointly agreed to as the identifier for
the equipment. For example, an owner name could be the “Lyndon Baines Johnson
East Johnson City Substation Line 3” but the Transmission Operator refers to it as
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Yes or No
Question 8 Comment
“East Johnson City 3” or “EJC3” or “Johnson 3”. The Planning Authority/Coordinator
may dictate a naming convention to be used in Operations systems that are used by
the System Operators (i.e. RTCA, outage scheduler, etc.). The name to be used
should be clearly identifiable, concise, and easily understood by all parties involved in
the Operating Communication. We suggest re-wording R1.1.4 to “When referring to
a Transmission interface Element or a Transmission interface Facility, each
responsible entity shall use a pre-determined, uniform identifier for each Element or
Facility.”
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
ISO New England Inc
No
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments.
Response: Thank you for your comments. Please see the response to the ISO/RTO Standard Review Committee comments.
Exelon Corporation and its
affiliates
No
Exelon is concerned with the requirement to use “the name” for the Element/Facility
specified by the Element/Facility's owner(s). By dictating “the name” this
requirement may become overly prescriptive. An entity should not be held
accountable for 100% adherence to a set "specified name" for an Element/Facility. It
is reasonable for entities to fully understand what Element/Facility is communicated;
however, verbatim use of a "specified name" should not in itself be a requirement.
For instance, if the formal name of a generating unit is "ABC Fossil Generating Station
Unit 1" and an entity communicates "ABC Station Unit 1" or "ABC Generating Station
1" by the Standard as written this could be considered a violation even though it can
effectively communicate the needed information. As in other sub-requirements to
R1, the use of "specified name" should be an expectation but not a requirement as
long as the transmitter and receiver use three way communications effectively.
Further, this appears as an internal inconsistency in the standard between R1 and R2.
For example, an entity owner specifies a unique name for an interface element.
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Yes or No
Question 8 Comment
R1.1.4 requires the use of that unique identifier but R2 does not require verbatim
response. It is not clear which part of the repeated information three part response in
R2 is allowed to be non-verbatim.
Response: Thank you for your comments. The SDT is not suggesting that this requirement need be as complex as you indicate. We
think it is fairly easy to follow the owner’s naming convention. The SDT has developed a different approach to the standard that
addresses your concern.
Brazos Electric Power
Cooperative
No
Please see formal comments provided by APM.
Oncor Electric Delivery
Company LLC
No
Again, Oncor take the position that this requirement contains far too much detail and
goes well beyond the 2003 Blackout recommendations. Furthermore, Oncor take the
position that a more appropriate approach would be to require internal procedures
that address internal communication protocols.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
JEA
Yes
R1.1.4 is unclear. Does this apply to both internal and external communications? JEA
believes that this should only apply to external communications only. Many entities
have internal numbering systems that have been in place without incident for
decades and should be able to continue to use these internal systems when
performing internal communications.
Response: Thank you for your comments. It applies when issuing Operating Instruction between functional entities. The SDT has
developed a new approach to the standard that addresses your concern.
SPP Standards Review Group
Yes
While the industry probably understands what is meant by ‘Transmission interface
Element or Facility’, the terms are somewhat cumbersome. Additionally, for
situations where there may be an agreement between owners designating multiple
names for an Element or Facility, we propose adding an ‘(s)’ to ‘name’. For example,
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Question 8 Comment
if one owner calls a line A-B and the other owner calls the line B-A and they agree to
use both names interchangeably, then either would be correct. Requirement 1.1.4
would then read: When referring to an Element or Facility that is part of an
interconnection between entities, use the name(s) specified by the owner(s) for that
Element or Facility.
Response: Thank you for your comments. The SDT has developed a different approach to the standard that addresses your
concern.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
None.
Colorado Springs Utilities
Yes
The possibility exists for an element/facility to be co-owned and for each owner to
have a different name.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Manitoba Hydro
Yes
See question 7 comments
NV Energy
Yes
Agree, however, we suggest that there be more clarity provided about what
constitutes a Transmission interface Element/Facility. Is it a connection between BA's
or between TOP's within a BA?
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Central Lincoln
Yes
Imperial Irrigation District
Yes
Detroit Edison
Yes
but please see Q 10.
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Pepco Holdings Inc & Affiliates
Yes
Hydro One Networks Inc.
Yes
Florida Municipal Power
Agency
Yes
GP Strategies
Yes
Progress Energy
Yes
Arizona Public Service
Company
Yes
Lakeland Electric
Yes
IESO
Yes
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
Yes
Hydro-Quebec TransEnergie
Yes
Clark Public Utilities
Yes
The United illuminating
Company
Yes
Utility Services, Inc.
Yes
Question 8 Comment
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Yes or No
City of Austin dba Autin
Energy
Yes
Utility System Efficiencies, InC.
Yes
Puget Sound Energy
Yes
Xcel Energy
Yes
Idaho Power Company
Yes
City of Tallahassee
Yes
City of Vero Beach
Yes
Seminole Electric Cooperative
Yes
U.S. Bureau of Reclamation
Yes
Kansas City Power & Light
Yes
Question 8 Comment
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Public Service Enterprise
Group
See #10.
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9.
Do you agree with the VRFs and VSLs for Requirements R1, R2 and R3?
Summary Consideration:
The major comment issues covered:
Commenters proposed the deletion of some or all of the requirements altogether. The commenters disagreed with the requirements
and thus disagreed with the associated VRFs and VSLs. Many other commenters called for reduction of all VRF levels to low. Some
believe there not be a severe VSL for R1 and that there is no justification for why some parts of R1 have higher VSL impact than others.
Other commenters believe there should not be a zero tolerance VSL. The SDT response is that due to changes made to the current draft
of the standard as a result of comments, the requirements have been significantly modified and the VRFs and VSLs had to be modified
accordingly and had to be consistent with FERC and NERC guidelines.
Some minor comment issues are:
Commenters believe the VSL should provide for a Lower Violation Severity Level for first occurrences of the violation and additional
clarity could be added in the VSLs. The SDT response is that due to changes made to the current draft of the standard as a result of
comments, the requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and had to be
consistent with FERC and NERC guidelines.
Organization
Northeast Power Coordinating
Council
Yes or No
Question 9 Comment
No
The white paper discusses many non-utility industries use of the three-part
communication. However, they are not out of compliance if they fail to use threepart communications. Only the Reliability Directives should require three-part
communications (and dictate compliance). This should be enforceable only if the
miscommunication results in an error on the BES. We support the use of three-part
communications with limitations. There is concern over the potential for being out of
compliance when there is no BES impact. Failure to meet Requirement R2, part 2.2
bullets 1 or 3 is either a Moderate or High. Failure to meet bullet 2 is a Severe VSL. It
is not clear why this differentiation was adopted. The White Paper reflects on Human
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Performance, and how miscommunications can cause a BES error resulting in an
outage, or possible cascading effects. Then the Standard (and the associated out of
compliance) should apply when, and to the extent that communications lapse (e.g.,
when there is an impactful violation of bullets 1, 2 and/or 3) results in an impactful
error on the BES. Otherwise, an out of compliance is inappropriate. Non-impactful
violations should be rated “Lower VSL.”
Response: The SDT thanks the commenter for the comments provided. Due to changes made to the current draft of the standard
as a result of comments, the requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly
and are consistent with FERC and NERC guidelines.
ACES Power Marketing
Standards Collaborators
No
1. The first Severe VSL listed for R1 says, “...did not correctly implement any of the
parts...” What is the definition of the word “any” in this VSL? We’ve interpreted the
VSL to mean that none of the parts of R1 were implemented. If this is the intent of
the SDT, then we suggest removing this VSL since the next Severe VSL listed says,
“...did not correctly implement three (3) or more of the four (4) parts...” Three or
more would include all of the parts (4 of 4) not being implemented correctly. Not
implementing 1 of the 4 parts is a Moderate VSL while not implementing 2 of the 4
parts is a High VSL. So, not implementing 3 or more of the parts would be a Severe
VSL.2. The second Moderate VSL for R1 says, “The responsible entity did not correctly
implement Part 1.2 of the requirement.” Corresponding with our comments in
Question 7 above, we don’t know how this requirement will be measured since the
term “accurate” in the requirement is not defined. If an entity can make up their
own clarifiers, who determines if they were “accurate” and whether they were
correctly implemented? Measure M1 doesn’t specify a measurement for Part 1.2 of
R1.3. The High VSL for R3 should be clarified to align with our suggestion of adding
the words, “before taking action” in Question 6 above.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
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Organization
Yes or No
Question 9 Comment
No
The MRO NSRF recommends the following comments for consideration by the SDT:
System Operators receive and issue many Operating Communications a day. The VSL
for one Operating Communication is Moderate. That is too high. While improving
communications is a laudable goal, the zero tolerance VSL is unacceptable and will
lead to a preponderance of self-reports and compliance and administrative overhead.
Also overlooked is the added stress that every time a System Operator speaks they
may be in violation.
and NERC guidelines.
Midwest Reliability
Organization NERC Standards
Review Forum
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Detroit Edison
No
VSL table for R1. Current format shows that an entity must be 100% compliant. The
break down from medium to severe is based on how many elements of R1 was not
followed. Suggest changing the format to how many times it was not followed rather
than the number of elements.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Duke Energy
No
The VRF’s should all be “Low”. For example, there will be thousands of routine
communications per year, and each instance of missing one alpha numeric identifier
(ex. “balloon” versus “baker”) would be a violation. As written, this standard would
drive allocation of resources for little reliability benefit.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
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Yes or No
Question 9 Comment
and NERC guidelines.
JEA
No
R2 & R3 should be removed from the standard. They are a best practice and do not
substantially affect reliability when a simple command such as increase load by
100MW for a new purchase agreement.
Response: Thank you for your comments.
Associated Electric
Cooperative JRO00088
No
AECI agrees with SERC OC STANDARDS REVIEW GROUP’s response to question 9.
LG&E and KU Services
No
LG&E and KU Services suggest deletion of all three requirements
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
MEAG Power, Danny Dees,
Steven Grego, Steve Jackson
No
VRFs and VSLs should be eliminated across the board.
Response: Thank you for your comments. The SDT notes your comments.
City Water Light and Power
No
These requirements should be eliminated entirely
Response: Thank you for your comments.
Hydro One Networks Inc.
No
The white paper discusses many non-utility industries use of the three-part
communication. However, they are not out of compliance if they fail to use threepoint communications. Only the Reliability Directives should require three-part
communications (and dictate compliance). This should be enforceable only if the
miscommunication results in an error on the BES. We support the use of three-part
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Question 9 Comment
communications. There is concern over the potential for being out of compliance
when there is no BES impact. Failure to meet Requirement R2, part 2.2 bullets 1 or 3
is either a Moderate or High. Failure to meet bullet 2 is a Severe VSL. It is not clear
why this differentiation was adopted. The White Paper reflects on Human
Performance, and how miscommunications can cause a BES error resulting in an
outage, or possible cascading effects. Then the Standard (and the associated out of
compliance) should apply when, and to the extent that communications lapse (e.g.,
when there is an impactful violation of bullets 1, 2 and/or 3) results in an impactful
error on the BES. Otherwise, an out of compliance is inappropriate. Non-impactful
violations should be rated “Lower VSL.”
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
SPP Standards Review Group
No
With the additional burden of monitoring and tracking compliance and the increased
risk of the zero-tolerance VSLs without a subsequent improvement in reliability of the
BES, the VRFs should be changed to Low. The VSLs should be reduced to Lower. We
suggest modifying the second part of the existing Moderate VSL for Requirement 1 to
include specific reference to Requirement 1 as is done in the first part of that VSL.
The VSL would then read: The responsible entity did not correctly implement
Requirement R1, Part 1.2.Likewise, we also suggest modifying the second part of the
existing High VSL for Requirement 1 to include specific reference to Requirement 1.
The VSL would then read: The responsible entity did not correctly implement one (1)
of the four (4) parts of Requirement R1 when it was appropriate to use three of the
four parts.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
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Yes or No
SERC OC Standards Review
Group
No
Question 9 Comment
We suggest deletion of all three requirements.
Response: Thank you for your comments. The SDT notes your comments.
Bonneville Power
Administration
No
BPA believes the VSLs for R3 are too extreme as written. The SDT needs to add
emphasis and clarity to the second *AND*. The requirement only asks for one of the
two bullets; the VSL could be incorrectly interpreted by and auditor that both bullets
are needed. Compliance is met if: (a) the receiver repeats back the Operating
Communication and waits for confirmation, or (b) requests it to be repeated because
it may not have been heard correctly. Compliance is not met if neither is done. So if
the entity received a communication but did not repeat it AND did not request it to
be repeated, that violation would be severe. For severity levels add impact to the
Bulk Electric System as a qualifier. IF Cascading outage or 1000 MW of load is lost
due to failure to repeat information back *AND* wait for confirmation ( equals
SEVERE). If equipment is damaged as a result (equals Moderate). If fails to repeat
*AND* fails to wait for confirmation (equals LOW). BPA would change its position if
categorizing a level of impact to the BES beginning with an equivalent to the severity
of the violation.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
NERC Operating Committee
No
See Response 10
Progress Energy
No
Progress Energy does not agree with having "Severe VSL" for all of R1
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
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Organization
Yes or No
Question 9 Comment
No
As mentioned in the previous comments, Southern does not agree with R1 as it is
imposing a single communications procedure on the industry and is focused on the
“HOW” as opposed to the “WHAT”, and does not agree with R2 and R3 as they imply
that that 3-part communications are needed for all communications, not just during
Reliability Directives, emergencies, or alerts. As such, Southern disagrees with the
VRFs and VSLs.
and NERC guidelines.
Southern Company
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
HHWP
No
VSL should provide for a Lower Violation Severity Level for first occurrences of the
violation. For the most part violation of this standard should be addressable through
FFT process.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with the
guidelines.
CenterPoint Energy Houston
Electric, LLC.
No
Question 9 Comments: No. VRFs and VSLs for requirements R1, R2, and R3 should not
be high or severe unless Adverse Reliability Impact has occurred.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with the
guidelines.
IESO
No
We do not agree with Requirements R2 and R3 to begin with. We therefore do not
agree with the VRFs and VSLs for these two requirements.
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Yes or No
Question 9 Comment
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
No
PPL Generation, LLC on behalf of its Supply NERC Registered Entities does believe that
this sub requirement R1.2 should be considered a moderate violation when alpha
numeric clarifiers are not used in general communication.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Clark Public Utilities
No
Failure to implement R1.2 is not necessarily a reliability problem. As stated in our
previous comments, not all alpha-numeric identifiers need clarification. However, the
current proposed standard would deem a failure to use a clarifier in any Operating
Communication that uses alpha-numeric identifiers as a violation.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Roger Zaklukiewicz Consulting
No
The standard should not be mandating the "HOW".
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Sacramento Municipal Utility
District
No
We have a problem with the standard and therefore we inherently don't agree with
VRFs and VSLs.
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Organization
Yes or No
Question 9 Comment
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Entergy Services
No
We disagree only in the sense that we disagree with the requirements, therefore, the
VRFs and VSLs are not relevant. We suggest deletion of all three requirements, and
the insertion of one new requirement. See Response to Questions 1, 2 and 4.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Reliability First
No
Reliability First votes in the Affirmative for this standard because the standard further
enhances reliability by providing communication protocols when participating in
Operating Communications (specifically three way communication). Clear, formal
and universally-applied communication protocols will help reduce the possibility of
miscommunication which could lead to action or inaction harmful to the reliability of
BES. Even though Reliability First votes in the Affirmative standard, Reliability First
votes in the negative for the VSLS and offer the following comments for
consideration:
1. VSL for Requirement R2 a. When referencing “Part” numbers within the VSL, a
consistent format (e.g. Requirement R2, Part 2.2 first bullet) should be used.
2. VSL for Requirement R3
a. The VSLs should state “oral ... Operating Communication” rather than “verbal ...
Operating Communication” to be consistent with the language in the requirement.
b. For consistency with the first part of the first bullet in Requirement R3, RFC
recommends the following language be considered for the “High” VSL: “The
responsible entity received and repeated an oral two-party, person-to-person
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Organization
Yes or No
Question 9 Comment
Operating Communication but did not wait for confirmation that the repetition was
correct. (Requirement R3, first bullet)”
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with the
guidelines.
City of Austin dba Austin
Energy
No
AE respectfully objects to the contents of COM-003-1 as described in these
comments. If, however, AE were to assume agreement with the requirements, we
offer the following comments regarding the VSLs:
AE does not believe the R1 VSLs provide for a fair application in practice. Risk to the
BES is not increased when fewer communication protocols apply to an entity. As
proposed, missing 1 of 4 parts when 4 parts are required is a Moderate VSL. Missing 1
of 4 when 3 are required is a High VSL (and it never has an opportunity for a lower
severity level because Moderate VSL applies only when 4 parts are required).
Similarly, if an entity misses 1 of 4 when 2 are required, it should not be penalized
with a Severe VSL. AE suggests the solution to this issue is to assign Moderate VSL to
missing 1 of 4, High VSL to missing 2 of 4 and Severe VSL to missing 3 or more of 4, in
all instances regardless of how many parts are required.
If the structure suggested above is not adopted, AE offers the following comments for
consideration:
Within the Severe VSL column for R1, the first paragraph (missing all of the parts
when four are required) duplicates the second paragraph (missing three or more
when four are required.)Within the Severe VSL column for R1, the third and final
paragraphs should say “two (2) or more” and “one (1) or more,” respectively, to
account for all possible situations. Doing so aligns with the second paragraph which
already says “three (3) or more.” Finally, with respect to the VSLs for R2 and R3, all
instances of “verbal” should be changed to “oral” to match the language of the
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Yes or No
Question 9 Comment
requirement.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Utility System Efficiencies, InC.
No
We agree with the classification of VRF as medium for Requirements R1, R2, and R3;
however, hopefully this will not detract from the vital importance of using three-part
communications in ALL operations communications relevant to the Bulk Electric
System (BES). We disagree with the VSLs for Requirements R1, R2, and R3. For R1 we
don't believe it is valid to claim that various combinations of not using the 24-hour
clock, or alphanumeric definitions, etc. will make any difference in the outcome of
poor communications. We recommend the following approach: For R1, failure to use
any of the required elements of this requirement should be documented for each
incident during the audit period. Greater than three failures but less than or equal to
5 would be considered "moderate;" greater than 5 but less than or equal to 8 would
be considered "high;" greater than 8 would be considered "severe." Any failure to use
the required elements of this Requirement R1 which results in a reportable incident
on the BES should be considered "severe." For Requirements R2 and R3, all failures to
use the required three-part communications should be documented by the
Registered Entity for the audit period. Greater than three failures but less than or
equal to 5 would be considered "moderate;" greater than 5 but less than or equal to
8 would be considered "high;" greater than 8 would be considered "severe." Any
failure to use three-part communication which results in a reportable incident on the
BES should be considered "severe."
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
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Yes or No
Question 9 Comment
Illinois Municipal Electric
Agency
No
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Xcel Energy
No
The Moderate VSL for missing one part of the sub-requirements in R1.1.1 thru R1.1.4
is too harsh with a six month effective date. We suggest a phased in VSL or a twelve
month effective date, as further explained under question 10.
Response: Thank you for your comments. We have extended the implementation time period to twelve calendar months. Due to
changes made to the current draft of the standard as a result of comments, the requirements have been significantly modified and
the VRFs and VSLs had to be modified accordingly and are consistent with FERC and NERC guidelines.
Ameren
No
We believe that the VSLs in this draft Standard create the potential for a violation or
self-report for almost every single individual conversation about the BES by real-time
operators. In this regard, we are concerned that the Functional Entities will greatly
decrease their oral communications to minimize the risk of a self-report or violation
which ultimately would undermine necessary discussions between operating entities.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
American Transmission
Company, LLC
No
System Operators receive and issue many Operating Communications each day. The
VSL for “one” Operating Communication is Moderate, which is considered too high.
While improving communications is a laudable goal, the zero tolerance VSL is
unacceptable and will lead to a preponderance of self-reports and compliance and
administrative overhead. Also overlooked is the added stress that every time a
System Operator speaks, they may be in violation.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
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Yes or No
Question 9 Comment
No
MISO respectfully submits that no justification has been provided regarding the VRF
and VSLs assigned to COM-003-0. Additionally, MISO suggests that the proposed VRFs
and VSLs may be disproportionate to the actual impacts of non-compliance with the
proposed standard and its requirements. For example, the proposed Standard
suggests that a failure to implement one of the four parts of Requirement R1, Part 1.1
when all four parts are required is less harmful than a failure to implement one of the
four parts when only two parts are required but fails to justify why the former presents
a lesser risk to reliability than the latter or why a more substantial penalty would be
appropriate in the latter instance. MISO respectfully suggests that the SDT revisit the
proposed VRF and VSLs and revise them to ensure the consistency with the likely actual
impacts on reliability.
and NERC guidelines.
MISO
Response: Thank you for your comments. The VRF and VSL justification was posted with the standard. Due to changes made to
the current draft of the standard as a result of comments, the requirements have been significantly modified and the VRFs and
VSLs had to be modified accordingly and are consistent with FERC and NERC guidelines.
Seminole Electric Cooperative
No
See previous comments
Exelon Corporation and its
affiliates
No
Exelon does not agree with the VRFs and VSLs for Requirements R1, R2 and R3.
Requirement R1 - The Violation Severity Levels imply that if the responsible entity did
not correctly implement any one (1) of the four (4) parts of R1 at any time that that
entity would be non-compliant. It is not reasonable to hold an entity responsible to
verify that every communication be in accordance with R1 at all times. It should be
an expectation, but not a requirement. Requirements R2 and R3 - Similar to R1 it is
not reasonable to hold an entity responsible to verify that every communication
meet the requirement of R2 or R3 in all instances. Exelon suggests that this
requirement be revised to address those instances where an actual event occurred
due to improper communication or be limited to communication of a stated
Reliability Directive. In general, the current VSLs for the current draft of COM-003-1
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Yes or No
Question 9 Comment
do not seem commensurate to the risk to the BES. See the response to Q10 for a
reasonable approach to implementation of the intent of this requirement.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with FERC
and NERC guidelines.
Brazos Electric Power
Cooperative
No
Please see formal comments provided by APM.
Kansas City Power & Light
No
VRFs and VSLs should be low.
Flathead Electric Cooperative,
Inc.
No
SMUD
No
Liberty Electric Power LLC
No
Salt River Project
No
South Carolina Electric and
Gas
No
Ingleside Cogeneration LP
Yes
With the transition of emergency communications to other projects, it is appropriate
to downgrade COM-003-1’s VRFs from “High” to “Medium”.
Response: Thank you for your comments. Due to changes made to the current draft of the standard as a result of comments, the
requirements have been significantly modified and the VRFs and VSLs had to be modified accordingly and are consistent with the
guidelines.
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Yes or No
Question 9 Comment
Idaho Power Company
Yes
At least I don't have a good reason not to agree.
City of Jacksonville Beach
dba/Beaches Energy Services
Yes
None.
Imperial Irrigation District
Yes
BC Hydro
Yes
Florida Municipal Power
Agency
Yes
GP Strategies
Yes
Arizona Public Service
Company
Yes
Lakeland Electric
Yes
Hydro-Quebec TransEnergie
Yes
Orlando Utilities Commission
Yes
The United illuminating
Company
Yes
Utility Services, Inc.
Yes
Colorado Springs Utilities
Yes
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Organization
Yes or No
Manitoba Hydro
Yes
City of Vero Beach
Yes
U.S. Bureau of Reclamation
Yes
Question 9 Comment
New York Power Authority
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Public Service Enterprise
Group
See #10.
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10. If you have any other comments or suggestions to improve the draft standard that you have not already provided in response to
the previous questions please provide them here.
Summary Consideration:
A common theme among many entities is that the approach to COM-003-1 should be changed. Most agreed with the
comments submitted by the NERC Operating Committee that applicable entities should be required to
1. develop written communication protocols that address the elements in draft 2 of COM-003-1,
2. train on those protocols, and
3. develop internal controls to find and correct deviances from those protocols.
After discussion, the SDT agreed with the commenters and modified its approach to closely align with the proposal. In
addition, the SDT felt that it would be beneficial to develop the RSAW for this standard in conjunction with NERC
Compliance staff, and has posted it for comment along with draft 3 of COM-003-1.
Another prevalent theme was questioning the necessity of the standard, specifically one that requires three part
communication for routine operations.
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval the
expedited development of a comprehensive communications program, which would address necessary communication
protocols for use in the operation of the Bulk Electric System. The SDT determined that protocols concerning three part
communication (when it is necessary and what is required) during normal operations was a necessary step in addressing
the BOT’s concern.
Another theme was the concern that the work of the SDT was overreaching the scope of the SAR.
The purpose of the SAR for this project is “Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten response time.”
Additionally, the SAR is very specific in that it also includes the term “normal” operating conditions under Applicability:
“Clear and mutually established communications protocols used during real time operations under normal and emergency
conditions ensure universal understanding of terms and reduce errors.”
Another theme was that the use of three part communications should be limited to Reliability Directives only.
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A Reliability Directive, by definition, is limited to instances where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact. The SDT believes that it is necessary to specify 3 part communication as a
necessary communications protocol for all Operating Instructions, not just emergency situations. The OPCPSDT believes
that the potential for risk to the reliability of the BES exists for all Operating Instructions.
Still others express a desire to combine COM-002-3 and COM-003-1 into a single standard.
The purpose of the SAR for this project is “Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten response time.” This is
a broader scope for communications than that for Project 2006-06.
Another concern was that this standard addressed “how” to communicate instead of “what” to communicate.
When defining common communication protocols to be used for communication between entities, it is necessary to be
specific on what must be communicated and how it must be communicated.
Many commenters also questioned the purpose of the whitepaper that was posted by the SDT during draft 2.
The whitepaper was intended to assist industry stakeholders understand the rationale behind the content in the standard.
For further information on communication guidelines, please refer to the paper developed by the NERC Operating
Committee titled “Reliability Guideline: System Operator Verbal Communication – Current Industry Practices” located at
http://www.nerc.com/filez/oc.html.
Several commenters expressed the desire that the language pertaining to three part communication in COM-003-1 match
that in COM-002-3.
The SDT agrees and is using the language of COM-002-3, R2 and R3 in draft 3 of COM 003-1.
Organization
Yes or No
Hydro One Networks Inc.
Question 10 Comment
- Hydro One strongly believes that three-part communication should be limited to
Reliability Directives only. Its application to virtually all communications will prove to
be an additional burden for operators, burden that is not justified and would not in
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Question 10 Comment
Response: Thank you for your comments. A Reliability Directive, by definition, is limited to instances where action by the
recipient is necessary to address an Emergency or Adverse Reliability Impact. The SDT believes that it is necessary to specify 3 part
communication as a necessary communications protocol for all Operating Instructions, not just emergency situations. The
OPCPSDT believes that the potential for risk to the reliability of the BES exists for all Operating Instructions.
Xcel Energy
(1) Requirement R1.1 refers to both written and oral Operating Communications. It
was our understanding that COM-003-1 was to be focused solely on oral
communications. If that was the SDT’s intent, then we suggest striking the word
“written” from this sub-requirement.
Response: The scope of the SAR for Project 2007-02 is not limited to oral
communications.
(2) Six month Effective Date is not likely to be enough time to develop, implement,
and test a new communication program. We need enough time to train the field
personnel, plant control room operators and system operators to use alpha-numeric
identifiers, 24-hr clock, time zone, etc. before the standard becomes effective. A
twelve month implementation period would be more appropriate.
Response: The SDT agrees and has made the suggested change.
Response: Thank you for your comments. Please see the response above.
Central Lincoln
1) Central Lincoln supports the comments provided by PNGC. We have a similar
situation, and believe the redirection of resources needed for compliance can only
have a negative effect on our local level of service.
Response: Please see our response to PNGC.
2) Central Lincoln is greatly concerned regarding how this standard will be audited.
We expect the Compliance Enforcement Authority, in order to avoid a data dump in
the form of a six year audit period’s worth of radio recordings consisting of mainly
distribution related instructions, will request searchable transcripts with pointers to
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Yes or No
Question 10 Comment
the relevant >100 kV parts. This will represent a huge amount of time to transcribe
the recordings and provide the pointers. This administrative burden in proving
compliance after the fact will not result in any improvement in reliability.
Response: The SDT understands your concerns and has developed a new approach
to the standard that addresses your concern.
Response Thank you for your comments. Please see the response above.
IESO
1. This standard is over-reaching into routine operations as it requires 3-part
communication for all instructions that change or maintain the state, status, output,
or input of an Element or Facility of the Bulk Electric System. This type of instructions
occurs every hour, if not every minute. Requiring operating personnel to apply a 3part communication procedure for each and all of these instructions is absolutely
unnecessary and overburdening, and can in fact adversely affect reliability. We
strongly suggest that any requirement for 3-part communication for routine
operating instructions be removed.
Response: The SDT believes that it is necessary to specify 3 part communication as
a necessary communications protocol for all Operating Instructions, not just
emergency situations. The OPCPSDT believes that the potential for risk to the
reliability of the BES exists for all Operating Instructions.
2. The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable
regulatory approval” in the Effective Dates Section A5 on P. 4 of the draft standard
COM-001, COM-002 and IRO-001, and on P. 2 of COM-001’s Implementation Plan and
P. 1 of COM-002’s and IRO-001’s Implementation Plans, to the following effect:”, or
as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.”
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Yes or No
Question 10 Comment
Response: The SDT modified the section in response to your comments.
Response: Thank you for your comments. Please see the response above.
ACES Power Marketing
Standards Collaborators
1. It is not clear that COM-003-1 R1 applies to COM-002-3. The latest draft of COM002-3 doesn’t reference the communications protocols listed in COM-003-1 R1 and
the definition of Reliability Directive does not state that it is a type of Operating
Communication. The only place that describes the relationship between a Reliability
Directive and Operating Communications is the text box under the definition of
Operating Communication in COM-003-1. There should be a better connection
between the two standards to emphasize this fact. We recommend the SDTs work
together to bridge this gap.
Response: COM-003-1, R1 applies to all communications that involve a “command
from a System Operator to change or preserve the state, status, output, or input of
an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
2. Bullet 2 of the Implementation Plan Effective Dates is missing a word or words
(section in question in parentheses): “If the version of COM-001-2 revised under
Project 2006-06 is not approved before COM-003-1 is approved, then COM-001-1.1
shall expire midnight of the day (immediately the) version of COM-001-2 developed
under Project 2007-02 ...” In addition, this bullet is simply too wordy and difficult to
comprehend. We suggest re-wording or splitting into separate sentences for easier
comprehension.
Response: The SDT agrees and has corrected the bullet.
3. Because all three Measures include voice recordings as evidence, the Data
Retention section inappropriately and without justification raises the bar on
retention of voice recordings. The section requires 365 days of voice recordings for
R1 and 180 days for R2 and R3. Many registered entities keep no more than 90 days
of voice recordings. Keeping more than 90 days would require unnecessary
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Yes or No
Question 10 Comment
additional storage. Furthermore, it is not consistent with any other NERC standard
(including COM-002) that compels, at most, 90 days. Thus, many registered entities
probably have evidence retention policies that actually require destruction of such
recordings after 90 days.
Response: The SDT has developed a new approach to the standard that addresses your
concern.
4. While we do not agree with all parts of the Whitepaper, we believe one major
point of clarification is needed. On page 3, in the first bullet regarding a general
description of how three-part communications is conducted, the face-to-face
communication needs to be clarified or removed. Including face-to-face
communications is not necessary for two primary reasons. First, the major reason
that three-part is necessary for telephonic communications is because you cannot
see the receiver and really tell if they comprehend the message. Second, this could
draw in communications between operators within the control center. Since these
conversations are not easily recordable, how does a registered entity prove
compliance?
Response: The SDT believes that Operating Communication on a face to face basis is
subject to the same risk of mistakes and misunderstanding. The OPCPSDT has
participated in the development of the RSAW for COM-003-1 and considered your
comments.
Response: Thank you for your comments. Please see the response above.
Texas Reliability Entity
1. The use of exploder or hotline calls, where a single oral communication is used to
alert a multitude of entities simultaneously to issues and directions affecting the BES,
should be addressed by this Standard. The use of these types of calls is economic,
efficient, and should be recognized for the purpose of providing Operating
Communications, including Reliability Directives. Not addressing this issue will have a
serious impact on System Operators during times, normal or emergency, when clear,
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Yes or No
Question 10 Comment
concise, and effective communications are needed. The 2003 Blackout
Recommendation #26 includes the following text: “Standing hotline networks, or a
functional equivalent, should be established for use in alerts and emergencies (as
opposed to one-on-one phone calls) to ensure that all key parties are able to give and
receive timely and accurate information.” This proposed Standard should address
the issue of what communication protocols should be applied to exploder or hotline
calls.
Response: The SDT has addressed all calls in draft 3.
2. There is a disconnect between COM-003-1 and COM-002-3 that will create
confusion within the industry regarding communications. COM-002-3 has limited
applicability, restricted to use of Reliability Directives ONLY in an Emergency or
Adverse Reliability Impact. COM-003-1 is limited to oral two party communications,
but it applies outside of Emergency situations. With proposed IRO-001-3 contained
in Project 2006-06, a Reliability Coordinator or other entity may not be certain of
whether to give a directive, a Reliability Directive, or an Operating Communication,
and a recipient may dispute whether the correct communication type was used.
What is the intended compliance impact of using the wrong type of communication,
for both the initiating entity and the receiving entity?
Response: Only a Reliability Directive must be identified as such. If a “directive” is a
“command from a System Operator to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System,” it is an Operating Instruction and must use the protocols identified in
COM-003-1.
3. COM-003-1 and COM-002-3 will cause substantial confusion as drafted because
they both require three-part communication, but they use different language to
describe it. That suggests that the communication protocols that are required must
be different, and as an entity moves from non-Emergency into Emergency
operations, its communication protocol will be expected to change. We strongly
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Yes or No
Question 10 Comment
suggest that a single three-part-communication protocol be set forth in one place
only, and that any differences between Emergency and non-Emergency
communication requirements be clearly identified.
Response: The SDT agrees and is using the language of COM-002-3, R2 and R3 in
draft 3 of COM 003-1.
Response: Thank you for your comments. Please see the response above.
Hydro-Quebec TransEnergie
1. Inconsistency between the sentences in R2 of COM-003 "that issues an oral, twoparty, person-to-person Operating Communications" and R3 "that receives an oral
two-party, person-to-person Operating Communication". The sentence in R2 has a
comma after the word oral, the sentence in R3 does not. Furthermore, what is the
difference between two-party and person-to-person communication?
Response: The SDT will remove the comma in R2. “Two party” was added based on
concerns that the requirement would be applicable to multi addressee or burst
communication. Person to person was added to address concerns of the
requirements applying to “machine” messages that some entities utilize.
2. For R2 of COM-003, should the Generator Operator be involved in this requirement
as an authority able to issue an oral Operating Communication?
Response: Based on the revised definition of Operating Instruction, a GOP can only
be a receiver of an Operating Instruction.
3. It’s not clear when an action is defined as a Reliability Directive. Does each utility
define the instruction to be included in the Reliability Directive? Our current practice
is that 3 ways communication is always directive. We still don't see the need to
separate the COM-002 (emergency) and COM-003 (normal operating).
Response: The Reliability Coordinator, Transmission Operator, or Balancing
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Question 10 Comment
Authority will issue a Reliability Directive during Emergency and Adverse Reliability
Impacts in accordance with COM-002-3.
4. The requirement R1 of COM-003 should also be reflected in the COM-002
standard. Especially during the Emergency situation, the Operation Communication
should be followed.
Response: The SDT thanks you for your comment.
Response: Thank you for your comments. Please see the response above.
Associated Electric
Cooperative JRO00088
AECI remains unconvinced that COM-003-1 adds sufficient value to our industry
reliability, for the degree of non-compliance risk it imposes. There are several issues
with the supporting white paper:
1) this paper appears void of citations supporting its assertions,
Response: The SDT disagrees. There are many citations especially those dealing
with human behaviors applicable to communication.
2) It also fails to differentiate cited industry failures in communication, between;
situations where somebody failed to communicate a field-change that significantly
affected BES situational awareness, situations where the change was clearly
understood and yet its situational impact was not, and situations where the affected
objects were misunderstood. All of these failures are critical to our industry’s
assessing true value in introducing and enforcing broad-scope three-part
communication, because COM-003-1 can only improve the last of those three
miscommunications,
Response: The SDT did not go into that detail because of ongoing discussion of
violations.
3) its citation, of 12 Entity’s broadly adopting three-point communication, seems
hardly a majority practice within our industry,
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Organization
Yes or No
Question 10 Comment
Response: The SDT would ask you to look at the load and customer impacts that
sample covered. The SDT could have added another 20 entities and believes the
results would not differ.
4) while Entities may internally adopt similar policies, that does not mean we should
risk being subject to Federal law in support of conceptual theories,
Response: The formalization of communication protocols enhances reliability by
reducing errors on the BES.
5) Citations of similar adoptions by other industries or cultures, fail to provide useful
differentiation between their critical and casual operational communications, except
in the case of military, where COM-003’s proposed broad scope of communication
appears to be inconsistent, while COM-002’s narrowed scope appears in alignment
with the military’s adopted practices as described.
Response: The OPCPSDT has military expertise that would suggest otherwise.
Response: Thank you for your comments. Please see the response above.
FirstEnergy
Although we believe the team made significant improvements to the standard, and
would support a 3-part communication standard, we believe the introduction of both
COM-002-2 which utilizes Reliability Directives and COM-003-1 which utilizes
Operating Communications cause confusion for system operators and may in fact be
detrimental to reliability. We do not support two standards on three-part
communication. We suggest, as we have in the past, that the subject of three-part
communication be addressed in a single standard, and that the requirements be
developed for simplicity. The industry is, and has been, using three-part
communication for decades and although we agree it should be more consistently
practiced and standardized, the required communications protocols should be simple
while meeting the goal of BES reliability. Introducing complicated requirements and
standards that have different definitions such as Reliability Directive and Operating
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Organization
Yes or No
Question 10 Comment
Communication may cause the operator to hesitate when issuing directives in realtime and every second counts when a potential system emergency must be
mitigated. Therefore, FE does not support the creation of neither COM-003-1 nor
COM-002-2 (see project 2006-06 vote and comments) and ask NERC to reevaluate
the need to have two separate standards for three-part communication.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope than that for Project 2006-06.
Western Electricity
Coordinating Council
As noted in our response to question 6, there is still a concern about having two
standards for communications on changes to elements of the BES. Bifurcations may
lead to the misuses of one protocol in place of another for the two standards.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope than that for Project 2006-06.
City of Austin dba Austin
Energy
Austin Energy (AE) respectfully disagrees with COM-003-1 because it:
(1) reaches beyond the SAR and
Response: The purpose of the SAR for this project is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” Additionally, the SAR is very specific in that it also includes the term
“normal” operating conditions under Applicability: “Clear and mutually established
communications protocols used during real time operations under normal and
emergency conditions ensure universal understanding of terms and reduce errors.”
(2) Requires “how” communication should take place instead of “what” and “when.”
Response: When defining common communication protocols to be used for
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communication between entities, it is necessary to be specific on what must be
communicated and how it must be communicated.
The scope of COM-003-1 reaches beyond the SAR by imposing protocols on normal
communications when the focus of the 2003 Blackout Report, Recommendation 26
and Order 693, Paragraph 532 is on timely and accurate EMERGENCY communication.
Recommendation 26 does not recommend tightened communication protocols under
normal operating conditions. It recommends that NERC “work with reliability
coordinators and control area operators to improve the effectiveness of internal and
external communications during alerts, emergencies, or other critical situations....”
AE believes Project 2006-06 (COM-002-3) sufficiently addresses this recommendation
by requiring three-part communication for Reliability Directives. If used correctly, the
say-repeat-confirm method improves effectiveness of communications during alerts,
emergencies and other critical time periods.
Response: Response: The OPCPSDT disagrees that the Blackout Report (and FERC
Order 693 and the SAR) only addresses the need to tighten protocols for
Emergencies. The Blackout Report uses the phrase “especially for emergencies”
which the SDT interprets to mean the authors were recommending applicability of
communication protocols for the total population of operating communication and
used this language to amplify the importance of such protocols during emergency
conditions. FERC Order 693 paragraph 532 (“This will eliminate possible ambiguities
in communications during normal, alert and emergency conditions”) and the SAR
are very specific in that both include the term “normal” operating conditions.
The other source for COM-003-1 (Paragraph 532) references communications during
normal conditions, but only in response to an EEI comment. The actual directive is in
paragraph 535, where FERC states, “Accordingly, we direct the ERO to either modify
COM-002-2 or develop a new Reliability Standard that requires tightened
communications protocols, especially for communications during alerts and
emergencies.” AE notes that the directive focuses on communications during alerts
and emergencies, similar to Recommendation 26. AE recognizes that the SDT reads
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Paragraph 532 to indicate a need for communication protocols even under normal
operating conditions. However, AE believes that a NERC Reliability Standard is not the
appropriate place to address the “how” of communication protocols under normal
conditions.
Response: FERC Order 693 paragraph 532 (This will eliminate possible ambiguities
in communications during normal, alert and emergency conditions”) and the SAR
are very specific in that both include the term “normal” operating conditions.
Industry stakeholders are justifiably concerned that deviations from the requirements
during normal operating conditions will inevitably occur (human performance factor)
without a risk to reliability. The potential number of self-reports industry-wide carries
an overly burdensome cost without an associated benefit to the BES. AE believes that
efforts at the regional level (e.g., training, guidelines, etc.) would be more effective
and relevant.
In summary, AE believes the focus of COM-003-1 should be on achieving accurate and
timely information (the “what” and “when”), not prescribing exactly “how” registered
entities achieve it. As written, COM-003-1 goes too far into the realm of mandating
best practices and claiming it is necessary for reliability.
Response The SDT understands your concerns and has developed a new approach
to the standard that addresses your concern.
Response: Thank you for your comments. Please see our response above.
Pepco Holdings Inc & Affiliates
COM-002 and COM-003 must be combined into one standard. COM-002 dealing with
emergency, reliability situations requires 3 part communication as specified. COM003 dealing with normal conditions, non reliability issues should not require 3 part
communications.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
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response time.” This is a broader scope than that for Project 2006-06.
ITC Holdings
COM-003-1 and COM-002-3 cannot be processed separately since they are
inextricably inter-related. In fact, they are so inter-related that there is no compelling
reason provided that suggests they should be separate standards. The comment
form for COM-003-1 even indicates that Reliability Directives are a subset of
Operational Communication which further indicates that all of the requirements
surrounding how communication is performed regardless of the nature of the
content should be addressed in one standard.
Response: Thank you for your comments. The purpose of the SAR for this project is
“Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve situational
awareness and shorten response time.” This is a broader scope than that for
Project 2006-06.
Further, 3 part communication is being cited as ensuring reliable operation of the
BES. It is not the act of 3 part communication that ensures reliable operation.
Rather, it is the effective transfer of information that does. Requiring 3 part
communication for all communication will reduce the effectiveness of the
communication as the novelty factor wears off and individuals only go through the
motions. Active listening and truly understanding the communication is what
accomplishes the intent. Use of 3 part communication for situations that the initiator
determines it is warranted based on their knowledge and training is the most
appropriate approach to ensure reliable operation of the BES.
Response: The SDT believes that it is necessary to specify 3 part communication as
a necessary communications protocol for all Operating Instructions, not just
emergency situations. The OPCPSDT believes that the potential for risk to the
reliability of the BES exists for all Operating Instructions.
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Response: Response: Thank you for your comments. Please see the responses above.
JEA
Combine COM002 & COM003.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope than that for Project 2006-06.
City Water Light and Power
CWLP generally echoes the SERC Operating Committee comments. Additional
comments have been provided to suggest better functionality if the standard moves
forward in its current form.
Response: Thank you for your comments. Please refer to the response to the SERC Operating Committee comments.
LG&E and KU Services
Does the industry agree that we need a standard on three part communications for
normal operations? Has a lack of a standard on three part communications for
normal operations created any reliability issues? If so, what are they? LG&E and KU
Services believes that the concerns expressed by the Blackout Report and cited as the
reason for creating this NERC Project are already addressed through EOP and TOP
Standards that specify what information is to be communicated, instead of how
information is to be communicated. “Lack of situational awareness” (2003 Blackout
Report, Recommendation 26) cannot be overcome by dictating “how”
communication takes place, but instead, can be overcome by responsible individuals
(NERC certified operators) ensuring that proper information is communicated. LG&E
and KU Services believes that the concerns expressed by the Blackout Report and
FERC Order 693, Paragraph 532 are not (and need not be) addressed by this or any
other NERC RS Project.
First, the recommendation for “tightened communication protocols” (FERC Order
693, Paragraph 531) is within the context of “alerts and emergencies.”
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Second, FERC’s Order 693, Paragraph 532 calls for “communication uniformity as
much as practical on a continent-wide basis.” This is calling for uniformity in
emergency communications, which was the context within which FERC was speaking,
as evidenced by the previous sentence (“during emergencies”). By establishing
emergency communication uniformity, “ambiguities in communications during
normal, alert and emergency conditions” will be eliminated. Nothing in the
Commission’s Determination was calling for establishing communication uniformity
for all communications.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
The OPCPSDT disagrees that both the Blackout Report and the FERC directive deal
with tightening protocols for Emergencies only. The Blackout Report uses the
language “Tighten communications protocols, especially for communications during
alerts and emergencies.” The SDT believes the authors are recommending
applicability of communication protocols for the total population of operating
levels and wanted to amplify the importance of it “especially” during emergency
conditions. FERC Order 693, paragraph 532 (This will eliminate possible ambiguities
in communications during normal, alert and emergency conditions”) and the SAR
are very specific in that both include the term “normal” operating conditions.
Additionally the excerpts from the text you cite (“Paragraph 532 calls for
“communication uniformity as much as practical on a continent-wide basis”) are very
clear in their intent and meaning and support the standard as drafted.
LG&E and KU Services suggest removing requirements R2 and R3. These
requirements do not improve reliability, but instead shift Operator focus from
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communicating proper information (“what”) to communicating in a compliant
manner (“how”). System Operator need to be wholly concerned with the
information they are communicating, not making sure they “say things the right way”
so they will not be non-compliant. Every communication should not be a compliance
event.
Response: The SDT believes that it is necessary to specify 3 part communication as
a necessary communications protocol for all Operating Instructions, not just
emergency situations. The OPCPSDT believes that the potential for risk to the
reliability of the BES exists for all Operating Instructions.
While LG&E and KU Services supports the addition of using the 24-hour clock format,
subpart 1.1.4 is already addressed in TOP-002-2b R18.
Including such a similar requirement here simply provides entities with a double
jeopardy opportunity to be non-compliant. We suggest subpart 1.1.4 be removed,
along with subpart 1.2, which again goes too far in dictating “how” and simply
creates another compliance event.
Response: The SDT is aware that Requirement R18 is being eliminated by the
RTOSDT as part of project 2007-03. Project 2007-03 chose to eliminate TOP-002-2a
Requirement R18 on the basis that “This requirement adds no reliability benefit.
Entities have existing processes that handle this issue. There has never been a
documented case of the lack of uniform line identifiers contributing to a System
reliability issue. This is an administrative item, as seen in the measure, which simply
requires a list of line identifiers. The true reliability issue is not the name of a line
but what is happening to it, pointing out the difficulty in assigning compliance
responsibility for such a requirement, as well as the near impossibility of coming up
with truly unique identifiers on a nation-wide basis. The bottom line is that this
situation is handled by the operators as part of their normal responsibilities, and no
one is aware of a switching error caused by confusion over line identifiers.” COM003-1, while reintroducing the concept of line identifiers, limits the scope to only
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Transmission interface Elements or Transmission interface Facilities (e.g. tie lines
and tie substations). This ensures that both parties are referring to the same
equipment for the Operating Instruction.
We suggest subpart 1.1.3 be rewritten to explicitly allow for entities to agree upon
using a particular format for communicating time. With these suggestions in mind, it
would be more appropriate to put the remaining requirements into COM-001. We
also suggest removing the definition for Operating Communication since this also
unnecessarily creates opportunities for non-compliance.
Response: When defining common communication protocols to be used for
communication between entities, it is necessary to be specific on what must be
communicated and how it must be communicated. Comments on prior postings of
COM-003-1 rejected allowances for entities to agree upon particular protocols,
feeling that the documentation of those agreements would be overly burdensome
and is contrary to the purpose of the SAR, which is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” The SDT is using the term “Operating Instruction” to limit the
communications that are subject to COM-003-1.
LG&E and KU Services have concerns about the white paper posted on the project
page. Some assertions made in the white paper are not defensible, and some are not
technically sound. This should not be used as support for the existing draft of COM003.
Response: The SDT believes its assertions are defensible, technically sound, and
carefully researched. The White Paper is intended to assist industry stakeholders
understand the rationale behind the content in the standard. For further
information on communication guidelines, please refer to the paper developed by
the NERC Operating Committee titled “Reliability Guideline: System Operator
Verbal Communication – Current Industry Practices” located at
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http://www.nerc.com/filez/oc.html.
Response: Thank you for your comments. Please see the response above.
Dominion
Dominion acknowledges the term Reliability Directive is proposed for inclusion in the
draft of COM-002-3, but we also prefer a notation be added, to clarify this is not an
existing term in the current version of the NERC Glossary of Terms. As mentioned in
response to Question #1; When the standard is implemented, the text box (on page 2
of the clean standard) will be removed, therefore losing any tieback to a Reliability
Directive as a type of operating communication.
Response: After filing with FERC and receiving FERC approval the definition will be
added to the NERC Glossary of Terms. The OPCPSDT and the RCSDT were
attempting to explain the relationship between the two standards to help
stakeholders understand. The textbox was an attempt to explain that relationship.
Draft 3 of the standard no longer contains the reference.
The data retention period for this standard for normal operating communications is
extensively longer than the COM-002-3 standard for emergency communications as
discussed in Project 2006-06. Dominion suggests the same data retention period as
COM-002-3 for Requirements 1, 2 and 3 of this standard, which is for the most recent
3 months.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Dominion also questions why the proposed standard is applicable to Distribution
Providers since changing the state of BES elements is not what they do. Therefore,
they would never receive an Operating Communication instructing them to do
anything to a BES element, so it would not be practical or useful for a DP to include
this standard in its compliance program. DP is included as an applicable Registered
Entity in COM-002. Other than a load shed Reliability Directive (during emergencies),
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what other Operating Communication would a DP receive?
Response: The SDT is aware of some DPs that operate and own BES assets. Load
shedding communications are the main reason they are applicable. Load shedding
can be requested during non emergency conditions.
Response: Thank you for your comments. Please see the response above.
Arizona Public Service
Company
Equipment identifiers at individual locations (generating stations as an example) have
the same alpha preceding the unique device numeric. It is unnecessary, redundant
and confusing to the operator to repeat the station location with an alpha clarifier.
Response: Thank you for your comments. The SDT is has developed an alternate approach to COM-003-1. Using the approach in
draft 3, an entity could define in their communication protocols that the equipment identifier does not include the preceding
alpha that designates the location.
Exelon Corporation and its
affiliates
Exelon believes that the proposed COM-003-1 exceeds what is necessary for
reliability and creates other problems such that the proposed standard may in fact
result in a decrease in reliability. In particular the language is overly prescriptive and
presents significant compliance questions both in terms of creating a credible
compliance measure and a reasonable way for entities to demonstrate compliance or
conduct internal self-assessment. Exelon believes that an alternative approach to
COM-003 is needed. The standard should set desired outcomes and leave the specific
implementation of communication protocols to registered entities. Standards should
not impede use of best practices and should encourage effective innovation.
An alternate approach is worth consideration:
Requirements:
1. Entities must have a protocol addressing communications for operating
personnel.
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1.1. The protocol should address; three part communication, English language
usage (include footnote for requirement to use legislatively prescribed
language), time zone, entity unique identifiers, 24 hour clock and alpha numeric
identifiers.
1.2. All control center operating personnel should be trained on the use of the
protocol. Measure: In an audit, a company would be expected to demonstrate
that they had such a protocol and that they trained their operators on its use.
This proposal would satisfy the Directives and Blackout Recommendation #26
which were to “tighten communication protocols, especially for...
emergencies”. Stakeholders and the NERC BOT approved COM-002-2 which
addressed communications capabilities being staffed and available for
addressing a real-time emergency condition. An associated interpretation of
COM-002 clarified whether routine operating instructions are “directives” or
whether “directives” are limited to actual and anticipated emergency operating
conditions. Our proposed changes to COM-003 are responsive to the FERC
recommendation to tighten operating protocols. Other possible responses to
this recommendation would be to conduct an assessment of NERC certification
requirements and if found lacking in this area, strengthen them. For the
reasons stated above, we urge NERC to change the focus of COM-003 from a
prescriptive what to do approach and allow entities to develop and implement
protocols in keeping with NERC and ISO/RTO operator certification
requirements and best practices within the industry.
Thank you for the opportunity to comment.
Response: Thank you for your comments. The SDT has developed a similar approach in draft 3.
Idaho Power Company
I believe the requirements for Directive should be included in this standard and
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removed from COM-002.
Response: Thank you for your comments.
Illinois Municipal Electric
Agency
IMEA agrees with comments submitted by the SERC OC Standards Review Group.
Response: Thank you for your comments. Please see our response to SERC Operating Committee comments.
Indiana Municipal Power
Agency
IMPA believes that each organization should follow its internal communication
protocol up to the point where a Reliability Directive is issued. IMPA does not see
why NERC is stating the “how” in this standard (sub-requirements 1.1, 1.1.1 thru
1.1.4) when its common practice has been to stay away from telling the entities
“how” to do a standard requirement. Therefore, IMPA believes that COM-003 should
just state that an entity needs to have a communication protocol in place for issuing
and receiving instructions. In addition, an entity should only have to do training on
its communication protocol in order to prove compliance that it is following or using
it. The record keeping or data retention of phone recordings will become very
burdensome on entities, especially if they have to keep five or six years worth (back
to its last audit date).
Response: Thank you for your comments. The SDT has developed a similar approach in draft 3.
Ingleside Cogeneration LP
Ingleside Cogeneration LP agrees in principle with the need for Operators and Field
Personnel to express and validate their intent before taking actions that may pose a
risk to the BES. However, we have serious reservations with the use of the audit
methodology to drive consistent behavior. Perhaps most significant is the
assessment of violations for a single instance where an operator does not use
alphanumeric identifiers or a 24 hour clock during the course of an Operating
Communication. We believe that even in an extremely well managed organization
that 100% adherence is statistically impossible. In our view, this flies in the face of
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fairness - and raises serious questions about the “public/private partnership” that is
supposed to be the foundation of NERC standards. This points to the “bean
counting” type of Standards that NERC is trying to get away from, rather than
focusing on reliability of the BES. Furthermore, entities will be assessed violations if
they cannot prove that every side conversation did not take place in accordance with
COM-003-1. In order to comply, we estimate it will take two or three times the time
to document a non-recorded communication than it will be to actually conduct one.
This is not an appropriate use of our front-line resources available time - nor does the
documentation serve a reliability purpose in our view.
Response: The SDT has developed a new approach in draft 3 that addresses your
concerns.
In addition, COM-003-1 is silent as to multiparty calls that are typical in some regions,
where an entity at random is elected for the three part response for the group on
conference calls, and not all parties are required to respond, but rather only
participate on the call.
Response: The SDT is incorporating protocols for multiparty calls in draft 3.
Response: Thank you for your comments. Please see the comments above.
Manitoba Hydro
Manitoba Hydro is voting negative on COM-003-1 based on our comments in the
previous questions in addition to the following:(M1/M2/M3)- it is unclear what
specifically is meant by ‘on site observations’ or how ‘on site observations’ can be an
effective measure of compliance with the standard’s requirements.
Response: Thank you for your comments. The measures have been modified in response to changes in the requirement language.
PNGC Small Entity Comment
Group
Modified PNGC Small Entity Group Comments:
The PNGC comment group believes there should be a distinction in the “Applicability”
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scheduling Distribution Provider”. PNGC members are small rural cooperatives that
are “Full service BPA customers.” This means that BPA is our power supplier and
scheduling agent and therefore handles all reliability directives, scheduling, tagging,
dispatching of resources and curtailments of load from breakers on BPA’s system for
PNGC members.
According to a letter from the WECC Reliability Coordinator (VRCC and LRCC) none of
PNGC’s members will ever receive a “Reliability Directive”. Such a Directive would be
sent to either a Balancing Authority (BA), or a Transmission Operator (TOP). We
estimate there are over 100 entities that are BPA Full Service customers that are in a
similar position and making this standard applicable to them does nothing to enhance
reliability. A simple declarative statement in the Applicability section of the standard
could focus the intent of the SDT on those entities that need it while lessening the
compliance risk and clerical burden for other entities that the standard should not
apply to.
We suggest:
4. Applicability:
4.1. Functional Entities
4.1.1 Reliability Coordinator
4.1.2 Transmission Operator
4.1.3 Balancing Authority
4.1.4 Generator Operator
4.1.5 Distribution Provider:
With Real-time Operations and Scheduling desk the PNGC comment group believes
the above change will lessen the compliance burden on small, non-scheduling entities
while still meeting the SDT’s intent with regard to Operating Personnel
Communications. We also note that FERC and NERC, on multiple occasions and in
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multiple filings, have indicated their openness to lessening unnecessary compliance
requirements for small entities.
Response: Thank you for your comments. The SDT notes that COM-002-3, draft 6 states that in addition to Reliability
Coordinators, Balancing Authorities and Transmission Operators can also issue Reliability Directives. Draft 3 of COM-003-1 also
limits protocols for Distribution Providers to those that apply to receiving Operating Instructions.
NERC Operating Committee
NERC Operating Committee (OC) comments on COM-003 (Operating Personnel
Communications Protocols) The current draft of COM-003 is prescriptive and is in fact
a procedure or rather a set of discrete tasks / actions that are not focused to support
the reliability intent. The NERC OC recommends that the SDT develop a purpose that
speaks to operators and their responsibility to maintain reliability not a process or set
of protocols that cannot account for every nuance and variable in the realm of
communications and human interaction.
Restated Purpose: To provide system operators a holistic communications program
that reduces the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of BES.
The OC just approved a guideline for System Operator Verbal Communications. The
OC feels this could be used as a basis for a new approach for COM-003-1. The OC
proposes that the SDT changes the draft of COM-003 to the following three
requirements:
R1: Each RC, TOP, GOP, BA, DP shall develop a written communications procedure to
address the following:
o Protocols
o Training and education
o Internal controls (Preventive, Detective and Corrective) that demonstrates a
process that will find, fix, track, trend, analyze and continuously improve
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R2: Each RC, TOP, GOP, BA, DP shall train applicable personnel on the
communication procedure developed for R1
R3: Each RC, TOP, GOP, BA, DP shall take appropriate actions to address deficiencies
revealed by internal controls.
Response: The SDT has developed a similar approach in draft 3.
Data retention must be rethought to focus less on significant data and evidence
archiving (backwards looking) and more on the internal program to continuously
improve (forward looking). Individual instances of not following the company’s
procedure should not be the basis of violation but instead - a demonstration of
internal assessment and refinement.
Response: The SDT has modified its approach to data and evidence retention.
The VRF/VSL should be based on an entity either not having a program, not
demonstrating their assessment and corrective action process or egregious / systemic
problems with the implementation of their program.
Response: The SDT has modified the VRFs and VSLs accordingly.
Response: Thank you for your comments. Please see the responses above.
Entergy Services
NERC standards are not procedures and this standard attempts to impose a single
procedure on the industry. Tightening of communications protocols between entities
does not equate to a procedural requirement to use 3-part communications between
personnel at various registered entities.
The actual impact to reliability of routine communications between entities is
minimal and further diminished by the Reliability Directive construct espoused by RC
SDT (Project 2006-06), which fully addresses the reliability implications of
communications.
Response: The SDT is aware of draft 6 of COM-002-3 from project 2006-06 and
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believes that while COM-002-3 addresses the risks to reliability during Emergencies
and Adverse Reliability Impacts it does not address the risks to reliability that exist
due to communication mistakes that occur during normal operating conditions. The
events that generate a Reliability Directive are high impact and low frequency
events. Most of the time the BES is operated in a normal state sustained by large
numbers of Element and Facility changes that require Operating Communications.
The communication protocols the SDT is proposing have been proven effective for
clarifying critical content in commands or orders. Reducing the potential for
mistakes on the BES enhances reliability.
While most of the industry practices three-way communications routinely, this is not
necessary to assure reliable operations. Rather, in many cases, entities are viewing
this as a “best practice”, that helps to formalize communications so that Operators
will develop good communications habits. The work by the RC SDT (Project 2006-06)
on Reliability Directives is all that is necessary to assure BES reliability, and the
approach currently espoused by OPCP SDT (Project 2007-02) in this COM-003
standard is massively redundant to that effort while not helping reliability. We
agree with SERC in suggesting another approach to COM-003. Rather than to specify
the solutions to achieving effective communication, COM-003 should instead focus
on developing and training on an approach that is designed appropriately for each
RE.
For instance, another approach to COM-003 might be along the lines of:
Requirement 1 (See our suggested alternate language in our response to Question 1)
could be written in a manner to require the appropriate registered entities to
develop a communication protocol that is appropriate for each RE. This
communications protocol should address how the RE is handling:
Time Zone Designations - for both internal and external communications
Language
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Alpha-numeric identifiers
Three - part communications - circumstances in which is it required, etc
Use of defined terminology. This approach would require the RE to address how it is
addressing these issues, without prescribing solutions. For instance, a RE could
include in its protocol a section dealing with time zone designation. In this section
the RE could explain that it, and its neighbors, all are in and use the same time zone.
As a result, the RE has determined that requiring the identification of time zone
reference in communication is not necessary.
Procedures should address the training of operators on the communication
protocol
Procedures should address the internal controls that the RE uses to review that
its protocol is being followed.
The compliance approach would be to: Assess whether the RE has developed a
written protocol and whether the protocol addresses each item - this does not mean
there is an assessment of HOW each item is assessed; assess whether the RE has
trained its operators on the communications protocol and assess whether the RE is
following its internal controls. Compliance with this requirement should not require
100% accuracy in compliance with the entities communication procedure by realtime operations staff. That would cause misdirection of resources and training time
from issues more important to BES reliability.
Response: The SDT has developed a similar approach in draft 3.
Any data retention requirements should be consistent with the COM-002 reliability
standard.
Response: The SDT has modified its approach to data and evidence retention.
What is the role of the Operating Communications Protocols White paper? Is it a
position of the STD? Was there a minority opinion? Why was it not vetted with a
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wide spectrum of industry stakeholders (we are unaware of any effort to circulate
this white paper even as far as to the standing Technical Committees of NERC).
Response: The White Paper is intended to assist industry stakeholders understand
the rationale behind the content in the standard. For further information on
communication guidelines, please refer to the paper developed by the NERC
Operating Committee titled “Reliability Guideline: System Operator Verbal
Communication – Current Industry Practices” located at
http://www.nerc.com/filez/oc.html.
The White Paper was requested by members of the Standards Committee to
provide a foundation for the team’s position on communication protocols for
normal operations.
Does the industry agree that we need a standard on three part communications for
normal operations? We have seen no evidence to support this contention. This
revision to COM-003 seems to have sprung into existence without any substantive
industry comments indicating that the industry would benefit from having a
procedure memorialized as a set of Requirements.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Response: Thank you for your comments. Please see the responses above.
Southern Company
NERC standards are not procedures and this standard attempts to impose a single
procedure on the industry. Where is the demonstrated need for such a standard?
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Have communications, especially during periods of normal operations, been shown
to be the root cause of many, if any, events? Registered Entities agree that there is a
need of clear and concise communication between entities; however, we must avoid
creating a system that is unmanageable and quite possibly results in less reliability.
FERC Order 693 directs the ERO to ‘‘and (3) requires tightened communications
protocols, especially for communications during alerts and emergencies”, in
paragraph 532. The proposed standard goes too far, especially for communications
outside of alerts and emergencies.
Response: Thank you for your comments. The purpose of the SAR for this project is “Require that real time system operators use
standardized communication protocols during normal and emergency operations to improve situational awareness and shorten
response time.” Additionally, the SAR is very specific in that it also includes the term “normal” operating conditions under
Applicability: “Clear and mutually established communications protocols used during real time operations under normal and
emergency conditions ensure universal understanding of terms and reduce errors.” The SDT has developed a new approach to the
standard that addresses your concern.
NextEra Energy, Inc
Next Era has the following additional recommended changes to increase the clarity of
COM-003-1:
1. A new provision on written Operating Communications that requires that the
sender to receive a notification that the recipient has received and read the
communication. As currently written, there is no read receipt requirement for
written Operating Communications. This appears to create a possible reliability gap,
given that the sender will not know that its instructions were received and read,
which leaves the system in a state of limbo as to what actions will or will not be
taken.
Accordingly, NextEra recommends that a requirement be added that reads as
follows:”
When a Reliability Coordinator, Transmission Operator and Balancing Authority sends
a written Operating Communication it shall include a “read receipt” requirement or
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similar mechanism to ensure the sender has received and read the Operating
Communication. If a “read receipt” is not received by the sender, the sender shall
call the intended recipient or rescind the Operating Communication.”
Response: The SDT has limited three part communication to oral communication. In
the alternative approach to COM003-1 an entity could address that concern in its
communication protocols.
2. R2.1 is confusing because it attempts to mix what occurs when a response is
received and when no response is received during a oral communication. To ensure
no confusion occurs, as well as providing for additional practical discretion when a
response is not received, NextEra recommends that R2.1 be separated into two
distinct sections and be rewritten to read as follows:
R2.2. After the response is received, do the following:
o Confirm the receiver’s response is correct (not necessarily verbatim).
o Reissue the Operating Communication if the repeated information is incorrect or if
the receiver does not issue a response.
o Reissue the Operating Communication, if requested by the receiver.
R2.3 If no response is received, do one of the following:
o Ask the receiver if the Operating Communication was received. If receiver confirms
receipt of the Operating Communication, then proceed through R2.2.
If the receiver, however, does not confirm receipt or no response is received, the
sender of the Operating Communication shall either reissue or rescind the Operating
Communication.
Response: The SDT has changed the language to the same language contained in
COM-002-3, R2 and R3 to be consistent and to reduce confusion.
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3. Unlike language on Reliability Directives in IRO-001-3 - “unless compliance with the
direction cannot be physically implemented or unless such actions would violate
safety, equipment, regulatory or statutory requirements” - there is no similar
qualifier for Operating Communications. To provide the recipient of an Operating
Communication the same rights as a Reliability Directive, NextEra requests that a new
section be added:
”The recipient of an Operating Communication is required to implement the
instruction, unless compliance with the instruction cannot be physically implemented
or unless such actions would violate safety, equipment, regulatory or statutory
requirements.
In the event the recipient is unable to carry out the instruction, it shall communicate
this situation to the sender of the Operating Communication.”This last recommended
addition should be added in both cases:
(a) if Next Era’s response to question 6 is adopted, or
(b) if NextEra’s response to question 6 is not adopted.
Response: The SDT has developed a new approach in draft 3.
.4. To provide clarity to COM-003-1, NextEra recommends that the purpose stated in
the white paper be transferred to the purpose statement of COM-003-1. The white
paper states that “[t]he purpose of the proposed standard is to: ‘Require that real
time System Operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.’” NextEra recommends that this purpose statement replace the draft purpose
statement in COM-003-1, so COM-003-1 is not misinterpreted to require three way
communications outside of real-time system operations.
Response: The SDT has modified the purpose statement in draft 3.
Response: Thank you for your comments. Please see the responses above.
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New York Power Authority
Question 10 Comment
NYPA supports the comments submitted by the NPCC Regional Standards Committee
(RSC).
Response: Thank you for your comments. Please see the response to the comments submitted by the NPCC Regional Standards
Committee (RSC).
American Electric Power
Our efforts in this regard should first be focused solely on Reliability Directives before
expanding this work, and creating similar requirements for all other Operating
Communications. Requiring three part communications for every scenario might be
considered a best practice by some, but making it a mandatory practice for routine
operations seems to emphasize the manner of communications rather than the
operations themselves. In addition, requiring three part communications for
Reliability Directives will likely result in more widespread usage for more routine
operating communications, without making it a requirement.
Response: The SDT has developed a different approach to the standard that
addresses your concern.
AEP believes that there should not be multiple project teams proposing concurrent
changes to COM-001, COM-002, and COM-003. Unless there are overwhelming
reasons for not doing so, these efforts should be consolidated and managed by a
single project team. In addition, current efforts on COM-003 need to be co-located
with the proposed changes to COM-002 within a single standard. Having multiple
project teams proposing concurrent changes results in problems such as this, where
a) changes are proposed to the same standard or b) similar changes are proposed to
separate standards. AEP cannot support revisions on these matters until they are
managed by a single project team.
Response: Thank you for your comments.
Response: Thank you for your comments. Please see the responses above.
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City of Palo Alto
Question 10 Comment
Palo Alto supports the comments submitted by PNGC Power regarding limiting the
applicability of the standard to a certain subset of Distribution Providers. Palo Alto is
similarly situated as PNGC.
Response: Thank you for your comments. Please see the response to the comments submitted by PNGC Power.
Brazos Electric Power
Cooperative
Please see formal comments provided by APM.
Response: Thank you for your comments. Please see the response to the comments submitted by APM.
Center Point Energy Houston
Electric, LLC.
Question 10 Comments: It appears that the SDT is using an undefined definition of
Reliability Directive to propose the new definition of Operating Communication. Is
the intent of the SDT to also introduce this definition for Reliability Directive with this
project?
Response: No. The OPCPSDT included it in COM-003-1 as a means to demonstrate
the relationship between the two terms. Both standards were posted for
stakeholder review at close to the same time. After filing with FERC and receiving
FERC approval the definition will be added to the NERC Glossary of Terms. The
OPCPSDT and the RCSDT were attempting to explain the relationship between the
two standards to help stakeholders understand. The textbox was an attempt to
explain that relationship. Draft 3 of the standard no longer contains the reference.
The purpose is not consistent with language in other currently enforced standards.
The words “could” and “possibility” needs to be removed from the language. The
purpose needs to be concrete. An alternative purpose would be “To specify clear,
formal, and universally-applied communication protocols for the operation of BES
facilities that reduce miscommunication, which will have a negative influence on the
reliability of the Bulk Electric System.
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Response: The SDT has modified the purpose statement.
The six month effective date following approval is too short and should be extended
to 12 months to allow adequate time for training and implementation.
Response: The SDT has changed the effective date to 12 months in draft 3.
Response: Thank you for your comments. Please see the responses above.
Sacramento Municipal Utility
District
Recommendation: Not-Approve
We feel that the direction for this communications standard is grossly in error. Focus
should be on ensuring proper training programs are in place that emphasize and best
prepare the System Operator for effective communication. The idea that effective
communication can be scripted is entirely mis-guided and that a regulatory body
might subject an entity to financial penalties for communication standards that
attempt to script the language spoken, how time is referenced, naming conventions
and alpha-numeric clarifiers has no precedence in industry that we are aware of.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
The United States’ Air Traffic Control protocols for communications between
controllers and commercial airline pilots are very tested, well trained and effective.
Controllers and pilots are trained in effective communication and the situations and
pronunciation types that may lead to confusion. But they are not fined for any
instance of not following them.
From the Air Traffic Controllers Handbook,
http://avstop.com/ac/atc/2-4-1.html#2-4-12-4-3
Pilot Acknowledgment / Read back
a. When issuing clearances or instructions ensure acknowledgment by the pilot.
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NOTE - Pilots may acknowledge clearances, instructions, or other information by
using "Wilco," "Roger," "Affirmative," or other words or remarks. REFERENCE - AIM,
Contact Procedures, paragraph 4-2-3.
b. If altitude, heading, or other items are read back by the pilot, ensure the read back
is correct. If incorrect or incomplete, make corrections as appropriate.
Response: The protocols above are analogous to the level of communication
discipline that is desired when operating the BES.
Mandating the use of the English language in all communications is not in the best
interest of reliability. We are not aware of any issue that has been raised of
significance with the current requirement contained within COM-001-1.1, R4
Response: Referencing the example you cited above, the English language is
mandated worldwide in the aviation industry. The SDT believes the aviation
industry utilizes strong protocols.
COM-003-1, R1 will replace COM-001-1.1, R4 when COM-003-1 is filed and
approved.
Response: Thank you for your comments. Please see the responses above.
Utility System Efficiencies, InC.
Regarding Measure 1, the "on-site observation" aspect should be expanded upon and
clarified. This concept would be very important to identify and document "failures"
to properly follow Requirements R1, R2, and R3, during the audit period. Registered
Entities should be encouraged to use such observations to coach employees and
reinforce their following proper communications protocols/procedures and
complying with this standard.
Response: Thank you for your comments. The measures have been modified in response to changes in the requirement language.
PPL Electric Utilities
Regarding R1.1.3: I request the SDT consider allowing for the Applicable Functional
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Entity to develop an Operating Procedure such that if all parties in the
communications are in the same time zone that the time zone does NOT need to be
used in the Operating Instruction.
Response: The use of a time zone reference is mandated only if one or more of the
parties are in different time zones.
Regarding the VSL/VRF: I request the SDT consider adjusting the std or VSLs to allow
for compliance with a 95% confidence. Such that 1 incomplete 3-part Operating
Communication could be considered low or not a PV. If sampling of voice recordings
provides a 95% confidence, this should be sufficient. E.g. If one sample of 30 voice
recordings results in 1 incomplete 3 part and a second Sample of 30 finds no issues,
the audit result should be no PV. This is a standard sampling technique.
Response: Due to changes made to the current draft of the standard as a result of
comments, the requirements have been significantly modified and the VRFs and
VSLs had to be modified accordingly and are consistent with FERC and NERC
guidelines.
We thank the SDT for their efforts. PPL EU supports the value added by using 3-part
communications and a phonetic alphabet as both are included in our current
communications operating instructions. Even with the many Human Performance
tools we use, our concern with the standard is being found non-compliant if one of
hundreds/thousands of operating communications in a year is not perfect 3-part
comm.
Response: The SDT applauds your use of 3-part communications and a phonetic
alphabet. The SDT has developed a new approach to the standard that addresses
your concern.
Response: Thank you for your comments. Please see the responses above.
City of Garland
Requirement 1.2 should be removed from the standard. The number of directives
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and switching orders that have been issued in North America over time probably
number in the billions. If one could determine the percentage of issues caused by
miscommunications out of that large number, it would be extremely small. The
reason that miscommunication issues exist is because the communication is between
two human beings and where people are involved, issues will happen. A requirement
for three part communications is more than sufficient to address the issue of
miscommunications.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Adding a requirement to use alpha-numeric clarifiers such as the NATO Spelling
Alphabet is not going to prevent miscommunications. The only thing that adding this
requirement will accomplish is to require auditors to listen to recorded conversations
trying to verify that operators used alpha-numeric clarifiers and then penalizing a
company if an operator does not; even though the directive or switching order was
followed correctly.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Response: Thank you for your comments. Please see the responses above.
City of Tallahassee
TAL is concerned that the proposed standard focuses too heavily on the
communications method without consideration of a successful result. While the
administrative approach/focus of this proposed language appears to be crafted with
the intent of standardizing communications and thereby improving communications,
it does not appear to place sufficient value on results-based performance. Should an
entity take proper action on a communication that is not delivered precisely in
accordance with this language, consideration of such at the Enforcement level would
be warranted.
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Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Utility Services, Inc.
The applicability of this standard is unclear in the case of Distribution Providers.
Response: The SDT believes Distribution Providers can be receivers of Operating
Communications and are applicable entities for requirements that govern protocols
for receiver. Load shedding is the most common Operating Communication a
Distribution Provider would receive.
The definition of Operating Communication includes “Elements” that could impact
the BES. The NERC Glossary definition for Elements includes non-BES devices and
equipment. Additionally, the Purpose section of the standard states "harmful to the
reliability of the BES." Since non-BES Elements could affect the BES this standard
could be deemed applicable to non-BES devices. If it is the intent of the SDT to apply
this standard to All Operating Communications concerning both BES and non-BES
Facilities this should be explicitly stated in the applicability section for transparency.
Otherwise clarifying language should be added to exclude non-BES Facilities.
Response: The SDT intended Operating Communication to apply to the BES and has
modified the definition accordingly.
Response: Thank you for your comments. Please see the responses above.
TransAlta Centralia
Generation LLC
The current effective date only gives the registered entities 6 calendar months to be
compliant with the requirements. We do not think this will be achievable. A longer
implementation time is required, such as 12 months. In order to comply with
standard requirements, the registered entities need to develop the internal controls,
such as the procedures/operator training documents, and then provides the training
to the operators. The 6 calendar months are not long enough to complete these
tasks.
In the white paper, Table 1-A shows only the three-part communication are currently
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used in the registered entities. However, for all other requirements, such as using
alpha-numeric clarifiers, the white paper does not show that these are currently used
in the registered entities. Thus, there is no base to justify that 6 months is reasonable
to achieve the compliance.
Response: Thank you for your comments. The SDT agrees and has made the suggested change.
Midwest Reliability
Organization NERC Standards
Review Forum
The MRO NSRF recommends the following comments for consideration by the SDT:
1. Concerning the “Purpose”: Recommend rewrite to state: “To specify universallyapplied communication protocols that reduce the possibility of miscommunication
which could impact the reliability of BES”. This shorter and to the point purpose
clearly defines the intent of the Standard.
Response: The SDT modified the purpose statement based on comments provided.
2. R1.1.3, An entity will be found non compliant if it merely has a written BES
switching order that does not contain a time, time zone or whether it is daylight
savings time or standard time. The Requirement states nothing about implementing
the written communication, just that it is written. The NSRF does not believe that
this is the intent of the SDT.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
3. This also applies to oral communications. If two operators are communicating
between each other while in different time zones and executing a BES switching
order, they would need to establish what time it is in both time zones, indicate
whether it is daylight saving time or standard time. So, since a Reliability Directive is
a component of an Operating Communication, prior to receiving an oral Reliability
Directive senders and receivers would need to establish what time it is in both time
zones, indicate whether it is daylight saving time or standard time and then give and
receive the Reliability Directive. The NSRF does not believe that this is the intent of
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the SDT.
Response: The SDT appreciates your comments and clarifies that the statement
above is the intent of the SDT, if the communication is occurring between
functional entities (not internal to a specific functional entity).
4. The SAR for this standard incorrectly addresses the blackout recommendation
number 26.
Recommendation 26 states:
”26. Tighten communications protocols, especially for communications during alerts
and emergencies. Upgrade communication system hardware where appropriate”.
“NERC should work with reliability coordinators and control area operators to
improve the effectiveness of internal and external communications during alerts,
emergencies, or other critical situations, and ensure that all key parties, including
state and local officials, receive timely and accurate information.”
“NERC should task the regional councils to work together to develop communications
protocols by December 31, 2004, and to assess and report on the adequacy of
emergency communications systems within their regions against the protocols by
that date.”
Response: The SAR is an industry vetted document and believes it does support
Blackout Recommendation 26. The SDT believes the Blackout report itself supports
the protocols established by COM- 003-1 based on the excerpts you provided.
5. Order No. 693 clearly says that the tightened protocols are primarily intended for
actions during alerts and emergencies. This was partially addressed in the
interpretation on COM-002 and is being addressed in Project 2006-06. Below is the
summary determination in the Order on this issue."535, Accordingly, we direct the
ERO to either modify COM-002 or develop a new Reliability Standard that requires
tightened communication protocols, especially for communications during alerts and
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emergencies."
Response: FERC Order 693, paragraph 532 (This will eliminate possible ambiguities
in communications during normal, alert and emergency conditions”) and the SAR
are very specific in that both include the term “normal” operating conditions.
6. It is not clear that COM-003-1 R1 applies to COM-002-3. The latest draft of COM002-3 doesn’t reference the communications protocols listed in COM-003-1 R1 and
the definition of Reliability Directive does not state that it is a type of Operating
Communication. Suggest combining the two standards into a single communication
standard.
Response: COM-003-1, R1 applies to any communication that involves a “command
from a System Operator to change or preserve the state, status, output, or input of
an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
7. The white paper states “Significant events have occurred on the BES when unclear
communication created or exacerbated misunderstandings that led to instability and
separation.” However, no specific examples were identified. During the June 7
webinar when this question was brought up, it was stated that three part
communication was used during these events. This begs the question as to why this
standard is needed for normal operations.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System.
8. In order to assign the same level of responsibility as COM-002-2, R2, the RC, TOP,
and BA should be the only applicable entities since a Reliability Directive is a sub
component of Operating Communications. The RC, TOP, and BA clearly understand
clear, concise and definitive communications. They are the only required entities to
be NERC Certified and should be held to the highest standards. They can establish
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other controls to mitigate their risk by training and informing DPs and GOPs that are
within their control. DPs and GOPs do not need to be included in R3.
Response: DPs and GOPs receive Operating Communications and must be able to
execute the requirements of a receiver, so they must be included as applicable
entities in COM-003-1.
Response: Thank you for your comments. Please see the responses above.
PNGC Small Entity Comment
Group
The PNGC comment group believes there should be a distinction in the “Applicability”
section of the standard between “Scheduling Distribution Provider” and “Nonscheduling Distribution Provider”. PNGC members are small rural cooperatives that
are “Full service BPA customers.” This means that BPA is our power supplier and
scheduling agent and therefore handles all reliability directives, scheduling, tagging,
dispatching of resources and curtailments of load from breakers on BPA’s system for
PNGC members. According to a letter from the WECC Reliability Coordinator (VRCC
and LRCC) none of PNGC’s members will ever receive a “Reliability Directive”. Such a
Directive would be sent to either a Balancing Authority (BA), or a Transmission
Operator (TOP). We estimate there are over 100 entities that are BPA Full Service
customers that are in a similar position and making this standard applicable to them
does nothing to enhance reliability. A simple declarative statement in the
Applicability section of the standard could focus the intent of the SDT on those
entities that need it while lessening the compliance risk and clerical burden for other
entities that the standard should not apply to.
We suggest:
4. Applicability:
4.1. Functional Entities
4.1.1 Reliability Coordinator
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4.1.2 Transmission Operator
4.1.3 Balancing Authority
4.1.4 Generator Operator
4.1.5 Distribution Provider: With Real-time Operations desk
The PNGC comment group believes the above change will lessen the compliance
burden on small, non-scheduling entities while still meeting the SDT’s intent with
regard to Operating Personnel Communications. We also note that FERC and NERC,
on multiple occasions and in multiple filings, have indicated their openness to
lessening unnecessary compliance requirements for small entities.
Response: The SDT appreciates your comments. The SDT notes that COM-002-3, draft 6 states that in addition to Reliability
Coordinators, Balancing Authorities and Transmission Operators can also issue Reliability Directives. Draft 3 of COM-003-1 also
limits protocols for Distribution Providers to those that apply to receiving Operating Instructions.
ISO/RTO Standards Review
Committee
The SDT’s proposals do not conform to the Standards Process because those
proposals do not reflect the public comments that were submitted. The Process
requires the SDT to use the Industry’s comments to drive the requirements and as
such the requirements should not be mandating a three part communications
procedure for all “changes in status” much less the maintaining of such status. Such a
request was not made by any of the commenters let alone a majority of the
commenters. It would be more appropriate if the SDT asked who favored the
approach being used, as opposed to asking if an “adjustment” to the requirement
were acceptable. Many of the adjustments are better than if they were not there, but
that ignores the fact that the requirement itself is not supported by the majority of
commenters.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
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communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern. The SDT has developed a new approach to the
standard based on industry feedback that addresses your concern.
The SDT’s proposals expand the scope of the SAR by totally ignoring communications
protocols used during emergencies and simply focusing on procedures imposed on
personnel during normal situations. This standard over-reaches into routine
operations by requiring 3-part communication for all instructions that change or
maintain the state, status, output, or input of an Element or Facility of the Bulk
Electric System. This type of instructions occurs every hour, if not minute. Requiring
operating personnel to apply a 3-part communication procedure for these
instructions is absolutely unnecessary and overburdening, and can in fact adversely
affect reliability.
We strongly suggest that any requirement for 3-part communication for routine
operating instructions be removed.
Response: The purpose of the SAR for this project is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” Additionally, the SAR is very specific in that it also includes the term
“normal” operating conditions under Applicability: “Clear and mutually established
communications protocols used during real time operations under normal and
emergency conditions ensure universal understanding of terms and reduce errors.”
****FERC Order 693
510. “The Commission proposed...
(4) requires tightened communications protocols, especially for communications
during alerts and emergencies.
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“SRC Note - The above language while allowing for a requirement to go beyond
emergencies, it states that the primary intent is “during alerts and emergencies”. The
SDT has no requirement for “alerts and emergencies” and focuses solely on normal
operations.
Response: The specified communication protocols are applicable to normal and
emergency operations.
532. While we agree with EEI that EOP-001-0, Requirement R4.1 requires
communications protocols to be used during emergencies, we believe, and the ERO
agrees, that the communications protocols need to be tightened to ensure Reliable
Operation of the Bulk-Power System. We also believe an integral component in
tightening the protocols is to establish communication uniformity as much as
practical on a continent-wide basis. This will eliminate possible ambiguities in
communications during normal, alert and emergency conditions. This is important
because the Bulk-Power System is so tightly interconnected that system impacts
often cross several operating entities’ areas.
230 EOP-001-0, Requirement R4 provides, in relevant part, that: “[e]ach Transmission
Operator and Balancing Authority shall have emergency plans that will enable it to
mitigate operating emergencies. At a minimum, Transmission Operator and Balancing
Authority emergency plan shall include [c]ommunication protocols to be used during
emergencies.
”SRC Note - the communications ambiguities noted above do not refer to issues with
interpersonal communications but rather refer to situational ambiguities.
Response: The SDT respectfully disagrees. The wording in paragraph 532 says “This
will eliminate possible ambiguities in communications during normal, alert and
emergency conditions.” There is no reference to situational ambiguities. The SDT
interprets ambiguities in communications to mean “unclear” communication.
With regard to EOP-001-0, Requirement R4, the SDT believes this to be an
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emergency planning requirement which only states “emergency plan shall include
communication protocols to be used during emergencies.” The requirement does
not address the development of those protocols.
540. “While the Commission identified concerns regarding COM-002-2, the proposed
Reliability Standard serves an important purpose by requiring users, owners and
operators to implement the necessary communications and coordination among
ENTITIES.
SRC Note - the above does not say “among OPERATING PERSONNEL” it says “among
ENTITIES”.
Response: The SDT respectfully points out that paragraph 540 also includes “the
proposed Reliability Standard serves an important purpose by requiring users,
owners and operators to implement the necessary communications and
coordination among entities. “ The SDT believes this is another statement that
sanctions the protocols the team has developed.
540. (Continued)ALTERNATIVELY, with respect to this final issue, the ERO may
develop a new Reliability Standard that responds to Blackout Report
Recommendation No. 26 in the manner described above.
“SRC note - The above is a key directive. It states tightened communications protocols
[it does not say three part communications for normal actions]’Also note that the
Blackout report recommendation is “an alternative” solution and not necessarily a
part of the FERC proposed solution.
Response: The SDT believes it has responded to Blackout Report Recommendation
No. 26 properly and effectively. The implementation of three part communication
during normal operation of the BES is tightening communications. During its
discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT
stipulated in its approval the expedited development of a comprehensive
communications program, which would address necessary communication
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protocols for use in the operation of the Bulk Electric System. The SDT determined
that protocols concerning three part communication (when it is necessary and what
is required) during normal operations was a necessary step in addressing the BOT’s
concern.
The SDT is also asked to identify the role of the posted White Paper. Is the White
paper to be retained as part of the support documentation? If so, then the paper
must be vetted by the Industry. The SDT did not afford the opportunity to respond to
the paper. There was no indication if the paper was a unanimous SDT position or if
there were any minority opinions.
Response: The Operating Communications Protocols White paper is the position of
the SDT.
The White Paper was requested by the Standards Committee to support the team’s
position on communication protocols for normal operations. Since the standard did
not reference the White Paper there was no requirement for vetting. The SDT
posted it for industry stakeholders to share the rationale for the team’s position.
The SRC would offer the following “whitepaper” to help in deciding whether or not a
requirement for 3 part communications for all operational communications rises to
the level of requiring a mandatory standard. The “whitepaper” frames the
communications issues generically providing an alternative to a zero defects
standard.
********The strides NERC is making in the areas of Events Analysis and Human
Factors will likely lead to useful practices and value-added standards. A fact-based
approach to standards will lead to improved reliability. This paper attempts to
quantify the problem that COM-003 is trying to address. While human error is often
the first theory to explain major accidents, the follow-on investigation typically finds
many factors beyond the front-line operator’s control. There is an axiom in the field
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of quality control that attributes 80% of manufacturing defects are controllable by
management rather than the cause of the front-line workers .Many people make
errors that contribute to outages. Manufacturers have equipment defects, planners
make incorrect design decisions, technicians draw maps incorrectly, managers cut
budgets (plant maintenance, vegetation management), etc. A study of errors at
nuclear power plants sheds light on the causes behind the scenes. Although 92% of
all root causes were man-made, only a small number of these were initiated by frontline operators. Most originated in either maintenance-related activities or in bad
decisions within the organization. In another study, a review of summaries of three
major industrial events (Three Mile Island, Bhopal, and Chernobyl) identified
operators as committing less than 10% of the missteps that led to the disasters.
Table 1 Contributors to Major Accidents To be conservative, this paper assumes that
30% of all major human errors that impact the BPS are attributed to front-line
workers (dispatchers, field operators, technicians and maintenance personnel).With
regard to which front-line workers commit errors, a study of electrical system
incidents at nuclear plants were generally evenly distributed between operators,
maintenance personnel and technicians. As to communications problems causing
trouble, an EPRI study reviewed nearly 400 switching mishaps by electric utilities and
found that roughly 19% of errors (generally classified as loss of load, breach of safety,
or equipment damage) were due to communication failures. This was nearly
identical to another study of dispatchers from 18 utilities representing nearly 2000
years of operating experience that found that 18% of the operators’ errors were due
to communication problems. Figure 1 EPRI Study Results on Operating Errors.
Bringing the pieces of this discussion together, the following assumptions are used to
estimate the percent of human errors on the BPS caused by operator communication
breakdowns:
o 30% of human failures impacting the BPS are due to front line workers
o Front line errors were generally evenly split into 3 groups
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o Dispatchers
o Field Personnel
o Maintenance and Relaying Technicians
o 18% of dispatcher errors are due to communication problems.
The net result is that using estimates of existing research shows that dispatcher
communications represent roughly 2% of the human failure on the BPS. Figure 2
Summary Human Failure Estimate.
While it has been stated that communication problems are found during the review
of all system events, this is similar to saying that gravity is involved in all trips and
falls. The statements are true, but the solutions to the problems are
multidimensional.
During a system event, there are hundreds, if not thousands of communications
among different operators, often on situations never seen by the participants. Many
of the communications are troubleshooting and information sharing that requires
give and take and must be done quickly. If every communication during a
disturbance needed to be 3-way, system restoration times for those disturbances
would increase.
NERC has built a solid foundation to make informed decisions in the future. The
Events Analysis process, GADS, and TADS should yield data on the impacts and
contributors to BPS failures. NERC’s Human Factors efforts can be used to develop
good practices for all front line personnel. NERC should build on the research similar
to that outlined in this paper via industry-wide surveys of operators to collect
additional data, lessons-learned and tips for improvement.
*****************A quick estimate of the workload associated with COM-003, for
the number of registered entities under the standard’s applicability list. If we assume
1 call each 10 minutes for a BA, TOP and RC and ¼ this amount for GOP and DP, you
get the totals below. Each of these is an auditable and sanctionable event. The
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review and self report on all of these is incompatible with the reliability impacts
realized?
BA TOP RC GOP DP Total 132 181 22 795 551
# of Entities19008 26064 3168 28620 19836
96,696 Calls per Day
35,294,040 Calls per year
*****************Lastly, the SRC requests that in the next posting that the SDT
include the question:
Does the Industry:
o Support continued development of a standard on personnel discussions during
non-emergency conditions?
o Support withdrawal of the standard?
o Support the creation of an alternative non-standard (e.g. certification) that
addresses the corporate protocols on communications?
Response: The SDT has read the attached white paper and a file copy that had more
content and found some aspects of it very supportive of the OPCPSDT efforts and
decisions. It is especially noteworthy that “18% of dispatcher errors are due to
communication problems.” That is what this standard is addressing.
With regard to your last request:
During its discussion of the approval of the Interpretation of COM-002-2 R2, the
NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System.
Including the proposed question would be counterproductive to the Board’s
direction and will not be entertained by the SDT.
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Response: Thank you for your comments. Please see the responses above.
U.S. Bureau of Reclamation
The standard should clarify what is evidence is considered acceptable to demonstrate
compliance with R 1.2. The requirement 3 appears to require the use of voice
recording to demonstrate compliance with repeating the operating communication
requirement. Not all facilities in which operating instruction may be received have
voice recording capability. The requirement/measure should clarify alternative
evidence when such a means is not present.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Also please refer to the RSAW posted with COM-003-1 draft 3.
PPL Generation, LLC on behalf
of its Supply NERC Registered
Entities
The statement, “Evidence may include, but is not limited to, voice recordings,
transcripts of voice recordings, on-site observations, or other equivalent evidence,” in
the Measures section of COM-003 is impractical. Any comprehensive body of
evidence would be unreasonably voluminous as well as requiring far more effort to
compile than could be justified. The only evidence required for Generation Owners
should be a procedure on the subject and a record showing that all applicable
personnel have been trained.
Response: The SDT appreciates your comments. The SDT has developed a new approach to the standard that addresses your
concern. Also please refer to the RSAW posted with COM-003-1 draft 3.
Northeast Power Coordinating
Council
The three-part communications in COM-003-1 are expanded beyond reliability
directives which unnecessarily force the inclusion of conversations which may be
impractical or unnecessary. Good practice dictates that three part communication be
used as a tool, but it should not be a requirement. The Standard is specifying how to
accomplish, not just what is required.”
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
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comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
1.1.4 When referring to a Transmission interface Element or a Transmission interface
Facility, use the name specified by the owner(s) for that Transmission interface
Element or Transmission interface Facility” may create a detriment to reliability.
Oftentimes, for switching, TOs have very detailed names for individual elements,
devices, equipment which may not translate into the TOP/RC systems. However, it is
known what equipment is being talked about. The requirement is unnecessary,
unreasonable and burdensome.
Response: The revised wording in draft 3 states:
“When referring to a Transmission interface Element or a Transmission
interface Facility, use the name specified by the owner(s) for that
Transmission interface Element or Transmission interface Facility unless
another name is mutually agreed to by the functional entities .”
The communications protocol to be followed in the event that there is a situation
that requires the removal of BES (or any other power system equipment for that
matter) from service on an immediate and emergency basis to protect the health and
safety of the public and/or an employee/s needs to be addressed. The instructions
issued to meet this condition fall under the definition of Operating Communication,
but in an emergency situation the time taken for the required repetition could be
catastrophic.
This also applies to BES (or any other power system) equipment that is in imminent
danger of failure, phase angle regulator or transformer tap changer runaway, or
other emergency conditions.
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This is also true of situations where the BES response to a disturbance results in a
facility or facilities being overloaded real time over their STE and LTE ratings, and
those facility loadings have to be reduced below their STE and LTE ratings within five
and fifteen minutes respectively. The time spent for the necessary three part
communication could mean the difference between maintaining continuity of service,
or having to shed load.
Suggest that wording be added to address the emergency situations described by
recognizing the possibility that an operator might have to respond to a situation by
issuing a “one way” order, then have a requirement for after the fact
communications which would be informational as to what emergency actions were
taken, and then resume normal communications protocols for subsequent actions.
Response: The SDT understands the gravity of the situations you describe. While
speed in response to an emergency involving life and property is critical, so is the
accuracy of the command to operate the Facility and the Element that will alleviate
the threat.
The SDT has developed a new approach to the standard the team believes will
mitigate your underlying concern by providing an entity the flexibility to assess its
own performance with respect to following its protocols.
Regarding the wording for the issuer in R2 “...that issues an oral, two-party, personto-person Operating Communication”, and the wording for the receiver in R3 “...that
receives an oral two-party, person-to-person Operating Communication”, what is the
significance of the use of the comma after “oral” in R2? What is the difference
between two-party and person-to-person communication?
Response: The comma was an error and is removed in draft 3. Two party was added
to preclude all call or multiple addressee communication. Person to person was
added to denote human to human rather than human to machine.
Also regarding R2, the Generator Operator should be included as an authority to
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issue an Operating Communication.
Response: The SDT discussed this and determined that a GOP would only be a
receiver of an Operating Instruction.
It is not necessary to separate normal and emergency communications into two
standards (COM-003, COM-002). One standard should encompass both. But having
two Standards, the communication protocols in COM-003 R1 should be incorporated
in COM-002.
Response: COM-003-1 R1 applies to all communications that involve a “command
from a System Operator to change or preserve the state, status, output, or input of
an Element of the Bulk Electric System or Facility of the Bulk Electric System.” The
SDT has changed the language in COM-003-1 concerning protocols to the same
language contained in COM-002-3, R2 and R3 to be consistent and to reduce
confusion.
The proposals expand the scope of the SAR by ignoring communications protocols
used during emergencies and focusing on procedures imposed on personnel during
normal situations. This standard overreaches into routine operations by requiring
three-part communication for all instructions that change or maintain the state,
status, output, or input of an Element or Facility of the Bulk Electric System. Because
of the real-time frequency of use these instructions, requiring operating personnel to
apply a three-part communication procedure for these instructions is unnecessary
and can in fact adversely affect reliability. Any requirement for three-part
communication for routine operating instructions should be removed.
Response: The purpose of the SAR for this project is “Require that real time system
operators use standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response
time.” Additionally, the SAR is very specific in that it also includes the term
“normal” operating conditions under Applicability: “Clear and mutually established
communications protocols used during real time operations under normal and
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emergency conditions ensure universal understanding of terms and reduce errors.”
During its discussion of the approval of the Interpretation of COM-002-2 R2, the
NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Response: Thank you for your comments. Please see the responses above.
Detroit Edison
There is a significant amount of redundancy between COM-002-3 and COM-003-1.
These two standards should be combined and one of them eliminated. COM-002
purpose states "To ensure communications by operating personnel are effective."
COM-003 could be sub-requirements under R2 of COM-002.The blue box on page 2
does not clarify Reliability Directives. Suggest using the same language as the
proposed definition of Reliability Directive from COM-002-3.
Response: The SDT appreciates your comments. COM-003-1, R1 applies to all communications that involve a “command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System.” The purpose of the SAR for this project is “Require that real time system operators use standardized
communication protocols during normal and emergency operations to improve situational awareness and shorten response time.”
This is a broader scope than that for Project 2006-06.
The blue text box and the exclusionary language regarding Reliability Directives in COM-003-1, R2 and R3 were added to address
concerns over potential double jeopardy. The text box has been removed from this draft of COM-003-1.
NIPSCO
There was a COM-002 NOP issued in January 2011, a COM-002 interpretation
recently approved by NERC, and presently there is a draft of both a COM-002 and a
COM-003 out for vote. These projects appear to address 3 part communication
requirements in a non-consistent manner. Why not combine these efforts into a
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single project that the industry can review and understand? The VRF/VSL difference
between routine and emergency does not warrant having two standards.
A suggested plan of attack could be to withdraw the NERC approved COM-002
interpretation from FERC and combine the COM002-COM003 drafting efforts into
one project resulting in a new version of COM-002; we already have enough
standards. The content of the two new drafts is good, the webinar was informative,
and the work of the SDTs is appreciated.
Response: Thank you for your comments and your support. The SDT has changed the language to the same language contained in
COM-002-3, R2 and R3 to be consistent and to reduce confusion.
Public Service Enterprise
Group
This standard (COM-003-1) should be combined with COM-002-3 and issued as one
standard to require ONE 3-part communications protocol for both Reliability
Directives and non-Reliability Directives. Both require 3-part communications;
however, COM-003-1 sets ADDITIONAL communications protocols and introduces a
new definition (Operating Communication) that is not contained in COM-002-3. In
addition, the text box on page 2 appears to redefine “Reliability Directive”
inappropriately. While the sentence confusion is the text box may be unintended, its
needs to be clarified.
Response: Thank you for your comments. The SDT has changed the language to the same language contained in COM-002-3, R2
and R3 to be consistent and to reduce confusion. The blue text box and the exclusionary language regarding Reliability Directives
in COM-003-1, R2 and R3 were added to address concerns over potential double jeopardy. The text box has been removed from
this draft of COM-003-1.
Avista
This standard as drafted is very prescriptive and will not ensure improved reliability.
A better approach would be to require applicable entities to; develop and implement
an internal communication plan that takes into consideration recommendations
discussed in the proposed NERC OC System Operator Verbal Communications
Guideline, implement internal controls and monitoring to ensure adherence to the
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communication plan, and implement an adequate communication training program.
Response: The SDT appreciates your comments. The SDT has developed a new approach to the standard that adopts many of your
suggestions.
Kansas City Power & Light
This standard needs to be written such that it allows for entity flexibility. Many
entities already have COM protocols that are used. To prove compliance in an audit,
entities will we need to provide 3 years worth of voice recordings to the auditors? It
would take a full-time position to review the daily voice recordings for submission
and what value does this add to the reliability or security of the BES. This standard is
“overkill” from what is existing standard already dictates. Overall - this standard is
going to cost the registered entities way more than the realized benefits.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
The United illuminating
Company
UI disagrees with the necessity for this Standard. The intent of Recommendation 26
was to improve the communications around situational awareness. The SAR states
the purpose is to “efficiently convey and mutually understood for all operating
conditions.” This Draft does not address the concern and a Reliability Standard will
not resolve the problem. It will create a compliance burden.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT has developed a new approach to the standard and believes that it may
address your concern.
The White Paper does not provide justification for imposing a compliance burden of
recording, reviewing and tagging every conversation in a control center for the
applicability of COM-003. There is no correlation between non-emergency
communication and BES reliability.
Response: The OPCPSDT White Paper does provide ample justification for
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establishing a higher level of communication discipline in an industry that serves
one of the most critical needs in North America. The SDT believes the correlation
between any operating communication and BES reliability is high.
There is no study to demonstrate that the cause of awkwardness when transitioning
from non-emergency to emergency communication will be resolved by any of the
requirements in this Standard. Awkwardness has been resolved by Com-002
Requirement to explicitly identify an action as a Directive.
Response: The Blackout Report provides instances where the reaction of operators
is described as confused and the communications are cited as unprofessional,
contributing to the lack of situational awareness.
Response: Response: Thank you for your comments. Please see the responses above.
Wisconsin Electric dba We
Energies
We agree that accurate communication is necessary and we must strive to eliminate
mistakes due to miscommunications.
In the White Paper, other industries are cited that use three-part communication.
Which of these industries also imposes sanctions and penalties on a company if an
operator says “for” instead of “fow-er”?
Response: The SDT responded to this in the previous draft 1 and also made
provisions in draft 2 to allow for the use of alpha-numeric identifiers in lieu of the
strict NATO Alphabet.
In order to verify compliance with this standard, there will be entities that will need
to listen to thousands of hours of voice recordings (8760 hours in a year, and multiple
operators). Listening to 10% of the voice recordings will be a full time job for one or
more persons.
What is the reliability benefit of this cost? Unless it is tempered with some
reasonableness, this standard as written will be detrimental to reliability because it
will slow down communications considerably with innumerable repeats because of
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fear of violating the standard.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Response: Thank you for your comments. Please see the responses above.
ISO New England Inc
We agree with, support and have signed onto the ISO/RTO Standards Review
Committee comments. Lastly, we do not believe this rises to the level of a Standard.
Response: Thank you for your comments. Please see the responses to the ISO/RTO Standards Review Committee comments
Duke Energy
We believe that having effective communications is an important goal; and there are
instances where the use of 3-part communication is appropriate. We also believe
that the industry is maturing, and the use of 3-part communication as a tool to
achieve effective communication has grown (as evidenced by Table 1-A in the May
2012 COM-003-1 Whitepaper.
This maturity and expanded use of 3-part communication has occurred without a
Standard in place; and that we do not believe a Standard is needed that focuses on
one way of establishing effective communication.
Response: Thank you for your comments. The SDT has modified its approach into a standard that focuses on an entity’s
communication protocols and the controls they have in place to evaluate and minimize deficiencies.
Ameren
We believe that multiple communication standards (COM-002, COM-003) are not
necessary and suggest that SDT work with the NERC Operating Committee members
to appropriately address what requirements are necessary from operating/reliability
perspective as well as any related FERC directives.
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Response: Thank you for your comments. Please refer to the response to the NERC Operating Committee comments.
SPP Standards Review Group
We believe the standard is too prescriptive as written. The purpose of the standard is
to ensure effective communications. The standard has given us a very specific listing
of items that must be done in a specific manner in order to accomplish this goal.
What the industry needs is flexibility in how it achieves the goal of effective
communications. The standard does not recognize that flexibility.
The Measures for Requirements 1, 2 and 3 do not contain specific references to the
requirements they are associated with. There is a parenthetical following the
measure that does include that reference but including the reference specifically in
the measure is a stronger statement and eliminates any possibility for confusion.
The section of M1 to be modified would then read:’...that the communication
protocols specified by Requirement 1 were implemented...’
The section of M2 to be modified would then read:’...that the communication
protocol specified by Requirement 2 was implemented.’
The section of M3 to be modified would then read:’...that the communication
protocol specified by Requirement 3 was implemented.’
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Flathead Electric Cooperative,
Inc.
We believe there should be a distinction in the “Applicability” section of the standard
between “Scheduling Distribution Provider” and “Non-scheduling Distribution
Provider”. Many small WECC entities re small rural cooperatives and PUDs are Full
service customers. This means that the TO/TOP is the power supplier and scheduling
agent and therefore handles all reliability directives, scheduling, tagging, dispatching
of resources and curtailments of load from breakers on the BES system. According to
a letter from the WECC Reliability Coordinator (VRCC and LRCC) none of the smaller
entities in the Pacific Northwest will ever receive a “Reliability Directive” directly
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from teh RC. Such a Directive would be sent to either a Balancing Authority (BA), or a
Transmission Operator (TOP). We estimate there are over 100 entities that are BPA
Full Service customers that are in a similar position and making this standard
applicable to them does nothing to enhance reliability. A simple declarative
statement in the Applicability section of the standard could focus the intent of the
SDT on those entities that need it while lessening the compliance risk and clerical
burden for other entities that the standard should not apply to.
We suggest:
4. Applicability:
4.1. Functional Entities
4.1.1 Reliability Coordinator
4.1.2 Transmission Operator
4.1.3 Balancing Authority
4.1.4 Generator Operator
4.1.5 Distribution Provider: With Real-time Operations and Scheduling desk
We believe the above change will lessen the compliance burden on small, nonscheduling entities while still meeting the SDT’s intent with regard to Operating
Personnel Communications. We also note that FERC and NERC, on multiple occasions
and in multiple filings, have indicated their openness to lessening unnecessary
compliance requirements for small entities.
Response: Thank you for your comments. The SDT notes that COM-002-3, draft 6 states that in addition to Reliability
Coordinators, Balancing Authorities and Transmission Operators can also issue Reliability Directives. Draft 3 of COM-003-1 also
limits protocols for Distribution Providers to those that apply to receiving Operating Instructions.
Consumers Energy
We believe this standard attempts to redefine “Reliability Directive” and should not
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do so. Specifics of communication for this standard should be centered on emergency
operations and not a blanket protocol for almost all operations communications.
Response: The SDT appreciates your comments. The OPCPSDT did not redefine the term Reliability Directive. The SDT supports the
term. The SDT believes the two standards will work together to improve reliability and desires to demonstrate that to industry
stakeholders. During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated in its approval
the expedited development of a comprehensive communications program, which would address necessary communication
protocols for use in the operation of the Bulk Electric System.
GP Strategies
We disagree that all DP’s should be subject to this Standard. For many small entities,
it is the TOP who will control the equipment to shed load. These DP’s do not operate
a 24x7 control center for receiving such instructions. During non-business hours calls
are forwarded to an answering service or an on-call technician.
We recommend the drafting team modify the applicability as follows:
Applicability:
4.1. Functional Entities
4.1.1 Reliability Coordinator
4.1.2 Transmission Operator
4.1.3 Balancing Authority
4.1.4 Generator Operator
4.1.5 Distribution Provider who is the 24 x 7 entity that operates their load shedding
equipment when instructed by the RC, TOP, or BA.
The TOP should be the responsible entity unless the Distribution Provider has agreed
on the responsibility for taking the action.
Response: Thank you for your comments. The SDT notes that COM-002-3, draft 6 states that in addition to Reliability
Coordinators, Balancing Authorities and Transmission Operators can also issue Reliability Directives. Draft 3 of COM-003-1 also
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Organization
Yes or No
Question 10 Comment
limits protocols for Distribution Providers to those that apply to receiving Operating Instructions.
We support the need to strive for good communications among users, owners, and
operators of the grid, but believe the standard, as drafted is misdirected. Review of
research done by Electrical Power Research Institute (EPRI) and others show that
dispatcher communications cause approximately 1-2% of human failure impacting the
Bulk Power System (BPS) and less than 1% of all BPS failures.
MISO
Response: The SDT has read the study and believes it supports the need for COM003-1.
“As to communications problems causing trouble, an EPRI study2 reviewed nearly
400 switching mishaps by electric utilities and found that roughly 19% of errors
(generally classified as loss of load, breach of safety, or equipment damage) were due
to communication failures. This was nearly identical to another study of dispatchers
from 18 utilities representing nearly 2000 years of operating experience that found
that 18% of the operators’ errors were due to communication problems. 3 “
We believe the more relevant and significant conclusion to be that, of 400 switching
mishaps, 19% were caused communication failures.
As drafted, this standard can actually impede reliability as there are at times better
ways to communicate when group action is needed and there are times when speed or
“give and take” are needed.
More specifically, the proposed Reliability Standard clearly and significantly expands
the requirement to utilize 3-way communication, to the obvious detriment of
reliability. The definition of Operating Communication results in the applicability of 32
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
3
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
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Organization
Yes or No
Question 10 Comment
way communication to non-requests / non-directives. As a result, COM-003-1 would
result in the additional expenditure of time and resources to ensure that 3-way
communication is utilized even when an entity is maintaining the status quo. This
expenditure may divert time and attention away from ensuring that changes necessary
for reliability are properly understood and implemented.
Response: The SDT has modified definition of Operating Communication (now
Operating Instruction) to be a “command from a System Operator to change or
preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System.”
The standard also fails to acknowledge that Supervisory Control and Data Acquisition
(SCADA) and other forms of data exchange also can form part of the feedback process
in communications. For example, observation of Area Control Error (ACE) recovery and
generation movement during a Disturbance Control Standard (DCS) event are better
confirmation that the message was received and understood than just parroting back a
phone call.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. COM003-1 concerns human to human communications.
Therefore, MISO cannot at this time support the current version of COM-003-1.
Response: Thank you for your comments. Please see the responses above.
American Transmission
Company, LLC
When a situation necessitating alpha-numeric clarifiers in an Operational
Communication arises, per the standard requirement, it becomes mandatory. There
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Yes or No
Question 10 Comment
are many instances when marginally defined elements such as a carrier grounding
switch, may need to be operated or changed state. If these devices can’t be clearly
defined as an element or facility, yet have alpha-numeric identifiers, the use of
clarifiers should be discretionary.
Response: The SDT’s intent is to focus on those BES Elements or BES Facilities that
are capable of changing the operating state of the BES.
FERC Orders and recommendations point to “Tightening communications protocols,
especially for communications during alerts and emergencies.” The NERC standards
addressing this issue are not approved yet. When they are approved by FERC,
subsequently implemented, and allowed to mature, the concept of tighter protocols
for normal operations may be developed.
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System.
Response: Thank you for your comments. Please see our responses above.
SERC OC Standards Review
Group
Where is the demonstrated need for such a Standard? Has communications,
especially during periods of normal operations, been shown to be the root cause of
many, if any, events?
Response: From a recently published paper “Estimating the Magnitude of the
Operator Communications Problem” by Terry Bilke, the following excerpt points out
the results of an EPRI study.
“As to communications problems causing trouble, an EPRI study4 reviewed nearly
400 switching mishaps by electric utilities and found that roughly 19% of errors
4
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
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Yes or No
Question 10 Comment
(generally classified as loss of load, breach of safety, or equipment damage) were
due to communication failures.
We believe the more relevant and significant conclusion to be that, of 400
switching mishaps, 19% were caused communication failures.
While there is easy agreement for the need of clear and concise communication
between entities, we must avoid creating a system that is unmanageable and quite
possibly results in less reliability. FERC Order 693 directs the ERO to ‘‘and (3) requires
tightened communications protocols, especially for communications during alerts
and emergencies.” in paragraph 532.
The proposed standard goes too far, especially for communications outside of alerts
and emergencies. NERC standards are not procedures and this standard attempts to
impose a single procedure on the industry. SERC suggests another approach to COM003. Rather than to specify the solutions to achieving effective communication,
COM-003 should instead focus on developing and training on an approach that is
designed appropriately for each RE.
For instance, another approach to COM-003 might be along the lines of:
Requirement 1 could be written in a manner to require the appropriate registered
entities to develop a communication protocol that is appropriate for each RE.
This communications protocol should address how the RE is handling the following:
Time Zone Designations - for both internal and external communications language
comm
Alpha-numeric identifiers
Three - part communications - when is it required, etc.
Use of defined terminology
Institute.
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Yes or No
Question 10 Comment
Other items deemed important for the communications protocol to address again, this would not define HOW these items are addressed This approach would
require the RE to address how it is addressing these issues, without prescribing
solutions. For instance, a RE could include in its protocol a section dealing with time
zone designation. In this section the RE could explain that it, and its neighbors, all are
in and use the same time zone. As a result, the RE has determined that requiring the
identification of time zone reference in communication is not necessary Procedures
should address the training of operators on the communication protocol
Procedures should address the internal controls that the RE uses to review that its
protocol is being followed.
The compliance approach would be to:
Assess whether the RE has developed a written protocol and whether the protocol
addresses each item - this does not mean there is an assessment of HOW each item is
assessed; assess whether the RE has trained its operators on the communications
protocol and assess whether the RE is following its internal controls.
Response: The SDT has developed a new approach to the standard that addresses
your concern.
Any data retention requirements should be consistent with the COM-002 reliability
standard.
Response: The data retention requirements have been modified based on the new
approach.
What is the role of the Operating Communications Protocols White paper? Is it a
position of the STD? If not, was there a minority opinion? Will it be part of the
standard?
Response: The leadership of the Standards Committee asked the OPCPSDT to
develop the White Paper as a means of explaining the rationale for the team’s
decisions. The team reached consensus on content based on deep and thoughtful
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Yes or No
Question 10 Comment
discussion. It will not be part of the standard, nor is it referenced by the standard.
Does the industry agree that we need a standard on three part communications for
normal operations? Yes or No?
Response: During its discussion of the approval of the Interpretation of COM-002-2
R2, the NERC BOT stipulated in its approval the expedited development of a
comprehensive communications program, which would address necessary
communication protocols for use in the operation of the Bulk Electric System. The
SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in
addressing the BOT’s concern.
Has a lack of a standard on three part communications for normal operations created
any reliability issues? If so, what are they?
Response: In the paper cited in our response above, 19% of errors (generally
classified as loss of load, breach of safety, or equipment damage) were due to
communication failures. Three part communication is one essential step in
addressing this reliability issue.
“The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review group only and should not be
construed as the position of SERC Reliability Corporation, its board or its officers.”
Response: Thank you for your comments. Please see the responses above.
Seminole Electric Cooperative
While we absolutely support the promotion and use of 3-part oral communication
protocol and the other features identified, the failure of individual persons to use
"proper" and "correct" oral operational communications should NOT constitute a
Standard violation. It is reasonable to require the responsible entity to have written
procedures requiring such use; to have evidence of applicable personnel training on
such; and to have a program for internal monitoring and enforcement of such. As
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Yes or No
Question 10 Comment
written, a subjective review of many oral operational communications will arguably
be identified by Compliance Auditors as medium, high or even severe levels.
Response: Thank you for your comments. The SDT has developed a new approach to the standard that addresses your concern.
Liberty Electric Power LLC
Yes. The regulation of market communications between entities is not the proper
subject for NERC standards. The STD proposes placing entities into the realm of zero
tolerance for thousands of routine communications. This assures failure. Further, this
will force entities to reallocate precious resources away from more critical reliability
functions to assure compliance and allow for self-certification. As such, the proposed
standard weakens the reliability of the BES. The proposed standard should be
withdrawn and the SAR closed.
Response: Thank you for your comments. Draft 3 of the standard does not include market communications. The SDT has
developed a new approach to the standard that addresses your concern about the number of communications.
City of Vero Beach
NONE
City of Jacksonville Beach
dba/Beaches Energy Services
None.
END OF REPORT
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot closed
June 20 2012.
Description of Current Draft:
This is the third draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
July 2012
2. Second Ballot of Standards.
August 2012
3. Successive Ballot of Standards
September 2012
4. Recirculation ballot of standards.
October 2012
5. Board adopts standards.
November 2012
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —Command from a System Operator to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System.
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A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operators uniform communications protocols that
reduce the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
have documented communication protocols for Operating Instructions that incorporate
the following: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning ]
1.1. Use of the English language when issuing an oral or written Operating Instruction
between functional entities, unless another language is mandated by law or
regulation. Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
1.2. Use of the 24-hour clock format when referring to clock times when issuing an
oral or written Operating Instruction.
1.3. When issuing an oral or written Operating Instruction between functional entities
in different time zones, when referring to clock times include the time, the time
zone where the action will occur and indicate whether the time is daylight saving
time or standard time.
1.4. When referring to a Transmission interface Element or a Transmission interface
Facility in an oral or written Operating Instruction between functional entities, use
the name specified by the owner(s) for that Transmission interface Element or
Transmission interface Facility unless another name is mutually agreed to by the
functional entities.
1.5. Use of alpha-numeric clarifiers when issuing an oral Operating Instruction for
Facilities and Elements in instances where the nomenclature of Facilities or
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Elements is in alpha-numeric format (e.g. if an entity designated a circuit breaker
“12B” 12B would need alpha-numeric clarifiers if used in an oral Operating
Instruction)
1.6. When issuing an oral two party, person-to-person Operating Instruction, require
the issuer to:
•
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
•
Reissue the Operating Instruction to resolve a misunderstanding.
1.7. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
1.8. When issuing an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), verbally or electronically confirm receipt from one
or more receiving parties.
1.9. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
R2. Each Distribution Provider and Generator Operator shall have documented
communication protocols for Operating Instructions that incorporate the following:
[Violation Risk Factor: Low] [Time Horizon: Long-term Planning ]
2.1. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
2.2. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
R3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement a process for identifying deficiencies with adherence to the documented
communication protocols specified in Requirement R1 that: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning ]
3.1. Identifies potential deficiencies,
3.2. Assesses the deficiencies found,
3.3. Corrects the deficiencies, and
3.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
•
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implements modifications to the process when the evaluation
determines that modification of the process is necessary to
address the deficiencies found; or
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•
demonstrates that no modification to the process is necessary to
address the deficiencies.
R4. Each Distribution Provider and Generator Operator shall implement a process for
identifying deficiencies with adherence to the documented communication protocols
specified in Requirement R2 that: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning ]
4.1. Identifies potential deficiencies,
4.2. Assesses the deficiencies found,
4.3. Corrects the deficiencies, and
4.4. Evaluates the process based on deficiencies found external to Part 4.1 and either
•
implements modifications to the process when the evaluation
determines that modification of the process is necessary to
address the deficiencies found; or
•
demonstrates that no modification to the process is necessary to
address the deficiencies.
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator, shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R2.
M3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide the results of its process developed for Requirement R3.
M4. Each Distribution Provider and Generator Operator shall provide the results of its
process developed for Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional Entity.
In such cases the ERO or a Regional Entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
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provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R3 Measure M3 for the most
recent 90 days.
Each Distribution Provider and Generator Operator shall retain evidence for
Requirement R4 Measure M4 for the most recent 90 days.
If a Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
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R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long Term
Planning
Low
The responsible entity did
not include one (1) of the
nine (9) parts of
Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
Moderate VSL
High VSL
Severe VSL
The responsible entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
The responsible entity
did not include three
(3) of the nine (9)
parts of Requirement
R1, Parts 1.1 to 1.9 in
their documented
communication
protocols
The responsible entity did
not include four (4) or more
of the nine (9) parts of
Requirement R1, Parts 1.1 to
1.9 in their documented
communication protocols
OR
The responsible entity did
not have documented
communication protocols as
required in Requirement R1.
R2
Long Term
Planning
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Low
N/A
N/A
The responsible entity
did not include one (1)
of the two (2) parts of
Requirement R2, Parts
2.1 to 2.2 in their
documented
communication
protocols
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The responsible entity did
not include Parts 2.1 to 2.3
(3) of Requirement R2, in
their documented
communication protocols
OR
The responsible entity did
not have documented
communication protocols as
required in Requirement R2.
COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R3
Operations
Planning
Medium
N/A
N/A
N/A
The Responsible Entity does
not have a process for
identifying deficiencies with
adherence to the
documented communication
protocols specified in
Requirement R1;
Or
The Responsible Entity did
not evaluate their process
based on deficiencies found
external to Part 3.1 to
determine whether
modification of the process
is necessary;
Or
The Responsible Entity did
not implement modifications
to the process when the
evaluation determined that
modification of the process
was necessary to address the
deficiencies found;
Or
The Responsible Entity did
not demonstrate that no
modification to the process
was necessary to address the
deficiencies found external
to Part 3.1.
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R4
Operations
Planning
Medium
N/A
N/A
N/A
The Responsible Entity does
not have a process for
identifying deficiencies with
adherence to the
documented communication
protocols specified in
Requirement R2;
Or
The Responsible Entity did
not evaluate their process
based on deficiencies found
external to Part 4.1 to
determine whether
modification of the process
is necessary;
Or
The Responsible Entity did
not implement modifications
to the process when the
evaluation determined that
modification of the process
was necessary to address the
deficiencies found;
Or
The Responsible Entity did
not demonstrate that no
modification to the process
was necessary to address the
deficiencies found external
to Part 4.1.
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E. Regional Variances
None.
Version History
Version
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Date
Action
Change Tracking
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction — Command from a System Operator to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the
Bulk Electric System.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and
Balancing Authorities may use an alternate
language for internal operations
COM-003-1 Requirement R1 Part 1.1
R1.
Each Balancing Authority, Distribution
Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall
have documented communications protocols
that incorporate the following:
1.1. Use of the English language when
issuing an oral or written Operating
Instruction between functional entities,
unless another language is mandated
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
by law or regulation. Transmission
Operators and Balancing Authorities
may use an alternate language for
internal operations.
Conform ing Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, 12 calendar months following
applicable regulatory approval; or, in those jurisdictions where no regulatory approval is required, the
first day of the first calendar quarter 12 calendar months from the date of Board of Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-001-2 in the particular Jurisdiction in which COM-001-2 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Communication Instruction — Communication of instructionCommand from a System
Operator to change or maintain preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of the Bulk Electric
System.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and
Balancing Authority shall use English as the
language for all communications between and
among operating personnel responsible for the
real-time generation control and operation of
the interconnected Bulk Electric System.
Transmission Operators and Balancing
Authorities may use an alternate language for
COM-003-1 Requirement R1 Part 1.1.1
R1.
Each Balancing Authority, Distribution
Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall use
the followinghave documented communications
protocols that incorporate the following:
1.1. Use of the English language when issuing
an oral or written Operating Instruction
between functional entities, unless another
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
internal operations
language is mandated by law or regulation.
Transmission Operators and Balancing
Authorities may use an alternate language
for internal operations.When participating
in verbal or written Operating
Communications:
1.1.1.
Use the English language when
communicating between functional
entities, unless another language is
mandated by law or regulation.
Conform ing Changes to Other Standards
None
Effective Dates
COM-001-2 and COM-003-1 shall become effective the first day of first calendar quarter, six twelve12
calendar months following applicable regulatory approval; or, in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter twelve12 calendar months a year from
the date of Board of Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-001-2 in the particular Jurisdiction in which COM-001-2 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Operating Personnel Communications Protocols
Project 2007-02
Unofficial Comment Form for Standard COM-003-1 —Operating Personnel
Communications Protocols
Please DO NOT use this form. Please use the electronic comment form located at the link below to
submit comments on the proposed draft COM-003-1 Operating Personnel Communications
Protocols standard. Comments must be submitted by September 20, 2012. If you have
questions please contact Joseph Krisiak at [email protected] or by telephone at 609-6510903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information
Effective communication is critical for real-time operations. Failure to successfully communicate
clearly can create misunderstandings resulting in improper operations increasing the potential for
failure of the BES.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and
approved by the Standards Committee on June 8, 2007. It established the scope of work to be
done for Project 2007-02 Operating Personnel Communications Protocols (OPCP SDT). The scope
described in the SAR is to establish essential elements of communications protocols and
communications paths, such that operators and users of the North American Bulk Electric System
will efficiently convey information and ensure mutual understanding. The August 2003 Blackout
Report, Recommendation Number 26, calls for a tightening of communications protocols. FERC
Order 693 paragraph 532 amplifies this need and applies it to all Operating Instructions. This
proposed standard’s goal is to ensure that effective communication is practiced and delivered in
clear language and standardized format via pre-established communications paths among preidentified operating entities.
The SAR indicated that references to communication protocols in other NERC Reliability Standards
may be moved to this new standard. The SAR instructed the standard drafting team to consider
incorporating the use of Alert Level Guidelines and three-part communications in developing this
new standard to achieve high level consistency across regions. The SDT believes the Alert Level
Guidelines, while valuable, belong in a separate standard and has petitioned the Standards
Committee to approve the transfer to another standard or to start a separate project.
The upgrade of communication system hardware where appropriate is not included in this project
(it is included in NERC Project 2007-08 Emergency Operations).
The standard will be applicable to Transmission Operators, Transmission Owners, Balancing
Authorities, Reliability Coordinators, Generator Operators, and Distribution Providers. These
requirements ensure that communications include essential elements, such that information is
efficiently conveyed and mutually understood for communicating changes to real-time operating
conditions and responding to directives, notifications, directions, instructions, orders, or other
reliability related operating information.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
The purpose statement of COM 003-1 states: “To provide system operators uniform
communications protocols that reduce the possibility of miscommunication that could lead to action
or inaction harmful to the reliability of BES.”
1) New NERC Glossary terms: The SDT has changed the definition Operating
Communications proposed in the Standard version 2 and added Operating Instructions.
Operating Instructions more accurately define the broad class of communications that deal
with changing or altering the state of the BES. Changes to the BES operating state with
unclear communications create increased opportunities for events that could place the bulk
electric system at an unacceptable risk of instability, separation, or cascading failures.
This term is proposed for addition to the NERC Glossary to establish meaning and usage
within the electricity industry.
2) Documented Communication Protocols: The OPCP SDT has incorporated a requirement
for an applicable entity to have documented communication protocols that incorporate the
following elements:
a)
English language: Use of the English language when issuing an oral or written
Operating Instruction between functional entities, unless another language is mandated
by law or regulation. Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
b)
24-hour clock R1 Part 1.2 and time zone reference R1 Part 1.3:
Use the 24-hour clock format when referring to clock times when issuing an oral or
written Operating Instruction.
When issuing an oral or written Operating Instruction between functional entities in
different time zones, include the time, time zone and indicate whether the time is
daylight saving time or standard time. (Example: 1500 EST or Eastern Standard Time)
The OPCP SDT proposed this change to address comments by industry while adhering
to the recommendations of the August 14, 2003 task force report.
c)
Line and equipment identifiers: When referring to a Transmission interface Element
or a Transmission interface Facility in an oral or written Operating Instruction between
functional entities, use the name specified by the owner(s) for that Transmission
interface Element or Transmission interface Facility unless another name is mutually
agreed to by the functional entities.
d)
Alpha-numeric clarifiers: Use of alpha-numeric clarifiers when issuing an oral
Operating Instruction for Facilities and Elements in instances where the nomenclature
of Facilities or Elements are in alpha-numeric format (e.g. if an entity designated a
circuit breaker “12B” 12B would need alpha-numeric clarifiers if used in an oral
Operating Instruction).
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
e)
Three-part Communication:
When issuing an oral two-party, person-to-person Operating Instruction, require the
issuer to:
•
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
•
Reissue the Operating Instruction to resolve a misunderstanding.
When receiving an oral two-party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
f)
One-way burst messaging system to multiple parties (all call): When receiving an
g)
Three-part Communication: For Distribution Providers (DP) and Generator
Operators (GOP): When receiving an oral two-party, person-to-person Operating
Instruction, require the recipient to repeat, restate, rephrase, or recapitulate the
Operating Instruction.
h)
One-way burst messaging system to multiple parties (all call): For Distribution
Providers (DP) and Generator Operators (GOP): When receiving an oral Operating
Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system),
request clarification from the initiator if the communication is not understood.
oral Operating Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system), request
clarification from the initiator if the communication is not understood.
3) Implement a process for identifying deficiencies: (COM-003-1, R3 and R4) The SDT
proposes a process to identify, assess and correct deficiencies with adherence to the
documented communication protocols. The process is evaluated to determine and improve
its effectiveness. Deficiencies that are identified, assessed and corrected will not be
determined as non-compliant.
4) VSL and VRF Changes from version two: The OPCP SDT reviewed the VRFs and VSLs
associated with R1, R2, R3 and R4 and made changes to more closely conform to NERC and
FERC guidelines.
The SDT is proposing to retire Requirement R4 from COM-001 and incorporate it into
Requirement R2 of this draft COM-003-1. Since Requirement R4 from COM-001-1 carries over
essentially unchanged there is no specific question related to it in this comment form.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of a
miscommunication during Operating Instructions. Requirements R1 and R2 are assigned a Low
Violation Risk Factor due to their potential direct impact on BES reliability. Requirements R3 and R4
are assigned a Medium Violation Risk due to their potential direct impact on BES reliability.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R1 and R2 must be implemented in long term planning operations and therefore
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
were assigned a Time Horizon of Long Term Planning. Requirements R3 and R4 must be
implemented during operations planning and therefore were assigned a Time Horizon of Operations
Planning. The drafting team is posting the standard for industry comment for a 30-day comment
period.
The Operating Personnel Communications Protocols Drafting Team would like to receive industry
comments on this draft standard. Accordingly, we request that you include your comments on this
form by September 20, 2012.
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
Comment Form
*Please use the electronic comment form to submit your final comments to NERC.
1. Do you agree with the changes made to the proposed definition “Operating Instruction” (now
proposed as a “Command from a System Operator to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System?”) to be added as a term for the NERC Glossary? If not, please explain in the comment
area.
Yes
No
2. The SDT has proposed that the applicable entities have documented communication protocols
that incorporate elements listed in COM-003-1, R1 and R2. Do you agree with these proposed
requirements ? If not, please explain in the comment area.
Yes
No
3. The SDT has proposed requirements (COM-003-1, R3 and R4) for appicable entities to
implement a process to identify, assess and correct deficiencies related to the entity’s
documented communication protocols; and to evaluate that process based on deficiencies found
externally from the process. Do you agree with the proposed requirements? If not, please
explain in the comment area.
4. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4?
Yes
No
5. Do you have any other comments or suggestions to improve the draft standard?
Comments:
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Operating Personnel Communications Protocols
Project 2007-02
Unofficial Comment Form for Standard COM-003-1 —Operating Personnel
Communications Protocols
Please DO NOT use this form. Please use the electronic comment form located at the link below to
submit comments on the proposed draft COM-003-1 Operating Personnel Communications
Protocols standard. Comments must be submitted by September 20, 2012. If you have
questions please contact Joseph Krisiak at [email protected] or by telephone at 609-6510903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information
Effective communication is critical for real-time operations. Failure to successfully communicate
clearly can create misunderstandings resulting in improper operations increasing the potential for
failure of the BES.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and
approved by the Standards Committee on June 8, 2007. It established the scope of work to be
done for Project 2007-02 Operating Personnel Communications Protocols (OPCP SDT). The scope
described in the SAR is to establish essential elements of communications protocols and
communications paths, such that operators and users of the North American Bulk Electric System
will efficiently convey information and ensure mutual understanding. The August 2003 Blackout
Report, Recommendation Number 26, calls for a tightening of communications protocols. FERC
Order 693 paragraph 532 amplifies this need and applies it to all Operating Instructions. This
proposed standard’s goal is to ensure that effective communication is practiced and delivered in
clear language and standardized format via pre-established communications paths among preidentified operating entities.
The SAR indicated that references to communication protocols in other NERC Reliability Standards
may be moved to this new standard. The SAR instructed the standard drafting team to consider
incorporating the use of Alert Level Guidelines and three-part communications in developing this
new standard to achieve high level consistency across regions. The SDT believes the Alert Level
Guidelines, while valuable, belong in a separate standard and has petitioned the Standards
Committee to approve the transfer to another standard or to start a separate project.
The upgrade of communication system hardware where appropriate is not included in this project
(it is included in NERC Project 2007-08 Emergency Operations).
The standard will be applicable to Transmission Operators, Transmission Owners, Balancing
Authorities, Reliability Coordinators, Generator Operators, and Distribution Providers. These
requirements ensure that communications include essential elements, such that information is
efficiently conveyed and mutually understood for communicating changes to real-time operating
conditions and responding to directives, notifications, directions, instructions, orders, or other
reliability related operating information.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
The purpose statement of COM 003-1 states: “To provide system operators uniform
communications protocols that reduce the possibility of miscommunication that could lead to action
or inaction harmful to the reliability of BES.”
1) New NERC Glossary terms: The SDT has changed the definition Operating
Communications proposed in the Standard version 2 and added Operating Instructions.
Operating Instructions more accurately define the broad class of communications that deal
with changing or altering the state of the BES. Changes to the BES operating state with
unclear communications create increased opportunities for events that could place the bulk
electric system at an unacceptable risk of instability, separation, or cascading failures.
This term is proposed for addition to the NERC Glossary to establish meaning and usage
within the electricity industry.
2) Documented Communication Protocols: The OPCP SDT has incorporated a requirement
for an applicable entity to have documented communication protocols that incorporate the
following elements:
a)
English language: Use of the English language when issuing an oral or written
Operating Instruction between functional entities, unless another language is mandated
by law or regulation. Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
b)
24-hour clock R1 Part 1.2 and time zone reference R1 Part 1.3:
Use the 24-hour clock format when referring to clock times when issuing an oral or
written Operating Instruction.
When issuing an oral or written Operating Instruction between functional entities in
different time zones, include the time, time zone and indicate whether the time is
daylight saving time or standard time. (Example: 1500 EST or Eastern Standard Time)
The OPCP SDT proposed this change to address comments by industry while adhering
to the recommendations of the August 14, 2003 task force report.
c)
Line and equipment identifiers: When referring to a Transmission interface Element
or a Transmission interface Facility in an oral or written Operating Instruction between
functional entities, use the name specified by the owner(s) for that Transmission
interface Element or Transmission interface Facility unless another name is mutually
agreed to by the functional entities.
d)
Alpha-numeric clarifiers: Use of alpha-numeric clarifiers when issuing an oral
Operating Instruction for Facilities and Elements in instances where the nomenclature
of Facilities or Elements are in alpha-numeric format (e.g. if an entity designated a
circuit breaker “12B” 12B would need alpha-numeric clarifiers if used in an oral
Operating Instruction).
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
e)
Three-part Communication:
When issuing an oral two-party, person-to-person Operating Instruction, require the
issuer to:
•
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
•
Reissue the Operating Instruction to resolve a misunderstanding.
When receiving an oral two-party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
f)
One-way burst messaging system to multiple parties (all call): When receiving an
g)
Three-part Communication: For Distribution Providers (DP) and Generator
Operators (GOP): When receiving an oral two-party, person-to-person Operating
Instruction, require the recipient to repeat, restate, rephrase, or recapitulate the
Operating Instruction.
h)
One-way burst messaging system to multiple parties (all call): For Distribution
Providers (DP) and Generator Operators (GOP): When receiving an oral Operating
Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system),
request clarification from the initiator if the communication is not understood.
oral Operating Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system), request
clarification from the initiator if the communication is not understood.
3) Implement a process for identifying deficiencies: (COM-003-1, R3 and R4) The SDT
proposes a process to identify, assess and correct deficiencies with adherence to the
documented communication protocols. The process is evaluated to determine and improve
its effectiveness. Deficiencies that are identified, assessed and corrected will not be
determined as non-compliant.
4) VSL and VRF Changes from version two: The OPCP SDT reviewed the VRFs and VSLs
associated with R1, R2, R3 and R4 and made changes to more closely conform to NERC and
FERC guidelines.
The SDT is proposing to retire Requirement R4 from COM-001 and incorporate it into
Requirement R2 of this draft COM-003-1. Since Requirement R4 from COM-001-1 carries over
essentially unchanged there is no specific question related to it in this comment form.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of a
miscommunication during Operating Instructions. Requirements R1 and R2 are assigned a Low
Violation Risk Factor due to their potential direct impact on BES reliability. Requirements R3 and R4
are assigned a Medium Violation Risk due to their potential direct impact on BES reliability.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R1 and R2 must be implemented in long term planning operations and therefore
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
were assigned a Time Horizon of Long Term Planning. Requirements R3 and R4 must be
implemented during operations planning and therefore were assigned a Time Horizon of Operations
Planning. The drafting team is posting the standard for industry comment for a 30-day comment
period.
The Operating Personnel Communications Protocols Drafting Team would like to receive industry
comments on this draft standard. Accordingly, we request that you include your comments on this
form by September 20, 2012.
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project
2007-02.0 - Operating Personnel Coomunication Protocols
Comment Form
*Please use the electronic comment form to submit your final comments to NERC.
1. Do you agree with the changes made to the proposed definition “Operating Instruction” (now
proposed as a “Command from a System Operator to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System?”) to be added as a term for the NERC Glossary? If not, please explain in the comment
area.
Yes
No
2. The SDT has proposed that the applicable entities have documented communication protocols
that incorporate elements listed in COM-003-1, R1 and R2. Do you agree with these proposed
requirements ? If not, please explain in the comment area.
Yes
No
3. The SDT has proposed requirements (COM-003-1, R3 and R4) for appicable entities to
implement a process to identify, assess and correct deficiencies related to the entity’s
documented communication protocols; and to evaluate that process based on deficiencies found
externally from the process. Do you agree with the proposed requirements? If not, please
explain in the comment area.
4. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4?
Yes
No
5. Do you have any other comments or suggestions to improve the draft standard?
Comments:
Unofficial Comment Form – Project 2007-02 Operating Personnel Communications Protocols
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project 2007-02, COM-003-1 Operating
Personnel Communication Protocols
Rationale and Technical Justification
Justification for Requirements in Draft 4
Rationale and Technical Justification
The Quality Review team for the draft 2 posting of COM-003-1 highly recommended that the
OPCPSDT provide a justification or rationale document to aid reviewers in their examination of this
draft of COM-003-1. The OPCPSDT agrees with the QR recommendation and has developed the
following to support the standard and to help stakeholders understand the intent and scope of the
standard. This version of the standard features a non traditional approach to standards that could
alleviate concerns that surfaced in comments in drafts one, two and three.
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to
implement documented communication protocols in a manner that identifies, assesses, and
corrects deficiencies. Because Operating Instructions affect Facilities and Elements of the Bulk
Electric System, the communication of those Operating Instructions must be understood by all
involved parties, especially when those communications occur between functional entities. An
EPRI study reviewed nearly 400 switching mishaps by electric utilities and found that roughly 19%
of errors (generally classified as loss of load, breach of safety, or equipment damage) were due to
communication failures.1 This was nearly identical to another study of dispatchers from 18 utilities
representing nearly 2000 years of operating experience that found that 18% of the operators’
errors were due to communication problems. 2The necessary protocols include the use of the
1
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
2
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
English language (from COM-001-1.1 R4), time formatting, mutually agreed nomenclature for
Transmission interface Elements, alpha-numeric clarifiers, and three part communications.
Requirement R2
Requirement R2 requires entities that only receive Operating Instructions to implement documented
communication protocols in a manner that identifies, assesses, and corrects deficiencies .
The two protocols (R2 , Parts 2.1 and 2.2) required are repeat back for three part communication and
clarification if an “all call” communication is unclear.
Rationale
The SDT has incorporated within this standard a recognition that these requirements should not focus
on individual instances of failure as a basis for violating the standard. In particular, the SDT has
incorporated an approach to empower and enable the industry to identify, assess, and correct
deficiencies in the implementation of certain requirements. The intent is to change the basis of a
violation in those requirements so that they are not focused on whether there is a deficiency, but on
identifying, assessing, and correcting deficiencies. It is presented in those requirements by modifying
“implement” as follows:
Each … shall implement, in a manner that identifies, assesses, and corrects deficiencies, . . .
The term documented communication protocols refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. This term does not imply any
particular naming or approval structure beyond what is stated in the requirements. An entity should
include as much as it believes necessary in their documented protocols, but they must address all of the
applicable parts of the Requirement. The documented protocols themselves are not required to include
the “. . . identifies, assesses, and corrects deficiencies, . . ." elements described in the preceding
paragraph, as those aspects are related to the manner of implementation of the documented protocols
and could be accomplished through other controls or compliance management activities.
Project 2007-02 Operating Personnel Communications Protocols (COM-003-1) | Rationale and Technical Justification
2
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1, R4 – Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1
Each Balancing Authority, Distribution Provider,
Generator Operator, Reliability Coordinator, and
Transmission Operator shall have documented
communications protocols that incorporate the
following:
1.1.
Use of the English language when issuing an
oral or written Operating Instruction
between functional entities, unless another
language is mandated by law or regulation.
Transmission Operators and Balancing
Authorities may use an alternate language
for internal operations.
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1.1
Comments
R1
Each Balancing Authority, Distribution Provider,
Generator Operator, Reliability Coordinator,
Transmission Operator, and Transmission Owner
shall have documented use the following
communications protocols that incorporate the
following: [Violation Risk Factor: MediumLow]
[Time Horizon: Real-time OperationsLong-term
Planning ]
1.1.
Use of the English language when issuing an
oral or written Operating Instruction
between functional entities, unless another
language is mandated by law or regulation.
Transmission Operators and Balancing
Project 2007-02 - Operating Personnel
Protocols
Communications Protocols
Requirement in Approved Standard
: Operating Personnel Communication
Translation to
New Standard or
Other Action
Comments
Authorities may use an alternate language
for internal operationsWhen participating
in oral or written Operating
Communications:
1.1.1 Use the English language when
communicating between functional
entities, unless another language is
mandated by law or regulation.
Mapping Document
2
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
2
Project YYYY-##.# - Project Name
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
3
Project YYYY-##.# - Project Name
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
4
Project YYYY-##.# - Project Name
VRF for COM-003-1:
There are three requirements in COM-003-1. Requirements R1, R2 and R3 were assigned a “Medium” VRF.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
5
Project YYYY-##.# - Project Name
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
6
Project YYYY-##.# - Project Name
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal,
or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system The VRF for this requirement is “Low” which is consistent
with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Low” which is
consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the establishment of communication protocols that reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
separation, or cascading failures. The VRF for this requirement is “Low” which is consistent with NERC
guidelines
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The responsible entity did not
include one (1) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
Moderate
The responsible entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
High
The responsible entity did not
include three (3) of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
Severe
The responsible entity did not
include four (4) or more of the
nine (9) parts of Requirement R1,
Parts 1.1 to 1.9 in their
documented communication
protocols
OR
The responsible entity did not
have documented communication
protocols as required in
Requirement R1.
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Low
NERC VRF Discussion
R2 is a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal,
or restorative conditions anticipated by the preparations, be expected to adversely affect the electrical
state or capability of the bulk electric system The VRF for this requirement is “Low” which is consistent
with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Low” which is
consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the establishment of communication protocols that reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Low” which is consistent with NERC
guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Proposed VSL
Lower
N/A
Moderate
N/A
High
The responsible entity did not
include one (1) of the two (2) parts
of Requirement R2, Parts 2.1 to 2.2
in their documented
communication protocols
Severe
The responsible entity did not
include Parts 2.1 to 2.3 (3) of
Requirement R2, in their
documented communication
protocols
OR
The responsible entity did not
have documented communication
protocols as required in
Requirement R2.
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
14
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Medium
NERC VRF Discussion
R3 is a requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for use of formal three part communication, among other communication
protocols. This requirement is analogous to R2 of COM-002-2, which describes a communication protocol
required for operating personnel to use when given a directive. The VRF for this requirement (COM-0022, R2) is “Medium” which is consistent with COM-003-1 R3 at a “Medium”. The SDT considers “Medium”
as the proper assignment because it is consistent with NERC and FERC guidelines.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of the requirement is unlikely to lead to bulk electric system instability, separation, or
cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to implement a process for identifying
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
deficiencies with adherence to the documented communication protocols. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Responsible Entity does not
have a process for identifying
deficiencies with adherence to the
documented communication
protocols specified in Requirement
R1;
Or
The Responsible Entity did not
evaluate their process based on
deficiencies found external to Part
3.1 to determine whether
modification of the process is
necessary;
Or
The Responsible Entity did not
implement modifications to the
process when the evaluation
16
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
determined that modification of
the process was necessary to
address the deficiencies found;
Or
The Responsible Entity did not
demonstrate that no modification
to the process was necessary to
address the deficiencies found
external to Part 3.1.
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Since R3 represents a new approach that does not currently exist, the VSL does not lower the current level
of compliance.
Guideline 2a:
The VSL assignment for R3 is binary and Severe.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
19
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for use of formal three part communication, among other communication
protocols. This requirement is analogous to R2 of COM-002-2, which describes a communication protocol
required for operating personnel to use when given a directive. The VRF for this requirement (COM-0022, R2) is “Medium” which is consistent with COM-003-1 R4 at a “Medium”. The SDT considers “Medium”
as the proper assignment because it is consistent with NERC and FERC guidelines.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of the requirement is unlikely to lead to bulk electric system instability, separation, or
cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R4 contains only one objective which is to implement a process for identifying
20
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
deficiencies with adherence to the documented communication protocols. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Responsible Entity does not
have a process for identifying
deficiencies with adherence to the
documented communication
protocols specified in Requirement
R2;
Or
The Responsible Entity did not
evaluate their process based on
deficiencies found external to Part
4.1 to determine whether
modification of the process is
necessary;
Or
The Responsible Entity did not
implement modifications to the
process when the evaluation
21
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
determined that modification of
the process was necessary to
address the deficiencies found;
Or
The Responsible Entity did not
demonstrate that no modification
to the process was necessary to
address the deficiencies found
external to Part 4.1.
22
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Since R4 represents a new approach that does not currently exist, the VSL does not lower the current level
of compliance.
Guideline 2a:
The VSL assignment for R4 is binary and Severe.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
23
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
24
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard COM-001-2 — Telecommunications
A. Introduction
Requirement R4 was assigned to
Project 2007-02. All other
requirements were assigned to Project
2006-06 and are being revised or
retired under Project 2006-06.
1.
Title:
Telecommunications
2.
Number:
COM-001-2
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
(Proposed) Effective Date: First day of the first calendar quarter, six calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter a year from the date of Board of
Trustee adoption.
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have
written operating instructions and procedures to enable continued operation of the system
during the loss of telecommunications facilities.
R5.
Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM001, “NERCNet Security Policy.”
C. Measures
Page 1 of 5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standard COM-001-2 — Telecommunications
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy, that will be used to confirm that it meets Requirement 4.
M3. The NERCnet User Organization shall have and provide upon request evidence that could
include, but is not limited to, documented procedures, operator logs, voice recordings or
transcripts of voice recordings, electronic communications, etc., that will be used to determine
if it adhered to the (User Accountability and Compliance) requirements in Attachment 1-COM001. (Requirement 5)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 4.
For Measure 3, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
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Standard COM-001-2 — Telecommunications
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance for every one of the following
requirements that is in violation:
2.3.1
There are no written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunication facilities, as
specified in R4.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed, as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
Page 3 of 5
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Standard COM-001-2 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Page 4 of 5
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Standard COM-001-2 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
Page 5 of 5
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Standard COM-001-1.12 — Telecommunications
A. Introduction
Requirement R4 was assigned to
Project 2007-02. All other
requirements were assigned to Project
2006-06 and are being revised or
retired under Project 2006-06.
1.
Title:
Telecommunications
2.
Number:
COM-001-1.12
3.
Purpose:
Each Reliability Coordinator, Transmission Operator and Balancing Authority
needs adequate and reliable telecommunications facilities internally and with others for the
exchange of Interconnection and operating information necessary to maintain reliability.
4.
Applicability
4.1. Transmission Operators.
4.2. Balancing Authorities.
4.3. Reliability Coordinators.
4.4. NERCNet User Organizations.
5.
(Proposed) Effective Date: First day of the first calendar quarter, six calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter a year from the date of Board of
Trustee adoption.May 13, 2009
B. Requirements
R1.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide
adequate and reliable telecommunications facilities for the exchange of Interconnection and
operating information:
R1.1.
Internally.
R1.2.
Between the Reliability Coordinator and its Transmission Operators and Balancing
Authorities.
R1.3.
With other Reliability Coordinators, Transmission Operators, and Balancing
Authorities as necessary to maintain reliability.
R1.4.
Where applicable, these facilities shall be redundant and diversely routed.
R2.
Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage,
alarm, test and/or actively monitor vital telecommunications facilities. Special attention shall
be given to emergency telecommunications facilities and equipment not used for routine
communications.
R3.
Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a
means to coordinate telecommunications among their respective areas. This coordination shall
include the ability to investigate and recommend solutions to telecommunications problems
within the area and with other areas.
R4.Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all communications between and among operating
personnel responsible for the real-time generation control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing Authorities may use an alternate language
for internal operations.
R5.R4.
Each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall have written operating instructions and procedures to enable continued
operation of the system during the loss of telecommunications facilities.
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Standard COM-001-1.12 — Telecommunications
R6.R5.
Each NERCNet User Organization shall adhere to the requirements in
Attachment 1-COM-001, “NERCNet Security Policy.”
C. Measures
M1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request evidence that could include, but is not limited to communication facility
test-procedure documents, records of testing, and maintenance records for communication
facilities or equivalent that will be used to confirm that it manages, alarms, tests and/or actively
monitors vital telecommunications facilities. (Requirement 2 part 1)
M2. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have and
provide upon request its current operating instructions and procedures, either electronic or hard
copy, that will be used to confirm that it meets Requirement 4.The Reliability Coordinator,
Transmission Operator or Balancing Authority shall have and provide upon request evidence
that could include, but is not limited to operator logs, voice recordings or transcripts of voice
recordings, electronic communications, or equivalent, that will be used to determine
compliance to Requirement 4.
M3.Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have
and provide upon request its current operating instructions and procedures, either electronic or
hard copy that will be used to confirm that it meets Requirement 5.
M4.M3.
The NERCnet User Organization shall have and provide upon request
evidence that could include, but is not limited to, documented procedures, operator logs, voice
recordings or transcripts of voice recordings, electronic communications, etc., that will be used
to determine if it adhered to the (User Accountability and Compliance) requirements in
Attachment 1-COM-001. (Requirement 65)
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations
Regional Reliability Organizations shall be responsible for compliance monitoring of all
other entities
1.2. Compliance Monitoring and Reset Time Frame
One or more of the following methods will be used to assess compliance:
-
Self-certification (Conducted annually with submission according to schedule.)
-
Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)
-
Periodic Audit (Conducted once every three years according to schedule.)
-
Triggered Investigations (Notification of an investigation must be made within 60
days of an event or complaint of noncompliance. The entity will have up to 30
calendar days to prepare for the investigation. An entity may request an extension of
the preparation period and the extension will be considered by the Compliance
Monitor on a case-by-case basis.)
The Performance-Reset Period shall be 12 months from the last finding of non-compliance.
1.3. Data Retention
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Standard COM-001-1.12 — Telecommunications
For Measure 1 each Reliability Coordinator, Transmission Operator, Balancing Authority
shall keep evidence of compliance for the previous two calendar years plus the current year.
For Measure 2 each Reliability Coordinator, Transmission Operator, and Balancing
Authority shall keep 90 days of historical data (evidence).
For Measure 32, each Reliability Coordinator, Transmission Operator, Balancing
Authority shall have its current operating instructions and procedures to confirm that it
meets Requirement 54.
For Measure 43, each Reliability Coordinator, Transmission Operator, Balancing Authority
and NERCnet User Organization shall keep 90 days of historical data (evidence).
If an entity is found non-compliant the entity shall keep information related to the noncompliance
until found compliant or for two years plus the current year, whichever is longer.
Evidence used as part of a triggered investigation shall be retained by the entity being
investigated for one year from the date that the investigation is closed, as determined by
the Compliance Monitor.
The Compliance Monitor shall keep the last periodic audit report and all requested and
submitted subsequent compliance records.
1.4. Additional Compliance Information
Attachment 1 COM-001 — NERCnet Security Policy
2.
Levels of Non-Compliance for Transmission Operator, Balancing Authority or Reliability
Coordinator
2.1. Level 1: Not applicable.
2.2. Level 2: Not applicable.
2.3. Level 3: There shall be a separate Level 3 non-compliance, for every one of the
following requirements that is in violation:
2.3.1
The Transmission Operator, Balancing Authority or Reliability Coordinator used
a language other then English without agreement as specified in R4.
2.3.22.3.1
There are no written operating instructions and procedures to enable
continued operation of the system during the loss of telecommunication facilities,
as specified in R5R4.
2.4. Level 4: Telecommunication systems are not actively monitored, tested, managed or
alarmed, as specified in R2.
3.
Levels of Non-Compliance — NERCnet User Organization
3.1. Level 1: Not applicable.
3.2. Level 2: Not applicable.
3.3. Level 3: Not applicable.
3.4. Level 4: Did not adhere to the requirements in Attachment 1-COM-001, NERCnet
Security Policy.
E. Regional Differences
None Identified.
Page 3 of 6
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Standard COM-001-1.12 — Telecommunications
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective Date
Errata
1
November 1, 2006
Adopted by Board of Trustees
Revised
1
April 6, 2007
Requirement 1, added the word “for”
between “facilities” and “the exchange.”
Errata
October 29, 2008
BOT adopted errata changes; updated
version number to “1.1”
Errata
1.1
Page 4 of 6
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Standard COM-001-1.12 — Telecommunications
Attachment 1 COM-001 — NERCnet Security Policy
Policy Statement
The purpose of this NERCnet Security Policy is to establish responsibilities and minimum requirements
for the protection of information assets, computer systems and facilities of NERC and other users of the
NERC frame relay network known as “NERCnet.” The goal of this policy is to prevent misuse and loss
of assets.
For the purpose of this document, information assets shall be defined as processed or unprocessed data
using the NERCnet Telecommunications Facilities including network documentation. This policy shall
also apply as appropriate to employees and agents of other corporations or organizations that may be
directly or indirectly granted access to information associated with NERCnet.
The objectives of the NERCnet Security Policy are:
•
•
•
To ensure that NERCnet information assets are adequately protected on a cost-effective basis and
to a level that allows NERC to fulfill its mission.
To establish connectivity guidelines for a minimum level of security for the network.
To provide a mandate to all Users of NERCnet to properly handle and protect the information that
they have access to in order for NERC to be able to properly conduct its business and provide
services to its customers.
NERC’s Security Mission Statement
NERC recognizes its dependency on data, information, and the computer systems used to facilitate
effective operation of its business and fulfillment of its mission. NERC also recognizes the value of the
information maintained and provided to its members and others authorized to have access to NERCnet. It
is, therefore, essential that this data, information, and computer systems, and the manual and technical
infrastructure that supports it, are secure from destruction, corruption, unauthorized access, and accidental
or deliberate breach of confidentiality.
Implementation and Responsibilities
This section identifies the various roles and responsibilities related to the protection of NERCnet
resources.
NERCnet User Organizations
Users of NERCnet who have received authorization from NERC to access the NERC network are
considered users of NERCnet resources. To be granted access, users shall complete a User Application
Form and submit this form to the NERC Telecommunications Manager.
Responsibilities
It is the responsibility of NERCnet User Organizations to:
•
•
•
•
•
•
•
•
Use NERCnet facilities for NERC-authorized business purposes only.
Comply with the NERCnet security policies, standards, and guidelines, as well as any procedures
specified by the data owner.
Prevent unauthorized disclosure of the data.
Report security exposures, misuse, or non-compliance situations via Reliability Coordinator
Information System or the NERC Telecommunications Manager.
Protect the confidentiality of all user IDs and passwords.
Maintain the data they own.
Maintain documentation identifying the users who are granted access to NERCnet data or
applications.
Authorize users within their organizations to access NERCnet data and applications.
Page 5 of 6
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Standard COM-001-1.12 — Telecommunications
•
•
•
Advise staff on NERCnet Security Policy.
Ensure that all NERCnet users understand their obligation to protect these assets.
Conduct self-assessments for compliance.
User Accountability and Compliance
All users of NERCnet shall be familiar and ensure compliance with the policies in this document.
Violations of the NERCnet Security Policy shall include, but not be limited to any act that:
•
Exposes NERC or any user of NERCnet to actual or potential monetary loss through the
compromise of data security or damage.
• Involves the disclosure of trade secrets, intellectual property, confidential information or the
unauthorized use of data.
Involves the use of data for illicit purposes, which may include violation of any law, regulation or
reporting requirement of any law enforcement or government body.
Page 6 of 6
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Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Successive Ballot and Non-Binding Poll Open Through 8 p.m.
Thursday, September 20, 2012
Now Available
A successive ballot of COM-003-1 – Operating Personnel Communications and Protocols and a nonbinding poll of the associated VRFs/VSLs is open through 8 p.m. Eastern on Thursday, September 20,
2012.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standard and opinion in the non-binding poll of the associated VRFs and VSLs by clicking here.
Please read carefully: All stakeholders with comments (both members of the ballot pool, as well as
other stakeholders; including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information
and are not required to answer any other questions.
Next Steps
The drafting team plans anticipates posting COM-003 for a recirculation ballot in October 2012.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve
reliability. As requested in the SAR, in the development of this proposed standard, the drafting team
reviewed communication protocols in other NERC standards and considered the use of alert level
guidelines and three-part communications to achieve consistency across regions. The proposed
standard is designed to ensure that reliability-related information is conveyed effectively, accurately,
consistently and in a timely manner to ensure mutual understanding by all key parties, both during
alerts and emergencies and during the communication of routine operating instructions.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High
Violation Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is “Command from a System Operator
to change or preserve the state, status, output or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement – Project 2007-02 update
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Operating Personnel Communications Protocols
Project 2007-02
Formal Comment Period Open:
August 22 – September 20, 2012
RSAW Posted for
Industry Comments:
August 22 – September 20, 2012
Upcoming:
Successive Ballot and Non-binding Poll:
September 11 – September 20, 2012
Now Available
A formal comment period for COM-003-1 – Operating Personnel Communication Protocols is open
through 8 p.m. Eastern on Thursday, September 20, 2012
In response to comments received during the last comment period and other input, the drafting team
has taken a new approach to COM-003-1.
This version requires entities to establish communication protocols and then implement a process for
identifying, assessing and correcting deficiencies with adherence to those communication protocols.
The entity is to ensure that its process is working, rather than requiring the demonstration of absolute
compliance with communication protocols at all times and identifying each deficiency as a possible
violation.
Additionally, this version was drafted in conjunction with the development of the Reliability Standard
Audit Worksheet (RSAW). The parallel development of these documents provided the opportunity for
the drafting team to consider the compliance implications of the language in the standard and to offer
input into the language of the RSAW. The RSAW is posted for informal comments along with COM-0031.
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Thursday,
September 20. Please use this electronic form to submit comments. If you experience any difficulties in
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
using the electronic form, please contact Monica Benson at [email protected]. An off-line,
unofficial copy of the comment form is posted on the project page.
Please read carefully: All stakeholders with comments (both members of the ballot pool as well as
other stakeholders, including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter the comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information and
are not required to answer any other questions.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Thursday, September 20,
2012. The draft RSAW is posted on the NERC Compliance Reliability Standard Audit Worksheet (RSAW)
page. Please submit comments on the draft RSAW using the RSAW comment form (located under
“Tools”) to [email protected].
Next Steps
A webinar on COM-003-1 is planned for the week of September 17, 2012. A separate announcement
will be sent when the date and time are finalized.
A successive ballot of COM-003-1 and a non-binding poll of the associated VRFs and VSLs will be
conducted beginning on Tuesday, September 11, 2012 through 8 p.m. Eastern on Thursday, September
20, 2012.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is “Command from a System Operator
to change or preserve the state, status, output or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Operating Personnel Communications Protocols
Project 2007-02
Formal Comment Period Open:
August 22 – September 20, 2012
RSAW Posted for
Industry Comments:
August 22 – September 20, 2012
Upcoming:
Successive Ballot and Non-binding Poll:
September 11 – September 20, 2012
Now Available
A formal comment period for COM-003-1 – Operating Personnel Communication Protocols is open
through 8 p.m. Eastern on Thursday, September 20, 2012
In response to comments received during the last comment period and other input, the drafting team
has taken a new approach to COM-003-1.
This version requires entities to establish communication protocols and then implement a process for
identifying, assessing and correcting deficiencies with adherence to those communication protocols.
The entity is to ensure that its process is working, rather than requiring the demonstration of absolute
compliance with communication protocols at all times and identifying each deficiency as a possible
violation.
Additionally, this version was drafted in conjunction with the development of the Reliability Standard
Audit Worksheet (RSAW). The parallel development of these documents provided the opportunity for
the drafting team to consider the compliance implications of the language in the standard and to offer
input into the language of the RSAW. The RSAW is posted for informal comments along with COM-0031.
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Thursday,
September 20. Please use this electronic form to submit comments. If you experience any difficulties in
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
using the electronic form, please contact Monica Benson at [email protected]. An off-line,
unofficial copy of the comment form is posted on the project page.
Please read carefully: All stakeholders with comments (both members of the ballot pool as well as
other stakeholders, including groups such as trade associations and committees) must submit
comments through the electronic comment form. During the ballot window, balloters who wish to
submit comments with their ballot may no longer enter comments on the balloting screen, but may still
enter the comments through the electronic comment form. Balloters who wish to express support for
comments submitted by another entity or group will have an opportunity to enter that information and
are not required to answer any other questions.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Thursday, September 20,
2012. The draft RSAW is posted on the NERC Compliance Reliability Standard Audit Worksheet (RSAW)
page. Please submit comments on the draft RSAW using the RSAW comment form (located under
“Tools”) to [email protected].
Next Steps
A webinar on COM-003-1 is planned for the week of September 17, 2012. A separate announcement
will be sent when the date and time are finalized.
A successive ballot of COM-003-1 and a non-binding poll of the associated VRFs and VSLs will be
conducted beginning on Tuesday, September 11, 2012 through 8 p.m. Eastern on Thursday, September
20, 2012.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
2
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requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is “Command from a System Operator
to change or preserve the state, status, output or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We
extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
3
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Standards Announcement
Project 2007-02 – Operating Personnel Communications Protocols
Successive Ballot and Non-Binding Poll Results
Now Available
A successive ballot of COM-003-1 – Operating Personnel Communications and Protocols and a nonbinding poll of the associated VRFs/VSLs concluded on Thursday, September 20, 2012.
Voting statistics for each ballot are listed below, and the Ballots Results page provides a link to the
detailed results.
Approval
Non-binding Poll Results
Quorum: 77.70%
Quorum: 84.05%
Approval: 50.57%
Supportive Opinions: 54.07%
Next Steps
The drafting team is reviewing comments to determine next steps..
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve
reliability. As requested in the SAR, in the development of this proposed standard, the drafting team
reviewed communication protocols in other NERC standards and considered the use of alert level
guidelines and three-part communications to achieve consistency across regions. The proposed
standard is designed to ensure that reliability-related information is conveyed effectively, accurately,
consistently and in a timely manner to ensure mutual understanding by all key parties, both during
alerts and emergencies and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High
Violation Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is “Command from a System Operator
to change or preserve the state, status, output or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend
our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
2
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Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007 -02 COM-003 Successive Ballot
Password
Ballot Period: 9/11/2012 - 9/20/2012
Ballot Type: Initial
Log in
Total # Votes: 338
Register
Total Ballot Pool: 435
Quorum: 77.70 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
50.57 %
Vote:
Ballot Results: The drafting team will review comments received.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
110
11
103
39
93
53
0
12
5
9
435
#
Votes
1
0.7
1
1
1
1
0
0.3
0
0.8
6.8
#
Votes
Fraction
44
1
39
18
34
24
0
1
0
5
166
Negative
Fraction
0.537
0.1
0.459
0.643
0.5
0.6
0
0.1
0
0.5
3.439
Abstain
No
# Votes Vote
38
6
46
10
34
16
0
2
0
3
155
0.463
0.6
0.541
0.357
0.5
0.4
0
0.2
0
0.3
3.361
4
0
2
2
7
0
0
0
1
1
17
24
4
16
9
18
13
0
9
4
0
97
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Member
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Ballot
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Comments
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Affirmative
Abstain
Abstain
Affirmative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Negative
Negative
Affirmative
Michael Moltane
Negative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
1
3
3
3
3
3
3
3
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Dave Markham
Negative
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Negative
Negative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Affirmative
Affirmative
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
NW Electric Power Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
David McDowell
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Rick Paschall
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Turlock Irrigation District
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Steve Eldrige
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Negative
Negative
Affirmative
Negative
Affirmative
Tim Beyrle
Affirmative
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
Keith Morisette
Steven C Hill
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Abstain
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
ICF International
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Brent B Hebert
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
David Gordon
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Michiko Sell
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
APX
INTELLIBIND
JDRJC Associates
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Lujuanna Medina
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Negative
Affirmative
Peter H Kinney
Affirmative
David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Michael Johnson
Kevin Conway
Jim Cyrulewski
Frederick R Plett
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Affirmative
Negative
Negative
Donald Nelson
Diane J. Barney
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=53aff95f-b14c-4a10-9caa-fe223d912548[9/24/2012 8:17:33 AM]
Abstain
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
Project 2007-02 COM-003
Non-binding Poll Results
Non-binding Poll
Project 2007-02 COM-003 Non-binding Poll
Name:
Poll Period: 9/11/2012 - 9/21/2012
Total # Opinions: 332
Total Ballot Pool: 395
84.05% of those who registered to participate provided an opinion or an abstention;
Summary Results: 54.07% of those who provided an opinion indicates support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
1
1
1
1
1
1
1
1
1
1
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric,
LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
CPS Energy
Dairyland Power Coop.
1
1
1
1
1
1
1
1
1
1
1
Non-binding Poll Results: Project 2007-02
Member
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
Kevin Smith
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
Opinions
Comments
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
John Brockhan
Negative
Michael B Bax
Marco A Sustaita
Negative
Abstain
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Non-binding Poll Results: Project 2007-02
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Bob Solomon
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Abstain
Negative
Affirmative
Abstain
Michael Moltane
Abstain
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
Affirmative
Negative
Affirmative
Affirmative
Negative
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Marvin E VanBebber
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Abstain
Negative
Negative
Affirmative
Abstain
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Independent Electricity System
Barbara Constantinescu
Operator
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Non-binding Poll Results: Project 2007-02
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Negative
Negative
Abstain
Abstain
Abstain
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Non-binding Poll Results: Project 2007-02
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Kent Kujala
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Abstain
Negative
Affirmative
Affirmative
Daniel D Kurowski
Affirmative
Charles A. Freibert
Stephen D Pogue
Negative
Negative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
Non-binding Poll Results: Project 2007-02
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Michael Schiavone
Affirmative
Skyler Wiegmann
Negative
William SeDoris
David McDowell
David Burke
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Negative
Affirmative
Abstain
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
5
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4
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4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
City of New Smyrna Beach Utilities
Tim Beyrle
Commission
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri
John Allen
Consumers Energy
David Frank Ronk
Cowlitz County PUD
Rick Syring
Detroit Edison Company
Daniel Herring
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Cairo Vanegas
Georgia System Operations Corporation Guy Andrews
Illinois Municipal Electric Agency
Bob C. Thomas
Imperial Irrigation District
Diana U Torres
Indiana Municipal Power Agency
Jack Alvey
LaGen
Richard Comeaux
Madison Gas and Electric Co.
Joseph DePoorter
Modesto Irrigation District
Spencer Tacke
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Oklahoma Municipal Power Authority
Ashley Stringer
Old Dominion Electric Coop.
Mark Ringhausen
Public Utility District No. 1 of Douglas
Henry E. LuBean
County
Public Utility District No. 1 of Snohomish
John D Martinsen
County
Sacramento Municipal Utility District
Mike Ramirez
Seattle City Light
Hao Li
Seminole Electric Cooperative, Inc.
Steven R Wallace
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
WPPI Energy
Todd Komplin
AEP Service Corp.
Brock Ondayko
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
Arizona Public Service Co.
Edward Cambridge
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc. Shari Heino
Calpine Corporation
Phillip Porter
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
Non-binding Poll Results: Project 2007-02
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
6
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Non-binding Poll Results: Project 2007-02
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Abstain
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Kenneth Silver
Affirmative
Mike Laney
S N Fernando
Negative
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Non-binding Poll Results: Project 2007-02
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Michiko Sell
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Affirmative
Abstain
Affirmative
Negative
Negative
Negative
Abstain
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
Negative
Affirmative
Abstain
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
8
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6
6
6
6
6
6
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6
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6
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6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
9
9
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
APX
JDRJC Associates
Massachusetts Attorney General
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Non-binding Poll Results: Project 2007-02
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Abstain
Negative
Affirmative
Affirmative
Brad Packer
Affirmative
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Abstain
Affirmative
Peter H Kinney
Affirmative
James A Maenner
Edward C Stein
Roger C Zaklukiewicz
Michael Johnson
Jim Cyrulewski
Frederick R Plett
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Donald Nelson
Affirmative
Affirmative
Negative
Affirmative
Negative
9
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10
10
10
10
10
10
10
10
10
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Non-binding Poll Results: Project 2007-02
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
10
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Group Name (23 Responses)
Lead Contact (23 Responses)
Contact Organization (23 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (9 Responses)
Comments (80 Responses)
Question 1 (61 Responses)
Question 1 Comments (68 Responses)
Question 2 (65 Responses)
Question 2 Comments (68 Responses)
Question 3 (62 Responses)
Question 3 Comments (68 Responses)
Question 4 (51 Responses)
Question 4 Comments (68 Responses)
Question 5 (0 Responses)
Question 5 Comments (68 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
No
It must be made clear in the requirements that functional entities can incorporate exceptions (to
address emergencies for example) in the protocols that are developed. Both of these requirements
are too prescriptive. The sub-requirements drill down too deeply into the communications needed to
conduct system operations.
No
It is unclear what identified reliability gap this Standard’s development project is intending to fulfill
given the recent adoption of the new COM-002-3 along with the OC white paper on communications
protocols.
The white paper written by the OC addressed the issues covered by this Standard.
Individual
Yes
Yes
No
No
Modify R1 accordingly... R1. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall have and follow documented communication protocols for Operating Instructions that
incorporate the following: R3 & R4 Delete R3 and R4 and M3 and M4 and associated VRFs and VSLs
Although R1 and R2 provide for better communications, R3 & R4… • Have little or no impact to the
protection or reliable operation of the BES in the event that no responsible entity performed the
requirement • Have little, if any, value as a reliability requirement Are requirements for monitoring
and enforcing Reliability Standards and do not provide for Reliable Operation… • Including without
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
limiting the foregoing, requirements for the operation of existing Facilities • Including cyber security
protection, and • Including the design of planned additions or modifications to such Facilities to the
extent necessary for Reliable Operation M1 should read… • M1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator, shall provide its documented communications protocols
developed for Requirement R1 and results of their internal compliance program’s processes which
assure that deficiencies with adherence to the documented communication protocols are identified,
assessed, and corrected. M2 should read • M2. Each Distribution Provider and Generator Operator
shall provide its documented communications protocols developed for Requirement R2 and results of
their internal compliance program’s processes which assure that deficiencies with adherence to the
documented communication protocols are identified, assessed, and corrected. In addition, we
recommend revision to the RSAW to be reflective of the removal of both R3 and R4.
Individual
No
The definition of the new term, “Operating Instruction,” uses the NERC Glossary term “System
Operator,” which is defined as “An individual at a control center…whose responsibility it is to monitor
and control that electric system in real time.” The lack of clarity regarding what constitutes a control
center leaves doubt as to which instructions would be covered by the standard.
No
The SDT shift from a zero-tolerance standard to a procedure required standard is admirable. Thank
you for the open-mindedness and willingness to change direction after much hard work went into the
original proposal. However, the requirements for specific content in the required procedure still goes
beyond the proper role of the standard. Suggested revision - eliminate R1 and R2, replace with new
R1: "Each (covered entity) shall have documented procedure(s) for communications with other users
of the Bulk Power System. Such procedure(s) shall have provisions which, in the judgment of the
registered entity, reduce the opportunity for miscommunications." This lowers the chances of
miscommunications without dictating the content of business practices.
No
There is no statement of periodicity in R4, leaving entities guessing until the time of audit regarding
the criteria for sufficient review. R4 also would appear to require a great deal of review of
communications in order to satisfy the requirement to identify potential defects. One of the
suggestions on the NERC Webinar for COM-003 was to review a "half-hour of communications" every
week. This is especially intrusive on smaller entities with a single compliance individual, as more than
an hour of that person's work-week would be spent randomizing, retrieving and listening to routine
communications. This effort would reduce the reliability of the bulk power system as efforts with
greater effect are reduced to comply with this requirement. Suggest requiring an annual review of
communications procedures with staff instead.
No
The need for a prescriptive standard remains in doubt. The SDT has responded to comments
questioning this need with a cite of a single study. The applicability of this study to GOPs is unclear.
We do not know the details, and question the number of cited miscommunications which involved
GOPs. Further, we are unclear as to the number of miscommunications which involved two entities, as
opposed to an entity giving direction to their own field operator. Such single-entity communications
would not be covered by the proposed standard. Lowering miscommunications is an admirable goal,
and again the SDT deserves commendation for their willingness to rethink the direction of the
proposed standard. However, the standard, if needed, should be limited to requiring an entity to have
communications procedures, and to reinforce those procedures on a periodic basis. The content of
those procedures should properly be left to the best judgement of the individual entity.
Individual
No
Requirement R1.6 provides inadequate protection against a misunderstanding when directives are
issued. Granted, the Requirement does obligate the party receiving the directive to repeat back the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
directive. However, if the recipient repeats the directive back to the person issuing the directive, and
the "repeat back" indicates the recipient has misunderstood the directive, this Requirement merely
obligates the person issuing the directive to state the directive again. The Requiremnt places no
obligation on the person issuing the directive, who knows he has been misunderstood, to explicitly
and clealy bring to the attention of the recipient that the recipient has misunderstood. All the party
issuing the directive has to do is repeat what he has already said. The party issuing the directive is
under no obligation to make it clear that there has been a misunderstanding. With respect, I suggest
having the person issuing the directive merely repeat it if he's been misunderstood, with no explicit
statement that there has been a mistake, leaves open the potential for the recipient to be unaware he
has misunderstood and to execute a misunderstood directive. As an example, consider the following
exchange. Transmission Operator to Field Operator: "Jim, open Breaker 104-696". Field Operator
repeats back "I understand open Breaker 104-699". Transmission Operator, noting the error, states
"Open Breaker 104-696". The field operator, having not been explictly made aware there has been an
error, opens Breaker 104-699. (Presumably, he would not do so had the Transmission Opeartor made
him aware of the misunderstaing with an exlicit statement that there has been an error.) Suggestion:
Add verbiage to R1.6 obligating the person issuing the directive to make an explicit statement to the
recipient that there has been an error if the recipient repeats the order back incorrectly. Presently,
the standard imposes no such obligation on the person issuing the directive. One possibe way to reword the standard might be: " …shall ensure the recipient of the directive repeats the information
back correctly; and, if the repeat back is correct, shall acknowledge the response as correct. If the
repeat back is incorrect, the person issuing the directive will state "You are wrong and have
misunderstood the directive". The person issuing the directive will then repeat the directive correctly.
This process will continue until the recipient repeats the directive back correctly.
Individual
Individual
Yes
Yes
Yes
Yes
No additional comments.
Individual
Yes
Yes
Yes
Yes
Individual
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Yes
Yes
VSLs for R3 and R4: There is no contemplation of the entity failing to assess deficiencies (3.2 and
4.2) or failing to correct deficiencies (3.3, 4.3).
Section C. Measures: The measures are unclear as to what exactly the requirement to ‘provide’
entails? Would this be upon request or periodically? Please clarify. Section D. Compliance: Compliance
Enforcement Authority is defined as CEA and then the full term Compliance Enforcement Authority is
continually used throughout. The acronym or words should be used consistently. Section D.
Compliance: There is no specification for R1 and R2 retention.
Group
ACES Power Marketing Standards Collaborators
Ben Engelby
ACES Power Marketing
No
The current definition of Operating Instruction, particularly “command from a System Operator”
sounds like a Reliability Directive. We recommend revising the SAR of COM-003-1 to retire the
definition of Reliability Directive and COM-002-3. There is no delineation between when COM-003-1
and COM-002-3 would apply, which could potentially subject registered entities to double jeopardy.
For example, an Operating Instruction that occurs during an Emergency could open up the potential
for a finding of non-compliance under both COM-002-3 and COM-003-1. We suggest that the SDT
work with the RC SDT to clearly define when COM-002-3 and COM-003-1 would apply. A single
communication should not result in multiple penalties.
No
(1) The SDT should strike all sub-parts of R1 and R2 and allow registered entities to define their own
communications protocols based on internal policies and procedures; not from overly-prescriptive
reliability standards. The SDT stated that COM-003-1 is shifting paradigms and putting the
responsibility on the registered entity to monitor, assess and correct its own deficiencies. If that is
true, then the registered entity should have the freedom to decide what elements are to be included
in its communication protocols. R1 and R2 are administrative in nature and unnecessary. There is no
need to include 9 sub-parts on how to achieve proper communications. (2) The standard, as currently
written, does not allow a registered entity to implement superior practices, such as multi-modal
communication (multiple mediums of communicating) or other superior communication methods and
technologies. There are other ways to achieve efficient and accurate operating communications and
the drafting team should modify the requirements to allow the registered entity to determine the best
method of communication. There will be a disincentive for registered entities to seek out new
technologies to improve communication if the standard remains with the current sub-parts. More
discussion on each sub-part below. (3) R1, part 1.1, use of the English language. The SDT should not
require use of the English language because the vast majority registered entities in North America
speak English, except for a small number of entities in Canada and Mexico. If anything, the
requirement should be modified to state that, “If the English language is not used by System
Operators, there must be a legal justification, such as another language is mandated by law or
regulation.” Not using the English language is a much greater risk to reliability. The majority of
companies that speak English should not have to maintain compliance policies to reaffirm something
that everyone knows that they are doing. The real issue here is if an entity does not use English
language, auditors should verify how they communicate internally and what controls are in place
when the non-English speaking entity communicates with English-speaking neighbors. The SDT
should not put the burden of compliance on English speakers. The team should focus on the entities
that pose a risk to the BES by not using the English language and the increased potential for
miscommunications from translation errors. (4) R1, part 1.2, the 24-hour clock, daylight/standard
time. This sub-part does not take into account real time, such as “perform an action in 5 minutes.”
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The purpose statement of the SAR is to provide System Operators with uniform communications
protocols that reduce the possibility of miscommunication that could lead to action or inaction harmful
to the reliability of the BES. Requiring an operator to use the 24-hour clock for an action that is about
to occur could cause more confusion and increase the possibility of miscommunication. The SDT
should consider either inserting exceptions for the 24-hour clock for real time activities, or strike the
24-hour clock from the requirements. (5) R1, part 1.3, Standard or Daylight Savings. This sub-part
also poses a risk for actions performed during real time operations and could increase the likelihood
for error. For example, if WECC RC (daylight) was trying to communicate to a registered entity
located in Arizona (no daylight savings time) to open a breaker. What is more effective, asking the
entity to open a breaker in 5 minutes or at 11:05? In that scenario, 11:05 may be an hour difference
because WECC RC is on daylight and Arizona is not, and the operators would be focusing on whether
they accounted for the time changes and could potentially lose focus of the task at hand – opening
the correct breaker. The SDT should consider either inserting exceptions for daylight savings/standard
time for real time activities, or strike daylight savings/standard time from the requirements. (6) R1,
part 1.4, Transmission interface Element or Facility. As discussed above, this sub-part is unnecessary
and should be struck from the standard. A registered entity should be able to define its own
communication protocol and the associated internal controls to ensure effective operating
communications. Further, the Real-time Transmission Operations SDT (Project 2007-03) eliminated
TOP-002 R18 which referred to the same concept as part 1.4, “uniform line identifiers when referring
to transmission facilities.” The reason the Real-time TOP SDT removed the language from the new
standard was because the “requirement adds no reliability benefit. …There has never been a
documented case of the lack of uniform line identifiers contributing to a System reliability issue.”
Project 2007-03 was approved by the NERC Board of Trustees on May 9, 2012. Why is the OPCP SDT
introducing language that the NERC Board has approved to remove from the requirements? There
needs to be more awareness of the other projects and actions by the NERC Board. To be consistent,
we recommend striking this sub-part in its entirety. (7) R1, part 1.5, Alpha-numeric Clarifiers. As
discussed above, this sub-part is unnecessary and should be struck from the standard. A registered
entity should be able to define its own communication protocol and the associated internal controls to
ensure effective operating communications. (8) R1, part 1.6 and 1.7, Three-part Communication. As
discussed above, these sub-parts are unnecessary and should be struck from the standard. There are
more effective methods of communicating besides using three-part communication. Multi-modal
communication utilizes several mediums (verbal, visual and other sensory cues) to enhance
communication and may include three-part, but could also include other equally efficient and effective
methods to communicate, such as through interactive smart phones and other remote communication
devices. Different strategies may be needed for different utilities and their communication objectives.
For instance, strategies and tools may be combined to meet a wide variety of communication
functions to meet the needs of system operations, including utilizing new technologies to improve
human performance when performing day-to-day operations. Three-part communications could be a
part of the protocol, but three-part should not be in the requirements because it limits utilities from
employing other methodologies are equally effective or superior to three-part communications. A
registered entity should be able to define its own communication protocol and the associated internal
controls to ensure effective operating communications. (9) R1, part 1.8 and 1.9, One-way Burst
Messaging. As discussed above, these sub-parts are unnecessary and should be struck from the
standard. An all call communication that is incorrect has just a big of an impact on reliability than one
that is not understood. Also, the SDT does not take into account all the various technologies that exist
in the marketplace; what does an entity do for an “all call conference call” where there are numerous
humans on the line? R1, part 1.6 refers to “two party, person to person” and part 1.8 is limited to
“one-way” communication. There is a gap here – does the SDT intend to exclude the “all call
conference call” from the requirements? What happens if there are errors in the sent message? Would
internal controls be the remedy? If the all call communication is not understood and there was no
request for clarification, would an internal control resolve this issue or would the auditor find a PV?
Also, sub-part 1.8 only requires confirmation from one party, even though the burst message could
have been a request for eight parties to reply. There is a gap in reliability if all parties do not reply in
that example. These sub-parts need additional information for clarity. Same comment for DP/GOP
below. (10) R2 should allow DPs and GOPs to define their own communications protocols based on
internal policies and procedures and there should not be a requirement to include sub-parts 2.1 and
2.2. (11) R2, part 2.1, Receiving a Three-part Communication. As discussed above, this sub-part is
unnecessary and should be struck from the standard. There are more effective methods of
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communicating besides using three-part communication. Multi-modal communication utilizes several
mediums (verbal, visual and other sensory cues) to enhance communication and may include threepart, but could also include other equally efficient and effective methods to communicate, such as
through interactive smart phones and other remote communication devices. Different strategies may
be needed for different utilities and their communication objectives. For instance, strategies and tools
may be combined to meet a wide variety of communication functions to meet the needs of system
operations, including utilizing new technologies to improve human performance when performing dayto-day operations. Three-part communications could be a part of the protocol, but three-part should
not be in the requirements because it limits utilities from employing other methodologies are equally
effective or superior to three-part communications. A registered entity should be able to define its
own communication protocol and the associated internal controls to ensure effective operating
communications. (12) R2, part 2.2, One-way burst messaging for DP and GOP. As discussed above,
this sub-part is unnecessary and should be struck from the standard. Please see (9) above for more
discussion of one way burst messaging.
No
(1) We support the concept of internal controls that the SDT has proposed. We agree that finding a
violation for each instance is burdensome and unreasonable and evaluating internal controls is a more
efficient use of resources. However, we are concerned about the evaluation of internal controls from
Regional audit staff. How is NERC planning to train the Regional auditors to ensure consistency during
compliance audits? There is too much room for auditor subjectivity, especially when evaluating
whether a single communication was deficient. There are so many communications that could occur
on a daily basis and there is not clear guidance when the Regions will find or not find a possible
violation in an audit. (2) In the webinar, SDT chair stated that a registered entity that catches a high
percentage of deficiencies, then their process is working, but if the entity is only catching 50% then
the entity needs to correct the process. There is currently no percentage or other guideline or metric
to determine if an entity’s process is sufficient. If this is the SDT’s intent, please provide further
detail. (3) We recommend the SDT provide additional information in the Rationale and Technical
Justification document to include a guideline to show how the Regional auditors would assess
compliance with a control-based standard. It seems that the trend in both COM-003-1 and CIP v5 is
to find the errors and fix them without the need to self-report. How are the Regions going to
determine when a PV is to be issued? The Technical Justification and the RSAW do not provide enough
information when a communication deficiency crosses the threshold of becoming a violation. How
does a registered entity know when to self-report? (4) We recommend adding more detail, perhaps
including an application guidelines section as other risk-based standards, for acceptable remediation
of deficient communications. For example, if an operator failed to use the 24-hour clock during an
Operating Instruction, would a simple reminder be sufficient or would the operator need to attend a
full-blown training session? What documentation would be required? It seems that a reminder would
remedy the deficiency, but then that would have to be documented. The internal controls used to
remedy deficiencies could turn into another documentation exercise instead of focusing on effective
communication. We recommend the SDT consider ways of satisfying remediation without creating an
unnecessary administrative burden for maintaining compliance. (5) Please clarify R3, part 3.4,
“deficiencies found external to Part 3.1.” Does the SDT mean that there would be deficiencies found in
an audit? Who is the external entity finding these deficiencies? Does the SDT intend for registered
entities to hire external consultants? Is this the RC notifying the DP that it has not communicated
appropriately? Would these externally found deficiencies result in audit report recommendations?
No
(1) We agree with the VRF classifications. (2) We agree with the VSLs for R1 and R2. We note that
there is a typo in Severe VSL for R2 – there is no part 2.3 in the standard. (3) We disagree with the
Time Horizons for R1 and R2. Developing documented communications protocols are not long term
planning, these activities are operations planning. (4) We disagree with the VSLs for R3 and R4. In
particular, the binary nature of implementing communication protocols needs to be reconsidered.
During the September 6 webinar, both Gerry Cauley and Mike Moon stated that internal controls
should focus on fixing deficiencies and auditors were not to find PVs for single instances of
noncompliance. Based on these statements, the VSLs should not be binary if the auditors are not to
find PVs for single instances. Also during the webinar, Mike Moon stated that the auditors are to make
recommendations in their audit reports to improve their processes, and not to be an “enforcement
hammer” for each individual deficiency. The way the VSLs are drafted, each instance will be severe.
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We recommend that the SDT revise the VSLs to allow for auditors to make recommendations instead
of findings of potential noncompliance. (5) R3 VSL, “The Responsible Entity did not demonstrate that
no modificiation to the process was necessary to address the deficiencies found external to Part 3.1.”
This is a documentation issue and should not result in a severe VSL classification. (6) There was a lot
of discussion in the webinar about Regional auditors not finding a violation, but there needs to be
clear guidelines describing when an auditor will find a PV. The VSLs currently describe a violation
when a deficiency is not remediated, but that same instance could result in no finding at all,
depending on how the individual auditor interprets the situation. This level of subjectivity is too high;
the SDT needs to revise the VSL table to reflect a more reasonable approach, perhaps by including
more information and examples of situations that might be viewed as non-compliance
(communication breakdown) but because of internal controls, there should be no finding of noncompliance. In the alternative, the SDT could develop a guidance document outlining when an auditor
is to find a PV and include examples to ensure consistency. The RSAW does not provide any additional
clarity. (7) In the webinar, there were several references to “systemic or chronic” communication
deficiencies. The VSLs do not reference any types of trends, but that seems to be the focus of
compliance. We suggest revising the VSLs to focus on broader issues, such as systemic deficiencies
that remain unresolved.
(1) If the Regional auditor is to make recommendations to registered entities on how to improve the
COM-003-1 internal controls, would the Regions allow an initial safe harbor to assess the entity’s
program? If Regional auditors find PVs on the initial audit, that practice would go against the spirit of
self-correcting and would stifle the entity’s actions to monitor, assess, and correct deficiencies. The
SDT should consider this sort of initial assessment in the implementation plan. (2) If there is
discussion of combining COM-002 and COM-003 in the future, why not combine them now? It would
be a better use of the ERO’s resources to produce a single communication standard while both SDT
projects are in development instead of going back through the entire process at some point in the
future. (3) A Reliability Directive appears to be a subset of the Operating Instruction definition, which
is basically an Operating Instruction that occurs during an Emergency. We suggest collaborating with
the RC SDT to clarify the bounds of each definition to avoid overlap. As discussed above, it would be
appropriate to combine the COM-002 and COM-003 and associated definitions to avoid confusion. (4)
There is no requirement for data retention for R1 or R2. Again, we recommend striking these
requirements. Thank you for the opportunity to comment.
Individual
Yes
Yes
Yes
These appear to be Internal Controls and they look good.
We want to see COM-002 and COM-003 combined, therefore we voted Negative. The Internal Controls
in R3 & R4 are workable.
Individual
Yes
Thank you for making this change. Central Lincoln believes the SDT is on the right track to limit the
scope of the standard to communications originating from System Operators. This will be less
burdensome for many registered entities as well as the Compliance Enforcement Authorities.
Yes
We appreciate the work the SDT has done to ensure the standard is not about having zero
communication defects, and is more about process.
Yes
Yes
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1) We note that per the proposed definition of Operating Instruction, only commands regarding the
states of BES Elements or Facilities are covered. We also note that per the Statement of Compliance
Registry Criteria, Distribution Providers need not own or operate BES Elements or Facilities in order to
be registered as DPs. This puts DPs without these facilities in the position of documenting protocols
for and processes for finding deficiencies for communications that don’t occur. We note the SDT
stated in the last Consideration of Comments “DPs that operate BES Facilities or BES Elements and
receive Operating Instructions are subject to the need for clear communication to avoid
misunderstandings that could impact the BES”, and we agree. We suggest: “4.1.2 Distribution
Provider that operates Bulk Electric System Facilities or Elements and receives Operating Instructions”
2) The references to Part 3.1 in Sub-requirement 3.4 and Part 4.1 in Sub-requirement 4.4 make no
sense, since the standard has no such sections. We assume the SDT meant Sub-requirements 3.1 and
4.1 respectively, and suggest that “Part” be replaced by “Sub-requirement.” 3) We agree with the
SDT’s attempt to move away from zero defect compliance, and Requirements 1 and 2 and the RSAW
all support this. We’re afraid the CEA may still be able to find non-compliance for a single defect
based on the language of R3 or R4. For example a CEA finds a single OI that referred to a 12 hour
clock time in violation of the entity’s protocol developed under R1.2. This is not a violation, but the
CEA goes on to discover that the entity failed to identify the deficiency under R3.1. While the entity
can show they have a process that has in fact identified and corrected deficiencies, the CEA maintains
they failed to implement the process for this one instance and finds a violation. When the entity
points to the RSAW that states the CEA should make recommendation rather than finding a violation,
the CEA states they audit to the language of the standard requirement as stated in Footnote 1 of the
very same RSAW.
Group
Detroit Edison
Kent Kujala
Detroit Edison
Yes
Yes
No
All actions that result in a potential violation must be reviewed and analysed to identify and correct
deficiencies. Communication issues are no different. Requirements 3 and 4 are not required.
No
Analysis during Annual Review of work procedure for R1 and R2 automatically includes an analysis of
the process and development of corrective actions.
Individual
Yes
No
Yes
Yes
Regarding Q2, Austin Energy (AE) believes that parts 1.1 through 1.5 of R1 are unnecessary. Threepart communication, as described in parts 1.6 through 1.9, is the preferred method for ensuring that
both parties understand an Operating Instruction. It provides a sufficient mechanism for clear,
concise and accurate communication. AE believes that creating a protocol that requires System
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Operators to essentially relearn the way to speak (specifically using alpha-numeric identifiers) will
only create confusion as operators try to follow protocol and catch/correct themselves. Additionally,
the constant use of alpha-numeric identifiers in transmission switching orders that contain many,
many steps will become burdensome. AE believes that its current use of three-part communication
during these switching orders is more effective. Regarding Q4, the phrase “Parts 2.1 to 2.3 (3)” in the
Severe VSL for R2 should be “Parts 2.1 and 2.2”
Individual
Yes
No
It must be made clear in the requirements that functional entities can incorporate exceptions (to
address emergencies for example) in the protocols that are developed. Both of these requirements
are too prescriptive. The sub-requirements drill down too deeply into the communications needed to
conduct system operations.
No
It is unclear what identified reliability gap this Standard’s development project is intending to fulfill
given the recent adoption of the new COM-002-3 along with the OC white paper on communications
protocols.
The white paper written by the OC addressed the issues covered by this Standard. Also the
requirements 1.6, 1.7 and 2.1, 2.2 seem to be redundant with the requirement R2 of COM-002-2.
Both touch on the issue of ensuring misunderstandings by requiring the parties to repeat, restate,
rephrase or recapitulate the information transmitted/received. If adhering to the philosophy of Project
2013-02 Paragraph 81 of FERC,we should remove unnecessary requirements as part of NERC,s Find,
Fix and Track Process
Individual
Yes
Occidental Energy Ventures Corp. ("OEVC") agrees that it is important to specify that the command
came from a System Operator. This allows us to leverage existing recording and monitoring systems
to capture the event. The previous definition was open ended – which would have required us to
expend an unknowable dollar amount in an attempt to capture every conversation related to a BES
Facility or Element.
Yes
Although in general, OEVC does not believe that process documents should be the primary reliability
consideration, it is the appropriate strategy in this case. Clearly, all of us want to eliminate Operator
miscommunications – which make up nearly 20% of all BES mishaps – but it is impossible to assure
100% compliance over the course of thousands of System Operator communications. Furthermore,
the effort required to capture the evidence needed by audit teams would overwhelm our resources, as
well as those of the Regional compliance organizations. In our view, the path chosen by the drafting
team is consistent with NERC’s Risk-based Compliance program. It drives attention in areas that
reliability data shows to be deficient, but recognizes that the benefit of COM-003-1 must outweigh the
costs and resources required to implement it.
No
OEVC supports the concept underlying R3 and R4, but believe that far more detail must be provided
in the measures and/or the RSAW. In general, we read these requirements as pertaining to System
Operator monitoring and feedback processes that take place either in real-time or after the fact
through the review of recordings. However, there may be other suitable options such as
comprehensive Operator logging or even regular awareness training. Our concern is that without
further clarification, auditors may choose to interpret these requirements to mean that 100% of all
conversations must be monitored and assessed. This would result in a cost-prohibitive situation, with
little incremental improvement in reliability. Every effective quality program relies on statistically
significant sample assessments – and there must be an acceptable sample size defined. Furthermore,
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OEVC would like to see the Cost Effective Analysis Process (CEAP) used in this initiative. Our initial
assessment is that at least one resource will need to be added at our four generation facilities in order
to supplement our Operator quality monitoring program to accommodate COM-003-1. However, this
is based upon our assumptions of a statistical monitoring method – which is very sensitive to the
number of samples required. If other industry stakeholders come to the same conclusion, the result
could drive upward pressure on electricity rates – and should be compared to the expected benefits of
the initiative.
Yes
Group
PNGC Comment Group
Ron Sporseen
PNGC Power
The PNGC Comment Group is fully in support of Central Lincoln PUD's comments.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
Yes
Yes
Yes
Yes
no
Individual
Yes
Yes
It will require us to write a communications protocol.
Yes
Yes
Individual
No
The definition of the new term, “Operating Instruction,” uses the NERC Glossary term “System
Operator,” which is defined as “An individual at a control center…whose responsibility it is to monitor
and control that electric system in real time.” The lack of clarity regarding what constitutes a control
center leaves doubt as to which instructions would be covered by the standard. Another disagreement
with the proposed definition of “Operating Instruction” is that it inappropriately imposes three-part
communication for routine communications of changes of generation output. Common operating
communications to and from generation plants should not be considered compliance events requiring
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the use of alphanumeric clarifiers. Such a requirement may shift operators’ focus from providing
proper information under critical situations to using the specified terms for every minor
communication, distracting them rather than sharpening their concentration. The standard should
specify the classes of TO/TOP-to-GOP communications that constitute compliance events, the formal
designations by which such communications can be recognized, and the parties authorized to issue
such commands.
No
Clarification is needed regarding what GOP procedures are to cover, ref. our comments to question
#1 above.
No
There is no statement of periodicity in R4, leaving entities guessing until the time of audit regarding
the criteria for sufficient review. R4 is also open-ended regarding scope, potentially requiring review
of every voice communication for every plant for the audit period. Everyday communications do not
merit such scrutiny, which would reduce rather than improve the attention that can be given to
matters of significance. All standards (not just COM-003-1) should clearly specify pass/fail criteria and
the associated evidence requirements. R4 should be split into DP and GOP sections, with the GOP
requirement being: R4. Each Generator Operator shall conduct in each calendar year a review session
with the operations function for registered entities, regarding the documented communication
protocols specified in Requirement R2. Corrective action shall be implemented and documented for
any potential deficiencies coming to light as a result of this review.
Individual
OG&E is in support of Southwest Power Pool Comments. OG&E also had individual comments (though
I am now not allowed to submit via the questionnaire; therefore, will submit here). Q1: No We prefer
the use of the word “Instruction” vs “Command”, though we understand that word is already part of
the term being defined. Could be open to using the term “Request” or “Order” or “Direction”. Q2: No
R2.1 does not read well. We would recommend changing to “”When receiving an oral two party,
person-to-person Operating Instruction, the recipient is required to repeat, restate, rephrase, or
recapitulate the Operating Instruction.” Regarding R2.2, we are struggling to identify what would be
considered a “one-way burst messaging system”. Perhaps examples could be provided to clarify what
the SDT is trying to address. Consider adding similar language that is currently provided in TOP-0011a R3 “…shall comply with reliability directives issued by the Transmission Operator, unless such
actions would violate safety, equipment, regulatory or statutory requirements. Under these
circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform the
directive so that the Reliability Coordinator or Transmission Operator can implement alternate
remedial actions.” to allow for those circumstances in which a Distribution Provider or Generator
Operator may not be able to respond to the Operating Instruction. Q3: The word “potential” in R3.1.
and R4.1. could be subjective. Please remove this word such that both R3.1. and R4.1. state
“Identifies deficiencies,”. Q4: No We believe R3 and R4 should be considered Low VRF as they are
establishing the process that supports R1 and R2 which are already designated as Low VRF. We do
not think the subsequent process should have a higher VRF than the original requirement. Other
Comments: OG&E continues to believe that the COM-003 standard, while obviously the result of
significant effort and good intentions, is unnecessary. Even though we believe that three-part
communication is a best practice, and we utilize it for switching and reliability-related instructions, we
do not believe that it should be mandated through an enforceable standard. COM-002 addresses
three-part communications during emergency conditions and we believe that is sufficient. With
respect to the Paragraph 81 project, NERC should be focused on retiring standard requirements that
meet the following criteria: (a) have little or no impact on reliability, (b) administrative, purely
documentation, redundant, or hinders protection of the BES, and (c) Lower VRF/VSL, lower tier
Actively Monitored Standard, etc. The industry has yet to be provided sufficient evidence that the lack
of three-part communication during normal operations has been the direct cause, or even a
contributing cause, to reliability failures. While a good idea in concept, the COM-003 standard is likely
to take significant effort to interpret, understand and implement, at a time when industry is already
overburdened with real reliability issues that we already know to be problematic. The documents
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referenced in the Rationale and Technical Justification document supporting the need for this standard
should be made available for review if the drafting team is using them as support for the justification
for COM-003.
Individual
Yes
Yes
R1.3 should allow the use of prevailing time in addition to Daylight Savings and Standard time.
Prevailing time eliminates the need to differentiate between daylight savings or standard time in
notices and reduces confusion since the clocks are changed at a scheduled time by the US
Government.
Yes
United Illuminating supports the language in COM-003 R3 and R4. Since the quantity of Operating
Instructions will be very large it is more important to have a process to monitor the communication
protocols and correct deficiencies.
Yes
It is not clear whether the protocols in COM-003 apply to Reliability Directives in Com-002. It can be
reasoned that a Reliability Directive is a form of Operating Instruction. A double jeopardy situation is
created. Also the COM-003 R3 and R4 requirements would be inappropriately applied to Reliability
Directives. UI believes there is a difference between Reliability Directives and Operating Instructions
and the difference should be maintained. A Directive occurs during an Emergency and has a higher
risk than an Operating Instruction. Directives should be limited in occurrences and therefore is not
conducive to sampling or error correction as opposed to Operating Instructions which occur multiple
times in a day and are numerous. The data retention requirement of 90 days is reasonable. But UI is
concerned with the approach to monitoring requiring an inventory of every conversation that occurred
in that 90 day period to identify it as an Operating Instruction. Finally UI suuports EEI's comment.
Individual
No
ReliabilityFirst does not agree with the changes made to the proposed definition “Operating
Instruction”. The definition of Operating Instruction begins with the word “Command”. ReliabilityFirst
is unsure what the word “command” means and believes it could be mistaken as a directive.
ReliabilityFirst requests further clarification on the meaning of the word “command”. ReliabilityFirst
recommends the following for consideration: “Communication of instruction from a System Operator
to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.
No
Requirements R1 and R2 require the responsible entities to have documented communication
protocols for Operating Instructions, but does not require the responsible entity to implement the
protocols. Absent implementation of the protocols, there is no need for the protocols themselves if the
responsible entity is not required to follow them. ReliabilityFirst recommends the following wording as
an example for Requirement R1: “Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall have and implement a documented communication protocols for Operating
Instructions…”
No
ReliabilityFirst believes the words “identifying deficiencies” (within R3 and R4)is ambiguous and could
be open to interpretation. ReliabilityFirst believes the drafting team should further clarify the
deficiencies in which will be required to be identified in Requirement R3 and R4.
Yes
ReliabiltiyFirst thanks the SDT for their work but has a question related to the Implementation Plan.
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The SDT indicated in the consideration of comments report (from the draft 2 posting) the standard’s
six calendar month implementation time frame has been extended 12 calendar months to provide an
adequate amount of time for training and implementation. As noted above, there is a conflict since
the draft standard does not require implementation of the protocols. ReliabilityFirst believes absent
any implementation requirement, the six calendar month implementation time frame is adequate for
an entity to have documented communication protocols for Operating Instructions.
Individual
No
We do not see the need to define the term “Operating Instructions” for a number of reasons: For
years, system operators deal with operating instructions on a daily if not minute basis. Having a
defined term, and calling such communication as “Command” is totally unnecessary, and can confuse
operators from what they understand to be the meaning of operating instructions. The main intent of
this standard is to ensure no miscommunication between operating personnel, a part of which is
proposed to be fulfilled by exercising 3-part communication for operating instructions.
Notwithstanding our disagreement to having such a requirement in this standard, such a requirement
can be developed without having to define a term that adds nothing to the universal understanding of
the term but which can confuse operators. For example, Requirement R1 can be revised to: R1. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall have documented
protocols for communicating operating instructions that will change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System,
which incorporate the following: 1.1 1.2 ….
No
We disagree with the need to repeat and confirm operating instructions (Part 1.6 to 1.9 and R2)
meant to be used for normal operating system conditions. As indicated in our previous comment, the
term Reliability Directives and the recently approved COM-002-3 cover instructions not only
emergency conditions but also conditions that can result in Adverse Reliability Impact. Requiring
operating entities to exercise 3-part communications (repeating and confirming) for routine operating
instructions that maintain the states or do not change the status of the BES Facilities, or simple
actions such as removing a transmission line which has no impact on the BES, or simple switching, or
adjusting a small amount of generation output, is totally unnecessary, and can in fact overburden
System Operators and harm reliability. And we respectfully disagree with the SDT’s response to our
previous comment regarding the applicability of the term “Reliability Directive” in which the SDT
claims that the term “Reliability Directive” in the approved version of COM-002-3, “…in the context of
COM-002-3, is specifically for Emergency operating conditions” and “…covers a very narrow band of
low frequency, high impact events. The definition covers not only emergency, but also Adverse
Reliability Impacts” Further, the definition does not explicitly indicate, nor is it implied, that such
conditions are “of low frequency, high impact events.” To address the BoT’s concerns expressed when
approving the interpretation of COM-002-2, the term Reliability Directive now defined in COM-002-3
together with the NERC Operating Committee’s guideline on System Operator Verbal Communication
fully cover the condition under which 3-part communication need to be (to address Adverse Reliability
Impacts) or should be (where deemed appropriate) exercised. We do not see the need for having a
standard requirement for 3-part communication for conditions other than when Reliability Directives
are issued. Regarding the other parts in Requirement R1, i.e. 1.1 to 1.5, these are good operating
practices but are not absolutely necessary the “must follow” protocols that rise up to a continent-wide
reliability standard level.
No
We do not see the need for these two requirements at all. Assuming Requirements R1 and R2 were to
stay (which we disagree), Responsible Entities need to comply with these requirements to develop
documented communication protocols for Operating Instructions that incorporate all parts in R1 and
R2. Any deficiencies with adherence to the documented communication protocols specified in R1 and
R2 will be assessed non-compliance, and sanction and remedial actions will be imposed to correct
such deficiencies. Having two requirements to obligate entities that already violated the standard is
totally unnecessary, and redundant and may result in double jeopardy.
No
We do not agree with the need for most if not all of these requirements, and therefore do not agree
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with the proposed VRFs and VSLs.
We do not see the need for this standard. We feel that Reliability Standards should have performance
based objectives, rather than prescriptive requirements that outline “how” to meet an objective. This
draft is not consistent with this approach. If the majority of the industry also express a similar view,
we urge the SDT to bring this to the Standards Committee’s attention, and seek its advice on way
forward, including stopping this project altogether.
Group
SERC OC Standards Review Group
Gerry Beckerle
Ameren
No
We do not see a significant difference between Operating Instructions and Operating
Communications, and we believe neither definition is necessary.
No
We support having a documented communications protocol, but do not support prescriptive elements.
Below is an example of language we could support. All the subparts of R1 and R2 need to be rewritten
along these lines. “R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall have documented communication protocols for Operating Instructions that address the
following: …. 1.6. The conditions under which an issuer is expected to: • Confirm that the response
from the recipient of the Operating Instruction was accurate, or • Reissue the Operating Instruction to
resolve a misunderstanding.”
No
We would suggest changing R3 and R4 to align with our suggestions for R1 and R2: “R3. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement a process for
identifying deficiencies with adherence to their documented communication protocols that each entity
developed in accordance with Requirement R1 that:”
Yes
We could agree within the context of our comments listed above.
The SERC OC Standards Review Group does not agree that the mandatory/prescriptive procedure for
three part communications in essentially all oral communications will improve reliability of the BES.
The standard needs to be changed to better reflect industry comments from this comment period and
the previous ballot. The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review Group only and should not be construed as the
position of SERC Reliability Corporation, its board, or its officers.
Individual
Yes
Yes
Yes
Yes
Regarding R1.4, drafting team should clarify whether "interface" means interfaces between
neighboring entities or between functional entities. Regarding R1.8, does the drafting team have an
appropriate response time-frame for the confirmation to occur from recipients? Regarding R1.9 and
R2.2, these requirements seem unnecessary and unauditable. An audit team can evaluate whether
the documented communications protocol contains language to address these requirements;
however, evaluating the actual execution would be subjective. It is not possible to determine whether
a recipient understood a message clearly and whether clarification was required. Further, it will be
difficult for entities to identify deficiencies with this requirement, as required by R3, for the same
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reasons.
Individual
Agree
MRO NSRF and MISO
Individual
Yes
No
No
No
CenterPoint Energy appreciates the revisions made to the current draft of COM-003 based on
stakeholder feedback; however, the company maintains a negative vote based on the following:
Requirements 1.1 through 1.5 are overly prescriptive. We recommend deletion of stated sub
requirements as an effort to move away from detailed micro requirements. Additionally, CenterPoint
Energy recommends deletion of R3 and R4. The “internal controls” concept can be incorporated into
the remaining requirements. CenterPoint Energy would vote affirmative if the SDT revised the
proposed standard as indicated below: R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall implement, in a manner that identifies, assesses, and corrects
deficiencies, documented communication protocols for Operating Instructions that incorporate the
following: 1.1 When issuing an oral two party, person-to-person Operating Instruction, require the
issuer to: • Confirm that the response from the recipient of the Operating Instruction was accurate, or
• Reissue the Operating Instruction to resolve a misunderstanding 1.2. When receiving an oral two
party, person-to-person Operating Instruction, require the recipient to repeat, restate, rephrase, or
recapitulate the Operating Instruction. 1.3. When issuing an oral Operating Instruction through a oneway burst messaging system used to communicate a common message to multiple parties in a short
time period (e.g. an all call system), verbally or electronically confirm receipt from one or more
receiving parties. 1.4. When receiving an oral Operating Instruction through a one-way burst
messaging system used to communicate a common message to multiple parties in a short time period
(e.g. an all call system), request clarification from the initiator if the communication is not
understood. R2. Each Distribution Provider and Generator Operator shall implement, in a manner that
identifies, assesses, and corrects deficiencies, documented communication protocols for Operating
Instructions that incorporate the following. [Violation Risk Factor: Low] [Time Horizon: Long-term
Planning] 2.1 When receiving an oral two party, person-to-person Operating Instruction, require the
recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction. 2.2 When receiving
an oral Operating Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system), request
clarification from the initiator if the communication is not understood.
Group
Duke Energy
Greg Rowland
Duke Energy
No
Duke Energy is very encouraged by the changes made by the Standard Drafting Team in the current
version of COM-003-1. The shift to requiring a communications protocol and a process for identifying
and correcting deficiencies is a major step in the right direction. Our concern with the definition is that
additional clarity is needed to distinguish the definition of Operating Instruction from the definition of
Reliability Directive so that entities know which communications COM-003-1 applies to. This could be
accomplished by changing the definition of Operating Instruction; replacing the word “Command” with
“Normal communication”, and replacing the word “preserve” with the word “maintain”. The revised
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definition would read as follows: “Normal communication from a System Operator to change or
maintain the state, status, output, or input of an Element of the Bulk Electric System or Facility of the
Bulk Electric System”.
No
1) In Requirements R1 and R2, the word “incorporate” should be changed to “address”. This change
will align the language of the requirements with the language of the RSAW, providing flexibility to
entities in how their communications protocols will be structured. This change will also help to
alleviate some of the following concerns. 2) In R1.1, 1.3 and 1.4 clarify the meaning of the phrase
“between functional entities”. Do these sub-requirements apply to Operating Instructions between
individuals located in the same functional entity? 3) In R1.7, the phrase “repeat, restate, rephrase, or
recapitulate” seems excessive. Suggest changing to just “repeat or rephrase”. 4) R1.6 and 1.7 are
describing 3-part communication. Suggest combining 1.6 and 1.7 5) R1.8 and 1.9 address “one-way
burst messaging”, but it’s not clear whether, or to what extent, 3-part communication is required.
Yes
No
1) Consistent with our comment to Question 2 above regarding changing the word “incorporate” to
“address” in Requirements R1 and R2, this change should also be made in the VSLs for R1 and R2,
changing the word “include” to “address”. 2) The Severe VSL for R2 incorrectly references a Part 2.3,
whereas it should just refer to both Parts 2.1 and 2.2
Individual
Yes
Yes
Yes
Yes
Individual
Yes
Yes
Yes
The proposed requirements (COM-003-1, R3 and R4) are in line with Risk-Based Reliability
Compliance Monitoring.
Yes
Requirement R1.5 should be an optional step to assist in resolving any misunderstanding found in
requirement R1.6. Alpha-numeric clarifiers, Requirement R1.5, in every three part communication of
an operating instruction is an activity that adds little if anything to promote the protection of the BES
and can hinder/distract from the reliable operation of the BES.
Individual
Yes
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No
LES requests the drafting team provide additional clarification regarding R2.1 as it relates to “oral two
party, person-to-person” communication occurring between the System Operators and field crews.
Does the drafting team intend for the communication protocols to be used for all communications
between the System Operators and field crews (such as for normal day-to-day switching of
distribution elements) or only as it occurs between defined functional entities? Within the Draft 2
consideration of comments under “Outstanding Unresolved Issues”, the drafting team states that “The
SDT clarified that COM-003-1 only applies to communication between functional entities. For example,
if a TOP System Operator is issuing an Operating Instruction to an individual that is internal to that
TOP, three part communication is not required by this standard”. Although LES supports this
clarification, it’s incorporation into the requirement is not obvious. Recommend the drafting team
modify R2.1 as follows to ensure this clarification remains evident within the standard going forward:
R2.1. When receiving an oral two party, person-to-person Operating Instruction between functional
entities, the recipient is required to repeat, restate, rephrase, or recapitulate the Operating
Instruction.
Yes
Yes
The Severe VSL for R2 should be modified to instead state “The responsible entity did not include
Parts 2.1 to 2.2 of Requirement R2, in their documented communication protocols”. The current VSL
incorrectly references Part 2.3 of R2 which does not exist.
LES believes additional clarification is needed to more clearly delineate who is considered to be the
Generator Operator (the power plant operator vs. system operator) responsible for compliance with
COM-003-1. As currently drafted, the Generator Operator, as the recipient of Operating Instruction,
must have and utilize documented communication protocols per R2. In the event generation redispatch were to be requested, is it the power plant operator performing the task or the system
operator requesting the execution of the task responsible for using the documented communication
protocols?
Individual
No
Although NextEra Energy, Inc. (NextEra) is encouraged by the refinements made to draft COM-003-1,
NextEra believes additional refinements are necessary for COM-003-1 to promote reliability, and in no
way hinder reliability. NextEra’s perspective is heavily influenced by the years of experience of its
system operators in their role as a large Transmission Operator, Reliability Coordinator agent and
Balancing Authority. Specifically with respect to the definition of Operating Instruction, NextEra
recommends that the definition more closely track the syntax of the definition of Reliability Directive
in COM-002-3, and, thus, read as follows: Operating Instruction – a command from a Reliability
Coordinator, Transmission Operator or Balancing Authority where action by the recipient is necessary
to change or preserve the state, status, output of an Element or Facility of the Bulk Electric System.
No
NextEra opposes any communication protocol in COM-003-1 that is not mirrored in COM-002-3.
NextEra views the implementation of two different communication protocols -- one for Reliability
Directives and one for Operating Instructions as problematic and not consistent with the promotion of
a reliable Bulk Electric System. This concern is heightened by the fact that there are more specific
protocols for Operating Instructions which are lower in the communication hierarchy when compared
to Reliability Directives. Such a model is counterintuitive. If implemented, this model will also likely be
counterproductive, increase confusion among System Operators and may unnecessarily cause a risk
to the Bulk Electric System. The inherent risk caused by the lack of synergy and consistency between
COM-003-1 and COM-002-3 could be resolved by combing the Standard Development projects and
having the SDTs work together to produce one uniform work product. Therefore, NextEra urges the
COM-003-1 SDT to request that the Standards Committee join the COM-002-3 and COM-003-1
efforts, so that one uniform three-way communication protocol can be developed and implemented
that promotes reliability. Further, in addition to comments that NextEra has previously submitted, it
asks that the following changes be made: R1.1 Delete “between functional entity” as unnecessary and
delete the second sentence altogether (or clarify it), because it is unclear and may add confusion. In
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the context of an Operating Instruction, it is best that English be used between Transmission
Operators and Balancing Authorities for external and internal communications related to Operating
Instruction. To allow for alternative languages to be used internally when an Operating Instruction is
given will likely result in difficult transitions between internal and external conversations which may
unintentionally result in a risk to the Bulk Electric System via an external miscommunication using a
language other than English. Thus, NextEra prefers that English be promoted and used for internal
and external communications related to Operating Instructions. R1.4 Add a comma after “Facility” in
the fourth line. R1.8 Use the term “entities” instead of “parties” in the second line. Entities is a more
widely recognized term than parties in the context of the Reliability Standards. Also, for clarity, rewrite the end of 1.8 to read “. . . confirm receipt from each entity.” The current wording states
“confirmed receipt from one or more receiving parties” seems to miss the point that what the sender
needs is confirmation from each entity that was sent the message. R1.9 Similarly, replace the term
“parties” in line two with “entities”.
No
Although NextEra supports Reliability Standards that are more risk and result based and provide for a
corrective bandwidth or prosecutory discretion for possible violations, as drafted, R3 and R4 need
refinement to meaningfully and clearly implement any of the above concepts. Therefore, NextEra
recommends that R3 and R4 both be re-written to read as follows: R3 Absent a possible violation that
resulted in (or could have resulted in) a significant risk to the Bulk Electric System, no violation of R1
and its subrequirements shall be found, provided that the Balancing Authority, Reliability Coordinator,
and Transmission Operator has implemented a process for identifying deficiencies with adherence to
the documented communication protocols specified in Requirement R1 that: . . . R4 Absent a possible
violation that resulted in (or could have resulted in) a significant risk to the Bulk Electric System, no
violation of R2 and its subrequirements shall be found, provided that the Distribution Provider and
Generator Operator shall implement a process for identifying deficiencies with adherence to the
documented communication protocols specified in Requirement R2 that: . . .
No
NextEra does not support VSLs that are checklist or document related. Rather NextEra favors VSLs
that balance results and performance against reliability risk. As drafted, the current VSLs are a
checklist approach to measuring reliability risk and compliance, which is not particularly helpful or
meaningful. Thus, NextEra suggests that VSLs be re-drafted to measure whether the entity posed an
actual risk to the Bulk Electric System based on how it delivered or received an Operating Instruction.
NextEra proposes the following as an alternative approach that more closely mirrors COM-0002-3 and
includes the internal controls language in R4 and R5. R1. When a Reliability Coordinator, Transmission
Operator or Balancing Authority requires actions to be executed as an Operating Communication, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as an
Operating Instruction to the recipient. R2. Each Balancing Authority, Transmission Operator,
Generator Operator, and Distribution Provider that is the recipient of an Operating Instruction shall
repeat, restate, rephrase or recapitulate the Operating Instruction. R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority that issues an Operating Instruction shall either: •
Confirm that the response from the recipient of the Operating Instruction (in accordance with
Requirement R2) was accurate, or • Reissue the Operating Instruction to resolve any
misunderstandings. R4 Absent a possible violation that resulted in (or could have resulted in) a
significant risk to the Bulk Electric System, no violation of R1 or R3 and its subrequirements shall be
found, provided that the Balancing Authority, Reliability Coordinator, and Transmission Operator has
implemented a process for identifying deficiencies with adherence to the documented communication
protocols specified in Requirement R1 and R3 that: 4.1. Identifies potential deficiencies, 4.2. Assesses
the deficiencies found, 4.3. Corrects the deficiencies, and 4.4. Evaluates the process based on
deficiencies found external to Part 3.1 and either • implements modifications to the process when the
evaluation determines that modification of the process is necessary to address the deficiencies found;
or • demonstrates that no modification to the process is necessary to address the deficiencies. R5
Absent a possible violation that resulted in (or could have resulted in) a significant risk to the Bulk
Electric System, no violation of R2 and its subrequirements shall be found, no violation of R2 and its
subrequirements shall be found, provided that the Distribution Provider and Generator Operator shall
implement a process for identifying deficiencies with adherence to the documented communication
protocols specified in Requirement R2 that: 5.1. Identifies potential deficiencies, 5.2. Assesses the
deficiencies found, 5.3. Corrects the deficiencies, and 5.4. Evaluates the process based on deficiencies
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found external to Part 3.1 and either • implements modifications to the process when the evaluation
determines that modification of the process is necessary to address the deficiencies found; or •
demonstrates that no modification to the process is necessary to address the deficiencies.
Group
Tacoma Public Utilities
Chang Choi
Tacoma Power, City of Tacoma
Yes
Yes
Yes
Yes
Individual
Yes
Yes
Yes
Yes
The issuance of a draft RSAW in combination with the draft standard helped clarify the audit approach
for some of the more subjective requirements such as R3 and R4 and how instances of deficiency will
not be considered violations of the standard. PNMR, Inc. and its two utility subsidiaries operating in
TRE, SPP and WECC would like to encourage other SDTs to follow the lead of this SDT with respect to
understanding that the RSAW is a critical piece of the Standards Development process.
Group
PacifiCorp
Sandra Shaffer
PacifiCorp
Yes
No
PacifiCorp does not feel that the requirements listed in R1.5 regarding the use of alpha-numeric
clarifiers when issuing an oral Operating Instruction is warranted. The requirements listed in R1.6,
and R1.7 requiring the strict used of three-way communication should alleviate any possibility of
miscommunication, which PacifiCorp understands to be the drafting team’s intent in the development
of separate Requirement R1.5. Also, implementing the use of alpha-numeric clarifiers poses additional
risk due to the introduction of ambiguous language.
No
PacifiCorp supports the addition of non-zero defect language which follows the CIP model. [model
PacifiCorp suggests that the language in Requirement R3 be modified and simplified as follows: “R3.
Each Balancing Authority, Reliability Coordinator, and Tranmission Operator shall implement R1 in a
manner that identifies potential deficiencies, assesses deficiencies found, and corrects those
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deficiencies.”
No
It is not clear to PacifiCorp why the VSLs are so much higher for R2 when R1 applies to Balancing
Authorities, Reliability Coordinators, and Transmission Operators, and thus has a potentially broader
application than R2. R2 applies to Distribution Providers and Generator Operators. Also, it is not clear
why the R2 VSL R2.3, as there is no R2.3 in the current draft.
Group
JEA
Thomas McElhinney
JEA
We beleive that three-part communications should only be necessary for directives. Also COM002 and
COM003 should be merged into one standard.
Individual
No
Operating Instruction Definition is too broad; this essentially imposes on affected entities the need to
use 3-part communication all the time. Additionally the broadness of the definition may cause
compliance difficulties between COM-003-1 and COM-002 if the requirements are not looked at
holistically between the two. A recommendation would be to combine the requirements into one
standard.
No
R1.2 Prescribed use of a 24 hour clock format seems over-bearing R1.3 The use of “functional
entities”- includes more entities than the applicability section and uses terms from the functional
model which goes beyond registered entities, may be some confusion here. R1.4 Transmission
interface Element Transmission interface Facility These terms may need to be defined. They may be
ambiguous to some entities as to what is intended R1.5 Use of alpha-numeric clarifiers in some
instances inhibit efficient communication, without increasing the effectiveness of the communication
or reducing the risk to the BES. In keeping with the requirement of entities to document its protocols,
it should be left to the entities of regions to define this. R2 Is missing a sub-requirement that requires
a clarification of two party communication that is not understood.
No
R3 & R4 As written are confusing and do not convey the intent of the SDT. Below is recommended rewrite: Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement a
process that assesses conformance and performance to the R1 documented protocols. This process
shall include identifying deficiencies, assessing the deficiencies and correcting the deficiencies when
feasible. R3.4 & R4.4 This should be removed as a sub-requirement and made its own requirement
Below is recommended re-write: Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall [insert time period] evaluate its process required by R3 (R4) for deficiencies. Identified
deficiencies shall be assessed and corrected when feasible. If no deficiencies found this is to be
documented.
No
VRF R3 & R4 NERC VRF Discussion: R3 (4) is a requirement that, if violated, could directly affect the
electrical state or the capability of the bulk electric system, or the ability to effectively monitor and
control the bulk electric system. However, violation of the requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures. The VRF for this requirement is “Medium”
which is consistent with NERC guidelines The violation of R3 (R4) does not result in informal
communication; it results in not identifying it. It is not a failure to identify that poses the risk to the
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BES, but the actual communication. The process implemented in R3 (R4) identifies, assesses, and
attempts to correct deficient communication practices in an attempt to make future communications
better. The process in R3 (R4) has no real-time impact on the BES, it aims at having real-time impact
on operators who have real-time impact on the BES. For these reasons the VRF should be “Low” FERC
VRF G1 Discussion: Discussion references wrong FERC Recommendation; should have referenced
Recommendation 26 rather than 24. Additionally, the SDT wrongly implies that Recommendation 26
applies to COM-003-1. Recommendation 26 “Tighten communications protocols, especially for
communications during alerts and emergencies…” applies to COM-002, thus removing it from FERC
VRF G1 allowing for a VRF of “Low” to be assigned. FERC VRF G3 Discussion: Though analogous to R2
of COM-002-2 they are not the same. One can argue that the importance of “directive” to the BES is
greater than the importance of an “Operating Instruction” to the BES and thus the risk to the BES is
less for R3 (R4) of COM-003-1, and accordingly should be assigned a lower VRF than R2 of COM-0022 to promote consistency between the standards, while also elevating the importance of COM-002-2
over COM-003-2. Said another way (Though each requirement addresses communication protocol,
the potential effects of the failure to follow the protocol are different in that one deals with Directives
and Emergency conditions and the other with Normal operations. So the VRF's shouldn't necessarily
be the same.) FERC VRF G4 Discussion: The violation of R3 (R4) does not result in informal
communication; it results in not identifying it. It is not a failure to identify that poses the risk to the
BES, but the actual communication. The process implemented in R3 (R4) identifies, assesses, and
attempts to correct deficient communication practices in an attempt to make future communications
better. The process in R3 (R4) has no real-time impact on the BES, it aims at having real-time impact
on operators who have real-time impact on the BES. For these reasons the VRF should be “Low” FERC
VRF G5 Discussion: The SDT has argued that R3 & R4 each contain only one objective (identification
of deficiencies). An Alternative read suggests the R3 & R4 as written each have six objectives:
1.Identify deficiencies in 3-part communication as defined by protocols in R1 2.Assess identified
deficiencies in 3-part communication 3.Correct identified deficiencies in 3-part communication
4.Identify deficiencies in process implemented in R3 (R4) 5.Assess identified deficiencies in process
implemented in R3 (R4) 6.Correct identified deficiencies in process implemented in R3 (R4) VSL
Justification R3 (R4) The SDT has argued that R3 & R4 each contain only one objective (identification
of deficiencies). An Alternative read suggests the R3 & R4 as written each have six objectives:
1.Identify deficiencies in 3-part communication as defined by protocols in R1 2.Assess identified
deficiencies in 3-part communication 3.Correct identified deficiencies in 3-part communication
4.Identify deficiencies in process implemented in R3 (R4) 5.Assess identified deficiencies in process
implemented in R3 (R4) 6.Correct identified deficiencies in process implemented in R3 (R4) Because
there are multiple objectives in R3 (R4) there is an opportunity for more granularities to the proposed
VSL.
Applicability Section: Functional Entities Section may not be broad enough to capture all entities
participating in communication for example a TO may have a switchman receiving Operating
Instructions from a TOP; the way the standard is written the TO would not be required to participate
in 3-part communication making it difficult for the TOP to fully implement its Communication
Protocols. M3 & M4 impose more requirements on the registered entity than are be required in R3 &
R4 respectively. For example R3 requires the implementation of a process, the measure looks for the
results of the process, the measure should be measuring the implementation not the result of the
process.
Individual
Yes
Yes
No
COM-003 cannot be a zero defect standard. We propose rewording R3 to state: "Each Reliability
Coordinator, Transmission Operator and Balancing Authority shall implement the requirements in R1
in a manner that identifies, assesses, and corrects deficiencies, if any. Where the entity is identifying,
assessing and correcting deficiencies, the entity is satisfactorily meeting the requirements or COM003." If there is no leeway given, requirement 1 of this standard will generate a very large number of
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violations and in our opinion it would become one of the most violated standards very quickly.
Yes
Individual
Agree
Central Lincoln
Individual
Yes
Yes
No
This is redundant with the continual improvement methodologies that the NERC process already has
in place. If a company finds, through a self assessment or NERC audit, that they are not meeting a
requirement in a standard, then the NERC process is to either self report, or be found in violation. In
either case the entity must complete their defficiency in the standard in order for the mitigation to be
approved by their regional entity. To have to have written process for this in order to meet R3 and R4
is redudant with the requirements on how NERC views the elements of a successful compliance
program. Smaller entities do not have the man power for redundancies such as this. I would rather
see R3 and R4 dropped from the standard for the reasons above. Most if not all companies will correct
issues through the self report process and mitigation plan approval process.
No
See comments from SPP
As stated drop requirements R3 and R4 as they seem redundant with the overall NERC program of
reporting and mitigation plan approval.
Individual
Agree
US Bureau of Reclamation
Individual
Agree
Florida Municipal Power Agency and Indiana Municipal Power Agency
Individual
No
While AEP would not argue against the definition of “Operating Instruction” as proposed, we object to
its inclusion as we disagree with the concept of requiring three part communications for more routine
operations. Our efforts in this regard should first be focused solely on Reliability Directives before
expanding this work, and creating similar requirements for all other Operating Communications.
Requiring three part communications for every scenario might be considered a best practice by some,
but making it a mandatory practice for routine operations emphasizes the manner of communications
rather than the operations themselves. In addition, requiring three part communication in such a
broader scope could actually diminish the perceived urgency during more urgent situations where
such communications are more appropriate. In any event, requiring three part communications for
Reliability Directives will likely result in more widespread usage for more routine operating
communications, without making it a requirement. AEP believes that there should not be multiple
project teams proposing concurrent changes to COM-001, COM-002, and COM-003. Unless there are
overwhelming reasons for not doing so, these efforts should be consolidated and managed by a single
project team. In addition, current efforts on COM-003 need to be co-located with the proposed
changes to COM-002 within a single standard. Having multiple project teams proposing concurrent
changes results in problems such as this, where a) changes are proposed to the same standard or b)
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similar changes are proposed to separate standards. AEP cannot support revisions on these matters
until they are managed by a single project team. If the team believes it should still proceed in their
current efforts, then there probably is no need for requiring three part communications for Reliability
Directives (COM-002 R2). As a result, COM-002 R2 should be retired and this definition should include
emergency situations as well.
No
AEP disagrees with the concept of requiring three part communications for more routine operations,
and as a result, also disagrees with requiring that entities have documented communication protocols
as proposed.
No
AEP disagrees with the concept of requiring three part communications for more routine operations,
and as a result, also disagrees with R3 and R4 which require that the entity shall implement a process
for identifying deficiencies with adherence to the documented communication protocols specified in
Requirement R1 and R2.
No
AEP disagrees with the concept of requiring three part communications for more routine operations,
and as a result, has no comment at this time on the proposed VRFs and VLSs.
AEP does not agree with the perceived necessity of this standard, but does support the overall
concept of the drafting team’s building controls into the standards as well as proposing RSAWs during
the comment that perpetuate the ideas and concepts of the drafting team.
Group
Wisconsin Electric Power Co.
James R. Keller
Wisconsin Electric Power Co.
Midwest ISO
The definition of Operating Instruction introduces a “Command” as opposed to COM-002 that defines
and requires identification of a “Reliability Directive”, yet there is no obligation to follow a Command
nor to identify the communication as containing a Command. Fatal flaw with the proposed definition.
The requirement to have a protocol is likely an ok approach with an objective to achieve well
understood communications and without the laundry list of things that must be in the document. Then
given the RC-BA-TOP have stringent training requirements in PER-005, duplicating the requirements
for good training and personnel proficiency evaluation lends itself to mandate a how to accomplish
this for a specific task. In addition, the type of oversight implied in COM-003 is overreaching by
NERC.
Group
Dominion
Connie Lowe
Dominion
No
Dominion requests clarification of “Command” verses “Directive”. Neither “Command” nor “Directive”
is defined in the NERC Glossary of Terms – some guidance/reference is needed. The word “command”
seems more forceful, how does a command differ from a directive?
No
We appreciate the SDT’s response to stakeholder comments in the previous draft, but still find subrequirements R1.1, R1.2, R1.3 to be too prescriptive. We agree that these entities should mutually
agree on (1) the language they will use to communicate and (2) the manner in which they will
communicate time (24 hour, zone, zulu, etc). Below are some additional suggestions; Dominion also
disagrees that Distribution Provider is listed as an Applicable Entity. Distribution Provider load is not
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considered part of a BES Element or Facility. The SDT response to an earlier comment on this issue
was that the SDT is aware of some DPs that operate BES equipment. If that is the case, then the
standard should be applicable to only those DPs that operate BES Elements or Facilities – not the
numerous DPs who do not. R2 should be clarified to read as follows: “For Distribution Providers, and
Generator Operators that operate BES Elements shall have documented communication protocols for
Operating Instructions that incorporate the following: R1.1 – In lieu of the English language
requirement, Dominion recommends defining the use of a common language for verbal or written
communications for Operation Instruction(s). English shall be the default language unless otherwise
mandated by the entity’s document or mandated by law, regulation, or mutual agreement. Under
R.1.2 and R1.1.3, It doesn’t matter (and may not be exactly clear) in what time zone the action will
occur. A transmission line can cross time zone boundaries. What is important is that all operators
involved have the same understanding of what is going to happen, when, and who is to do it. If a TOP
that operates in two different time zones already has a protocol that establishes one zone or the other
as their time standard, will they have to revise their protocol and use two different zones? Dominion
would recommend the following language to read as follows: Clock-time communications shall be
precise and include the following: Use of a 24-hour format or 12-hour format with AM/PM designation
Specification of the applicable Time-Zone when multiple Time-Zones are covered Specification of
Standard Time or Daylight Saving Time for Operating Instructions that will be implemented beyond
the present/current day R1.4 – This requirement is overly redundant as it is also covered by TOP-002
R18. Under R.1.8 and R.1.9, Dominion feels this would create an unnecessary burden to document
routine notifications that rely on a burst messaging system and do not have any effect on the Bulk
Power System. A one-way burst messaging system is typically used to quickly inform/advise. It is
designed as one-way to provide efficiency and should not be used for Operating Instructions. It would
be much simpler to state that, “for the communications of Operating Instructions (regardless of the
technology employed), the message must be repeated or confirmed by the recipient, and validated by
the sender.” This approach focuses on “Operating Instructions” and not the technology employed. The
requirement as currently written does not allow for exceptions due to routine or informative
communications. (Example: NERC Alerts to the Industry based are based on severity level and do not
always require receipt of message by the Registered Entity). R2 – Why not simply include DP and GOP
in R1? R4 – Why not simply include DP and GOP in R3? Dominion also recommends defining 3 Part
Communication in the NERC glossary as a result of this standard to help eliminate confusion. We need
to have the System Operator maintain a focus on reliability through precise communications without
unduly adding unnecessary requirements that create a burden without adding value. The mandatory
use of Time-Zones for parties communicating within the same Time-Zone, or the use of
Standard/Daylight Savings Time for current day activities adds an administrative burden with no
value to reliability.
No
No, Dominion does not agree that these requirements are needed. As part of any certification to R1
and R2, we would expect the entity to perform some sort of analysis to determine whether its
communication protocols meet the intent of the purpose stated for this standard. We do not believe
imposing a mandatory requirement to perform this analysis inherently increases reliability.
No
For the reasons cited in the comments above
Implementation plan – page 1; Revisions or Retirements to Approved Standard – Proposed
Replacement Requirement(s), states; “COM-003-1 Requirement R1 Part 1.1.1 R1. Each Balancing
Authority, Distribution Provider, Generator Operator, Reliability Coordinator, and Transmission
Operator shall have documented communications protocols that incorporate the following:”
Distribution Provider and Generator Operator needs to be removed, also after communications
protocols, ‘for Operating Instructions’ needs to be added (to match the R1 Requirement, if accepted
as written). Mapping document, Page 1; Comments, states: “R1 Each Balancing Authority,
Distribution Provider, Generator Operator, Reliability Coordinator, Transmission Operator, and
Transmission Owner shall have documented communications protocols that incorporate the following:
[Violation Risk Factor: Low] [Time Horizon: Long-term Planning ]” Distribution Provider and Generator
Operator needs to be removed. Also after communications protocols,'for Operating Instructions’ needs
to be added (to match the R1 Requirement, if accepted as written).
Individual
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Yes
Yes
Yes
Yes
While TAL is voting affirmative, we still have some reservations that Compliance Enforcement will cite
specific instances of non-3-way communications as violations. However, we are ready to codify the
need for standardized communications as defined in the purpose of the standard and Blackout
recommendation #26 and thank the drafting team for their hard work in avoiding a “zero-defect”
standard.
Individual
Agree
Midwest Reliability Organization (MRO) NERC Standards Review Forum (NSRF); AND Southwest Power
Pool (SPP) RTO
Group
MRO NSRF
WILL SMITH
MIDWEST RELIABILITY ORGANIZATION
No
Yes
Yes
The NSRF would like to thank the SDT for allowing entities to identify, assess, and correct deficiencies
per R3 and R4. The proposed COM-003-1 uses the verb of “issuing” in R1.1, 1.2, 1.3, 1.4, 1.5, 1.6,
and 1.8, and uses the verb of “receiving” in R1.7, 1.9, 2.1, and 2.2. Since these are real-time actions
and FERC Order 693, section 532 states in part, “This will eliminate ambiguities in communications
during normal, alert, and emergency conditions”, The NSRF recommends that the proposed definition
of Operating Instruction have the words “in Real-time” at the end of the definition. The definition of
System Operator also uses the term in real time in its definition. R1.3 Some entities already have an
agreed upon time zone standard such as MISO. MISO operates on Eastern Standard Time (EST) and
has a business practice manual stating that. Suggest the requirement be modified to state: “that
unless the operating entities already have an agreed upon operating time zone” then operations
occurring across time zone boundaries should include a time-zone designation. R1.5 Naming
conventions for terminal equipment can be long. For example, switch, P2ZDQEN. In a switching order,
this switch name may be mentioned several times and with each communication there is a required
echo. The Alpha-numeric requirement is a one-size fits all solution and is not needed in all situations.
Recommend the following as an alternative to the above language; The risk of unclear communication
is addressed by R1.6 and R1.7. R1.5 should be reworded to require alpha-numeric clarifiers when
reissuing an Operating Instruction to resolve a misunderstanding (per R1.6). R1.4 The SDT has not
made the case for the reliability benefit of the requirement for standardized names. Again, this
requirement is being retired from TOP-002. “TOP-002-2a Requirement R18 on the basis that “This
requirement adds no reliability benefit. Entities have existing processes that handle this issue.” This
requirement creates a compliance process where one is not needed. Each entity will be required to
document and maintain each facility name and who is the responsible owner for the facility name.
Suggest this requirement be removed. A list would be required for “every” element of the BES
between entities to assure that the proper names are used in all Operating Instructions. The NSRF
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does not see the reliability benefit of using this naming convention since TOP-002 is already
enforceable. R.1.8 and R.1.9, The NSRF feels this would create an unnecessary burden to document
routine notifications that rely on a burst messaging system and do not have any effect on the Bulk
Power System. A one-way burst messaging system is typically used to quickly inform/advise. It is
designed as one-way to provide efficiency and should not be used for Operating Instructions. It would
be much simpler to state that, “for the communications of Operating Instructions (regardless of the
technology employed), the message must be repeated or confirmed by the recipient, and validated by
the sender.” This approach focuses on “Operating Instructions” and not the technology employed. The
requirement as currently written does not allow for exceptions due to routine or informative
communications. (Example: NERC Alerts to the Industry based are based on severity level and do not
always require receipt of message by the Registered Entity). R1.8 states in part, ” When issuing an
oral Operating Instruction through a one-way burst messaging system…”. The NSRF does not
understand how an oral Operating Instruction can be made through a one-way messaging system?
Unless, the Operating Instruction was captured on an answering machine or on an un-listened to
voice mail message system. The NSRF views this as an electronic source to electronic source, as
explained in the “note to auditor” within the proposed RSAW states, “Communication that is
generated by an electronic source to another electronic source is not to be included as “oral or written
Operating Instruction”. If the NSRF is correctly assuming this, then no verbal or electronic
confirmation is required. Please clarify. R2. As stated in the Purpose statement, “To provide System
Operators uniform communications protocols that reduce the possibility of miscommunication that
could lead to action or inaction harmful to the reliability of BES.” The NSRF concurs with this
statement but questions why “all” DPs and GOPs are included in COM-003-1, Applicability section?
The NSRF recommends that the Applicability section have 4.1.2 updated to read ”For Distribution
Providers, and Generator Operators that operate BES Elements shall have documented
communication protocols for Operating Instructions that incorporate the following”. On page 7, under
Severe VSL it states: “The responsible entity did not include Parts 2.1 to 2.3 (3) of Requirement R2,
in their documented communication protocols”, part 2.3 does not exist, please clarify if this is to
mean “part 2.2”? The NSRF recommends R3 to be updated to state: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall implement R1 in a manner that identifies,
assesses, and corrects deficiencies, if any. Where the entity is identifying, assessing, and correcting
deficiencies, the entity is satisfactorily performing the requirement. Justification for R3. The above
rewrite requires implementing a deficiency process, which puts the focus of R3 on a deficiency
process and not on implementing R1. The proposed language changes says to implement R1 and does
not require a specific process for deficiencies. This is consistent with CIP standards Version 5 draft 3
and Generally Accepted Government Auditing standard strategies (the yellow book or GAGAS). The
proposed second sentence provides clarity on satisfactory performance expectations in the
requirement. Note this proposed language should also be applied to R4.
Individual
ACES Power Marketing
No
See ACES comments.
No
See ACES comments. Additionally, if it is determined that all of the elements need to be kept in the
standard, the list of elements needs to be improved. Some of the elements are noun phrases (e.g.,
1.1 and 1.2) and some are instruction statements. All elements should be noun phrases. It is
grammatically improper for a list to have more than one type of phrase and, more significantly, may
lead to confusion about compliance obligations. Instruction statements could be construed to require
perfect performance of those elements, but that does appear to be the intent of the SDT.
No
See ACES comments.
No
See ACES comments.
See ACES comments.
Individual
Agree
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Consolidated Edison and Northeast Power Coordinating Council
Individual
Agree
ATC endorses and supports those comments submitted by the Edision Electric Institute(EEI)on behalf
of ATC and other REAC members.
Group
Hydro One
Sasa Maljukan
Hydro One Networks Inc.
Yes
No
− We request clarification on the rationale for limiting communication protocol requirements for DPs
and GOPs. We believe that the communication protocol should contain essentially the same elements
regardless of the function an entity performs. Consequently, we recommend combining R1 and R2 to
state: “Each responsible entity (BA, RC, TOP, DP, GOP) shall have documented communication
protocols for the communication of Operating Instructions. This protocol should contain following
elements: ...” − In order to improve readability we recommend that the Sub-Requirements R1.1
through R1.9 be re-arranged and grouped. For example, R1.7 and R1.9 deal with information
receiving. They should be combined into one with two sub-requirements or bullets. The same can be
done with R1.3, R1.6 and 1.8 which deal with issuing Operating Instructions. − Requirement 1.6: We
suggest that for clarity purposes the SDT rewords the first bullet as follows: ”Confirm that the
recipient’s response of the Operating Instruction as per R1.7 was accurate, or” − Requirement 1.9:
The requirement asks the recipient to request clarification when the communication is not understood.
We believe that the requirement is not measurable and as such it should be deleted. Additionally, it
represents common sense because in any type of communication if one party does not understand all
or part of the conversation, it is natural that he/she will ask for clarification. − Requirement 2.2:
Hydro One recommends deleting this section for the same reasons mentioned in our comment for
Requirement 1.9 (measurability). − It must be made clear in the requirements that functional entities
can incorporate exceptions in their protocols, for example, to address emergencies. As proposed, both
of these requirements are too prescriptive. The sub-requirements drill down too deeply into the
communications needed to conduct system operations.
No
− It is unclear what identified reliability gap this Standard development project is intending to
address, given the recent adoption of the new COM-002-3 along with the OC white paper on
communications protocols. − Hydro One believes that, as written, the requirements are too
prescriptive. We think that the SDT should concentrate and focus on specifying WHAT is required to
achieve the reliability objective of the standard rather than on HOW to go about achieving such
objective. With this in mind, we recommend deleting R3.1 through R3.4 and R4.1 through R4.4.
Additionally, in line with our comment regarding R1 and R2 we believe that these two requirements
should be combined as well. We would like to propose following wording: “Each responsible entity
shall develop and implement a process for identifying and addressing deficiencies found in the
adherence to the documented communication protocol specified in Requirements R1 and R2.”
Yes
The white paper written by the OC addressed the issues covered by this Standard.
Individual
No
See response to question 5.
No
See response to question 5.
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No
See response to question 5.
No
See response to question 5.
(1)We believe the drafting team has made some great strides to get this to be a useful standard for
industry. The idea that we have a process for self-correction instead of self-reporting is a good
concept. However, the reasons for our “No” vote is that the current wordings in the latest draft still
need some changes to provide clarification. In this regard, we agree in principle with alternate
language provided by NextEra (which we have modified slightly) and have also provided additional
clarifying comments and recommendations. (R1) When a Reliability Coordinator, Transmission
Operator or Balancing Authority requires actions to be executed as an Operating Instruction, the
Reliability Coordinator, Transmission Operator or Balancing Authority shall identify the action as an
Operating Instruction to the recipient. (R2) Each Balancing Authority, Transmission Operator,
Generator Operator, and Distribution Provider that is the recipient of an Operating Instruction shall
repeat, restate, rephrase or recapitulate the Operating Instruction. (R3) Each Reliability Coordinator,
Transmission Operator, and Balancing Authority that issues an Operating Instruction shall either:
(a)Confirm that the response from the recipient of the Operating Instruction (in accordance with
Requirement (R2) was accurate, or (b) Reissue the Operating Instruction to resolve any
misunderstandings. (2)Along with the revised language proposed above, we request the drafting team
to clarify the concept of what constitutes an Operating Instruction (or command) because the current
understanding is too broad. We strongly believe that it should focus only on instructions related
directly to BES reliability and which are not considered Reliability Directives covered under COM-002,
and that it should not include normal or routine dispatching instructions of generators. (3)Given the
revised language proposed in comment (1) above, the definition of Operating Instruction should be
revised to replace the term 'System Operator' with 'Reliability Coordinator, Transmission Operator, or
Balancing Authority', since these functions are the ones who will initiate the Operating Instruction.
(4)"Transmission interface Element" and "Transmission interface Facility" both are not in the NERC
glossary as defined terms and they need to be added to the NERC glossary or clearly defined in the
standard. (5)We suggest a 24 month Implementation Plan upon approval of COM-003. This would
allow Registered Entities time to develop their compliance processes. (6)We request that the drafting
team consider the possibility of substituting the CIP v.5 'zero defects' language in COM-003 in order
to minimize potential confusion. (7)We request that any of the "violations" shown in the VSL table on
pages 7, 8, and 9 should not qualify for a high or severe level and at the most these should either be
categorized as low or, but no more than, moderate level. (8)In the VSL table for R2, in the column
under Severe VSL, it states that "The responsible entity did not include Parts 2.1 to 2.3 (3) of
Requirement R2…" Requirement R2 does not have a Part 2.3, only 2.1 and 2.2. (9)If the drafting
team retains the current language we are concerned about the prescriptive language in R1 and R2.
We request that the drafting team in both R1 and R2 have the word “incorporate” changed to
“consider” or “address”, thereby making the requirements less prescriptive.
Group
Associated Electric Cooperative Inc - JRO00088
David Dockery - NERC Reliability Compliance Coordinator
Associated Electric Cooperative Inc - NCR01177
No
The Operating Instruction definition is no help beyond the “existing” Operating Command definition,
as the later exists neither within the NERC Glossary downloaded this morning, 9/20/2012, nor within
the Clean COM-003-1 copy downloaded for final review. The proposed Operating Instruction definition
would add value, were the BES Definition itself properly scoped to only those assets and functions
that undoubtedly affect the reliable Operation of bulk power system. However the BES Definition is,
by NERC and FERC desire and design, too broad, and so our industry must now attempt containment
of compliance scope and risk within multiple standards, including COM-003-1. As a result, AECI
determines this Operation Instruction definition to insufficient to responsibly exclude conversations
that have little to no effect upon the BES reliability.
No
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AECI believes the sub-parts of this requirement to be overly prescriptive, whereas communication
clarity should be the stated requirement. The sub-parts should appear only as examples of elements
to be considered for improving clarity. Less is better, as evidenced by additional qualifiers already
necessary to sub-requirement R1.1. (see suggested language in comment 5 below.)
Yes
This could work, were wording per concepts already suggested per questions 1 & 2 and question 5,
such that the documented evidence of an effective program, precludes violations of any individual
requirement. In interest of providing our industry with greater consistency in wording and format
throughout future standards, AECI strongly suggests that this SDT review the current draft release of
CIP Version 5’s draft (for ballot), and similarly format these requirements. However please see AECI's
general observations concerning COM-003-1 in comment 5 below.
No
It could be appropriate, were the expectations properly bounded similar to the wording outlined for
Question 5 below.
In general, AECI believes that NERC and FERC should completely reevaluate the necessity of COM003-1. COM-003 still appears to overreach the cited 2003 blackout recommendation #26, whereas
industry-approved changes to COM-002 do meet the expectation, pertaining to verbal communication
protocols: “Tighten communications protocols, especially for communications during alerts and
emergencies..." However AECI also offers the following observations: 1) Recommendation #26 is
hardly top of the list. (Lessons-learned is that future industry recommendations really must be careful
in what they recommend for improvements, because those can and will be extrapolated into future
requirements.) 2) Recommendation #26 "especially" highlights alerts and emergencies, not normal
operational communications, yet the scope of COM-003 pertains to any normal communication that
would alter the state of anything BES, including mundane operational conditions that have
questionable effect upon the BES reliability. 3) In AECI's opinion, there is greater risk of noncompliance with this standard for the industry, than non-compliance with the NERC BOT in their
insistence to move it forward. The EEI suggested wording, recited below, helps to mitigate this risk,
but still at cost of additional and often unnecessary communication overhead. Specific to the wording
of COM-003-1 draft, AECI does believe the direction of EEI's wording, submitted in comment response
to this draft, could help the industry with mitigating some risk of non-compliance to the proposed
standard. In lieu of our being able to view EEI's posted comments, we recite them below::
========Begin the EEI draft as circulated in emails earlier this week========= R1. When a
Reliability Coordinator, Transmission Operator or Balancing Authority requires actions to be executed
as an Operating Communication, the Reliability Coordinator, Transmission Operator or Balancing
Authority shall identify the action as an Operating Communication to the recipient. R2. Each Balancing
Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the recipient
of an Operating Communication shall repeat, restate, rephrase or recapitulate the Operating
Communication. R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues an Operating Communication shall either: • Confirm that the response from the recipient of the
Operating Communication (in accordance with Requirement R2) was accurate, or • Reissue the
Operating Communication to resolve any misunderstandings. R4 Absent a possible violation that
resulted in (or could have resulted in) a significant risk to the Bulk Electric System, no violation of R1
or R3 and its subrequirements shall be found, provided that the Balancing Authority, Reliability
Coordinator, and Transmission Operator has implemented a process for identifying deficiencies with
adherence to the documented communication protocols specified in Requirement R1 and R3 that: 4.1.
Identifies potential deficiencies, 4.2. Assesses the deficiencies found, 4.3. Corrects the deficiencies,
and 4.4. Evaluates the process based on deficiencies found external to Part 3.1 and either ∙
implements modifications to the process when the evaluation determines that modification of the
process is necessary to address the deficiencies found; or ∙ demonstrates that no modification to the
process is necessary to address the deficiencies. R5 Absent a possible violation that resulted in (or
could have resulted in) a significant risk to the Bulk Electric System, no violation of R2 and its
subrequirements shall be found, no violation of R2 and its subrequirements shall be found, provided
that the Distribution Provider and Generator Operator shall implement a process for identifying
deficiencies with adherence to the documented communication protocols specified in Requirement R2
that: 5.1. Identifies potential deficiencies, 5.2 Assesses the deficiencies found, 5.3. Corrects the
deficiencies, and 5.4. Evaluates the process based on deficiencies found external to Part 3.1 and
either ∙ implements modifications to the process when the evaluation determines that modification of
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the process is necessary to address the deficiencies found; or ∙ demonstrates that no modification to
the process is necessary to address the deficiencies. ========End the EEI draft as circulated in
emails earlier this week=========
Individual
No
The definition of the new term, “Operating Instruction,” uses the NERC Glossary term “System
Operator,” which is defined as “An individual at a control center…whose responsibility it is to monitor
and control that electric system in real time.” The lack of clarity regarding what constitutes a control
center leaves doubt as to which instructions would be covered by the standard. Another disagreement
with the proposed definition of “Operating Instruction” is that it inappropriately imposes three-part
communication for routine communications of changes of generation output. Common operating
communications to and from generation plants should not be considered compliance events requiring
the use of alphanumeric clarifiers. Such a requirement may shift operators’ focus from providing
proper information under critical situations to using the specified terms for every minor
communication, distracting them rather than sharpening their concentration. The standard should
specify the classes of TO/TOP-to-GOP communications that constitute compliance events, the formal
designations by which such communications can be recognized, and the parties authorized to issue
such commands.
No
Clarification is needed regarding what GOP procedures are to cover, ref. our comments to question
#1 above.
No
There is no statement of periodicity in R4, leaving entities guessing until the time of audit regarding
the criteria for sufficient review. R4 is also open-ended regarding scope, potentially requiring review
of every voice communication for every plant for the audit period. Everyday communications do not
merit such scrutiny, which would reduce rather than improve the attention that can be given to
matters of significance. All standards (not just COM-003-1) should clearly specify pass/fail criteria and
the associated evidence requirements. R4 should be split into DP and GOP sections, with the GOP
requirement being: R4. Each Generator Operator shall conduct in each calendar year a review session
with the operations function for registered entities, regarding the documented communication
protocols specified in Requirement R2. Corrective action shall be implemented and documented for
any potential deficiencies coming to light as a result of this review.
No
The VRFs and VSLs are divided into long-term planning and operation planning categories. These
terms are not explained in the standard, so the difference between them is unclear. They do suggest
however that, in accordance with our comment #1 above, this standard is not meant to apply to
routine transmission system operator-to-plant communications.
The SDT received many comments questioning the need for the standard. They are relying on a single
EPRI study that claims 19% of 400 studied switching errors (76 events) resulted from
miscommunication, but this statistic is meaningless without context. Specifically: -Did any of these 76
events involve GOPs? If not, is it appropriate to make COM-003-1 applicable to these entities at all,
much less for routine communications of minor importance? -How many events involved oral
communication, vs. written miscommunication? Of the oral miscommunications, how many involved
miscommunication between separate entities, as opposed to internal entity miscommunication? After
all, internal miscommunications, which may be the vast majority of the events, will not be covered by
the standard.
Group
ISO/RTO Standards Review Committee
Albert DiCaprio
PJM
No
The proposal to standardize the meaning of "Operating Instruction" will likely cause more problems
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than it solves. The concept of “to change or preserve the state, status…” is ambiguous enough for
CEAs to still apply the requirement to virtually all verbal conversations. Such a proposed definition
may help clarify what the SDT intends to address, however, by making such a common word a
Glossary term potentially will result in the Industry having to redefine their own manuals and
procedures in which they use the phrase "Operating Instruction". For years, system operators have
dealt with operating instructions on a daily if not minute basis. To them, operating instructions are
necessarily a communication to alter or preserve the state and status of the BES condition or BES
Element/Facility. Having a defined term, and calling such communication a “Command” is totally
unnecessary, and can confuse operators from what they understand to be the meaning of operating
instructions. Any proposed standard must clearly limit the application of the communication protocol
requirements to communications that impact reliability. As proposed, the standard does not do this.
Based on the existing language and the proposed Defined term Operating Instruction, the scope could
readily be interpreted to include numerous communications that have nothing to do with system
reliability. To remedy this, the SDT should either revise the proposed term in accordance with Order
693’s limited scope, or delete this term and focus the standard on reliability directives, which is in line
with Order 693.
No
The SRC fully supports the concept that certain aspects of our business are better viewed based on
the internal controls used by the entity. The SRC recognizes that the intention of the SDT is to be
flexible. However, the nature of a standard is to eliminate that flexibility by not addressing how
compliance will be monitored in the controls approach and by prescribing specific items for inclusion
in the protocols. An entity is less likely to create a highly sophisticated best practice protocol if the
RSAW subjects that entity to penalties for implementing that protocol. While presenters at the COM003 Webinar presentation stated that violations are not based on implementing the steps of the
protocols, the draft RSAW (dated July 2012) states: If the CEA finds in subsequent, follow up audits
or other compliance monitoring activities that the same or similar deficiencies continue to occur after
the entity was provided the feedback by the CEA, the CEA will seek to understand what changes the
entity made to their process based on prior recommendations. If changes to the entity’s process are
not implemented to identify, assess and correct deficiencies, the Auditors may make a determination
of possible non‐compliance with Requirement 3, Part 3.4. The proposed requirements (R1 and R2) are
a significant improvement from the previous postings. Requirement R1 is still too prescriptive. The
elements within R1 make the requirement a checklist of rules and do not add to the reliability of the
power system and do not address the reliability needs requested in Recommendation 26 and Order
693. The reliability need for clear protocols was in reference to “situational awareness” issues (i.e.
when is the system in jeopardy and who makes that decision to respond - See references provided
below). The reliability need was not related to common verbal mistakes. The proposed requirements
do not address those needs. The SRC believes that IRO-016-1 does address those issues and needs.
2003 Blackout Report Section: Data Exchanged for Operational Reliability (pages 50-51) Voice
Communications: Voice communication between control area operators and reliability is an essential
part of exchanging operational data. When telemetry or electronic communications fail; some
essential data values have to be manually entered into SCADA systems, state estimators, energy
scheduling and accounting software, and contingency analysis systems. Direct voice contact between
operators enables them to replace key data with readings from other systems’ telemetry, or surmise
what an appropriate value for manual replacement should be. Also when operators see spurious
readings or suspicious flows, direct discussions with neighboring control centers can help avert
problems like those experienced on August 14, 2003. SRC COMMENT - This is clearly focused on
establishing communications where they potentially may not occur. It is not focused on prescribing
particular terminology or protocols based on the belief that existing practices are inadequate. Page
109 Effectiveness of Communications Under NORMAL conditions, parties with reliability responsibility
NEED TO COMMUNICATE important and prioritized information to each other in a timely way, to help
preserve the integrity of the grid. This is especially important in emergencies. During emergencies,
operators should be relieved of duties unrelated to preserving the grid. A common factor in several of
the events described above was that information about outages occurring in one system was not
provided to neighboring systems. SRC COMMENT - The above discussion is not related to terminology
or repeating information. The concern focuses on the failure to provide appropriate information,
which, as discussed above, as well as in Order 693, is focused on “important” and “prioritized”
information. This is a limited set of communications that the proposed standard’s new term Operating
Instruction exceeds in scope. Pages 161-162 26. Tighten communications protocols, especially for
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communications during alerts and emergencies. Upgrade communication system hardware where
appropriate. NERC should work with reliability coordinators and control area operators to improve the
EFFECTIVENESS of internal and external communications during alerts, emergencies, or other critical
situations, and ENSURE that all key PARTIES, including state and local officials, RECEIVE timely and
accurate information. NERC should task the regional councils to work together to develop
communications protocols by December 31, 2004, and to assess and report on the adequacy of
emergency communications systems within their regions against the protocols by that date. On
August 14, 2003, reliability coordinator and control area communications REGARDING CONDITIONS in
northeastern Ohio were in some cases ineffective, unprofessional, and confusing. INEFFECTIVE
COMMUNICATIONS contributed to a LACK OF SITUATIONAL AWARENESS and PRECLUDED EFFECTIVE
ACTIONS to prevent the cascade. Consistent application of effective communications protocols,
particularly during alerts and emergencies, is essential to reliability. Standing hotline networks, or a
functional equivalent, should be established for use in alerts and emergencies (as opposed to one-onone phone calls) to ensure that all key parties are able to give and receive timely and accurate
information. [SRC COMMENT: Recommendation 26 is clearly about communicating information about
“conditions” and not about communicating the commands to a particular “asset”. The proposed
standard is unresponsive to the issues raised in the Blackout and by FERC. By not addressing the core
reliability issues raised by the very report that drove this Project, the SDT is jeopardizing the
reliability of the power system. The SRC strongly urges the SDT to reconsider this posting and to
either rescind the Project and accept that IRO-016-1 has adequately responded to the Blackout
Report, or to revise its proposal to directly address the issues noted above. If R1 is not rescinded as
suggested above, then the prescriptive subparts 1.1 thru and including 1.6 should be removed.
No
The SRC fully supports the concept that functional entities’ internal controls be used to monitor the
effectiveness of their own protocols. The SRC suggests that any requirement to implement a plan may
significantly reduce the incentives to create more effective protocols because of the Compliance
uncertainty related to measuring effective internal controls. Requirement 3 requires entities to
implement their process and to identify deficiencies with adherence to the protocol. The less complex
a plan is the lower the number of deficiencies and therefore the lower the number of reports.
Moreover, the RSAW states that the applicable entity could be found non-compliant if the entity did
not follow an auditors suggested changes to remedy those deficiencies. Thus this standard would
incent writing simple protocols.
No
The SRC does not agree with the VSLs of R3 and R4 . The SRC feels that it is not binary and actually
fits the Requirements with Parts that Contribute Unequally to the Requirement in the VSL guideline
document. While part 3.3 is the most critical, an entity would certainly not get any reliability benefit if
you don’t do parts 3.1 – 3.3 or 3.3 in itself, which could be a severe VSL. But if an entity performs
parts 3.1 – 3.3 and does not perform part 3.4, it should not be a severe VSL because you are getting
a substantial amount and majority of the reliability benefit from performing 3.1-3.3. Failure to do part
3.4 should be a high VSL perhaps, but it is not all binary. If an entity fails to do 3.2, it may be a
medium only.
The SRC requests that the SDT include a milestone in the implementation plan that requires NERC
and the industry to reach agreement on how internal controls will be monitored by the CEAs BEFORE
this standard is effective. The SRC believes that this standard could be improved by modifying the
subparts of R1 and R2 to include parts that are communication protocols directly relevant to the
improving situational awareness and shortening response time. Requirements R1.1, 1.2 in theory
shorten response time by providing a commonly understood language and clock format for Operating
Instructions but are unnecessary in practice. The modification includes the removal of: • R1.3 as it
does not improve situational awareness or shorten response time. This is such a small population of
Operating Instructions and any real time Operating Instructions will be immediate. This is overly
prescriptive and provides little if any reliability benefit. This is not a documented reliability concern in
any investigation, FERC Order, Blackout report, etc. that the SRC is aware of. • R1.4 as it does not
improve situational awareness or shorten response time. It may actually confuse entities that have
established practices that may have to make changes to accommodate this requirement part. This is
overly prescriptive and provides little if any reliability benefit. This is not a documented reliability
concern in any investigation, FERC Order, Blackout report, etc. that the SRC is aware of. • R1.5 as it
does not improve situational awareness or shorten response time. It may actually confuse entities
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that have established practices that may have to make changes to accommodate this requirement
part. This is overly prescriptive and provides little if any reliability benefit. This is not a documented
reliability concern in any investigation, FERC Order, Blackout report, etc. that the SRC is aware of. •
R1.6 and R1.7, and 2.1 as it does not improve situational awareness or shorten response time. It
actually lengthens response time and does not improve situational awareness as it does not address
the content of the communication. This is already addressed through COM-002-3 and will only add to
confusion for entities to have a COM-003-1 requirement in the overlap it creates. This is not a
documented reliability concern in any investigation, FERC Order, Blackout report, etc. that the SRC is
aware of where lack of 3 part communication directly contributed to a adverse reliability impact on
the BES. The NERC OC established guidelines that outline best practices for industry and are sufficient
to communicate such best practices. As the drafting team has communicated in its previous white
paper, a significant amount of industry already employs 3 part communication during normal and
emergency situations. Requirements R1.8, 1.9, and 2.3 could shorten response time by providing a
protocol for quickly disseminating information from one to multiple parties. The drafting team should
craft the standard to address communication between functional entities and not within entities to
properly address FERC Order and Blackout Recommendation that clearly speaks to communication
protocols between entities. To not do so is expanding upon the scope of the SAR, creates confusion,
and is not focusing on the reliability concerns cited in the FERC Order 693 and Blackout Report
Recommendation #26. The draft RSAW introduces subjective concepts as well as a new requirement.
An auditor is to: • The CEA is to … • Understand the process …. • The CEA is to review a sample of
the entity’s communication activities to verify whether the entity is identifying, assessing,
communicating and correcting deficiencies. If the entity had implemented corrections, the sample is
to be pulled from activities conducted after any corrections to the entity’s process were implemented
or, if the correction had been recently implemented, the CEA is to consider the impact the correction
will have when reviewing the samples. This sample size will be based on the auditor’s confidence in
the entity’s ability to identify, assess, and correct its deficiencies. • Where the auditor … • If an
auditor cannot verify that the entity is adequately identifying [SRC: suggest changing “is” to “is not”],
assessing, and correcting its own deficiencies due to limitations in its process, the auditor will not
have a finding of non‐compliance. The auditor will provide the entity with recommendations as
necessary. If the CEA finds in subsequent, follow up audits or other compliance monitoring activities
that the same or similar deficiencies continue to occur after the entity was provided the feedback by
the CEA, the CEA will seek to understand what changes the entity made to their process based on
prior recommendations. [“same or similar deficiencies” is subjective and opens the compliance to CEA
vision of what is “similar”.] New Requirement: If the CEA finds in subsequent, follow up audits or
other compliance monitoring activities that the same or similar deficiencies continue to occur after the
entity was provided the feedback by the CEA, the CEA will seek to understand what changes the
entity made to their process based on prior recommendations. If changes to the entity’s process are
not implemented to identify, assess and correct deficiencies, the Auditors may make a determination
of possible non‐compliance with Requirement 3, Part 3.4.
Group
Southern Company
Antonio Grayson
Operations Compliance
No
Southern does not agree with the definition of “Operating Instruction” as it continues to be too broad
and encompass routine communications between System Operators and other system personnel and
other functional entities. While Southern agrees that 3-part communications is a good utility practice
that has been used by operating entities for many years, Southern disagrees with the broadness of
“Operating Instructions” as in some of these cases, 3-part communications are not required to protect
the reliability of the system. In fact, this prescriptive requirement, if used on all communications that
could fall under “Operating Instructions” (i.e. very general information at times), would take System
Operators time from other tasks that are more critical to maintaining reliability. Please note that there
are numerous (i.e. in the millions) of conversations between operating entities each year and some
important tasks could be missed or delayed if required to follow a standard script for everything. If
the SDT agrees with Southern’s comments related to Requirements 1 and 2, then the definition of
“Operating Instruction” would be unnecessary as each operating entity would define the times when
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3-part are necessary, which in Southern’s case, would be broader than emergency communications
and reliability directives, but not so broad that it would cover general exchange of information
between operating entities.
No
Southern supports having a documented communications protocol, but we do not support the
prescriptive elements of this version of the standard. The protocols should give the entity the
flexibility to define the conditions where they expect 3-part communications and the verbal cues they
use to tell the recipient they expect 3-part communication or that action is required. Southern
suggest the following changes to R1 and R2 and could support these changes in future drafts of this
new standard.
Yes
Provided that the SDT incorporate the changes suggested for R1 and R2, Southern generally agrees
with the concept of implementing a process to identify and correct deficiencies without compliance
exposure for each deficiency. However, this is a new concept and we do have questions as to how it
will be implemented. For example, how many discrepancies would it take for an entity to identify
before requiring a self report rather than waiting to present the log of deficiencies found and
corrected during an audit?
Yes
While Southern agrees that 3-part communications is a good utility practice that has been used by
operating entities for many years, Southern disagrees with the broadness of the types of
communications the SDT is suggesting for requiring 3-part communications. In some of these cases,
3-part communications are not required to protect the reliability of the system. In fact, this
prescriptive requirement, if used on all communications that could fall under “Operating Instructions”
(which can be very general information at times), would take System Operators time away from other
tasks that are more critical to maintaining reliability. Please note that there are numerous (i.e. in the
millions) of conversations between operating entities each year and some important tasks could be
missed or delayed if required to follow a standard script for everything.
Individual
No
Previous version has a description regarding Reliability Directives. This version does not address
Reliability Directives and the relationship to an Operating Instruction. Is a Reliability Directive a
subset of Operating Instruction? Is a “directive,” as mentioned in several standards, an Operating
Instruction?
No
This Standard does not address electronic Operating Instructions, thus creating a possible gap. For
example, ERCOT (acting as the BA) uses ICCP links to issue electronic dispatch instructions to
generators (ERCOT Protocol 6.5.7.4). The recipient of the electronic dispatch instruction must
acknowledge receipt of the dispatch instruction to ERCOT electronically, within one minute and must
include the receiving operator’s identification with the electronic acknowledgement (ERCOT Protocol
6.5.7.8(5)). ERCOT regional rules have similar language as current NERC standards regarding
compliance with dispatch instructions, which include electronic dispatch instructions (ERCOT Protocol
6.5.7.9). Consider adding “Reliability Coordinator” or “Functional Entities” in 1.1 statement where
TOPs and BAs are singled out: "Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.”
No
If a deficiency is identified and then training is provided to attempt to correct it, what happens if the
same deficiency is identified again? Is the entity considered to have failed to correct its identified
deficiency? Does the entity need to file a self report when the second deficiency occurs? Texas RE
agrees with the premise of having a process for identifying issues, but at some point if a pattern of
deficiencies continues, when does a violation occur?
No
R2 Severe VSL references “Parts 2.1 to 2.3 (3)” when a “2.3” does not exist (this issue is also in the
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VRF/VSL Justification document). The VSLs for R3 and R4 say nothing about assessing and correcting
identified deficiencies per 3.2, 3.3, 4.2 and 4.3.
(1) Requirements R2 and R4 should also apply to Load-Serving Entities (TOP-001-2 R1, VAR-001-3
R5), Purchasing-Selling Entities (VAR-001-3 R5), and Generator Owners (VAR-001-3 R11, VAR-0021.1b R5) so that all entities receiving Operating Instructions are covered. For M3 and M4 the process
should be included as well as results. (2) Capitalize “responsible entity” in VSL language for R1 and
R2 as was done in R3 and R4. (3) RELIABILITY GAP: We believe a reliability gap exists because no
standard generally requires compliance with Operating Instructions, Reliability Directives and other
valid instructions. We realize this issue may be considered to be outside of the scope of this project,
but we are quite concerned that reliability is compromised because operating entities can elect to
ignore valid instructions for economic or other reasons, and that much more attention is being given
to the form of the instructions than to requiring that they be obeyed. VRF/VSL JUSTIFICATION: (4) In
the VRF/VSL Justification document there is only reference to 3 requirements in the COM-003-1
Standard (page 5). There are 4 requirements. (5) The “Low” VRF rating for R1 and R2 seems
unjustified based on the following points: 1) In the VRF/VSL Justification document there is the
following statement at the top of page 5: “Requirements R1, R2 and R3 were assigned a “Medium”
VRF.” 2) In the Rationale and Technical Justification document there is the following statement:
”Because Operating Instructions affect Facilities and Elements of the Bulk Electric System, the
communication of those Operating Instructions must be understood by all involved parties, especially
when those communications occur between functional entities. An EPRI study reviewed nearly 400
switching mishaps by electric utilities and found that roughly 19% of errors (generally classified as
loss of load, breach of safety, or equipment damage) were due to communication failures. This was
nearly identical to another study of dispatchers from 18 utilities representing nearly 2000 years of
operating experience that found that 18% of the operators’ errors were due to communication
problems.” If there is not a process, would there not be more errors? 3) In the VRF/VSL Justification
document there is the following statement: “In the VSL Order, FERC listed critical areas (from the
Final Blackout Report) where violations could severely affect the reliability of the Bulk-Power System”
and “Communication protocol and facilities” is listed. R1 and R2 attempt to address this issue. (6) In
the VRF and VSL Justification document, at page 15 and page 20, the FERC VRF Guideline 3
Discussion is inconsistent with R3 and R4 language respectively (R3 and R4 do not call for “use of
formal three part communication”).
Individual
MidAmerican Energy supports MRO NSRF comments
No
MidAmerican has concerns that Operating Instructions as defined is too broad.
Yes
Yes
Yes
MidAmerican would recommend the following changes to R3 as a primary consideration to allow COM003-1 to move forward. COM-003 is only acceptable as a non-zero defect standard. R3 should be
rewritten as follows: Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement R1 in a manner that identifies, assesses, and corrects deficiencies if any. Where the
entity is identifying, assessing, and correcting deficiencies, the entity is satisfactorily performing the
requirement. Make similar changes to R4. R3 as posted requires implementing a deficiency process,
which puts the focus of R3 on a deficiency process and not on implementing R1. The proposed
language changes focus the requirement to implement R1 and does not require a specific process for
deficiencies. This is consistent with CIP standards Version 5 draft 3 and Generally Accepted
Government Auditing standard strategies (the yellow book or GAGAS). The proposed second sentence
provides clarity on satisfactory performance expectations in the requirement.
Individual
Agree
We agree with and support the comments submitted by NPCC, the SRC, and ERCOT.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Yes
Yes
Yes
Yes
Puget Sound Energy appreciates the opportunity to submit comments on the proposed standard, as
well as the work of the standards drafting team in developing a workable approach to the
implementation of operating communication protocols. The purpose statement in the proposed
standard uses the term "System Operators". As defined in the NERC Glossary, System Operators
include individuals who work for Balancing Authorities, Transmission Operators, Generator Operators
and Reliability Coordinators. However, the standard also applies to Distribution Providers, an entity
not covered by the term System Operator. As a result, I recommend that the standard drafting team
expand the purpose statement to accurately reflect the applicability of the standard. Perhaps the
statement could be revised to begin "To provide individuals who may issue or receive Operating
Instructions with uniform communications protocols...".
Group
APPA, LPPC and TAPS
Allen Mosher
American Public Power Association
Yes
Yes
Yes
In response to comments received during the last comment period and in an effort to draft a standard
that focuses on risk control rather than zero tolerance metrics, the drafting team has taken a new
approach to COM-003-1. This version requires responsible entities to establish communication
protocols and then implement a process for identifying, assessing, and correcting deficiencies with
adherence to those communication protocols. This new standard is drafted such that the entity is to
ensure that its process is working, rather than requiring the demonstration of absolute compliance
with communication protocols at all times and identifying each deficiency as a possible violation. In
addition, this version of the standard was drafted in conjunction with the development of the
Reliability Standard Audit Worksheet (RSAW). The parallel development of the standard and the
RSAW provided the opportunity for the drafting team to consider the compliance implications of the
language in the standard and to offer input into the language of the RSAW. APPA staff, LPPC and
TAPS have reviewed the proposed standard and have not identified any material concerns and
support the drafting team's new approach. We of course urge the drafting team to give full
consideration to all substantive comments on the proposed standard and RSAW. We do anticipate that
commenters will identify editorial changes that will clarify the proposed standard. Such changes are
unlikely to affect our support for the standard.
Group
FirstEnergy
Sam Ciccone
FirstEnergy Corp.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
Although we believe the definition is on the right track, the wording may inadvertently cover many
conversations between operators and personnel that do not impact the reliable operation of the BES.
We ask the team to consider clarification, examples, or inclusions/exclusions much like the new
definition of BES. For instance, tasks that may involved transmission lines associated with IROLs or
SOLs, and other critical tasks.
No
We support many of the protocols as a minimum to standardize communications across the industry.
However, we believe some of the sub-parts of R1 contain language which may be too prescriptive and
in some cases language is missing for special situations. ♣ 1.2 – We understand the importance of
knowing the time of day but an operator can specify “am” or “pm” instead of using the 24 clock
format. The requirement should be less prescriptive to allow this. ♣ 1.3 – This requirement as written
may confuse the parties communicating. We suggest it be reworded in a simple fashion as follows:
“Assure both parties understand the correct time being used in the communication.” ♣ When the
receiver of an operating instruction is unable to comply they should be allowed to notify the operator
of the restriction (e.g. based on safety, loss of life, or damage to equipment) so that the operator is
able to implement other actions to perform the desired operation. This should be added in the
language requiring three-part communication in requirements R1 and R2.
Yes
FirstEnergy supports this new concept being introduced by NERC. It allows entities to sharpen their
internal controls while not being penalized for minor non-compliance situations that do not impact the
BES. The only question we raise is how this will be implemented in the CEAP. The draft RSAW for
COM-003-1 is silent on this issue and we ask that NERC give more guidance on it as this paradigm
develops.
Yes
♣ To have clear communication protocols NERC must develop clear and concise standards that include
non-prescriptive language that provides entities with the latitude to operate their systems as they are
accustomed to while requiring a heightened awareness of the importance of clear communications
while operating those systems. From discussions in various industry forums, there seems to be much
confusion as to the intent of COM-003 versus COM-002. For instance, is a Reliability Directive as
defined by the Project 2006-06 team in COM-002-3 a subset of an Operating Instruction as defined in
COM-003-1? If so, then we recommend the retirement of COM-002-3 as a standard since COM-003-1
covers all communications. One standard that requires 3-part communication is sufficient and no
reliability gap would exist if COM-002-3 is retired. FE and the industry want to contribute to effective
reliability and believe tight standardized communication protocols are critical. But if confusion and
needlessly burdensome requirements result from the development of these COM standards, we
believe this could have an adverse affect on reliability. In COM-002-3, requiring an operator to pause
to determine if he or she should utter the phrase “this is a Reliability Directive” can escalate an
emergency situation and not help alleviate it. Regardless of the situation, when the Operator issues a
command it must be carried out by the receiver with confirmation that the receiver has understood
what needs to be done and when it needs to be done. COM-003-1, with some wording adjustments,
accomplishes this reliability goal. We support COM-003-1 Draft 3, on its own without COM-002-3,
along with some adjustment to requirement language to relieve prescriptiveness and needless
language while adding some clearer guidance on the internal control requirements detailed in R3 and
R4. ♣ The measures as proposed simply reiterate the requirement and provide no useful information.
We suggest they either be removed or be elaborated to include useful examples of evidence and
possibly incorporate some of the information found in the RSAW.
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Nowhere in the Blackout Report, Order 693, nor the SAR does it indicate that communication
protocols used during normal and emergency operations need to be identical - only that there are
standardized communications for normal operations and standardized protocols for emergency
communications. The term Operating Instruction as included in the requirements of the draft standard
does not take into consideration that communications during alert or emergency conditions have a
heightened need to be effective (Blackout Report Recommendation 26). A much better approach is to
rely on operating personnel to determine when an Alert or Emergency condition exists to change from
standardized communication used for normal operation to a different standard protocol for emergency
operation. Operating personnel have substantial training requirements, including explicit requirements
for training on emergency operations, which provide the basis for allowing operating personnel to
make this determination. A standard phrase to identify that protocols for Alert or Emergency
conditions are to be used (such as "I am issuing a Reliability Directive") would trigger the need to
switch from protocols for normal operation to protocols for emergency conditions. This approach also
addresses concerns that complacency will set in if identical protocols are used for normal and
emergency communications. Active listening is much more likely when using a protocol that is used
only for emergency conditions which occur much less frequently than normal operations.
Individual
Yes
Yes
No
The current wording necessitates creating a process to evaluate a process that evaluates protocols.
We believe this is unnecessarily cumbersome and confusing. The addition of extra controls from the
last version to this version lends nothing to improving reliability or improving the function of the
standard. Accordingly, the NERC SC recently approved the SAR for the Paragraph 81 initiative to
eliminate certain requirements from the Reliability Standards with little effect on reliability. The SAR
identifies criteria to be used to identify those requirements that could easily be identified for removal.
It would seem that the draft R3 and R4 would meet the criteria identified for P81. GTC recommends
the deletion of R3 and R4. Alternatively, at a minimum, we suggest improvements to requirements R3
and R4 as currently drafted. We suggest changing all instances of the word “process” to “protocols” in
both part 4s and also removing “found external to Part 4.1” from both part 4s. Finally we suggest
removing parts 2 and 3 simply to keep the requirements from becoming redundant with the changes
made to their respective part 4s.
No
The VSLs for requirements R3 and R4 are too severe. We understand that they were designated as
binary, which led them to automatically be designated as severe VSLs. However, it is our position that
these requirements are no more binary than requirements R1 or R2 and that their VSLs should be
rewritten. We propose: Moderate VSL: The responsible entity did not include one (1) of the four (4)
parts of Requirement R3 in its implementation of a process for identifying deficiencies with adherence
to documented communication protocols specified in Requirement R1. High VSL: The responsible
entity did not include two (2) of the four (4) parts of Requirement R3 in its implementation of a
process for identifying deficiencies with adherence to documented communication protocols specified
in Requirement R1. Severe VSL: The responsible entity did not include three (3) or more of the four
(4) parts of Requirement R3 in its implementation of a process for identifying deficiencies with
adherence to documented communication protocols specified in Requirement R1 or did not have such
a process.
Individual
Agree
please see FMPA's formal comments.
Group
PPL Corporation NERC Registered Affiliates
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Brent ingebrigtson
LG&E and KU Services
No
The PPL Companies do not agree with the proposed definition of Operating Instruction as the standard
appears to be focused on imposing three part communications on the industry for all normal / routine
operating communications. Imposing requirements for three part communication for Operating
Instructions may have the effect of elevating all communications to the state of Reliability Directive
(as defined in COM-002-3). Splitting communications requirements across different standards
introduces the potential of unnecessary confusion. Communications involving the changing of the
state, status, output, or input of a facility, occur very frequently and potentially even more frequently
on preserving the state of the system. Many of these communicated changes, in and of themselves,
would not have an impact on reliability. However, there are times (examples could be during a DCS
event, an SOL, or an IROL) when even seemingly insignificant changes to the system must be made
promptly, although the system has not reached the level of emergency or instability. It is at these
times, “when action must be taken”, which the miscommunication of the action or inaction could lead
to amplifying the risk to the system. Further, the focus of the standard is on operations and therefore
the communications subject to the requirement should be those requiring action in the Real-time
Operations Time Horizon. The definition of which is included in the NERC document located at
http://www.nerc.com/files/Time_Horizons.pdf . Suggest modifying the proposed definition as follows:
Operating Instruction – Command, other than a Reliability Directive, from a System Operator to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System in which action must be taken in the Real-time Operations Time
Horizon.
No
The PPL Companies do not agree with the proposed requirements as they are administrative in
nature. Should the requirements remain, we suggest the following be considered: R.1. Each
Responsible Entity shall implement, in a manner that identifies, assesses and corrects deficiencies,
one or more documented communication protocols that address each of the following Requirements
R1.1 through R1.3 applicable to such Responsible Entity: R1.1. When a Reliability Coordinator,
Transmission Operator or Balancing Authority requires actions to be executed pursuant to an
Operating Instruction, the Reliability Coordinator, Transmission Operator or Balancing Authority shall
identify the communication as an Operating Instruction to the recipient. R1.2. Each Balancing
Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the recipient
of an Operating Instruction shall repeat, restate, rephrase or recapitulate the Operating Instruction.
R1.3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues an
Operating Instruction shall either: • Confirm that the response from the recipient of the Operating
Instruction (in accordance with Requirement R1.2) was accurate, or • Reissue the Operating
Instruction to resolve any misunderstandings. For purposes of clarity, the term “implement” in
Requirement R1 does not mean that there were no failures to follow the protocol in specific cases. The
following language is suggested for the measures related the proposed R1.1 through R1.3: Measures
The Responsible Entity shall have documented communications protocols developed for Requirements
R1.1 through R1.3. Additional examples of evidence may include, but are not limited to, the
Responsible Entity: • trained or otherwise educated the affected personnel about the protocols •
established controls to identify failures to follow the protocols • assessed identified failures to follow
the protocols • took appropriate actions to correct the identified failures
No
The PPL Companies agree with the concept of internal controls and/or the elimination of zero defect
requirements. However, the concept of internal controls to identify, assess, and correct deficiencies
related to documented communications protocols should be imbedded in R1 as proposed in our
response to question 2. We do not agree with the specific details in the internal controls/elimination of
zero defect language that is currently included in R3.1 – R3.4 and R4.1 – R4.4. Incorporating the new
language proposed by the PPL Companies in R1 makes COM-003 more consistent with the approach
being followed in the NERC CIP Version 5 standards. The added language proposed by the SDT in R3
and R4 creates uncertainty as to whether COM-003 is imposing greater requirements than CIP
Version 5 regarding identifying, assessing, and correcting deficiencies and the documentary evidence
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
that is required.
It appears the SDT may be basing the perceived need for communication protocols during normal
operations on a misunderstanding of the findings in an EPRI report. The SDT responded to multiple
comments questioning the need for communication requirements during normal operations by quoting
a paper (Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State
University, 1998) that cited an EPRI study. The SDT stated, “[w]e believe the more relevant and
significant conclusion to be that, of 400 switching mishaps, 19% were caused [by] communication
failures.” It is concerning that the SDT may be basing their conclusions on erroneous data. The EPRI
report in fact indicates only 14.5% were “cited” as “faulty communication”, not necessarily “due to” or
“caused” as the SDT response would indicate. Nearly half of those 58 (14.5%) of the 399 incidents
reviewed resulted from most commonly not communicating “critical information”, i.e. failing to “call
in” or communicate in the first place. The EPRI report reads as follows: “Faulty communications were
cited [emphasis on “cited”] in 58 (14.5%) of the 399 incidents reviewed. The most common kind of
communication error was failure to communicate critical information, which occurred in 22 (39%) of
the 58 cases. Examples are: failure to conduct a thorough pre-job briefing, failure to call in before
operating a switch, failure to communicate about equipment problems, or failure to question some
unusual aspect of an order. “ Mandating “how” communications occur will not address the failure of
“what” critical information needs to be communicated. Furthermore, it is concerning that the SDT
“believes that the potential for risk” necessitates requirements applicable to all operating
communications as stated in their response to comments during draft 2. It is impossible to eliminate
the potential for risk in all circumstances. What is important is that the SDT assess risk to the BES as
a result of certain actions or inactions and that the Reliability Standard reduce that risk in an efficient
and cost effective manner.
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
Yes
Yes
Yes
we commend the SDT for doing a good job of writing a difficult standard and avoiding the "zerodefect" problem (the problem of just having just one violation in tens of thousands be punishable by
fines) and we support the approach taken. If we think of managing operations, we think of the
process: Step 1 - Vision, goals, policies - what do we want to accomplish? Step 2 - Protocols, plans,
procedures, programs, processes, methodologies - how will we do it and who will do what? Step 3 Do it Step 4 - Measure, monitor - did we accomplish what we set out to do? Step 5 - Learn, adjust,
back to 1. The problem with the prior draft of COM-003, before this latest draft, is that the standard
essentially micromanaged industry by causing auditors to monitor actual communications, e.g., the
auditors would be doing step 4, which ends up with the zero-defect problem. We have seen other
standards that have this zero defect problem, e.g., PRC-005 has a requirement for step 2 of the
process above, to have a program, and then for step 3 of the process, to do it in accordance with the
program, which results in the zero-defect problem. We've seen still other standards avoid the zero
defect problem by only requiring step 2, but with no requirement to actually do it, e.g., the currently
enforceable CIP-001 has requirements for step 2 of the process above for sabotage reporting
procedures, but, has no requirement to actually follow those procedures if a sabotage event occurs,
which leaves questions of accountability. The SDT for COM-003 is doing the appropriate thing and
backing up one level to measure how effectively we are managing our own operations, and this is the
first time I've seen a standard developed in this clever fashion of developing requirements for Step 2
(protocols) and Steps 4 & 5 (measure, monitor, learn, adjust) of the process above, but not Step 3 of
the process. However, Step 3 would need to be performed for the entity to comply with Steps 4&5,
meaning we are still accountable for "doing it". The method that the SDT is using to ensure we have
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the appropriate operations management mechanisms in place seems a clever and pragmatic
approach. We have one suggestion to improve R3. R3 requires entities to “implement” a process for
identifying deficiencies. Use of the word “implement” implies that all deficiencies must be identified,
which means that the auditors would need to independently identify deficiencies and compare notes,
which reintroduces the "zero-defect" problem. FMPA recommends replacing "implement" with
“institute”.
The RSAW seems to re-introduce the “zero-defect” problem by directing auditors to sample actual
recordings of communications to see if the entity identified all deficiencies. The RSAW ought to be
changed to get away from sampling actual voice communications altogether and simply review the
evidence of the entity doing its own internal monitoring. For instance, the entity might decide to
randomly sample a few hours a month itself and identify deficiencies in those hours, that should be
the only voice recorded evidence required and not any other hours that the entity did not randomly
sample. In addition, the evidence for correction of deficiencies is not more voice recordings, but
rather evidence of revised protocols, processes, procedures, or evidence of disciplinary action. So,
FMPA believes the RSAW needs a lot of work.
Individual
No
We believe this is a standard that requires procedures or documents but has nothing to do with
performance. These types of standards lead to auditors making a wide range of interpretations.
This is an attempt to make a requirement for 3 way communication for all operating communications.
Not all operating conversations avail themselves to that format. The concept is good but allowances
must be made for other situations.
Individual
No
See comments under question # 5.
Yes
Yes
Xcel Energy feels this new draft of COM-003-1 is greatly improved than prior versions. We are
especially in favor of the internal controls approach the team has taken. However, while we have
identified several areas of concern with this latest draft, our issue with R1.5 is the single item that is
preventing us from voting affirmative. As indicated in our previous comments, our issue is that we do
not believe alpha-numeric identifiers should be required for all oral Operating Instructions. Instead,
we feel this should be an optional tool that the operator may use where clarity in the Operating
Instruction is needed or anticipated. (For example, the operator may use alpha-numeric clarifiers to
restate the original Operating Instruction, when it was apparent from the receiver’s repeat back that
the details of the Operating Instruction were not accurately understood.) Below are additional issues
and modifications Xcel Energy would like to see addressed: 1)Since a Distribution Provider may issue
Operating Instructions that would impact the BES, we feel they should be added to the applicability
under R1 and R3. 2) We recommend that the term “functional entities” be capitalized in R1.1, and a
reference added to Section A4 of the standard. This way it is clear that the term includes all entities
under the standard (Section 4) and not just the entities under R1.
Individual
No
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The definition of “System Operator” includes BA, RC, TOP, and GOP. Because GOP is included the
definition, “System Operator” should be replaced by “Balancing Authority, Reliability Coordinator, or
Transmission Operator.” See also Project 2010-16: Definition of System Operator.
No
There should not be a requirement for entities in R1 and R2 to have documented communications
protocols. The subparts specify the protocol requirements. R1 should merely state: “Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall use the following communication
protocols for Operating Instructions:” R2 should be similar involving DP and GOP functions
No
These questions apply equally to R3 and R4. In R4.1, what is a “potential” deficiency? In R4.3, how
can one correct a deficiency since that happened in the past? In R4.4, how does one evaluate the
process based on deficiencies identified that are “external to Part 4.1”? (Part 4.1 is the process for
identifying deficiencies.) We are also concerned about the draft RSAW for R3 and R4. The RSAW has
two bullets for R3 and R4. One states “Where the auditor can verify that the entity is identifying,
assessing, and correcting its own deficiencies, the auditor will not have a finding of non‐compliance.”
The second bullet states “If an auditor cannot verify that the entity is adequately identifying,
assessing, and correcting its own deficiencies due to limitations in its process, the auditor will not
have a finding of non‐compliance.” The auditor will provide the entity with recommendations as
necessary.” Per the RSAW for R3 or R4, how will an auditor verify that an entity is not “adequately
identifying, assessing, and correcting its own deficiencies due to limitations in its process”? In other
words, what evidence will be required by the auditor, and how many months of communications
records should be kept? Because of the volume of communications, sampling may be required. Unless
one listens to 100% of communications recording, one cannot be sure one is identifying all
deficiencies. Is 100% deficiency detection the goal? Furthermore, M3 or M4, which only require the
entity to provide the results of its process in R3 and R4, are not mentioned in the RSAW. Measures
are supposed to represent one acceptable from of compliance and should be acceptable in the RSAW.
Finally, if R1 and R2 are changed as recommended in #2 above (i.e., remove the requirement for an
entity to have documented communications protocols and just require it to adhere to protocols n R1
and R2), incidents of non-compliance with the protocols will be detected via R3 and R4. We first
recommend that M1 and M3 have the same measures – M1 and M2 would both read “Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall provide the results of its process
developed for Requirement R3.” The same would apply for M2 and M4, which would both read “Each
Distribution Provider and Generator Operator shall provide the results of its process developed for
Requirement R4.” If this were done, the draft RSAWs two bullets discussed should have these phrases
modified for R3 and R4, with the modification shown in capital letters: • In R3, modify “the auditor
will not have a finding of non‐compliance FOR EITHER R1 OR R3” in two bullets. • In R4, modify “the
auditor will not have a finding of non‐compliance FOR EITHER R2 OR R4” in two bullets.
We did not evaluate these.
PSEG fully supports the use of 3-part communications. In our previous comments, we stated “This
standard (COM-003-1) should be combined with COM-002-3 and issued as one standard to require
ONE 3-part communications protocol for both Reliability Directives and non-Reliability Directives.” We
reiterate that request and believe that the SDTs should be combined into a single SDT and develop
one standard. COM-002-3 addresses Reliability Directive communications, while COM-003-1
addresses Operating Instructions communications. The same Registered Entities are subject to both
standards. Both require 3-part communications (a “protocol”), but COM-003-1 has more extensive
requirements. Having two standards is harmful for these reasons: • The lack of a common protocol
would result in communications confusion among these entities for this reason: some Operating
Instructions are Reliability Directives, but not all Reliability Directives are Operating Instructions. •
Finally, without a common communications protocol, entities would need to be concerned about what
protocol they are using for compliance purposes; this would hinder the efficiency of communications
and therefore reliability. The single SDT should be charged with the following tasks: 1. Both draft
standards have pluses and minuses listed below, and the SDT shall consider these and take the best
from each to develop a single standard with a common protocol. a. Both standards require 3-part
communications (a “protocol”), but COM-003-1 has more extensive requirements, such as the use of
alpha-numeric clarifiers and a 24-hour clock format. [PSEG prefers the COM-002-1 simplified
protocol.] b. Reliability Directive communications need to be identified as such by the sender as part
of its protocol; Operating Instructions do not contain a similar requirement. [PSEG prefers that both
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Reliability Directives and Operating Instructions be identified by the sender.] c. The protocol for
Operating Instructions explicitly addresses both written and oral communications; the protocol for
Reliability Directives is not specific. [If identified as such by the sender, PSEG does not object to
written and oral communications being addressed in a single standard; however, only oral
communications should require the use of 3-part communications.] d. The protocol for Operating
Instructions exempts “one-way burst messaging” from a requirement for 3-part communications with
one practical exception – the receivers must request clarification from the sender if the
communication in not understood; the protocol for Reliability Directives does not address explicitly
exempt such communications, implying that 3-part communications is required for them. [PSEG
prefers the “one-way burst” language in COM-003-1 for both Reliability Directives and Operating
Instructions.] e. The Operating Instructions protocol must be separately documented by each entity;
no such documentation is required for Reliability Directives. If documentation is required in a posted
standard developed by the SDT, the SDT shall explain the reliability benefits of documentation and
why the protocols in the standard, which are themselves communications performance requirements,
are insufficient as “documentation.” [PSEG prefers no documentation of protocols since they are
performance requirements in the standard.] 2. COM-003-1 requires a process for identifying and
correcting deficiencies.” COM-002-3 does not. [Instead of the COM-003-1 language, PSEG prefers a
requirement that adopts the CIP version 5 language: “R#. Each applicable entity shall have a process
that identifies, assesses, and corrects deficiencies in the use of communication protocol.”] 3. The SDT
shall describe the potential measure or criteria for success for determining the successful
implementation of the single standard. 4. “Generator Operator” is included the Glossary definition of
“System Operator,” which in turn is used in the Operating Instruction definition. “System Operator”
shall be replaced by “Balancing Authority, Reliability Coordinator, or Transmission Operator” in the
Operating Instruction definition. Generator Operators receive Operating Instructions but do not issue
them. See also Project 2010-16: Definition of System Operator – the goal of this project is to remove
Generator Operator from the definition of System Operator. (The Standards Committee should
consider increasing the priority of this project so that this problem is addressed systematically in the
System Operator definition.)
Individual
Yes
No
This requirement will be burdensome to small Distribution Providers where communications from a
System Operator will not ever occur. Requiring entities to prepare for nonexistent reliability gaps is
not acceptable. DPs should be allowed to document via RC, TO, and BA letters of agreement that
establishes System Operator communication protocol is not required. These small DPs can only shed
load in a reliability emergency, and in some cases would need to do so manually. Further, such load
would be more effectively dropped by the TOP functioning as the DP’s Transmission Service Provider.
No
See response to question two.
Individual
No
We can accept the definition but want to bring to the attention of the Drafting Team that the
description of OI in the Background section of the Comment form, "Operating Instructions more
accurately define the broad class of communications that deal with changing or altering the state of
the BES", does not agree with the Definition being balloted. The inclusion of the phrase "or preserve"
changes the definition. Nowhere in the discussion of the need for Operating Instructions or
communication protocols is there discussion of or justification for including the "or preserve"
statement. Exelon can support the modified definition but we believe it will cause entities to oppose
this standard at ballot and create confusion when implementing controls and auditing to the modified
definition.
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No
Exelon agrees with all requiremnts except R1.1.3 and R1.1.4. We disagree that R1.1.3, “include time
zones” when issuing operating instructions is necessary. Operating instructions are typically issued in
real time; an instruction to do something “now” or at the "top of the hour" does not require the use of
time zones. 1.1.4 has the effect of requiring verbatim use of a specified name; this should not be a
requirement as long as the transmitter and receiver use three way communications effectively to
assure understanding of the element to be operated. Additionally, TOP-002-R18 already requires use
of “uniform line identifiers when referring to transmission facilities of an interconnected network”. The
statement to use the TO specified name or a mutually agreed to name is not necessary in light of
TOP-002.
Yes
Exelon agrees with the prposed requiremnt but thinks it could be improved before final adoption. The
Requirement as written is confusing. For example, R3 is to identify deficiencies with respect to the
entities protocols. R3.1 addresses “potential” deficiencies. It is unclear what a potential deficiency is.
We suggest using deviations from the entities protocol in place of deficiencies or potential
deficiencies. Similarly we question how an entity will demonstrate that modifications to their program
are not required in light of the assessment being done in response to deviations from the protocol. We
believe R3.4 should be clarified. We believe its purpose is to direct an entity to take action if an
external entity (auditor) identifies a deviation from the entity protocol. We do not think the response
to identifying a deviation / deficiency should vary based on how it was identified. Once identified
(R3.1), a deviation / deficiency should be assessed (3.2) Corrected (3.3) and when necessary (3.4)
the program should be modified to account for the deficiency. Since a similar effort to utilize an
internal controls approach is underway in the CIP Version 5 drafting, it may be valuable for COM-003
to also utilize the same language of “in a manner that identifies, assesses, and corrects deficiencies.”
Exelon supports the effort to utilize an internal controls approach but remains concerned compliance
auditing and the potential for interpretations related to the requirement. We urge NERC, in
collaboration with the Regional Entities to develop a clear roll out plan prior to implementation of
COM-003 so that stakeholders and auditors understand the compliance obligations for this new
approach.
We would like to point out that the OI definition includes another defined term, “System Operator”. In
the Glossary, this is defined as is an individual at a control center, including a Generator Operator.
Control center is not currently defined but has a proposed definition in CIP version 5 that puts limits
on which generator operators (# of units) work in “control centers”. If approved as part of CIP version
5, this definition of Control Center is likely to cause confusion when applying this and other standards.
Will OI apply to all Generator Operators or just those working in "Control Centers" as defined by CIP
ver 5. In spite of our concerns with the current draft, Exelon intends to vote affirmative on this ballot
for COM-003. Significant improvements have been made but there is opportunity to make additional
changes before the final ballot.
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
No
We suggest changing ‘command’ to ‘order’. The definition would then read ‘An order from a System
Operator…’
No
The wording in R2.1 is awkward, we suggest the following: When receiving an oral two party, personto-person Operating Instruction, the recipient is required to repeat, restate, rephrase, or recapitulate
the Operating Instruction. The one-way burst messaging in R1.9 and R2.2 is confusing to us in that
we don’t understand how you request clarification over a one-way messaging system. As written
there is no ‘out’ for an entity that cannot perform the Operating Instruction as given. An entity has
the option of not performing a Reliability Directive if that directive violates regulatory, safety,
equipment, or statutory requirements (TOP-001, R3). A similar exemption needs to be incorporated
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into COM-003.
No
Delete ‘potential’ in R3.1 and R4.1.
No
The Severe VSL for R2 contains a typo and should be reworded to read: ‘The responsible entity did
not include Parts 2.1 to 2.2 of Requirement 2…’ We would suggest that the VRFs for R3 and R4 be
reduced to Low. The VRFs for R1 and R2 are Low. R3 and R4 are processes that monitor R1 and R2;
therefore, they should not be treated more severely than R1 and R2.
The processes outlined in R3 and R4 would be sufficient in themselves but with the requirements of
PER-005 regarding identifying gaps and training to eliminate those gaps, it would appear that R3 and
R4 add unnecessary duplication. Why do we need to have the same requirements in two different
standards? Do some of the issues that are being addressed in the Paragraph 81 project come into
play here? Given the approval of COM-002-3 which places requirements on the DP and GOP when
receiving a Reliability Directive, there appears to be the possibility of confusion regarding specific
requirements on the DP and GOP in COM-003. During the COM-003 webinar, the comment was made
that if COM-003 is approved, there may be a new project that would attempt to more efficiently
coordinate the two standards. We would be supportive of that effort. The papers referenced in the
Rationale and Technical Justification document supporting the need for this standard should be made
available for review if the drafting team is using them as support for the justification for COM-003.
Individual
No
NERC defines the term “System Operator” as “an individual at a control center (Balancing Authority,
Transmission Operator, Generator Operator, Reliability Coordinator) whose responsibility it is to
monitor and control that electric system in real time.” NERC does NOT define a “control center” which
could be problematic when it comes to how an entity views a control center and how an auditor
defines a control center. IMPA believes that there is too much ambiguity when using the words “to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.” IMPA recommends that the entity giving the Operating
Instruction declares it to be one which eliminates many potential problems of applying a definition of
an Operating Instruction. The receiver of the Operating Instruction immediately knows what the
following instructions will be and will know to apply the proper communication protocol instead of
trying to figure out if the definition of Operation Instruction applies to what the entity just said.
No
IMPA believes it should be made clear that Operating Instructions and the use of documented
communication protocols are required by these two requirements for when Operating Instructions are
given by a Balancing Authority, Reliability Coordinator, or Transmission Operator to a Distribution
Provider or Generator Operator. The current requirements could apply to a generator station
(Generator Operator) who receives Operating Instructions from its Market Operations (also the same
Generator Operator entity). The Market Operations would not need to follow the communication
protocol since it is issuing the Operating Instructions, but the generator station would have to follow
the communication protocol since it is receiving the Operating Instruction. IMPA does not believe that
the SDT intended to include communications between a Generator Operator’s Market Operations and
its remote power plant.
No
IMPA recommends adding clarification to the words “deficiencies found external to Part 3.1 (4.1)" so
that entities and auditors know that these requirements allow defeciencies found outside of the
entitie’s process including deficiencies that had previously passed the entity’s process) will be able to
go through the entity’s process of assessing and correcting without the auditor giving a finding of
non-compliance, since the entity itself failed to identify the potential deficiency in R3.1. or R4.1. The
clarity can be added in the standard itself or in the RSAW- it currently is not stated in the standard
and it is especially absent in the RSAW under Section 2 on page 4 of 5 or Section 2 page 5 of 5. It is
also not clear how many times an entity will be allowed to identify, assess, and correct the same
deficiency or similar deficiencies before an auditor can find an enitiy in non-compliance with R3 and
R4 (including subrequirments of each). It appears that the SDT is saying that as long as an entity is
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making the changes provided in the feedback by the CEA to its process to identify, assess and correct
that it will not be found non-compliant for all same or similar deficiencies that continue to occur –
there is no set number as long as the entity is trying to improve its process or communication
protocols, is this correct? If so, IMPA supports this practice and would like to see clarity added.
no comment
IMPA believes the best quality of evidence for proving compliance to most of the sub-requirements
under R1 and for requirement 2.1 will be voice recordings. IMPA agrees with keeping this evidence for
90 days, but to keep these voice recordings for potential 6 years (back to our last audit date) will be
very costly when it comes to storage. We understand that other evidence can be used to show
compliance back to our last audit date, but what other quality evidence besides voice recordings will
be acceptable to prove compliance to these requirements? IMPA recommends making the data
retention of this standard just 90 days regardless of the last audit date. Performance should be
focused on the short past time of 90 days and not what the entity did five or six years ago, which is
irrelevant when one is forward looking or wanting to improve.
Individual
No
MISO believes that the proposed definition of “Operating Instruction” is overly broad and ambiguous.
System Operators engage in thousands of communications each year. Many of these are geared
toward confirming system conditions, data, or information and/or gathering information in
anticipation of responding to conditions observed on the Bulk Electric System. The definition’s breadth
and ambiguity are likely to give System Operators pause before they engage in necessary
communications to determine whether or not such communications would be Operating Instructions.
This would delay necessary information and data gathering by System Operators, which delay would
likely be detrimental to the reliability of the BES. Conversely, to avoid confusion regarding which
communications are Operating Instructions and to avoid potential delays, System Operators may opt
to treat, as Operating Instructions, all or many communications that should not fall within the scope
of this definition, resulting in every communication being subject to this standard. Under either
scenario, because of the System Operators’ caution and desire to avoid possible penalization by NERC
and FERC, the net effect of this definition is detrimental to the reliability of the BES. Further, because
of delays in issuing or initiating communications, there is significant potential that penalty exposure
from other NERC Reliability Standards (in addition to that identified in the COM-003-1 Reliability
Standard, e.g., resulting from a deficiency in implementing or failing to implement specified protocols
and/or three-way communication, a deficiency in the review process, which is now significantly
expanded beyond that envisioned during the drafting of this standard) could be increased.
Accordingly, System Operators are likely to apply the protocols applicable to Operating Instructions
under R1 of COM-003 to all communications, whether or not they qualify as Operating Instructions.
This result would be overly burdensome, and its inefficiency could hamper System Operators’ ability
to perform their necessary reliability functions. As a result, MISO does not support the proposed
definition of Operating Instruction at this time.
No
MISO does not agree with the proposed requirements of COM-003-1, R1 and R2. Although MISO
agrees that clear communications are important to system reliability, it respectfully submits that any
requirement for System Operators to have a communication protocol should allow the subject System
Operators to define when and how the protocol would apply. In addition, MISO respectfully submits
that System Operators should retain greater flexibility in deciding which elements to include in their
respective protocols. For instance, the protocols should allow the System Operator to outline how and
when to use blast calls and messaging systems. Thus, despite its conceptual support for a
communication protocol for System Operators, MISO is concerned that the requirements currently set
forth in COM-003-1 are, in many cases, overly-prescriptive, and, rather than enhancing system
reliability, could actually undermine it. As explained above, because the definition of the term
“Operating Instruction” is overly broad and ambiguous, System Operators may treat most, if not all,
communications as Operating Instructions. Applying the required elements of the communication
protocols for Operating Instructions to most communications would be inefficient and could adversely
affect the ability of System Operators to perform their reliability functions. Indeed, while MISO agrees
that clear communications in system operations are important, an excessive reliance on the three-
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way communications protocols detailed in the proposed standard can be an unnecessary distraction
for personnel operating the Bulk Electric System, hampering as opposed to enhancing overall system
reliability. MISO’s primary point of disagreement with the current Standard is therefore one of scope.
MISO recommends that the SDT replace “Operating Instruction” with the existing proposed definition
for the term “Reliability Directive” in Project 2006-06, Reliability Coordination. Limiting the scope of
applicability for utilization of the communication protocol required by COM-003-1, R1 and R2 would
prevent System Operators from applying the communication protocol to virtually all communications
out of an abundance of caution and, unlike the current draft of COM-003-1, would not be an undue
distraction from the reliability functions performed by these operators. Further, as explained in its
comments on Draft 2 of COM-003, MISO does not support including certain of the proposed required
elements in the communication protocol for Operating Instructions and does not believe these issues
have been sufficiently addressed by Draft 3. First, MISO does not agree with the proposed
requirement to indicate time zone and Standard or Daylight Saving Time when issuing an oral or
written Operating Instruction between functional entities in different time zones. This requirement
would result in the expenditure of significant time, resources and attention by System Operators for a
minimal benefit to reliability. Accordingly, this modification appears to place upon operators an
unjustified, onerous requirement. MISO respectfully requests that the SDT reconsider this
requirement. Second, MISO continues to believe that the requirement to use alpha-numeric clarifiers
when issuing Operating Instructions to or Facilities and Elements in instances where the nomenclature
of Facilities or Elements is in alpha-numeric format is ambiguous and could lead to unintended
compliance burdens. MISO respectfully submits that if alpha-numeric clarifiers are to be required,
NERC should adopt a uniform set of clarifiers to ensure that all System Operators communicate
efficiently and effectively. However, MISO reiterates its belief that mandating the use of alphanumeric clarifiers will have, at most, a minimally beneficial impact on reliability while requiring
Registered Entities to expend substantial additional resources. Finally, MISO disagrees with the
proposed requirement that Operating Instructions reference the name specified by the owner for a
Transmission interface Element or Transmission interface Facility. To date, System Operators have
identified equipment by to/from station and voltage level. Such identification has been sufficient to
ensure the accurate identification of Transmission interface Elements and Facilities. Additionally, MISO
notes that internal identifiers utilized by owners may result from internal coding or naming
conventions that would not be known by or comprehensible to external entities. Hence, MISO cannot
support this requirement, based on the potential adverse impacts to reliability that could result.
No
MISO respectfully submits that COM-003-1, R3 and R4 require clarification in two regards. MISO first
notes that requirements R3.4 and R4.4, which require Registered Entities to evaluate “the process
based on deficiencies found external to [R3.1/R4.1],” are written in a confusing manner. More
specifically, it is not clear what the phrase “found external to” means and, therefore, Registered
Entities cannot know or understand when their compliance obligations under these requirements are
applicable. In addition, MISO respectfully submits that the SDT must add clarifying language to COM003-1 to clarify that an individual failure to execute elements of a System Operator’s communication
protocol is not, on its own, a compliance violation, provided that the System Operator evaluates
adherence to its protocol as required by Requirements R3 and R4. MISO is concerned that the current
draft of COM-003-1 could give rise to double penalties for individual failures to execute one of the
elements of a communication protocol. Without clarifying language in the Reliability Standard itself,
any Registered Entity that fails to adhere to its communication protocol required by COM-003-1, R1
and R2 would likely self-report this failure, and would subsequently complete a mitigation plan that
addresses -- and implements new processes to prevent the repetition of -- the failure. An additional
requirement to evaluate adherence to the communication protocol would be redundant and would not
increase or bolster reliability – and, further, would only increase the potential for Registered Entities
to violate yet another requirement of a Reliability Standard. Thus, unless COM-003-1 is revised to
clarify that a Registered Entity’s failure to implement an element of its communication protocol for
Operating Instructions is not a compliance violation in and of itself and, therefore, is not subject to
self-reporting under NERC and Regional Entities Compliance Monitoring and Enforcement Program
(“CMEP”), MISO cannot support proposed Requirements R3 and R4 at this time.
No
MISO appreciates the changes that the SDT has made to the VRFs and VSLs in response to comments
and to ensure that the VRFs and VSLs are consistent with FERC and NERC guidelines. However, MISO
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cannot support either the VRF or the VSLs for R3 and R4 as it does not agree: (1) that there is a
direct impact on reliability that results from an entity’s internal self-assessment and (2) with the
expressed rationale. Further, MISO notes that COM-003-1, R3 and R4, primarily require internal
administrative processes or documentation thereof. MISO respectfully submits that internal
administrative processes have not previously been linked to direct impacts on the reliability of the
BES.
The RSAW states that the applicable entity could be found non-compliant if the entity did not follow
an auditor’s suggested changes to remedy those deficiencies. This requirement is not found in COM003-1 itself, and the RSAW therefore includes requirements that are beyond the scope of the
Standard it supports. The draft RSAW also introduces subjective concepts that place uncontrolled
discretion in the hands of auditors. For instance, the RSAW states that the size of the sample of the
entity’s communication activities reviewed to verify whether the entity is identifying, assessing,
communicating and correcting deficiencies “will be based on the auditor’s confidence in the entity’s
ability to identify, assess, and correct its deficiencies.” MISO submits that sample size should be
determined mathematically and in a manner that can itself be audited. Indeed, NERC’s own Sampling
Methodology Guidelines and Criteria states that "Statistical sampling helps ensure a high confidence
level of compliance for the larger population of documents when a smaller population is statistically
sampled . . . Statistical sampling should be employed when auditing all processes, procedures and
any documentation‐related evidence (documents, logs, voice recordings, etc.) when a sample is
required because the entire population cannot be audited." Allowing an auditor to determine sample
size based on an abstract concept such as confidence is contrary to NERC’s own sampling
methodology; would prevent Registered Entities from challenging such sample sizes; and could allow
auditors to make such decisions punitively.
Group
Bonneville Power Adminstration
Jamison Dye
Transmission Reliability Program
Yes
No
In R1.5, BPA disagrees with the mandatory use of alpha numeric communication protocols for internal
communications. BPA believes that these communication protocols should apply only to external
communications between system operators for the TOP, GOP, and BA. BPA suggests that the drafting
team update R1.5 to specify that “Transmission Operators and Balancing Authorities may adopt
methods other than alpha-numeric clarifiers to ensure accurate communication of Operating
Instructions for internal operations.” BPA suggests that R1.1 should be modified to make clear that
the use of English should be mandated for communications between entities in separate regions
where the common language in one of the regions may not be English. In response to Draft 2,
Essential Power LLC commented that “The use of English should be mandated for communications
between entities in separate regions where the common language in one of the regions may not be
English. Allowing an entity to use a language other than English when communicating with regions
where English is the required language is counter to the purpose of the Standard and could in fact
jeopardize reliability through miscommunication.” The SDT stated that it “agreed with (Essential
Power, LLC’s) comments (shown below) and clarifies that is the intent of the requirement”, but this
intent is not clear in the requirement as written because it does not specify that the language
mandate needs to apply to both entities. Additionally, there is no expressed limitation that the
language(s) acceptable in these circumstances be limited to only the language(s) specified by such
law or regulation. To resolve these issues, we propose that COM-003-1 R1.1 be modified to read as
follows: Use of the English language when issuing an oral or written Operating Instruction between
functional entities, unless another language is mandated by law or regulation FOR BOTH ENTITIES; IN
WHICH CASE, ACCCEPTIBLE USE IS EXPANDED TO INCLUDE THOSE SPECIFIED LANGUAGES.
Transmission Operators and Balancing Authorities may use an alternate language for internal
operations.
No
BPA supports the move to the identify, assess, and correct deficiencies approach that eliminates the
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need for the entity to report each deficiency as a potential violation. BPA believes that based on the
current R1 and R2, it is not reasonable to expect entities to review all communications in order to be
compliant with R3 and R4. BPA suggests that the drafting team update R3.1 and R4.1 to state that
entities shall implement a process that “identifies potential deficiencies through sampling”.
No
BPA does not agree with the VRFs and VSLs. R3 & R4 should include a range of VSLs. A
documentation error such as a failure to record that modification of a process was not necessary
would not merit a severe VSL if training was implemented as an appropriate solution to an identified
deficiency.
Individual
No
No
Operating Instructions are issued in real time and are expected to be implemented promptly.
Including the “time zone” in oral communications is not necessary. COM-003 and COM-002 need to
fully coordinate.
Individual
No
ERCOT agrees with the SRC comments, and has these additional comments: As proposed, the term
“Operating Instruction” could include communications that have nothing to do with reliability – e.g.
communications that are market related and have no impact on system reliability. That outcome is
inconsistent with FERC’s direction in Order No. 693. FERC’s discussion of this issue in Order 693
focuses on alerts and emergencies - “We adopt our proposal to require the ERO to establish tightened
communication protocols, especially for communications during alerts and emergencies…” (693 at P
531) “Accordingly, we direct the ERO to either modify COM-002-2 or develop a new Reliability
Standard that requires tightened communications protocols, especially for communications during
alerts and emergencies.” (693 at P 535) In addition, the scope of FERC’s concerns is limited to
communications that impact the reliability of the BPS – “We note that the ERO’s response to the Staff
Preliminary Assessment supports the need to develop additional Reliability Standards addressing
consistent communications protocols among personnel responsible for the reliability of the Bulk-Power
System.” (693 at P 531) “…we believe, and the ERO agrees, that the communications protocols need
to be tightened to ensure Reliable Operation of the Bulk-Power System.” (693 at P 532) Simply
because FERC noted the benefits to communications during normal conditions does not mean the
standard has to apply to those circumstances. All FERC said was that implementing consistent
protocols will likely provide benefits across all operating conditions. The focus of the concern was
clearly alerts and emergencies, and limiting the application of the standard to those conditions will
provide benefits to relevant communications during normal conditions. However, as written, the
standard is overbroad and inconsistent with the Commission’s directives in Order 693. Consistent with
this discussion, the IRC believes the most effective way to remedy this issue is to eliminate the
proposed term and focus the standard on conditions that actually have a reliability impact. This can
be achieved focusing the requirements on Reliability Directives.
No
The overarching premise of NERC standards is that they typically establish the “what” and not the
“how” (Order 672 at P 260). The proposal to mandate specific communication protocols contravenes
that approach and undermines the value inherent therein. Allowing entities to establish their own
protocols to meet a desired end result facilitates means that best suit particular entities and also
allows for improvements based on experience. Prescribing specific protocols would preclude such
benefits. The proposed requirements are better suited as non-binding illustrative approaches / best
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practices. These could be presented as suggested approaches, for example, in an attachment to a
standard that establishes a general requirement to have communication protocols in place, but they
should not be mandated. FERC did state that in some cases it may be appropriate to prescribe specific
implementation rules in the standards if the how is inextricably linked to the standard and may need
to be specified by the ERO to ensure the enforcement of the Reliability Standard. The Commission
went on to note that for some standards leaving out implementation features could: (1) sacrifice
necessary uniformity in implementation of the Reliability Standard; (2) create uncertainty for the
entity that has to follow the Reliability Standard; (3) make enforcement difficult; and (4) increase the
complexity of the Commission's oversight and review process. None of these conditions apply to
communication protocols. For this matter, a general requirement relative to reliability directives is
adequate with implementation left to the functional entities. This is already addressed in COM-002 R2,
and, therefore, COM-003 is not needed. Communication protocols are more appropriately addressed
by an entity’s internal controls rather than a Reliability Standard, because this approach provides the
benefits described above (i.e. 1) application of suitable protocols based on an entity’s structure and
relationships and other relevant rules and 2) flexibility for improvement of such protocols over time).
The proposed standard eliminates these benefits by prescribing specific items for inclusion in the
protocols. Again, the scope of the proposed standard is askew relative to the reliability concern at
issue. The proposed standard is unresponsive to the issues raised in the Blackout and by FERC. By not
addressing the core reliability issues raised by the very report that drove this Project, the SDT is
jeopardizing the reliability of the power system. Accordingly, the focus of the proposed standard is
misplaced and, if approved, will do nothing to address the reliability concerns identified in the
blackout report and Order 693, but rather will do nothing but impose ineffective and inappropriate
obligations that will create liability risk with no corresponding reliability benefit. ERCOT strongly urges
the SDT to reconsider this posting and to either rescind the Project and accept that IRO-016 has
adequately responded to the Blackout Report, or to revise its proposal to directly address the issues
noted above. If R1 is not rescinded as suggested above then the prescriptive subparts 1.1 thru and
including 1.6 should be removed, and R1 should be revised to include "applicable communication
protocols".
No
ERCOT agrees with the SRC comments, and has these additional comments: ERCOT fully supports the
concept that functional entities’ internal controls be used to monitor the effectiveness of their own
protocols. However, these matters are not suitable for reliability standards. Imposition of mandatory
controls applicable to all functional entities is inappropriate because of the wide variety of
organizational structures that necessarily requires flexibility with respect to developing appropriate
controls for each entity’s specific circumstances. Furthermore, entities’ internal controls are beyond
the scope of the Section 215 reliability purview generally, and they are inconsistent with the risk
based initiative being pursued by NERC because they do not impact/are not related to actual reliability
impacts. Furthermore, this deficiency review process is ambiguous and, accordingly, lends itself to
inefficient and ineffective CMEP results. As an initial matter, what constitutes a deficiency will be an
issue that is vulnerable to subjective disagreements. Even assuming there is agreement on that issue,
what constitutes an appropriate remedy for a deficiency in terms of assessment and correction will
similarly be susceptible to subjective disagreements. Finally, with respect to the obligation to evaluate
the deficiency identification process itself, again, the potential for the introduction of subjective
compliance review will be problematic n practice in terms of reviewing whether the decision whether
to implement a modification or not, and, if a modification is implemented, whether the revision is
adequate.
No
ERCOT agrees with the SRC comments.
As discussed above, the proposed standard is not consistent with the reliability issue/concern raised
in the blackout report, and, therefore, in Order 693, given that the 693 discussion was relative to the
concern raised in the blackout report. The mandates in the proposed standard do not provide
reliability value. COM-002 and other standards that address situations that pose actual reliability risks
already requires appropriate entities to communicate with each other during emergencies, which is
the real focus of the blackout report and Order 693. In those circumstances 3-part communications
are required in a clear, concise and definitive manner. This effectively ensures that the recipient
understands the communication, which practically obviates the need for specific, mandatory
terminology, practices and protocols. Accordingly, for these reasons and the reasons discussed above,
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the need for COM-003 is suspect. In fact, it is arguable that it provides marginal to nil reliability
value, but yet presents potential liability exposure to the relevant functional entities. The SDT should
consider another approach to addressing the concerns in the blackout report and Order 693.
Specifically, any responsive effort should focus on ensuring communications occur relative to specific
system conditions that truly reflect reliability concerns, and any such communications should be
appropriately distributed to ensure dissemination is only to appropriate entities that may be impacted
and/or can assist in remedying the situation. In the alternative, the proposed standard should be
revised consistent with these comments, and in accordance with the principle that a reliability
standard should establish the what, not the how. In addition, the ERCOT offers the following specific
comments. As noted above, as drafted the term Operating Instruction is overly broad relative to the
scope intended by FERC and the Blackout Report, and, in fact, could include purely market related
discussions that have no reliability impact. Yet, the proposed standard requires 3-part communication
for all such interactions. There is no reliability value to 3-part communications for such interactions.
Accordingly, this requirement should be removed. The proposed standard also requires entities
issuing an all-call, or similar multiple party communication, to receive confirmation, electronic or
verbal, from at least one of the recipients that the message was received. The nature of all calls
provides a structural means to distribute messages to a host of recipients. The mediums used for this
purpose ensure that the messages are delivered. There is no need to require confirmation as
proposed in the standard. Furthermore, there is little reliability benefit. Accordingly, for these types of
communications confirmation should not be required. Finally, 1.9 requires recipients of multi-party
communications to ask for clarification if they do not understand the message. It is difficult to
understand how compliance with this requirement will be reviewed, and what value it will have. For
example, if an entity never asks for clarification but an audit determines the entity failed to follow a
directive, the CEA staff may question whether the entity complied with the obligation to request
clarification, but the entity may believe that clarification was not necessary and failure to follow the
instruction was due to some other reason. As with other aspects of the proposed standard, this lends
itself to subjective disagreements in practice. Furthermore, it is unnecessary, because an entity that
does not understand a directive will ask for clarification.
Individual
No
Oncor offers instead a new glossary term called “Operating Communication” in order to support
alternate language proposed for R1 and R2: Operating Communication – Communication from a
System Operator that when executed results in the change or preserves the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System
No
According to the 2003 Black Out Report, “Ineffective communications contributed to a lack of
situational awareness and precluded effective actions to prevent the cascade. Consistent application
of effective communication protocols, particularly during alerts and emergencies, is essential to
reliability” Oncor is not aware of any evidence to support the position that lack of communication
protocols contributed to the NE Black Out of 2003, the 2008 Florida Black Out or the more recent SW
Black Out. Oncor also takes the position that many of the ideas prescribed within the standard are
already being effectively implemented as industry Best Practice. Oncor is concerned that
implementing the specific elements as prescribed in the standard will result in confusion, and could
compromise personnel safety. Oncor offers the following alternative language. R1 “When a Reliability
Coordinator, Transmission Operator or Balancing Authority requires actions to be executed as an
Operating Communication, the Reliability Coordinator, Transmission Operator or Balancing Authority
shall identify the action as an Operating Communication to the recipient. “ Oncor also offer the
following alternative language for R2 “R2. Each Balancing Authority, Transmission Operator,
Generator Operator, and Distribution Provider that is the recipient of an Operating Communication
shall repeat, restate, rephrase or recapitulate the Operating Communication.”
No
Oncor also takes the position that all of the ideas prescribed within these requirements including the
implementation, assessment, evaluation and correction of communication protocols, are already being
effectively implemented as industry Best Practice. In addition, Oncor requests that NERC substitute
the CIP v.5 'zero defects' (Each Responsible Entity shall implement, in a manner that identifies,
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assesses, and corrects deficiencies, one or more documented processes) language in COM-003 in
order to minimize potential confusion. Oncor offers the following substitute language for R3 and R4.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues an
Operating Communication shall either: • Confirm that the response from the recipient of the
Operating Communication (in accordance with Requirement R2) was accurate, or • Reissue the
Operating Communication to resolve any misunderstandings.
No
Additional Comments Received:
AESO Successive Ballot for Project 2007-02 (COM-003-1)
AESO has issues with some of the content of this reliability standard as follows:
1. The AESO does not support mandating the use of alpha-numeric identifiers as included in
requirement R1.5. We deem that this may be part of good operating practices, but does not
support this to be a mandatory obligation enforceable by law.
2. The AESO does not support requirement R3 to implement a process for identifying deficiencies
with adherence to the communication protocols in requirement R1. It is the opinion of the AESO
that if the failure to fully implement an operating instruction results in a reliability issue that it
should be caught through routine event analysis, including the analysis used in EOP-004 when
determining whether a disturbance report is required. The AESO does not support a separate
process to be developed to identify deficiencies with adherence to the specified communication
protocols.
Grant Count PUD
Grant fully supports the intent of the proposed language for COM-003 and recognizes the significant effort
towards emphasizing identification, assessment and corrective actions that promote reliability. However,
we believe that the language contained under R1.5 will hinder normal operations. If R1.5 could be altered
to include language such as “alpha-numeric clarifiers shall be used when necessary to clearly
communicate Operational Instructions”, then we would cast an affirmative vote. The acknowledgement
portion of three way communications will allow either the recipient or issuer of the Operational Instructions
the ability to confirm that the message was received accurately or not. If not, then the use of clarifiers is
appropriate. But the use of alpha-numeric clarifiers in ALL Operational Instructions is burdensome and
unnecessary.
Edison Electric Institute
EEI generally supports the proposed COM-003 structure and content. We believe that COM003 will provide a good response to both FERC Order No. 693 (P. 540) and Blackout
Recommendation #26 in the U.S./Canada joint Blackout Report. EEI commends the drafting
team for its work and for laying out a pragmatic framework for tightened communications
protocols.
Since the new proposed draft marks a significant change from the previous direction, EEI
understands that some issues need to be considered. Some can be addressed by the drafting
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team and others are likely beyond the scope of the team. In general, companies seek to ensure
that mandatory requirements when applied in the future will avoid causing confusion in realtime. For example, the definition of “Operating Instruction” in draft COM-003-1(1) may need
some clarification to make sure that it sufficiently differentiates such communications from a
“Reliability Directive” issued under COM-002-3. (2)
Clarification may be needed to synchronize the COM-003 process requirements with protocols
in already-approved COM-002-3( 3). We view these as relatively minor changes that would not
require substantial changes to the draft COM-003 language.
In addition, companies also have questions regarding language referred to as ‘internal controls’
or ‘zero defects’ language, and how NERC and the regions will apply various judgments on
potential violations under this new and untested concept. While both CIP v.5 and draft COM003 take aim at certain symptoms, it is difficult for companies to see how NERC will actually
perform these tasks since no field experience has been tested or broadly communicated with
stakeholders. Instead of this piecemeal approach, EEI has strongly believed for several years
that NERC should address this issue as a strategic matter and develop a comprehensive plan
that would set both compliance and enforcement on a more sustainable foundation. The
resources being applied to compliance and enforcement across the electric industry need to be
efficiently applied. EEI continues to urge NERC to make commitments to develop a
comprehensive framework that will redesign the program.
1
Proposed COM-003-1: http://www.nerc.com/docs/standards/sar/COM-003-1__20120821_Clean.pdf
“Operating Instruction — Command from a System Operator to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
2
Pending COM-002-3: http://www.nerc.com/docs/standards/sar/COM-002-3_Standard_20120607_Clean.pdf
“Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator, or
Balancing Authority where action by the recipient is necessary to address an Emergency or Adverse
Reliability Impact.”
3
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Consideration of Comments
Operating Personnel Communications Protocols
Project 2007-02
The Operating Personnel Communications Protocols Drafting Team thanks all commenters who
submitted comments on the proposed draft COM-003-1 Operating Personnel Communications
Protocols standard. This standard was posted for a 45-day public comment period from August 22,
2012 through September 20, 2012. Stakeholders were asked to provide feedback on the standard and
associated documents through a special electronic comment form. There were 80 sets of comments,
including comments from approximately 232 different people from approximately 141 companies
representing all 10 Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration:
The SDT agreed with the commenters from draft 2 and modified its approach to closely align COM003-1 draft 3 with the proposal by the NERC Operating Committee that applicable entities should be
required to:
a) develop written communication protocols that address the elements in draft 2 of COM-003-1,
b) train on those protocols, and
c) develop internal controls to find and correct deviances from those protocols.
In addition, the SDT developed the RSAW for this standard in conjunction with NERC Compliance
staff, and posted it for comment along with draft 3 of COM-003-1. Most Draft 3 commenters
supported this approach and many requested additional clarification and confirmation that the
majority of communication protocol deficiencies will be addressed in a non-zero defect environment;
and that the documented communication protocols would permit flexibility to reflect the operating
environment and circumstances that an entity experiences when operating the BES.
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
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A prevalent theme in draft 3 was questioning the necessity of the standard, specifically one that
requires three part communication for routine operations. This was also a continuation of similar
comments from draft 2.
During its discussion of the approval of the Interpretation of COM-002-2 R2, the NERC BOT stipulated
in its approval the expedited development of a comprehensive communications program, which
would address necessary communication protocols for use in the operation of the Bulk Electric
System. The SDT determined that protocols concerning three part communication (when it is
necessary and what is required) during normal operations was a necessary step in addressing the
BOT’s concern. The SDT remains resolute in its position to require three part communication in
documented communication protocols.
Another theme that was repeated in draft 3 comments from draft 2 was the concern that the work of
the SDT was not addressing the intentions of the SAR, related directives and orders.
The SDT disagrees and cites language from those documents. The purpose of the SAR for this project
is “Require that real time system operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and shorten response time.”
Additionally, the SAR is very specific in that it also includes the term “normal” operating conditions
under Applicability: “Clear and mutually established communications protocols used during real time
operations under normal and emergency conditions ensure universal understanding of terms and
reduce errors.”
Another repetitive theme was that the use of three part communications should be limited to
Reliability Directives only.
A Reliability Directive, by definition, is limited to instances where action by the recipient is necessary
to address an Emergency or Adverse Reliability Impact. The SDT believes that it is necessary to
specify 3 part communication as a necessary communications protocol for all Operating Instructions,
not just emergency situations. The OPCPSDT believes that the potential for risk to the reliability of
the BES exists for all Operating Instructions.
Still others expressed a desire to combine COM-002-3 and COM-003-1 into a single standard.
The SDT does not disagree, but that is outside the scope of the SAR for this project. The purpose of
the SAR for this project is “Require that real time system operators use standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time.” This is a broader scope for communications than that for Project 2006-06.
Definitions: (Question 1)
About half of the draft 3 commenters disagreed with the new proposed term Operating
Instructions, introduced in Draft 3 and defined as: “Command from a System Operator to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System.”
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Commenters stated:
• The proposed term Operating Instruction is confusing and the large extent of operations to
which it potentially applies could create an overwhelming compliance exposure due to the large
number of communications described in the definition.
•
The term would include general discussions and discussions on options and alternatives that
take place to determine courses of action to address BES operating concerns.
•
The term, Operating Instruction, and its relation to the proposed term “Reliability Directive”
from COM-002-3 is unclear.
To eliminate the confusion expressed by commenters; and to clarify the scope and intent of an
Operating Instruction, the SDT has revised the definition to read:
“Operating Instruction —A cCommand from by a System Operator of a Reliability Coordinator,
or of a Transmission Operator, or of a Balancing Authority, where the recipient of the command
is expected to act to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information
and of potential options or alternatives to resolve BES operating concerns are not commands
and are not considered Operating Instructions. “
Requirements: Question 2
Requirement R1 (Issuers and receivers of Operating Instructions, RCs, BAs and TOPs) and R2(receivers
only - of Operating Instructions, DPs and GOPs) (requires entities to have documented communication
protocols to use the English Language, 24 Hour Clock, and Time Zone reference, Common interface
identifiers, and alpha-numeric clarifiers, three part communication, and all call communication during
oral and written Operating Communication):
•
In response to Question 2 dealing with the English language, 24 hour clock and time zone
reference, common interface identifiers, and alpha-numeric clarifiers, a large majority of the
commenters still believe that all of subparts are too prescriptive. The SDT acknowledges this
and has defended it as necessary for this standard in drafts 1, 2and 3. When developing
common communication protocols to be used for communication between entities, it is
necessary to have a standard structure to build the protocols. Absent such structure it would
be unlikely that protocols would be developed in a manner that would be recognizable among
the communicating entities leading to greater confusion. While the Parts of R1 and R2 call for
specific content, draft 3 and draft 4 Requirements permit greater latitude to create protocols
that fit the environment in which an entity must operate.
•
There was a lack of agreement on requiring the use of the English language as part of a
communication protocol. Some commenters support requiring the use of English, and indicated
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that communicating in a language other than English would cause confusion, while others
contested requiring English exclusively, stating in some areas the use of other languages in a
localized environment may be effective. The SDT believes that English should prevail in almost
all cases and those situations where another language would be required by law would be a
rare exception. Furthermore, this requirement only applies to communication initiated by a
System Operator at one functional entity to another functional entity.
•
Commenters were also divided on the use the 24 hour clock and time zone references as part of
a communication protocol. Those who indicated support stated they felt it added clarity to
communications. Other commenters stated that the 24 hour clock and time zone references
are too prescriptive and should be eliminated. The SDT believes use of the 24 hour clock and
time zone references, when a clock time is used, clarifies the time element of
communications, which will enhance reliability by avoiding time related mistakes that could
affect the reliability of the BES. The SDT points out in this response that these protocols are to
be used only when a specific clock time is cited. The SDT accepts relative time such as: “ in the
next 10 minutes, on the hour or half hour” as clear and unambiguous and not requiring the
use of the 24 hour clock and time zone references.
•
Commenters in draft 3 indicated that “alpha-numeric clarifiers” are of no value and would only
lead to confusion and delays by System Operators. The SDT has chosen to retain the inclusion
of alpha-numeric clarifiers as a means of clarifying Operating Instructions. The use of such
clarifiers, which an entity can develop to suit their preferences, eliminates the ambiguity of
similar sounding letters and numbers. Their use, based on the experience of other
organizations that use them, becomes a natural part of communication language.
•
Many commenters stated that Requirement R1 Part 1.4 is not necessary, stating that it is
covered by standard TOP-002 R18. “Project 2007-03 chose to eliminate TOP-002-2a
Requirement R18. Entities have existing processes that handle this issue. This is an
administrative item. The bottom line is that this situation is handled by the operators as part of
their normal responsibilities, and no one is aware of a switching error caused by confusion over
line identifiers.” The SDT is aware that Requirement R18 is being eliminated by the RTOSDT as
part of project 2007-03. P COM-003-1, while reintroducing the concept of line identifiers,
limits the scope to only Transmission interface Elements or Transmission interface Facilities
(e.g. tie lines and tie substations). This ensures that both parties are readily familiar with
each other’s interface Elements and Facilities eliminating hesitation and confusion when
referring to equipment for the Operating Instruction. This shortens response time and
improves situational awareness. Additionally the SDT has added the commenters’
recommended language “……., unless otherwise mutually agreed,”- to permit entities to
develop mutually acceptable nomenclature.
•
Many commenters indicated that the scope of Operating Instructions and the associated
requirements were too broad and that the sheer numbers of Operating Instructions would
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overwhelm the entities in terms of monitoring and evidence retention. They also are concerned
that under these Requirements, operators would be distracted to focus more on complying with
the specifications for three part communication rather than effectively responding to incidents,
thereby reducing reliability. The SDT believes universal communication protocols are critical to
avoid mistakes that would result in reduced reliability on the BES, which is within the scope of
the SDT’s SAR. After consideration of comments in these questions, as well as question 10,
the SDT modified its approach in COM-003-1, draft 3 to a control based standard where such
deficiencies are corrected generally without a finding of non compliance. While there may be
many such deficiencies or deviations the entity has the ability to improve performance and
compliance without a potential violation for each incident. This is an equivalent approach to
the one provided in the CIP version 5 standards, which was recently approved by industry.
•
Several stakeholders continue to identify potential conflicts between COM-003-1 and the
recently approved COM-002-3 standard, which also addresses the use of three-part
communications. Some stated that the applicability of the two standards was confusing and
called for one communication standard to reduce the confusion. A few commenters continue to
stress this should be limited to COM-002-3. In COM-002-3 the proposed requirements focus on
the use of three part communication when issuing and receiving “Reliability Directives.” As
proposed in COM-002-3, a Reliability Directive is a directive issued to address an Emergency or
an Adverse Reliability Impact. The OPCP SDT believes the scope of their SAR extends during
and beyond communications during emergency situations, thereby necessitating a new
standard such as the proposed COM-003-1. The OPCP SDT proposes use of three-part
communication for all Operating Instructions, under normal and emergency conditions, and
has worked with the RCSDT to ensure that COM-002-3 and COM-003-1 are complementary to
achieve this objective.
Requirements: Question 3
Requirement R3 (Issuers and receivers of Operating Instructions: RCs, BAs and TOPs) and R4
(receivers only of Operating Instructions: DPs and GOPs) (requires entities to implement a process to
identify, assess and correct deficiencies and to review and improve the process.)
• Many commenters, even those who voted no on Question 3 supported the SDT’s decision to
incorporate internal controls. Some of their concerns were if regional CEAs are “onboard” with
the SDT’s approach. The SDT has collaborated with NERC compliance and jointly developed
the RSAW for COM-003-1. NERC Compliance and NERC executives have been speaking to
industry, Regional Entities and regulators to advocate for control based standards citing the
absolute need for this approach to address burdensome and unreasonable requirements and
to promote a more efficient use of resources.
• A large number of commenters, for various reasons recommended that the SDT consider using
a similar format and language to emulate the CIP v.5 standards which are also nascent control
based standards and to address concerns over their understanding of R3 and R4. The
commenters stated that it would be more consistent and less confusing. The SDT discussed the
5
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
commenters’ concerns and concluded that adopting the same general format for COM-003-1
would add value by improving consistency and remaining effective as a standard to improve
communication and reliability on the BES.
“R1 (and R2-DP and GOP). Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to
deficiencies and the quality of an entity’s implementation of the communication protocols in
a manner that identifies, assesses and corrects deficiencies. The COM-003-1 RSAW, VSLs, VRFs
and Measures have been updated to reflect this change.
VRFs and VSLs
The SDT acknowledges there were many comments on draft 3 regarding VSLs and VRFs and we
appreciate the contributions. The SDT has dramatically changed draft 4 and all of the VRFs and VSLs
have been adjusted to reflect those changes. The adoption of the language similar to CIP v.5 and the
subsequent elimination of R3 and R4 will require another set of industry comments.
Additional Issues addressed by the SDT:
Small numbers of commenters raised issues around:
•
Some commenters questioned why the standard addressed “all call” types of communications
(Requirement 1, Part 1.9 and Requirement 2, Part 2.2). The SDT added language to
(Requirement 1, Part 1.9 and Requirement 2, Part 2.2) to clarify how these Requirements
apply when all calls are used to communicate based on requests from many commenters in
COM-003-1, draft 2.
Outstanding Unresolved Issues:
Whether “read” receipts for written Operating Instructions should be addressed in the
Measures. - This is in reference to the parts of R1 and R2 which are applicable only to oral
Operating Communication, so the SDT made no change,
• Exclusion for Face to Face Operating Instructions in a control room, - The SDT clarified that
COM-003-1 only applies to communication between functional entities. For example, if a TOP
System Operator is issuing an Operating Instruction to an individual that is internal to that
TOP, three part communication is not required by this standard. If a TOP System Operator is
issuing an Operating Instruction to an individual in another TOP or another functional entity
(e.g. Distribution Provider, Generator Operator), then three part communication is required
by this standard. If a TOP System Operator is issuing an Operating Instruction to an individual
6
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
that is not in a functional entity, then three part communication is not required by this
standard.
Index to Questions, Comments, and Responses
_Toc335986474
1.
Do you agree with the changes made to the proposed definition “Operating Instruction” (now
proposed as a “Command from a System Operator to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System?”) to be
added as a term for the NERC Glossary? If not, please explain in the comment area. .................25
2.
The SDT has proposed that the applicable entities have documented communication protocols
that incorporate elements listed in COM-003-1, R1 and R2. Do you agree with these proposed
requirements ? If not, please explain in the comment area. ..................................................51
3.
The SDT has proposed requirements (COM-003-1, R3 and R4) for appicable entities to implement a
process to identify, assess and correct deficiencies related to the entity’s documented
communication protocols; and to evaluate that process based on deficiencies found externally
from the process. Do you agree with the proposed requirements? If not, please explain in the
comment area of the last question. ..................................................................................96
4.
Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4? ........................... 131
5.
Do you have any other comments or suggestions to improve the draft standard?................... 147
7
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec Transenergi
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Michael Jones
National Grid
NPCC 1
Hydro One Networks Inc.
NPCC 1
10. David Kiguel
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
11. Michael R. Lombardi Northeast Utilities
NPCC 1
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, Inc.
NPCC 5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Brian Robinson
Utility Services
NPCC 8
20. Michael Schiavone
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
24. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
2.
Group
Additional Organization
Region
East Kentucky Power Cooperative
SERC
Brazos Electric Power Cooperative, Inc.
ERCOT 1, 5
3. Scott Brame
North Carolina Electric Membership Corporation
RFC
1, 3, 4, 5
4. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
5. Susan Sosbe
Wabash Valley Power Association
RFC
3
6. Robert Thomasson Big Rivers Electric Corporation
Kent Kujala
6
7
8
9
10
1, 3, 5
SERC
Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.
Group
5
Segment
Selection
2. Shari Heino
3.
4
X
1. Ashley Gonyer
7. John Shaver
3
ACES Power Marketing Standards
Collaborators
Ben Engelby
Additional
Member
2
Detroit Edison
WECC 1, 4, 5
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Christie Wicke
RFC
3, 4, 5
2. Al Eizans
RFC
3, 4, 5
3. Jeffery DePriest
RFC
3, 4, 5
9
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4. Dan Herring
4.
RFC
Group
Ron Sporseen
Additional Member
3
4
5
6
7
8
9
10
3, 4, 5
PNGC Comment Group
Additional Organization
X
X
X
X
X
X
Region Segment Selection
1.
Joe Jarvis
Blachly-Lane Electric Cooperative
WECC 3
2.
Dave Markham
Central Electric Cooperative
WECC 3
3.
Dave Hagen
Clearwater Power Company
WECC 3
4.
Roman Gillen
Consumers Power Inc.
WECC 1, 3
5.
Roger Meader
Coos-Curry Electric Cooperative
WECC 3
6.
Bryan Case
Fall River Electric Coooperative
WECC 3
7.
Rick Crinklaw
Lane Electric Cooperative
WECC 3
8.
Annie Terracciano
Northern Lights Inc.
WECC 3
9.
Aleka Scott
PNGC Power
WECC 4
10. Heber Carpenter
Raft River Rural Electric Cooperative WECC 3
11. Steve Eldrige
Umatilla Electric Cooperative
WECC 1, 3
12. Marc Farmer
West Oregon Electric Cooperative
WECC 4
13. Margaret Ryan
PNGC Power
WECC 8
14. Rick Paschall
PNGC Power
WECC 3
5.
Gerry Beckerle
Group
2
SERC OC Standards Review Group
Additional Member Additional Organization Region Segment Selection
1.
Jeff Harrison
SERC
1, 3, 5, 6
2.
Robert Thomasson Big Rivers
AECI
SERC
1
3.
Dan Roethemeyer
Dynegy
SERC
5
4.
Jim Case
Entergy
SERC
1, 3, 6
5.
Mark Thomas
Entergy
SERC
1, 3, 6
6.
Phil Whitmer
Georgia Power
SERC
3
7.
Brad Young
LGE-KU
SERC
1
8.
Terry Bilke
MISO
SERC
2
9.
Scott Brame
NCEMC
SERC
1, 3, 4, 5
10. William Berry
OMU
SERC
3, 5
11. Tim Hattaway
PowerSouth
SERC
1, 5
12. Troy Blalock
SCANA
SERC
1, 3, 5, 6
10
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13. John Rembold
SIPC
SERC
1
14. Marc Butts
Southern Co. Services
SERC
1, 5
15. Randy Hubbert
Southern Co. Services
SERC
1, 5
16. Todd Lucas
Southern Co. Services
SERC
1, 5
17. Joel Wise
TVA
SERC
1, 3, 5, 6
18. Sam Austin
TVA
SERC
1, 3, 5, 6
19. Stuart Goza
TVA
SERC
1, 3, 5, 6
20. Steve Corbin
SERC
SERC
10
6.
Greg Rowland
Group
Duke Energy
2
3
X
X
X
X
X
X
4
5
X
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
Duke Energy
RFC
1
2. Lee Schuster
Duke Energy
FRCC
3
3. Dale Goodwine
Duke Energy
SERC
5
4. Greg Cecil
Duke Energy
SERC
6
7.
Group
Chang Choi
Tacoma Public Utilities
X
X
Additional Member Additional Organization Region Segment Selection
1. Travis Metcalfe
Tacoma Public Utilities
WECC 3
2. Keith Morisette
Tacoma Public Utilities
WECC 4
3. Chris Mattson
Tacoma Power
WECC 5
4. Michael Hill
Tacoma Public Utilities
WECC 6
8.
Group
Thomas McElhinney
JEA
X
Additional Member Additional Organization Region Segment Selection
1. Ted Hobson
FRCC
1
2. Garry Baker
FRCC
3
3. John Babik
FRCC
5
9.
Group
James R. Keller
Additional Member
Additional Organization
Wisconsin Electric Power Co.
1. Linda Horn
Wisconsin Electric Power Co. RFC
5
2. Tony Jankowski
Wisconsin Electric Power Co. RFC
4
10.
Group
Connie Lowe
X
X
X
Region Segment Selection
Dominion
X
X
X
X
11
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
5
6
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Louis Slade
RFC
5, 6
2. Randi Heise
MRO
5, 6
3. Mike Garton
NPCC 5, 6
4. Michael Crowley
SERC
11.
Group
WILL SMITH
1, 3, 5, 6
MRO NSRF
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1.
MAHMOOD SAFI
2.
3.
MRO
1, 3, 5, 6
CHUCK LAWRENCE ATC
MRO
1
TOM BREENE
WPS
MRO
3, 4, 5, 6
4.
JODI JENSON
WAPA
MRO
1, 6
5.
KEN GOLDSMITH
ALTW
MRO
4
6.
DAVE RUDOLPH
BEPC
MRO
1, 3, 5, 6
7.
ERIC RUSKAMP
LES
MRO
1, 3, 5, 6
8.
JOE DEPOORTER
MGE
MRO
3, 4, 5, 6
9.
SCOTT NICKELS
RPU
MRO
4
10. TERRY HARBOUR
MEC
MRO
1, 3, 5, 6
11. MARIE KNOX
MISO
MRO
2
12. LEE KITTELSON
OTP
MRO
1, 3, 5
13. SCOTT BOS
MPW
MRO
1, 3, 5, 6
14. TONY EDDLEMAN
NPPD
MRO
1, 3, 5
15. MIKE BRYTOWSKI
GRE
MRO
1, 3, 5, 6
16. DAN INMAN
MPC
MRO
1, 3, 5, 6
12.
Sasa Maljukan
Group
OPPD
Hydro One
X
Additional Member Additional Organization Region Segment Selection
1. David Kiguel
13.
Group
Hydro One Networks Inc. NPCC 1
David Dockery - NERC
Reliability Compliance
Coordinator
Additional Member
Associated Electric Cooperative Inc JRO00088
X
X
Additional Organization Region Segment Selection
12
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1. Central Electric Power Cooperative
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
14.
Group
Albert DiCaprio
ISO/RTO Standards Review Committee
2
3
4
5
6
7
8
9
10
X
Additional Member Additional Organization Region Segment Selection
1. Terry Bilke
MISO
RFC
2
2. Greg Campoli
NYISO
NPCC
2
3. Kathleen Goodman ISO NE
NPCC
2
4. Ben Li
IESO
NPCC
2
5. Ali Miremadi
CAISO
WECC 2
6. Stephanie Monzon
PJM
RFC
7. Steve Myers
ERCOT
ERCOT 2
8. Charles Yeung
SPP
SPP
15.
Group
Allen Mosher
APPA, LPPC and TAPS
Additional Member Additional Organization
Region
1. Joseph Tarantino
SMUD (on behalf of LPPC)
2. William Gallagher
TAPS
16.
Group
2
X
X
X
X
X
X
X
X
X
X
Segment Selection
1, 3, 4, 5, 6
NA - Not Applicable 1, 3, 4, 5, 6
Sam Ciccone
FirstEnergy
Additional Member Additional Organization Region Segment Selection
1. D. Hohlbaugh
FE
RFC
2. L. Raczkowski
FE
RFC
3. J. Reed
FE
RFC
4. G. Pleiss
FE
RFC
5. B. Duge
FE
RFC
17.
Group
Brent ingebrigtson
Additional Member
1. Elizabeth Davis
Additional Organization
PPL EnergyPlus LLC
PPL Corporation NERC Registered Affiliates
X
Region Segment Selection
WECC 6
13
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Annette Bannon
PPL Generation LLC
RFC
5
3. Brenda Truhe
PPL Electric Utilities Corporation RFC
1
18.
Group
Frank Gaffney
Florida Municipal Power Agency
2
X
3
X
4
X
5
6
X
X
X
X
7
8
9
10
Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Joe Stonecipher
Beaches Energy Services FRCC
1
6. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
7. Randy Hahn
Ocala Utility Services
3
19.
Group
FRCC
Robert Rhodes
Additional Member
Additional Organization
Region Segment Selection
1.
Rick Brenneman
Xcel Energy
SPP
1, 3, 5, 6
2.
Michelle Corley
Cleco Power
SPP
1, 3, 5
3.
Denney Fales
Kansas City Power & Light
SPP
1, 3, 5, 6
4.
Greg Froehling
Rayburn Country Electric Cooperative SPP
3
5.
Ron Gunderson
Nebraska Public Power District
MRO
1, 3, 5
6.
Jonathan Hayes
Southwest Power Pool
SPP
2
7.
Bo Jones
Westar Eneregy
SPP
1, 3, 5, 6
8.
Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
9.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
10. Greg McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
11. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
12. Jamie Strickland
Oklahoma Gas & Electric
SPP
1, 3, 5
13. Bryan Taggart
Westar Energy
SPP
1, 3, 5
20.
Jamison Dye
Group
X
SPP Standards Review Group
Bonneville Power Adminstration
X
X
Additional Member Additional Organization Region Segment Selection
1. Timothy
Loepker
WECC 1
2. Theodore
Snodgrass
WECC 1
14
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
3. Rodney
Krauss
WECC 1
4. Erika
Doot
WECC 3, 5, 6
5. Deanna
Phillips
WECC 1, 3, 5, 6
6. James
Burns
WECC 1
7. Alfredo
Bocanegra
WECC 1
2
3
4
5
6
7
8
9
10
21.
Group
David Dworzak
Edison Electric Institute
Additional members can be found at www.eei.org
Individual
Janet Smith, Regulatory
Affairs Supervisor
Arizona Public Service Company
X
X
X
X
23.
Individual
Sandra Shaffer
PacifiCorp
X
X
X
X
24.
Individual
Antonio Grayson
Southern Company
X
X
X
X
25.
Individual
Scott McGough
Georgia System Operations
26.
Individual
Daniel Duff
Liberty Electric Power, LLC
27.
Individual
Robert W. Kenyon
NERC - Investigations Group
28.
Individual
Gary Cox
Southwestern Power Administration
29.
Individual
Martin Bauer
US Bureau of Reclamation
30.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
X
31.
Individual
NIPSCO
X
X
X
X
Individual
Joe O'Brien
Steve Alexanderson
P.E.
33.
Individual
Andrew Gallo
City of Austin dba Austin Energy
34.
Individual
Chantal Mazza
Hydro-Quebec TransEnergie
35.
Individual
Michelle R. D'Antuono
Occidental Energy Ventures Corp.
36.
Individual
Greg Travis
Idaho Power Co.
37.
Individual
Cristina Papuc
TransAlta Centralia Generation LLC
38.
Individual
Terri Pyle
Oklahoma Gas & Electric
22.
32.
X
X
X
X
X
X
X
X
X
X
X
Central Lincoln
X
X
X
X
X
X
X
X
X
X
15
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
39.
Individual
3
4
5
6
The United Illuminating Company
Individual
41. Individual
Anthony Jablonski
Michael Falvo
ReliabilityFirst
Independent Electricity System Operator
42.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
43.
Individual
Dale Wadding
Dairyland Power Cooperative
X
X
8
9
10
44.
Individual
John D. Brockhan
CenterPoint Energy Houston Electric, LLC.
X
45.
Individual
Daniel McGuire
Salt River Project
46.
Individual
Jose H Escamilla
47.
Individual
48.
X
X
X
X
X
X
X
X
X
X
X
CPS Energy
X
X
X
Kayleigh Wilkerson
Lincoln Electric System
X
X
X
X
Individual
Brian Murphy
NextEra Energy Inc.
X
X
X
X
49.
Individual
Laurie Williams
Public Service Company of New Mexico
X
X
50.
Individual
Wryan Feil
Northeast Utilities
X
51.
Individual
Kenneth A Goldsmith
Alliant Energy
X
52.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
X
53.
Individual
Fred Meyer
The Empire District Electric Company
54.
Individual
Melissa Kurtz
US Army Corps of Engineers
55.
Individual
Bob Thomas
Illinois Municipal Electric Agency
56.
Individual
Thad Ness
American Electric Power
Individual
58. Individual
Karen Webb
Don Schmit
City of Tallahassee
Nebraska Public Power District
59.
Individual
Shari Heino
Brazos Elextric Power Cooperative, Inc.
60.
Individual
David Burke
Orange and Rockland Utilities
X
X
61.
Individual
Andrew Z. Pusztai
American Transmission company
X
62.
Individual
Kirit Shah
Ameren
X
63.
Individual
Patrick Brown
Essential Power, LLC
57.
7
X
Jonathan Appelbaum
40.
2
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
16
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
64.
Individual
2
3
4
5
7
8
9
10
X
Don Jones
Texas Reliability Entity
Individual
66. Individual
Terry Harbour
Kathleen Goodman
MidAmerican Energy
ISO New England Inc.
X
67.
Individual
Denise M. Lietz
Puget Sound Energy Inc.
68.
Individual
Michael Moltane
ITC Holdings
X
X
69.
Individual
Kevin Luke
GTC
X
70.
Individual
Lynne Mila
City of Clewiston
X
71.
Individual
Eric Salsbury
Consumers Energy
72.
Individual
Alice Ireland
Xcel Energy
X
X
73.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
74.
Individual
Russell A. Noble
Cowlitz County PUD
X
X
X
75.
Individual
Chris Scanlon
Exelon
X
X
X
76.
Individual
Scott Berry
Indiana Municipal Power Agency
77.
Individual
Rebecca Moore Darrah
MISO
78.
Individual
David Thorne
Pepco Holdings Inc
79.
Individual
Cheryl Moseley
ERCOT
80.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
65.
6
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
17
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration:
The OPCPSDT has reviewed the section and responded to Oklahoma Gas & Electric’s comments. They are absorbed in the question 5
summary.
Organization
Agree
Supporting Comments of “Entity Name”
American Transmission
company
Agree
ATC endorses and supports those comments
submitted by the Edision Electric Institute(EEI)on
behalf of ATC and other REAC members.
City of Clewiston
Agree
please see FMPA's formal comments.
Dairyland Power Cooperative
Agree
MRO NSRF and MISO
Flathead Electric Cooperative,
Inc.
Agree
Central Lincoln
Illinois Municipal Electric
Agency
Agree
Florida Municipal Power Agency and Indiana
Municipal Power Agency
ISO New England Inc.
Agree
We agree with and support the comments
submitted by NPCC, the SRC, and ERCOT.
Nebraska Public Power
District
Agree
Midwest Reliability Organization (MRO) NERC
Standards Review Forum (NSRF); ANDSouthwest
18
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
Power Pool (SPP) RTO
Orange and Rockland Utilities
Agree
Consolidated Edison and Northeast Power
Coordinating Council
US Army Corps of Engineers
Agree
US Bureau of Reclamation
Brazos Elextric Power
Cooperative, Inc.
ACES Power Marketing
MidAmerican Energy
MidAmerican Energy supports MRO NSRF
comments
Oklahoma Gas & Electric
OG&E is in support of Southwest Power Pool
Comments. OG&E also had individual comments
(though I am now not allowed to submit via the
questionnaire; therefore, will submit here).
Q1: No We prefer the use of the word
“Instruction” vs “Command”, though we
understand that word is already part of the term
being defined. Could be open to using the term
“Request” or “Order” or “Direction”.
Response: The SDT received many comments on
draft 2 (previous version) that the word
“instruction” in the body of the definition was
unclear as what type of communication was
covered by the definition. The word “command”
is absolute and strong; leaving no doubt as to the
type of communication the definition is
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
describing.
Q2: No R2.1 does not read well. We would
recommend changing to ““When receiving an oral
two party, person-to-person Operating Instruction,
the recipient is required to repeat, restate,
rephrase, or recapitulate the Operating
Instruction.”
Response: The SDT understands your
recommendation, but used this type of
grammatical structure to specify to the entity that
they must require the recipient to respond as
specified.
Regarding R2.2, we are struggling to identify what
would be considered a “one-way burst messaging
system”. Perhaps examples could be provided to
clarify what the SDT is trying to address.
Response: These are systems several entities use
to convey Operating Instructions to groups of
entities for such things as requesting VARs ,
increases or decreases of input or output. They
employ many forms of technology. The most
common is a group telephone call that has an
option for a receiver of an issued Operating
Instruction to select a “number” to acknowledge
receipt. The technologies are many and vary in
functionality. Each entity would be able to
customize their Communication protocols in R1
and R2 to reflect the capabilities of their system.
20
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
Consider adding similar language that is currently
provided in TOP-001-1a R3 “...shall comply with
reliability directives issued by the Transmission
Operator, unless such actions would violate safety,
equipment, regulatory or statutory requirements.
Under these circumstances the Transmission
Operator, Balancing Authority or Generator
Operator shall immediately inform the Reliability
Coordinator or Transmission Operator of the
inability to perform the directive so that the
Reliability Coordinator or Transmission Operator
can implement alternate remedial actions.” to
allow for those circumstances in which a
Distribution Provider or Generator Operator may
not be able to respond to the Operating
Instruction.
Response: The SDT does not want to add
repetitive language that could possibly create a
double jeopardy situation. We would prefer the
TOP-001-1a R3 requirement to govern this type of
scenario. COM-003-1 deals with operating
communication protocols, not the actions
themselves.
Q3: The word “potential” in R3.1. and R4.1. could
be subjective. Please remove this word such that
both R3.1. and R4.1. state “Identifies deficiencies,”.
Response: This language has been eliminated in
the latest draft of the standard.
21
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
Q4: No
We believe R3 and R4 should be considered Low
VRF as they are establishing the process that
supports R1 and R2 which are already designated
as Low VRF. We do not think the subsequent
process should have a higher VRF than the original
requirement.
Response: The SDT believes the R3 and R4 process
provides an entity great opportunity strengthen
and improve their communication protocols. The
Medium VRF is appropriate because a process
that is dysfunctional and yields growing numbers
of deficiencies is creating the atmosphere for
miscommunication and undesirable impacts on
the BES. The team has incorporated R3 and R4
into R1 and R2, and has assigned a medium VRF
for these requirements.
Other Comments: OG&E continues to believe that
the COM-003 standard, while obviously the result
of significant effort and good intentions, is
unnecessary. Even though we believe that threepart communication is a best practice, and we
utilize it for switching and reliability-related
instructions, we do not believe that it should be
mandated through an enforceable standard. COM002 addresses three-part communications during
emergency conditions and we believe that is
sufficient. With respect to the Paragraph 81
project, NERC should be focused on retiring
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
standard requirements that meet the following
criteria:
(a) have little or no impact on reliability,
(b) administrative, purely documentation,
redundant, or hinders protection of the BES, and
(c) Lower VRF/VSL, lower tier Actively Monitored
Standard, etc. The industry has yet to be provided
sufficient evidence that the lack of three-part
communication during normal operations has been
the direct cause, or even a contributing cause, to
reliability failures. While a good idea in concept,
the COM-003 standard is likely to take significant
effort to interpret, understand and implement, at a
time when industry is already overburdened with
real reliability issues that we already know to be
problematic.
The documents referenced in the Rationale and
Technical Justification document supporting the
need for this standard should be made available
for review if the drafting team is using them as
support for the justification for COM-003.
Response: The SDT respectfully disagrees with
your comment. COM-003-1 does address the
human factor in communication. Human beings
can and will make mistakes during verbal
exchanges . These mistakes have the potential to
create risk for BES operations. FERC Order 693,
the Blackout Report and the SAR call for “tighter”
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Agree
Supporting Comments of “Entity Name”
communications and that is exactly what COM003-1 provides.
The SDT cited those references from the “OC
white Paper” authored by Terry Bilke which was
appended to the Response to Comment for COM003-1, draft 2 by a commenter.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
PNGC Comment Group
The PNGC Comment Group is fully in support of
Central Lincoln PUD's comments.
Wisconsin Electric Power Co.
Midwest ISO
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
1.
Do you agree with the changes made to the proposed definition “Operating Instruction” (now proposed as a “Command from a
System Operator to change or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System?”) to be added as a term for the NERC Glossary? If not, please explain in the comment area.
Summary Consideration:
Many commenters state the proposed definition of “Operating Instruction” is overly broad and ambiguous. System
Operators engage in thousands of communications each year. Many of these are geared toward confirming system
conditions, data, or information and/or gathering information in anticipation of responding to conditions observed on the
Bulk Electric System. The definition’s breadth and ambiguity are likely to give System Operators pause before they
engage in necessary communications to determine whether or not such communications would be Operating
Instructions. The SDT believes the draft 4 language changes, many recommended by commenters, will reduce the
perceived ambiguity. The OPCPSDT has added clarifying language to the definition for draft 4 which is now:
Operating Instruction —“A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator,
or of a Balancing Authority, where the recipient of the command is expected to act to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES operating concerns are not commands and
are not considered Operating Instructions.”
Other commenters cite this would delay necessary information and data gathering by System Operators, which would be
detrimental to the reliability of the BES. “System Operators may opt to treat, as Operating Instructions, all or many
communications that should not fall within the scope of this definition, resulting in every communication being subject to
this standard. That because of the System Operators’ caution and desire to avoid possible penalization by NERC and FERC,
the net effect of this definition is detrimental to the reliability of the BES. Further, because of delays in issuing or
initiating communications, there is significant potential that penalty exposure from other NERC Reliability Standards (in
addition to that identified in the COM-003-1 Reliability Standard, e.g., resulting from a deficiency in implementing or
failing to implement specified protocols). This result would be overly burdensome, and its inefficiency could hamper
System Operators’ ability to perform their necessary reliability functions.” The SDT believes that entities should be
aware that under COM-003-1, draft 3 and now draft 4 they must identify, assess and correct deficiencies with
adherence to communication protocols, not absolute adherence to the protocols, with potential non-compliance for
each deficiency. The emphasis is on monitoring and correction.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
The use of communication protocols, based on its history in other industries, becomes a second nature routine. The SDT
believes the general level of professionalism in the ranks of BES System Operators support a routine transition to these
communication protocols.
Finally there were many recommendations to change for language and terms in the definition by commenters. The SDT
used many of the recommendations provided by commenters. The suggestions added clarity and in other cases
streamlined the flow of the standard. The team responded to commenters whose suggestions were not used with
explanations as to why not.
Organization
ACES Power Marketing Standards
Collaborators
Yes or No
Question 1 Comment
No
The current definition of Operating Instruction, particularly “command from
a System Operator” sounds like a Reliability Directive. We recommend
revising the SAR of COM-003-1 to retire the definition of Reliability
Directive and COM-002-3. There is no delineation between when COM003-1 and COM-002-3 would apply, which could potentially subject
registered entities to double jeopardy. For example, an Operating
Instruction that occurs during an Emergency could open up the potential for
a finding of non-compliance under both COM-002-3 and COM-003-1. We
suggest that the SDT work with the RC SDT to clearly define when COM002-3 and COM-003-1 would apply. A single communication should not
result in multiple penalties.
Response: The OPCPSDT thanks you for your comments. There is no violation of COM-003-1 in the example provided. The
requirements of COM-003-1 call for documented communication protocols implemented in a manner to identify, assess and
correct deficiencies.
SERC OC Standards Review Group
No
We do not see a significant difference between Operating Instructions and
Operating Communications, and we believe neither definition is necessary.
Response: The OPCPSDT thanks you for your comments. The SDT disagrees and has used “Operating Instructions” to narrow the
definition to preclude general discussion communications. The SDT believes that a definition is necessary to identify direct
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Yes or No
Question 1 Comment
commands by a System Operator that alter the configuration of the BES.
Duke Energy
No
Duke Energy is very encouraged by the changes made by the Standard
Drafting Team in the current version of COM-003-1. The shift to requiring a
communications protocol and a process for identifying and correcting
deficiencies is a major step in the right direction. Our concern with the
definition is that additional clarity is needed to distinguish the definition of
Operating Instruction from the definition of Reliability Directive so that
entities know which communications COM-003-1 applies to. This could be
accomplished by changing the definition of Operating Instruction; replacing
the word “Command” with “Normal communication”, and replacing the
word “preserve” with the word “maintain”. The revised definition would
read as follows: “Normal communication from a System Operator to change
or maintain the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System”.
Response: The OPCPSDT thanks you for your comments. The SDT addressed the relationship between the definition of Operating
Instruction and the definition of Reliability Directive in draft 2. The SDT believes a Reliability Directive, during an Adverse
Reliability Impact or an Emergency that that requires a change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System, is a subset or a type of an Operating Instruction.
Dominion
No
Dominion requests clarification of “Command” verses “Directive”. Neither
“Command” nor “Directive” is defined in the NERC Glossary of Terms some guidance/reference is needed. The word “command” seems more
forceful, how does a command differ from a directive?
Response: The OPCPSDT thanks you for your comments. Neither term is a definition and the two words are synonyms. The word
command is forceful and more clearly underscores what an Operating Instruction is and what it is not. The SDT does not see a
need to add it to the NERC Glossary because of the clear dictionary meaning of the term.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Associated Electric Cooperative Inc JRO00088
Yes or No
Question 1 Comment
No
The Operating Instruction definition is no help beyond the “existing”
Operating Command definition, as the later exists neither within the NERC
Glossary downloaded this morning, 9/20/2012, nor within the Clean COM003-1 copy downloaded for final review. The proposed Operating
Instruction definition would add value, were the BES Definition itself
properly scoped to only those assets and functions that undoubtedly affect
the reliable Operation of bulk power system. However the BES Definition
is, by NERC and FERC desire and design, too broad, and so our industry
must now attempt containment of compliance scope and risk within
multiple standards, including COM-003-1. As a result, AECI determines this
Operation Instruction definition to insufficient to responsibly exclude
conversations that have little to no effect upon the BES reliability.
Response: The OPCPSDT thanks you for your comments. The SDT is not clear on the intent of your comment. The “BES definition”
is out of the scope of this question and does not have a bearing on the “Operating Instruction” definition. The definition of
“Operating Instruction” is a proposed definition that will not appear in the NERC Glossary until the standard is filed and approved
by FERC. The SDT has not created a term named “Operating Command” and is not aware of its existence in the NERC glossary. The
SDT has stated many times that general conversation or discussion of options is not an “Operating Instruction.” The OPCPSDT has
added clarifying language to the definition for draft 4 which is now:
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of potential
options or alternatives to resolve BES operating concerns are not commands and are not considered Operating Instructions.
ISO/RTO Standards Review Committee
No
The proposal to standardize the meaning of "Operating Instruction" will
likely cause more problems than it solves. The concept of “to change or
preserve the state, status...” is ambiguous enough for CEAs to still apply the
requirement to virtually all verbal conversations.
Response: The SDT disagrees. The language is very specific and is related
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Yes or No
Question 1 Comment
to “commands from system operators” rather than any verbal
conversations. The OPCPSDT has added clarifying language to the
definition for draft 4 which is now:
Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating
Instructions.
Such a proposed definition may help clarify what the SDT intends to
address, however, by making such a common word a Glossary term
potentially will result in the Industry having to redefine their own manuals
and procedures in which they use the phrase "Operating Instruction". For
years, system operators have dealt with operating instructions on a daily if
not minute basis. To them, operating instructions are necessarily a
communication to alter or preserve the state and status of the BES
condition or BES Element/Facility.
Having a defined term, and calling such communication a “Command” is
totally unnecessary, and can confuse operators from what they understand
to be the meaning of operating instructions. Any proposed standard must
clearly limit the application of the communication protocol requirements to
communications that impact reliability. As proposed, the standard does not
do this. Based on the existing language and the proposed Defined term
Operating Instruction, the scope could readily be interpreted to include
numerous communications that have nothing to do with system reliability.
To remedy this, the SDT should either revise the proposed term in
accordance with Order 693’s limited scope, or delete this term and focus
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
the standard on reliability directives, which is in line with Order 693.
Response: The SDT believes the definition is clear and the word
“command” does convey an order to take an action, rather than to carry
on a general conversation.
The word command is not defined. The capital letter is there because it
was the first word in the definition. The SDT reworded the sentence in
draft 4 to read “A command.”
The SDT is also confident the definition is within the scope of FERC Order
693.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
FirstEnergy
No
Although we believe the definition is on the right track, the wording may
inadvertently cover many conversations between operators and personnel
that do not impact the reliable operation of the BES. We ask the team to
consider clarification, examples, or inclusions/exclusions much like the new
definition of BES. For instance, tasks that may involved transmission lines
associated with IROLs or SOLs, and other critical tasks.
Response: The OPCPSDT thanks you for your comments. The SDT believes the definition is focused on reconfiguration of the BES
and a command from to System Operator to initiate such a reconfiguration. The SDT believes there is a reliability risk from a
mishap if the communication of a command if it is ambiguous or misunderstood. The OPCPSDT has added clarifying language to
the definition for draft 4 which is now:
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
30
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
PPL Corporation NERC Registered
Affiliates
Yes or No
Question 1 Comment
No
The PPL Companies do not agree with the proposed definition of Operating
Instruction as the standard appears to be focused on imposing three part
communications on the industry for all normal / routine operating
communications. Imposing requirements for three part communication for
Operating Instructions may have the effect of elevating all communications
to the state of Reliability Directive (as defined in COM-002-3).
Response: The SDT believes that communications protocols for all normal
/ routine operating communications as well as emergency operating
communication mitigate the same risks. An unintended reconfiguration of
the BES due a miscommunication can be damaging under any operating
condition. Three part communication is a proven and effective protocol
that reduces that risk.
Splitting communications requirements across different standards
introduces the potential of unnecessary confusion. Communications
involving the changing of the state, status, output, or input of a facility,
occur very frequently and potentially even more frequently on preserving
the state of the system. Many of these communicated changes, in and of
themselves, would not have an impact on reliability. However, there are
times (examples could be during a DCS event, an SOL, or an IROL) when
even seemingly insignificant changes to the system must be made
promptly, although the system has not reached the level of emergency or
instability. It is at these times, “when action must be taken”, which the
miscommunication of the action or inaction could lead to amplifying the
risk to the system.
Response: The SDT agrees. Miscommunication transcends operating
states. Universal and consistently applied protocols are proven
instruments that mitigate that risk.
Further, the focus of the standard is on operations and therefore the
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
communications subject to the requirement should be those requiring
action in the Real-time Operations Time Horizon. The definition of which is
included in the NERC document located at
http://www.nerc.com/files/Time_Horizons.pdf .Suggest modifying the
proposed definition as follows: Operating Instruction - Command, other
than a Reliability Directive, from a System Operator to change or preserve
the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System in which action must be taken in the
Real-time Operations Time Horizon.
Response: The SDT believes the suggested language would narrow the
intended focus of the definition. The OPCPSDT has added clarifying
language to the definition for draft 4 which is now:
Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act to change or preserve
the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and
of potential options or alternatives to resolve BES operating concerns are not
commands and are not considered Operating Instructions.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
SPP Standards Review Group
No
We suggest changing ‘command’ to ‘order’. The definition would then read
‘An order from a System Operator...’
Response: The OPCPSDT thanks you for your comments. The SDT acknowledges that the term order adds clarity, but the term
command is even more distinct.
Southern Company
No
Southern does not agree with the definition of “Operating Instruction” as it
continues to be too broad and encompass routine communications
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
between System Operators and other system personnel and other
functional entities. While Southern agrees that 3-part communications is a
good utility practice that has been used by operating entities for many
years, Southern disagrees with the broadness of “Operating Instructions” as
in some of these cases, 3-part communications are not required to protect
the reliability of the system. In fact, this prescriptive requirement, if used
on all communications that could fall under “Operating Instructions” (i.e.
very general information at times), would take System Operators time from
other tasks that are more critical to maintaining reliability. Please note that
there are numerous (i.e. in the millions) of conversations between
operating entities each year and some important tasks could be missed or
delayed if required to follow a standard script for everything.
Response: The SDT believes the definition is clear and that the word
command conveys an order to take an action rather than to carry on a
general conversation. The SDT believes the communication protocols in
COM-003-1 would not take any additional time and would become a
natural part of operators’ communications as they do within other
industries that employ communication protocols.
If the SDT agrees with Southern’s comments related to Requirements 1 and
2, then the definition of “Operating Instruction” would be unnecessary as
each operating entity would define the times when 3-part are necessary,
which in Southern’s case, would be broader than emergency
communications and reliability directives, but not so broad that it would
cover general exchange of information between operating entities.
Response: The SDT is not advocating the use of three part communication
to convey general information. The SDT agrees their use should be
addressed in R1 and R2 in the required documented communication
protocols.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Liberty Electric Power, LLC
No
The definition of the new term, “Operating Instruction,” uses the NERC
Glossary term “System Operator,” which is defined as “An individual at a
control center...whose responsibility it is to monitor and control that
electric system in real time.” The lack of clarity regarding what constitutes
a control center leaves doubt as to which instructions would be covered by
the standard.
Response: The OPCPSDT thanks you for your comments. The SDT sees no reason to define “control center” as it is a very
commonly used and understood term in the industry. The OPCPSDT has added clarifying language to the definition for draft 4
which is now:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
TransAlta Centralia Generation LLC
No
The definition of the new term, “Operating Instruction,” uses the NERC
Glossary term “System Operator,” which is defined as “An individual at a
control center...whose responsibility it is to monitor and control that
electric system in real time.” The lack of clarity regarding what constitutes
a control center leaves doubt as to which instructions would be covered by
the standard.
Response: The SDT sees no reason to define “control center” as it is a very
commonly used and understood term in the industry. The SDT has made
several changes to the definition in draft 4 that add additional
clarification.
Another disagreement with the proposed definition of “Operating
34
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Instruction” is that it inappropriately imposes three-part communication for
routine communications of changes of generation output. Common
operating communications to and from generation plants should not be
considered compliance events requiring the use of alphanumeric clarifiers.
Such a requirement may shift operators’ focus from providing proper
information under critical situations to using the specified terms for every
minor communication, distracting them rather than sharpening their
concentration.
The standard should specify the classes of TO/TOP-to-GOP communications
that constitute compliance events, the formal designations by which such
communications can be recognized, and the parties authorized to issue
such commands.
Response: The SDT believes the use of three part communications is a
proven communication protocol that has wide spread use and is an
effective means of eliminating miscommunication of commands on the
BES. The SDT believes it will help sharpen the operator’s concentration
rather than distracting them.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ReliabilityFirst
No
ReliabilityFirst does not agree with the changes made to the proposed
definition “Operating Instruction”. The definition of Operating Instruction
begins with the word “Command”. ReliabilityFirst is unsure what the word
“command” means and believes it could be mistaken as a directive.
ReliabilityFirst requests further clarification on the meaning of the word
“command”. ReliabilityFirst recommends the following for consideration:
“Communication of instruction from a System Operator to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT thanks you for your comments. A command is an order given by someone in authority. The SDT believes
the definition is clear and that the word command means to take an action that conveys an order rather than to carry on a general
conversation. The language suggested above was featured in draft 2 where commenters stated it was not clear. The word
command is more focused and direct.
Independent Electricity System
Operator
No
We do not see the need to define the term “Operating Instructions” for a
number of reasons: For years, system operators deal with operating
instructions on a daily if not minute basis. Having a defined term, and
calling such communication as “Command” is totally unnecessary, and can
confuse operators from what they understand to be the meaning of
operating instructions. The main intent of this standard is to ensure no
miscommunication between operating personnel, a part of which is
proposed to be fulfilled by exercising 3-part communication for operating
instructions. Notwithstanding our disagreement to having such a
requirement in this standard, such a requirement can be developed without
having to define a term that adds nothing to the universal understanding of
the term but which can confuse operators. For example, Requirement R1
can be revised to:
R1. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall have documented protocols for communicating operating
instructions that will change or preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of the Bulk Electric
System, which incorporate the following: 1.11.2....
Response: The OPCPSDT thanks you for your comments. The SDT believes the definition is clear and that the word “command”
conveys an order to take an action rather than to carry on a general conversation. The OPCPSDT has added clarifying language to
the definition for draft 4 which is now:
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of potential
options or alternatives to resolve BES operating concerns are not commands and are not considered Operating Instructions.”
NextEra Energy Inc.
No
Although NextEra Energy, Inc. (NextEra) is encouraged by the refinements
made to draft COM-003-1, NextEra believes additional refinements are
necessary for COM-003-1 to promote reliability, and in no way hinder
reliability. Next Era’s perspective is heavily influenced by the years of
experience of its system operators in their role as a large Transmission
Operator, Reliability Coordinator agent and Balancing Authority.
Specifically with respect to the definition of Operating Instruction, NextEra
recommends that the definition more closely track the syntax of the
definition of Reliability Directive in COM-002-3, and, thus, read as follows:
Operating Instruction - a command from a Reliability Coordinator,
Transmission Operator or Balancing Authority where action by the recipient
is necessary to change or preserve the state, status, output of an Element
or Facility of the Bulk Electric System.
Response: The OPCPSDT thanks you for your comments. The SDT has incorporated much of your recommended language into
draft 4 of COM-003-1. The OPCPSDT has added clarifying language to the definition for draft 4 which is now:
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Northeast Utilities
No
Operating Instruction Definition is too broad; this essentially imposes on
affected entities the need to use 3-part communication all the time.
Additionally the broadness of the definition may cause compliance
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
difficulties between COM-003-1 and COM-002 if the requirements are not
looked at holistically between the two. A recommendation would be to
combine the requirements into one standard.
Response: The OPCPSDT thanks you for your comments. The SDT notes your recommendation, but that is outside the scope of the
SAR for this project. This Issue has been discussed at the Standards Committee.
American Electric Power
No
While AEP would not argue against the definition of “Operating Instruction”
as proposed, we object to its inclusion as we disagree with the concept of
requiring three part communications for more routine operations. Our
efforts in this regard should first be focused solely on Reliability Directives
before expanding this work, and creating similar requirements for all other
Operating Communications. Requiring three part communications for every
scenario might be considered a best practice by some, but making it a
mandatory practice for routine operations emphasizes the manner of
communications rather than the operations themselves. In addition,
requiring three part communication in such a broader scope could actually
diminish the perceived urgency during more urgent situations where such
communications are more appropriate. In any event, requiring three part
communications for Reliability Directives will likely result in more
widespread usage for more routine operating communications, without
making it a requirement.
Response: The SDT believes that communications protocols for all normal
/ routine operating communications as well as emergency operating
communication mitigate the same risks. An unintended reconfiguration of
the BES due a miscommunication can be damaging under any operating
condition. Three part communication is a proven protocol that is effective
in preventing misunderstandings. FERC Order 693, P 532 supports
communication protocols for normal as well as emergency BES
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
communication.
AEP believes that there should not be multiple project teams proposing
concurrent changes to COM-001, COM-002, and COM-003. Unless there are
overwhelming reasons for not doing so, these efforts should be
consolidated and managed by a single project team. In addition, current
efforts on COM-003 need to be co-located with the proposed changes to
COM-002 within a single standard. Having multiple project teams proposing
concurrent changes results in problems such as this, where
a) changes are proposed to the same standard or
b) similar changes are proposed to separate standards.
AEP cannot support revisions on these matters until they are managed by a
single project team. If the team believes it should still proceed in their
current efforts, then there probably is no need for requiring three part
communications for Reliability Directives (COM-002 R2). As a result, COM002 R2 should be retired and this definition should include emergency
situations as well.
Response: The SDT notes your recommendation, but that is outside the
scope of the SAR for this project. This Issue has been discussed at the
Standards Committee.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Essential Power, LLC
No
The definition of the new term, “Operating Instruction,” uses the NERC
Glossary term “System Operator,” which is defined as “An individual at a
control center...whose responsibility it is to monitor and control that
electric system in real time.” The lack of clarity regarding what constitutes
a control center leaves doubt as to which instructions would be covered by
the standard.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: The SDT sees no reason to define “control center” as it is a very
commonly used and understood term in the industry. The OPCPSDT has
added clarifying language to the definition for draft 4 which is now:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating
Instructions.”
Another disagreement with the proposed definition of “Operating
Instruction” is that it inappropriately imposes three-part communication for
routine communications of changes of generation output. Common
operating communications to and from generation plants should not be
considered compliance events requiring the use of alphanumeric clarifiers.
Such a requirement may shift operators’ focus from providing proper
information under critical situations to using the specified terms for every
minor communication, distracting them rather than sharpening their
concentration. The standard should specify the classes of TO/TOP-to-GOP
communications that constitute compliance events, the formal designations
by which such communications can be recognized, and the parties
authorized to issue such commands.
Response: The SDT believes the use of three part communications is a
proven communication protocol that has wide spread use and is an
effective means of eliminating miscommunication of commands on the
BES. The SDT believes it will help sharpen the operator’s concentration
rather than distracting them.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
Organization
Yes or No
Question 1 Comment
“Operating Instructions” apply to applicable functional entities that issue
and receive them to and from other applicable functional entities.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Texas Reliability Entity
No
Previous version has a description regarding Reliability Directives. This
version does not address Reliability Directives and the relationship to an
Operating Instruction. Is a Reliability Directive a subset of Operating
Instruction? Is a “directive,” as mentioned in several standards, an
Operating Instruction?
Response: The OPCPSDT thanks you for your comments. The SDT advocates that a Reliability Directive and any other directive is a
subset of Operating Instructions when it is a command from a System Operator to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.
MidAmerican Energy
No
MidAmerican has concerns that Operating Instructions as defined is too
broad.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has added clarifying language to the definition for draft 4
which is now:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
Public Service Enterprise Group
No
The definition of “System Operator” includes BA, RC, TOP, and GOP.
Because GOP is included the definition, “System Operator” should be
replaced by “Balancing Authority, Reliability Coordinator, or Transmission
Operator.” See also Project 2010-16: Definition of System Operator.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT thanks you for your comments. The SDT has incorporated your recommended language into draft 4 of
COM-003-1.
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
Exelon
No
We can accept the definition but want to bring to the attention of the
Drafting Team that the description of OI in the Background section of the
Comment form, "Operating Instructions more accurately define the broad
class of communications that deal with changing or altering the state of the
BES", does not agree with the Definition being balloted. The inclusion of the
phrase "or preserve" changes the definition. Nowhere in the discussion of
the need for Operating Instructions or communication protocols is there
discussion of or justification for including the "or preserve" statement.
Exelon can support the modified definition but we believe it will cause
entities to oppose this standard at ballot and create confusion when
implementing controls and auditing to the modified definition.
Response: The OPCPSDT thanks you for your comments. The word “preserve” is used to denote efforts to hold the current state or
status of a BES Element or Facility; in other terms a command not to make any changes to the system to preserve the existing
operating state. The SDT changed it from “maintain” because of confusion cited by draft 2 commenters stating it created a
possible reference to maintenance and repair activities.
Indiana Municipal Power Agency
No
NERC defines the term “System Operator” as “an individual at a control
center (Balancing Authority, Transmission Operator, Generator Operator,
Reliability Coordinator) whose responsibility it is to monitor and control
that electric system in real time.” NERC does NOT define a “control center”
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
which could be problematic when it comes to how an entity views a control
center and how an auditor defines a control center.
Response: The SDT sees no reason to define “control center” as it is a very
commonly used and understood term in the industry.
IMPA believes that there is too much ambiguity when using the words “to
change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System.” IMPA
recommends that the entity giving the Operating Instruction declares it to
be one which eliminates many potential problems of applying a definition
of an Operating Instruction. The receiver of the Operating Instruction
immediately knows what the following instructions will be and will know to
apply the proper communication protocol instead of trying to figure out if
the definition of Operation Instruction applies to what the entity just said.
Response: The SDT points out the beginning of this definition sentence is
“Command from a System Operator ….. “ which we believe eliminates
that ambiguity. The OPCPSDT has added clarifying language to the
definition for draft 4 which is now:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating
Instructions.”
The SDT also believes an entity is permitted to address the declaration
option by creating it in the documented communication protocols in R1
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
and R2.
Response: The OPCPSDT thanks you for your comments.
MISO
No
MISO believes that the proposed definition of “Operating Instruction” is
overly broad and ambiguous. System Operators engage in thousands of
communications each year. Many of these are geared toward confirming
system conditions, data, or information and/or gathering information in
anticipation of responding to conditions observed on the Bulk Electric
System. The definition’s breadth and ambiguity are likely to give System
Operators pause before they engage in necessary communications to
determine whether or not such communications would be Operating
Instructions. This would delay necessary information and data gathering by
System Operators, which delay would likely be detrimental to the reliability
of the BES. Conversely, to avoid confusion regarding which
communications are Operating Instructions and to avoid potential delays,
System Operators may opt to treat, as Operating Instructions, all or many
communications that should not fall within the scope of this definition,
resulting in every communication being subject to this standard.
Under either scenario, because of the System Operators’ caution and desire
to avoid possible penalization by NERC and FERC, the net effect of this
definition is detrimental to the reliability of the BES. Further, because of
delays in issuing or initiating communications, there is significant potential
that penalty exposure from other NERC Reliability Standards (in addition to
that identified in the COM-003-1 Reliability Standard, e.g., resulting from a
deficiency in implementing or failing to implement specified protocols
and/or three-way communication, a deficiency in the review process, which
is now significantly expanded beyond that envisioned during the drafting of
this standard) could be increased. Accordingly, System Operators are likely
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
to apply the protocols applicable to Operating Instructions under R1 of
COM-003 to all communications, whether or not they qualify as Operating
Instructions. This result would be overly burdensome, and its inefficiency
could hamper System Operators’ ability to perform their necessary
reliability functions.
Response: The SDT believes the draft 3 language for the definition of an
Operating Instruction is clear. A “command” should never be confused
with or interpreted as casual or informational conversation. A command is
a very distinct and forceful word where generally the only response
expected is compliance. The OPCPSDT has added clarifying language to
the definition for draft 4 which is now:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating
Instructions.”
Previous commenters have cited the professionalism of the majority of
System Operators. Based on those comments and the experience of the
OPCPSDT as operators we are confident System Operators will be able to
easily manage all of the protocols.
The SDT also requests that MISO look at this draft standard in the context
of its identify, assess and correct features that permit the entity to
improve reliability by correcting deficiencies without being subject to a
finding of non compliance.
As a result, MISO does not support the proposed definition of Operating
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Instruction at this time.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ERCOT
No
ERCOT agrees with the SRC comments, and has these additional comments:
As proposed, the term “Operating Instruction” could include
communications that have nothing to do with reliability - e.g.
communications that are market related and have no impact on system
reliability. That outcome is inconsistent with FERC’s direction in Order No.
693. FERC’s discussion of this issue in Order 693 focuses on alerts and
emergencies - “We adopt our proposal to require the ERO to establish
tightened communication protocols, especially for communications during
alerts and emergencies...” (693 at P 531)”Accordingly, we direct the ERO to
either modify COM-002-2 or develop a new Reliability Standard that
requires tightened communications protocols, especially for
communications during alerts and emergencies.” (693 at P 535)In addition,
the scope of FERC’s concerns is limited to communications that impact the
reliability of the BPS - “We note that the ERO’s response to the Staff
Preliminary Assessment supports the need to develop additional Reliability
Standards addressing consistent communications protocols among
personnel responsible for the reliability of the Bulk-Power System.” (693 at
P 531)”...we believe, and the ERO agrees, that the communications
protocols need to be tightened to ensure Reliable Operation of the BulkPower System.” (693 at P 532)Simply because FERC noted the benefits to
communications during normal conditions does not mean the standard has
to apply to those circumstances. All FERC said was that implementing
consistent protocols will likely provide benefits across all operating
conditions. The focus of the concern was clearly alerts and emergencies,
and limiting the application of the standard to those conditions will provide
benefits to relevant communications during normal conditions.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 1 Comment
Response: The SDT continues to believe the very documents you cite as
not supporting any drafts of COM-003-1 do indeed support and sanction
the requirements developed by the SDT. The SDT remains properly
focused on the guidance provided by the Blackout Report, FERC order 693
and the SAR and from the agencies that developed those documents. The
SDT summarizes by quoting “communications protocols need to be
tightened to ensure Reliable Operation of the Bulk-Power System.” The
SDT has developed a standard that effectively and fairly “tightens
communication”.
However, as written, the standard is overbroad and inconsistent with the
Commission’s directives in Order 693. Consistent with this discussion, the
IRC believes the most effective way to remedy this issue is to eliminate the
proposed term and focus the standard on conditions that actually have a
reliability impact. This can be achieved focusing the requirements on
Reliability Directives.
Response: The SDT will continue to develop COM-003-1 consistent with
the directives and guidance contained in FERC Order 693.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Oncor Electric Delivery Company LLC
No
Oncor offers instead a new glossary term called “Operating
Communication” in order to support alternate language proposed for R1
and R2:Operating Communication - Communication from a System
Operator that when executed results in the change or preserves the state,
status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System
Response: The OPCPSDT thanks you for your comments. “Operating Communication” was the original term the SDT presented in
draft 2. Commenters stated it was too ambiguous. The SDT has added the phrase “that when executed” to draft 4.
47
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Brazos Elextric Power Cooperative, Inc.
No
Question 1 Comment
See ACES comments.
Response: The OPCPSDT thanks you for your comments. Please see our responses to ACES comments.
Ameren
No
See response to question 5.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 5.
MRO NSRF
No
Central Lincoln
Yes
Thank you for making this change. Central Lincoln believes the SDT is on the
right track to limit the scope of the standard to communications originating
from System Operators. This will be less burdensome for many registered
entities as well as the Compliance Enforcement Authorities.
Response: The OPCPSDT thanks you for your comments.
Occidental Energy Ventures Corp.
Yes
Occidental Energy Ventures Corp. ("OEVC") agrees that it is important to
specify that the command came from a System Operator. This allows us to
leverage existing recording and monitoring systems to capture the event.
The previous definition was open ended - which would have required us to
expend an unknowable dollar amount in an attempt to capture every
conversation related to a BES Facility or Element.
Response: The OPCPSDT thanks you for your comments.
Northeast Power Coordinating Council
Yes
Detroit Edison
Yes
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Tacoma Public Utilities
Yes
Hydro One
Yes
APPA, LPPC and TAPS
Yes
Florida Municipal Power Agency
Yes
Bonneville Power Adminstration
Yes
Arizona Public Service Company
Yes
PacifiCorp
Yes
Georgia System Operations
Yes
Southwestern Power Administration
Yes
US Bureau of Reclamation
Yes
Manitoba Hydro
Yes
NIPSCO
Yes
City of Austin dba Austin Energy
Yes
Hydro Québec TransÉnergie
Yes
Idaho Power Co.
Yes
The United Illuminating Company
Yes
Question 1 Comment
49
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
South Carolina Electric and Gas
Yes
CenterPoint Energy Houston Electric,
LLC.
Yes
Salt River Project
Yes
CPS Energy
Yes
Lincoln Electric System
Yes
Public Service Company of New Mexico
Yes
Alliant Energy
Yes
The Empire District Electric Company
Yes
City of Tallahassee
Yes
Puget Sound Energy Inc.
Yes
GTC
Yes
Cowlitz County PUD
Yes
Question 1 Comment
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
2.
The SDT has proposed that the applicable entities have documented communication protocols that incorporate elements listed
in COM-003-1, R1 and R2. Do you agree with these proposed requirements ? If not, please explain in the comment area.
Summary Consideration:
Commenters state that it must be made clear in the requirements that functional entities can incorporate exceptions
(to address emergencies for example) in the protocols that are developed. The SDT believes that there is enough
flexibility in the development of the documented communication protocol documents for the entity to account for
exceptions to deal with emergencies or exceptional circumstances that may exist among communicating entities.
Other commenters note these requirements are too prescriptive. The sub-requirements drill down too deeply into the
communications needed to conduct system operations. sub-parts of R1 and R2 and allow registered entities to define
their own communications protocols based on internal policies and procedures; not from overly-prescriptive reliability
standards. They state the registered entity should have the freedom to decide what elements are to be included in its
communication protocols. R1 and R2 are administrative in nature and unnecessary. There is no need to include 9 subparts on how to achieve proper communications. The SAR and 2003 Blackout Report specified consistent and
uniform communication protocols. The parts to the requirements serve as a frame to sustain a basis for
standardizing the type of protocol the entity should develop. Beyond the framework specified in the parts, an entity
has the flexibility to develop the protocols to fit their particular situation.
There were many other comments on each of the Parts for R1 and R2. Most cited the individual need for each. The
SDT responded to each comment by demonstrating the contribution each protocol makes to communication clarity,
which in turn increases the level of reliability.
Some commenters disagree that the Distribution Provider is listed as an Applicable Entity. The Distribution Provider
load is not considered part of a BES Element or Facility. “The SDT response to an earlier comment on this issue was
that the SDT is aware of some DPs that operate BES equipment. If that is the case, then the standard should be
applicable to only those DPs that operate BES Elements or Facilities - not the numerous DPs who do not.”
If a DP has never or will never receive an Operating Instruction it would not be an applicable entity. If the DP has or
could receive Operating Instruction it must comply with the standard. The DP would have to confirm their situation
with the CEA.
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Northeast Power Coordinating
Council
Yes or No
Question 2 Comment
No
It must be made clear in the requirements that functional entities can incorporate
exceptions (to address emergencies for example) in the protocols that are developed.
Both of these requirements are too prescriptive. The sub-requirements drill down
too deeply into the communications needed to conduct system operations.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language of the requirement R1 and R2 permits the
entity to assess whether variations from the required protocol were valid. The exceptions referenced in your comments are TOP001-2, R1 and IRO-001-3, R2.
ACES Power Marketing
Standards Collaborators
No
(1) The SDT should strike all sub-parts of R1 and R2 and allow registered entities to
define their own communications protocols based on internal policies and
procedures; not from overly-prescriptive reliability standards. The SDT stated that
COM-003-1 is shifting paradigms and putting the responsibility on the registered
entity to monitor, assess and correct its own deficiencies. If that is true, then the
registered entity should have the freedom to decide what elements are to be
included in its communication protocols. R1 and R2 are administrative in nature and
unnecessary. There is no need to include 9 sub-parts on how to achieve proper
communications.
Response: The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain
a basis for standardizing the type of protocol the entity should develop.
(2) The standard, as currently written, does not allow a registered entity to
implement superior practices, such as multi-modal communication (multiple
mediums of communicating) or other superior communication methods and
technologies. There are other ways to achieve efficient and accurate operating
communications and the drafting team should modify the requirements to allow the
registered entity to determine the best method of communication. There will be a
disincentive for registered entities to seek out new technologies to improve
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
communication if the standard remains with the current sub-parts. More discussion
on each sub-part below.
Response: The SDT believes there is nothing in the standard that precludes an
entity from embracing technology or incorporating best practices. The language of
R1 and R2 states [an entity] “shall have documented communication protocols for
Operating Instructions that incorporate the following.” If technology supplants or
improves communication accuracy it can be incorporated in the documented
communication protocol.
(3) R1, part 1.1, use of the English language. The SDT should not require use of the
English language because the vast majority registered entities in North America speak
English, except for a small number of entities in Canada and Mexico. If anything, the
requirement should be modified to state that, “If the English language is not used by
System Operators, there must be a legal justification, such as another language is
mandated by law or regulation.” Not using the English language is a much greater
risk to reliability. The majority of companies that speak English should not have to
maintain compliance policies to reaffirm something that everyone knows that they
are doing. The real issue here is if an entity does not use English language, auditors
should verify how they communicate internally and what controls are in place when
the non-English speaking entity communicates with English-speaking neighbors. The
SDT should not put the burden of compliance on English speakers. The team should
focus on the entities that pose a risk to the BES by not using the English language and
the increased potential for miscommunications from translation errors.
Response: The SDT believes the language of the requirement requires the use of the
English language among functional entities which is consistent with COM-001-1.1,
R4, which will be replaced by COM-003-1.
(4) R1, part 1.2, the 24-hour clock, daylight/standard time. This sub-part does not
take into account real time, such as “perform an action in 5 minutes.” The purpose
statement of the SAR is to provide System Operators with uniform communications
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
protocols that reduce the possibility of miscommunication that could lead to action
or inaction harmful to the reliability of the BES. Requiring an operator to use the 24hour clock for an action that is about to occur could cause more confusion and
increase the possibility of miscommunication. The SDT should consider either
inserting exceptions for the 24-hour clock for real time activities, or strike the 24hour clock from the requirements.
Response: The SDT believes the language of the requirement allows the entity to
determine the use of the 24 hour clock time only if they state an actual clock time
or to use relative time periods if they chose to use relative time consistent with
your example.
(5) R1, part 1.3, Standard or Daylight Savings. This sub-part also poses a risk for
actions performed during real time operations and could increase the likelihood for
error. For example, if WECC RC (daylight) was trying to communicate to a registered
entity located in Arizona (no daylight savings time) to open a breaker. What is more
effective, asking the entity to open a breaker in 5 minutes or at 11:05? In that
scenario, 11:05 may be an hour difference because WECC RC is on daylight and
Arizona is not, and the operators would be focusing on whether they accounted for
the time changes and could potentially lose focus of the task at hand - opening the
correct breaker. The SDT should consider either inserting exceptions for daylight
savings/standard time for real time activities, or strike daylight savings/standard time
from the requirements.
Response: The SDT believes the language of the requirement allows the entity to
determine the use of a time zone if you use a clock time or to use relative time
periods if they chose to use relative time as your example demonstrates. The SDT
does not want to dictate the “how” under this format. The protocol should be
uniform, clear and must increase reliability.
(6) R1, part 1.4, Transmission interface Element or Facility. As discussed above, this
sub-part is unnecessary and should be struck from the standard. A registered entity
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
should be able to define its own communication protocol and the associated internal
controls to ensure effective operating communications. Further, the Real-time
Transmission Operations SDT (Project 2007-03) eliminated TOP-002 R18 which
referred to the same concept as part 1.4, “uniform line identifiers when referring to
transmission facilities.” The reason the Real-time TOP SDT removed the language
from the new standard was because the “requirement adds no reliability benefit.
...There has never been a documented case of the lack of uniform line identifiers
contributing to a System reliability issue.” Project 2007-03 was approved by the
NERC Board of Trustees on May 9, 2012. Why is the OPCP SDT introducing language
that the NERC Board has approved to remove from the requirements? There needs
to be more awareness of the other projects and actions by the NERC Board. To be
consistent, we recommend striking this sub-part in its entirety.
Response: The OPCPSDT is aware of the disposition of TOP-002 R18. The OPCPSDT,
in the context of communication clarity and to tighten communications, believes
that a common naming convention for interface BES Facilities and Elements of
neighboring entities reduces response time and enhances situational awareness.
(7) R1, part 1.5, Alpha-numeric Clarifiers. As discussed above, this sub-part is
unnecessary and should be struck from the standard. A registered entity should be
able to define its own communication protocol and the associated internal controls
to ensure effective operating communications.
Response: The requirement does allow an entity to develop its own protocol
around alpha numeric clarifiers. The protocol should be uniform, clear and must
increase reliability.
(8) R1, part 1.6 and 1.7, Three-part Communication. As discussed above, these subparts are unnecessary and should be struck from the standard. There are more
effective methods of communicating besides using three-part communication. Multimodal communication utilizes several mediums (verbal, visual and other sensory
cues) to enhance communication and may include three-part, but could also include
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other equally efficient and effective methods to communicate, such as through
interactive smart phones and other remote communication devices. Different
strategies may be needed for different utilities and their communication objectives.
For instance, strategies and tools may be combined to meet a wide variety of
communication functions to meet the needs of system operations, including utilizing
new technologies to improve human performance when performing day-to-day
operations. Three-part communications could be a part of the protocol, but threepart should not be in the requirements because it limits utilities from employing
other methodologies are equally effective or superior to three-part communications.
A registered entity should be able to define its own communication protocol and the
associated internal controls to ensure effective operating communications.
Response: There is flexibility in R1 and R2 to incorporate technology that will
enhance human performance. The SDT believes that until technology that can
absolutely ensure that communications are clear and accurate proliferate
throughout the BES; most Operating Instructions will be exchanged human to
human. Three part communication is an effective tool that is used to increase the
accuracy of verbal communication.
(9) R1, part 1.8 and 1.9, One-way Burst Messaging. As discussed above, these subparts are unnecessary and should be struck from the standard. An all call
communication that is incorrect has just a big of an impact on reliability than one that
is not understood. Also, the SDT does not take into account all the various
technologies that exist in the marketplace; what does an entity do for an “all call
conference call” where there are numerous humans on the line? R1, part 1.6 refers
to “two party, person to person” and part 1.8 is limited to “one-way” communication.
There is a gap here - does the SDT intend to exclude the “all call conference call” from
the requirements?
Response: The “all call conference call” would not be subject to the requirements if
it only deals with general information. If the “all call conference call” results in
“Operating Instructions” those “Operating Instructions” would be subject to an
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entity’s communication protocols.
What happens if there are errors in the sent message? Would internal controls be
the remedy?
If the all call communication is not understood and there was no request for
clarification, would an internal control resolve this issue or would the auditor find a
PV? Also, sub-part 1.8 only requires confirmation from one party, even though the
burst message could have been a request for eight parties to reply. There is a gap in
reliability if all parties do not reply in that example. These sub-parts need additional
information for clarity. Same comment for DP/GOP below.
Response: The standard only addresses communication protocols not human
performance errors. Managing human performance is the responsibility of the
entity’s organization. The protocols exist to prevent the error.
The reason to have one recipient reply is to confirm to the issuer that the Operating
Instruction was sent. There are many diverse technologies over many
communication medias that the entity can reflect their in their own documented
communication protocols.
(10) R2 should allow DPs and GOPs to define their own communications protocols
based on internal policies and procedures and there should not be a requirement to
include sub-parts 2.1 and 2.2.
Response: Our responses above address this comment.
(11) R2, part 2.1, Receiving a Three-part Communication. As discussed above, this
sub-part is unnecessary and should be struck from the standard. There are more
effective methods of communicating besides using three-part communication. Multimodal communication utilizes several mediums (verbal, visual and other sensory
cues) to enhance communication and may include three-part, but could also include
other equally efficient and effective methods to communicate, such as through
interactive smart phones and other remote communication devices. Different
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strategies may be needed for different utilities and their communication objectives.
For instance, strategies and tools may be combined to meet a wide variety of
communication functions to meet the needs of system operations, including utilizing
new technologies to improve human performance when performing day-to-day
operations. Three-part communications could be a part of the protocol, but threepart should not be in the requirements because it limits utilities from employing
other methodologies are equally effective or superior to three-part communications.
A registered entity should be able to define its own communication protocol and the
associated internal controls to ensure effective operating communications.
Response: If those technologies exist and are acquired and provide absolute clarity
among Functional Entities, the entity can employ them and redraft their protocol to
reflect more effective functionality of the system.
(12) R2, part 2.2, One-way burst messaging for DP and GOP. As discussed above, this
sub-part is unnecessary and should be struck from the standard. Please see (9) above
for more discussion of one way burst messaging.
Response: The SDTs response to (9) covers the SDTs position. The SDT thanks you
for a very comprehensive review.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
SERC OC Standards Review
Group
No
We support having a documented communications protocol, but do not support
prescriptive elements. Below is an example of language we could support. All the
subparts of R1 and R2 need to be rewritten along these lines.
”R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall have documented communication protocols for Operating Instructions that
address the following:
....1.6. The conditions under which an issuer is expected to:
o Confirm that the response from the recipient of the Operating Instruction was
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accurate, or
o Reissue the Operating Instruction to resolve a misunderstanding.”
Response: The OPCPSDT thanks you for your comments. The SDT replaced the word incorporate” with “include” which we believe
is consistent with your suggestion.
Duke Energy
No
1) In Requirements R1 and R2, the word “incorporate” should be changed to
“address”. This change will align the language of the requirements with the language
of the RSAW, providing flexibility to entities in how their communications protocols
will be structured. This change will also help to alleviate some of the following
concerns.
Response: The SDT replaced the word incorporate” with “include” which we
believe is consistent with your suggestion.
2) In R1.1, 1.3 and 1.4 clarify the meaning of the phrase “between functional
entities”. Do these sub-requirements apply to Operating Instructions between
individuals located in the same functional entity?
Response: As stated in the sub requirements they apply to Operating Instructions
between functional entities. They do not apply to individuals in the same functional
entity. The SDT recommends that they should, but will leave that to the entity.
3) In R1.7, the phrase “repeat, restate, rephrase, or recapitulate” seems excessive.
Suggest changing to just “repeat or rephrase”.
Response: The SDT used the same language as COM-002-3 because the industry
believes the different language of the requirements originally used in each standard
was confusing.
4) R1.6 and 1.7 are describing 3-part communication. Suggest combining 1.6 and
1.75) R1.8 and 1.9 address “one-way burst messaging”, but it’s not clear whether, or
to what extent, 3-part communication is required.
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Response: Part 1.6 and 1.7 are separate in order to fairly divide the requirements
for the issuer and for the receiver.
“All calls” or “one-way burst messaging” are not subject to three part
communication because the SDT believes that it would be impractical for many
receiving parties to acknowledge receipt and repeat the message. The
acknowledgement by one or more receiving entity is a confirmation to the issuer
that the all call message went out.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Dominion
No
We appreciate the SDT’s response to stakeholder comments in the previous draft,
but still find sub-requirements R1.1, R1.2, R1.3 to be too prescriptive. We agree that
these entities should mutually agree on
(1) the language they will use to communicate and
(2) the manner in which they will communicate time (24 hour, zone, zulu, etc).
Response: The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain
a basis for standardizing the type of protocol the entity should develop.
Below are some additional suggestions;
Dominion also disagrees that Distribution Provider is listed as an Applicable Entity.
Distribution Provider load is not considered part of a BES Element or Facility. The SDT
response to an earlier comment on this issue was that the SDT is aware of some DPs
that operate BES equipment. If that is the case, then the standard should be
applicable to only those DPs that operate BES Elements or Facilities - not the
numerous DPs who do not.
Response: The SDT also is aware that many DPs are receivers of load shedding
instructions which are Operating Instructions. They are subject to communication
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protocols on that basis.
R2 should be clarified to read as follows: “For Distribution Providers, and Generator
Operators that operate BES Elements shall have documented communication
protocols for Operating Instructions that incorporate the following:
R1.1 - In lieu of the English language requirement, Dominion recommends defining
the use of a common language for verbal or written communications for Operation
Instruction(s). English shall be the default language unless otherwise mandated by
the entity’s document or mandated by law, regulation, or mutual agreement.
Response: The SDT believes that the language of the requirement allows the entity
to develop the communication protocol in terms that are more effective for
reliability in the entity’s own operating environment.
Under R.1.2 and R1.1.3, It doesn’t matter (and may not be exactly clear) in what time
zone the action will occur. A transmission line can cross time zone boundaries. What
is important is that all operators involved have the same understanding of what is
going to happen, when, and who is to do it. If a TOP that operates in two different
time zones already has a protocol that establishes one zone or the other as their time
standard, will they have to revise their protocol and use two different zones?
Response: No, as long as they include that time zone in the Operating Instruction.
Dominion would recommend the following language to read as follows: Clock-time
communications shall be precise and include the following:
Use of a 24-hour format or 12-hour format with AM/PM designation
Specification of the applicable Time-Zone when multiple Time-Zones are covered
Specification of Standard Time or Daylight Saving Time for Operating Instructions that
will be implemented beyond the present/current day
Response: The SDT believes that the standard permits an entity to develop the
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language you suggested above in the entity’s protocols required in R1 and R2.
The only concern the SDT has with what you suggest is the use of a 12-hour format
with AM/PM designation. The SDT believes this can easily be misunderstood
creating increased potential for a miscommunication The SDT knows of no entity
that uses an ‘am – pm’ term for critical communications.
R1.4 - This requirement is overly redundant as it is also covered by TOP-002 R18.
Response: The SDT believes neighboring entities should have a clear understanding
of each other’s BES Elements and BES Facilities to increase situational awareness
and to shorten response time. TOP-002 R18 will be eliminated by the RTOSDT.
Under R.1.8 and R.1.9, Dominion feels this would create an unnecessary burden to
document routine notifications that rely on a burst messaging system and do not
have any effect on the Bulk Power System. A one-way burst messaging system is
typically used to quickly inform/advise. It is designed as one-way to provide
efficiency and should not be used for Operating Instructions. It would be much
simpler to state that, “for the communications of Operating Instructions (regardless
of the technology employed)( apply above comments), the message must be
repeated or confirmed by the recipient, and validated by the sender.” This approach
focuses on “Operating Instructions” and not the technology employed. The
requirement as currently written does not allow for exceptions due to routine or
informative communications. (Example: NERC Alerts to the Industry based are based
on severity level and do not always require receipt of message by the Registered
Entity).
Response: The SDT does not want to document routine notifications. The
requirement requires develop communication protocols for “Operating
Instructions.”
It would be unwieldy for a large number of all call recipients to all respond to an all
call “Operating Instruction” which is why the SDT called for confirmation from at
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least one (if an entity wants more it can request it) recipient to ensure transmission
of the “Operating Instruction.”
R2 - Why not simply include DP and GOP in R1?
R4 - Why not simply include DP and GOP in R3?
Response: The SDT points out that R1 and R3 are applicable to entities that issue
and receive Operating Instructions, while R2 and R4 are applicable to entities that
only receive Operating Instructions. The SDT did not want to stipulate that entities
that do not issue Operating Instructions must have protocols that only apply to
issuance.
Dominion also recommends defining 3 Part Communication in the NERC glossary as a
result of this standard to help eliminate confusion. We need to have the System
Operator maintain a focus on reliability through precise communications without
unduly adding unnecessary requirements that create a burden without adding value.
The mandatory use of Time-Zones for parties communicating within the same TimeZone, or the use of Standard/Daylight Savings Time for current day activities adds an
administrative burden with no value to reliability.
Response: The SDT defined three part communication in draft 1 of the standard.
Industry comment was universally against the definition.
The addition of accurate time information is not administrative. The time element
of an Operating Instruction is critical and should be clearly conveyed and
understood so it does not result in a compromised system due to an unexpected
operation at the wrong time.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Hydro One
No
ï€ We request clarification on the rationale for limiting communication protocol
requirements for DPs and GOPs. We believe that the communication protocol should
contain essentially the same elements regardless of the function an entity performs.
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Consequently, we recommend combining R1 and R2 to state: “Each responsible
entity (BA, RC, TOP, DP, and GOP) shall have documented communication protocols
for the communication of Operating Instructions. This protocol should contain
following elements: ...”
Response: R1 and R3 are applicable to entities that issue and receive Operating
Instructions, while R2 and R4 are applicable to entities that only receive Operating
Instructions. Combining the requirements would cause the DP and GOPs to develop
protocols they would never use.
ï€ In order to improve readability we recommend that the Sub-Requirements R1.1
through R1.9 be re-arranged and grouped. For example, R1.7 and R1.9 deal with
information receiving. They should be combined into one with two sub-requirements
or bullets. The same can be done with R1.3, R1.6 and 1.8 which deal with issuing
Operating Instructions.
Response: The SDT respectfully prefers the order it created in draft 3 keeping three
part communication and all call together.
ï€ Requirement 1.6: We suggest that for clarity purposes the SDT rewords the first
bullet as follows: “Confirm that the recipient’s response of the Operating Instruction
as per R1.7 was accurate, or”
Response: The SDT adopted the language for 1.6 and 1.7 from COM-002-3 due to
comments from industry on draft 2 of the standard that expressed confusion over
different language for three part communication requirements.
ï€ Requirement 1.9: The requirement asks the recipient to request clarification when
the communication is not understood. We believe that the requirement is not
measurable and as such it should be deleted. Additionally, it represents common
sense because in any type of communication if one party does not understand all or
part of the conversation, it is natural that he/she will ask for clarification.
Response: The SDT believes it is measureable and agrees that it is common sense to
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ask for clarification.
ï€ Requirement 2.2: Hydro One recommends deleting this section for the same
reasons mentioned in our comment for Requirement 1.9 (measurability).
Response: Please refer to our response to 1.9
ï€ It must be made clear in the requirements that functional entities can incorporate
exceptions in their protocols, for example, to address emergencies. As proposed,
both of these requirements are too prescriptive. The sub-requirements drill down
too deeply into the communications needed to conduct system operations.
Response: The SDT believes the language of the requirement allows the entity to
address exceptions.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Associated Electric
Cooperative Inc - JRO00088
No
AECI believes the sub-parts of this requirement to be overly prescriptive, whereas
communication clarity should be the stated requirement. The sub-parts should
appear only as examples of elements to be considered for improving clarity. Less is
better, as evidenced by additional qualifiers already necessary to sub-requirement
R1.1. (see suggested language in comment 5 below.)
Response: The OPCPSDT thanks you for your comments. The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain a basis for standardizing the type of protocol
the entity should develop.
ISO/RTO Standards Review
Committee
No
The SRC fully supports the concept that certain aspects of our business are better
viewed based on the internal controls used by the entity. The SRC recognizes that the
intention of the SDT is to be flexible. However, the nature of a standard is to
eliminate that flexibility by not addressing how compliance will be monitored in the
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controls approach and by prescribing specific items for inclusion in the protocols.
Response: The SDT simultaneously considered and changed the RSAW for COM003-1 as it developed draft 3 and believes the two documents do address how
compliance will be monitored. The SAR and 2003 Blackout Report specified
consistent and uniform communication protocols. The parts to the requirement
serve as a frame to sustain a basis for standardizing the type of protocol the entity
should develop.
An entity is less likely to create a highly sophisticated best practice protocol if the
RSAW subjects that entity to penalties for implementing that protocol. While
presenters at the COM-003 Webinar presentation stated that violations are not
based on implementing the steps of the protocols, the draft RSAW (dated July 2012)
states: If the CEA finds in subsequent, follow up audits or other compliance
monitoring activities that the same or similar deficiencies continue to occur after the
entity was provided the feedback by the CEA, the CEA will seek to understand what
changes the entity made to their process based on prior recommendations. If
changes to the entity’s process are not implemented to identify, assess and correct
deficiencies, the Auditors may make a determination of possible non †compliance
with Requirement 3, Part 3.4.
Response: The Webinar also addressed the RSAW language you reference. An
entity that does not improve a deficient process, (R3.4 or R4.4) after a considerable
amount of opportunity in a non PV environment, and chooses to ignore
modification which would be required to improve that process; or does not provide
justification to why the entity decided not to modify the process may and should be
subject to a finding of non compliance.
(The proposed requirements R1 and R2) are a significant improvement from the
previous postings. Requirement R1 is still too prescriptive. The elements within R1
make the requirement a checklist of rules and do not add to the reliability of the
power system and do not address the reliability needs requested in Recommendation
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26 and Order 693. The reliability need for clear protocols was in reference to
“situational awareness” issues (i.e. when is the system in jeopardy and who makes
that decision to respond - See references provided below). The reliability need was
not related to common verbal mistakes. The proposed requirements do not address
those needs. The SRC believes that IRO-016-1 does address those issues and needs.
Response: The SDT has read IRO-016-1 (To ensure that each Reliability
Coordinator’s operations are coordinated such that they will not have an Adverse
Reliability Impact on other Reliability Coordinator Areas and to preserve the
reliability benefits of interconnected operations) and view it as a requirement for
RCs to work together to preserve system stability. COM-003-1 is being developed
to tighten communications. The SDT does not discern the linkage.
2003 Blackout Report Section:
Data Exchanged for Operational Reliability (pages 50-51)
Voice Communications: Voice communication between control area operators and
reliability is an essential part of exchanging operational data. When telemetry or
electronic communications fail; some essential data values have to be manually
entered into SCADA systems, state estimators, energy scheduling and accounting
software, and contingency analysis systems. Direct voice contact between operators
enables them to replace key data with readings from other systems’ telemetry, or
surmise what an appropriate value for manual replacement should be. Also when
operators see spurious readings or suspicious flows, direct discussions with
neighboring control centers can help avert problems like those experienced on August
14, 2003.
SRC COMMENT - This is clearly focused on establishing communications where they
potentially may not occur. It is not focused on prescribing particular terminology or
protocols based on the belief that existing practices are inadequate.
Response: The SDT interprets this as data entry under contingency operations and
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does not discern linkage to Communication protocols.
Page 109 Effectiveness of Communications Under NORMAL conditions, parties with
reliability responsibility NEED TO COMMUNICATE important and prioritized
information to each other in a timely way, to help preserve the integrity of the grid.
This is especially important in emergencies. During emergencies, operators should be
relieved of duties unrelated to preserving the grid. A common factor in several of the
events described above was that information about outages occurring in one system
was not provided to neighboring systems.
SRC COMMENT - The above discussion is not related to terminology or repeating
information. The concern focuses on the failure to provide appropriate information,
which, as discussed above, as well as in Order 693, is focused on “important” and
“prioritized” information. This is a limited set of communications that the proposed
standard’s new term Operating Instruction exceeds in scope.
Response: The SDT agrees with the remarks from page 109, but fails to discern the
linkage to Operating Personnel Communications Protocols. The SDT believes the
important and prioritized information in an Operating Instruction is critical and
must be addressed.
Pages 161-16226. Tighten communications protocols, especially for communications
during alerts and emergencies. Upgrade communication system hardware where
appropriate. NERC should work with reliability coordinators and control area
operators to improve the EFFECTIVENESS of internal and external communications
during alerts, emergencies, or other critical situations, and ENSURE that all key
PARTIES, including state and local officials, RECEIVE timely and accurate information.
NERC should task the regional councils to work together to develop communications
protocols by December 31, 2004, and to assess and report on the adequacy of
emergency communications systems within their regions against the protocols by that
date.
On August 14, 2003, reliability coordinator and control area communications
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REGARDING CONDITIONS in northeastern Ohio were in some cases ineffective,
unprofessional, and confusing. INEFFECTIVE COMMUNICATIONS contributed to a
LACK OF SITUATIONAL AWARENESS and PRECLUDED EFFECTIVE ACTIONS to prevent
the cascade. Consistent application of effective communications protocols,
particularly during alerts and emergencies, is essential to reliability. Standing hotline
networks, or a functional equivalent, should be established for use in alerts and
emergencies (as opposed to one-on-one phone calls) to ensure that all key parties are
able to give and receive timely and accurate information.[
SRC COMMENT: Recommendation 26 is clearly about communicating information
about “conditions” and not about communicating the commands to a particular
“asset”. The proposed standard is unresponsive to the issues raised in the Blackout
and by FERC. By not addressing the core reliability issues raised by the very report
that drove this Project, the SDT is jeopardizing the reliability of the power system.
The SRC strongly urges the SDT to reconsider this posting and to either rescind the
Project and accept that IRO-016-1 has adequately responded to the Blackout Report,
or to revise its proposal to directly address the issues noted above. If R1 is not
rescinded as suggested above, then the prescriptive subparts 1.1 thru and including
1.6 should be removed.
Response: The SDT believes Recommendation 26 is about tightening
communications by consistent application of effective communication protocols.
This is further amplified by FERC order 693 and is memorialized in the SAR. The
project was initiated with the approval of the Standards Committee.
The SDT, respectfully, will not reconsider this posting and will not rescind the
Project and will not accept that IRO-016-1 has adequately responded to the
Blackout Report. The SDT does not have the authority or the inclination to do
either. The SDT requests that you consider our positions and assist us in making this
an effective and fair standard.
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Response: The OPCPSDT thanks you for your comments. Please see our responses above.
FirstEnergy
No
We support many of the protocols as a minimum to standardize communications
across the industry. However, we believe some of the sub-parts of R1 contain
language which may be too prescriptive and in some cases language is missing for
special situations.
 1.2 - We understand the importance of knowing the time of day but an operator
can specify “am” or “pm” instead of using the 24 clock format. The requirement
should be less prescriptive to allow this.
 1.3 - This requirement as written may confuse the parties communicating. We
suggest it be reworded in a simple fashion as follows: “Assure both parties
understand the correct time being used in the communication.”
 When the receiver of an operating instruction is unable to comply they should be
allowed to notify the operator of the restriction (e.g. based on safety, loss of life, or
damage to equipment) so that the operator is able to implement other actions to
perform the desired operation. This should be added in the language requiring threepart communication in requirements R1 and R2.
Response: The OPCPSDT thanks you for your comments. The only concern the SDT has with what you suggest is the use of a 12hour format with AM/PM designation. The SDT believes this can easily be misunderstood, creating increased potential for a
miscommunication The SDT knows of no entity that uses an ‘am – pm’ term for critical communications. The SDT, based on the
revised format of draft 3 of the standard, believes an entity would have the flexibility to incorporate your suggestions for
emergency situations into the entity’s documented communication protocols (R1 and R2).
PPL Corporation NERC
Registered Affiliates
No
The PPL Companies do not agree with the proposed requirements as they are
administrative in nature.
Response: The SDT notes having documented communication protocols (R1 and R2)
may appear to be administrative in nature, but they represent a preliminary
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element for the process to identify, assess and correct deficiencies for adherence to
documented communication protocols.
Should the requirements remain, we suggest the following be considered:
R.1. Each Responsible Entity shall implement, in a manner that identifies, assesses
and corrects deficiencies, one or more documented communication protocols that
address each of the following Requirements.
R1.1 through R1.3 applicable to such Responsible Entity:
R1.1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed pursuant to an Operating Instruction, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the
communication as an Operating Instruction to the recipient.
R1.2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Instruction shall repeat,
restate, rephrase or recapitulate the Operating Instruction.
R1.3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority
that issues an Operating Instruction shall either:
o Confirm that the response from the recipient of the Operating Instruction (in
accordance with Requirement R1.2) was accurate, or
o Reissue the Operating Instruction to resolve any misunderstandings.
For purposes of clarity, the term “implement” in Requirement R1 does not mean that
there were no failures to follow the protocol in specific cases.
The following language is suggested for the measures related the proposed R1.1
through R1.3:
Measures: The Responsible Entity shall have documented communications protocols
developed for Requirements R1.1 through R1.3.Additional examples of evidence may
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include, but are not limited to, the Responsible Entity:
o trained or otherwise educated the affected personnel about the protocols
o established controls to identify failures to follow the protocols
o assessed identified failures to follow the protocols
o took appropriate actions to correct the identified failures
Response: The SDT has considered your recommendations but believes the draft 3
language more comprehensively covers communication protocols.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
SPP Standards Review Group
No
The wording in R2.1 is awkward, we suggest the following:
When receiving an oral two party, person-to-person Operating Instruction, the
recipient is required to repeat, restate, rephrase, or recapitulate the Operating
Instruction.
Response: The wording is the same language as the requirements in COM-002-3.
The OPCPSDT incorporated this language into the standard based on industry
comment on draft 2 stating that the different language for the two standards
caused confusion.
The one-way burst messaging in R1.9 and R2.2 is confusing to us in that we don’t
understand how you request clarification over a one-way messaging system.
Response: It the obligation of the recipient to contact the issuer if the recipient
does not understand the Operating Instruction.
As written there is no ‘out’ for an entity that cannot perform the Operating
Instruction as given. An entity has the option of not performing a Reliability Directive
if that directive violates regulatory, safety, equipment, or statutory requirements
(TOP-001, R3). A similar exemption needs to be incorporated into COM-003.
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Yes or No
Question 2 Comment
Response: COM-003-1 covers communication protocols not the action required.
TOP-001-1, R3 and IRO-001 R1 govern the obligation to act.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Bonneville Power
Adminstration
No
In R1.5, BPA disagrees with the mandatory use of alpha numeric communication
protocols for internal communications. BPA believes that these communication
protocols should apply only to external communications between system operators
for the TOP, GOP, and BA.
BPA suggests that the drafting team update R1.5 to specify that “Transmission
Operators and Balancing Authorities may adopt methods other than alpha-numeric
clarifiers to ensure accurate communication of Operating Instructions for internal
operations.”
Response: The SDT agrees that these communication protocols apply only to
external communications between system operators for the TOP, GOP, and BA. It
would only make sense to have them apply internally but that is the entity’s option.
Most entities use all or some of these communication protocols already.
The SAR and 2003 Blackout Report specified consistent and uniform communication
protocols. The parts to the requirement serve as a frame to sustain a basis for
standardizing the type of protocol the entity should develop.
BPA suggests that R1.1 should be modified to make clear that the use of English
should be mandated for communications between entities in separate regions where
the common language in one of the regions may not be English. In response to Draft
2, Essential Power LLC commented that “The use of English should be mandated for
communications between entities in separate regions where the common language
in one of the regions may not be English. Allowing an entity to use a language other
than English when communicating with regions where English is the required
language is counter to the purpose of the Standard and could in fact jeopardize
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Question 2 Comment
reliability through miscommunication.” The SDT stated that it “agreed with (Essential
Power, LLC’s) comments (shown below) and clarifies that is the intent of the
requirement”, but this intent is not clear in the requirement as written because it
does not specify that the language mandate needs to apply to both entities.
Additionally, there is no expressed limitation that the language(s) acceptable in these
circumstances be limited to only the language(s) specified by such law or regulation.
To resolve these issues, we propose that COM-003-1 R1.1 be modified to read as
follows:
Use of the English language when issuing an oral or written Operating Instruction
between functional entities, unless another language is mandated by law or
regulation FOR BOTH ENTITIES; IN WHICH CASE, ACCCEPTIBLE USE IS EXPANDED TO
INCLUDE THOSE SPECIFIED LANGUAGES. Transmission Operators and Balancing
Authorities may use an alternate language for internal operations.
Response: The SDT appreciate your proposed recommendation but believes the
language in draft 3 is clear and unambiguous. The English language is required with
appropriate exceptions.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
PacifiCorp
No
PacifiCorp does not feel that the requirements listed in R1.5 regarding the use of
alpha-numeric clarifiers when issuing an oral Operating Instruction is warranted. The
requirements listed in R1.6, and R1.7 requiring the strict used of three-way
communication should alleviate any possibility of miscommunication, which
PacifiCorp understands to be the drafting team’s intent in the development of
separate Requirement R1.5. Also, implementing the use of alpha-numeric clarifiers
poses additional risk due to the introduction of ambiguous language.
Response: The OPCPSDT thanks you for your comments. The SDT believes alpha-numeric clarifiers are important tools for entities
conveying information that contains alpha-numeric identifiers. The SDT also believes they reduce ambiguity.
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Southern Company
Yes or No
Question 2 Comment
No
Southern supports having a documented communications protocol, but we do not
support the prescriptive elements of this version of the standard. The protocols
should give the entity the flexibility to define the conditions where they expect 3-part
communications and the verbal cues they use to tell the recipient they expect 3-part
communication or that action is required. Southern suggest the following changes to
R1 and R2 and could support these changes in future drafts of this new standard.
Response: The OPCPSDT thanks you for your comments. The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain a basis for standardizing the type of protocol
the entity should develop. Beyond the frame specified in the parts an entity has the flexibility to develop the protocols to fit their
particular situation.
Liberty Electric Power, LLC
No
The SDT shift from a zero-tolerance standard to a procedure required standard is
admirable. Thank you for the open-mindedness and willingness to change direction
after much hard work went into the original proposal. However, the requirements for
specific content in the required procedure still goes beyond the proper role of the
standard. Suggested revision - eliminate R1 and R2, replace with new R1:"Each
(covered entity) shall have documented procedure(s) for communications with other
users of the Bulk Power System. Such procedure(s) shall have provisions which, in the
judgment of the registered entity, reduce the opportunity for
miscommunications."This lowers the chances of miscommunications without
dictating the content of business practices.
Response: The OPCPSDT thanks you for your comments. The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain a basis for standardizing the type of protocol
the entity should develop.
NERC - Investigations Group
No
Requirement R1.6 provides inadequate protection against a misunderstanding when
directives are issued. Granted, the Requirement does obligate the party receiving the
directive to repeat back the directive. However, if the recipient repeats the directive
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back to the person issuing the directive, and the "repeat back" indicates the recipient
has misunderstood the directive, this Requirement merely obligates the person
issuing the directive to state the directive again. The Requiremnt places no obligation
on the person issuing the directive, who knows he has been misunderstood, to
explicitly and clealy bring to the attention of the recipient that the recipient has
misunderstood. All the party issuing the directive has to do is repeat what he has
already said. The party issuing the directive is under no obligation to make it clear
that there has been a misunderstanding. With respect, I suggest having the person
issuing the directive merely repeat it if he's been misunderstood, with no explicit
statement that there has been a mistake, leaves open the potential for the recipient
to be unaware he has misunderstood and to execute a misunderstood directive. As
an example, consider the following exchange. Transmission Operator to Field
Operator: "Jim, open Breaker 104-696". Field Operator repeats back "I understand
open Breaker 104-699". Transmission Operator, noting the error, states "Open
Breaker 104-696". The field operator, having not been explictly made aware there
has been an error, opens Breaker 104-699. (Presumably, he would not do so had the
Transmission Opeartor made him aware of the misunderstaing with an exlicit
statement that there has been an error.)Suggestion: Add verbiage to R1.6 obligating
the person issuing the directive to make an explicit statement to the recipient that
there has been an error if the recipient repeats the order back incorrectly. Presently,
the standard imposes no such obligation on the person issuing the directive. One
possibe way to re-word the standard might be: " ...shall ensure the recipient of the
directive repeats the information back correctly; and, if the repeat back is correct,
shall acknowledge the response as correct. If the repeat back is incorrect, the person
issuing the directive will state "You are wrong and have misunderstood the directive".
The person issuing the directive will then repeat the directive correctly. This process
will continue until the recipient repeats the directive back correctly.
Response: The OPCPSDT thanks you for your comments. The SDT has used the same three part communication requirement
language as contained in COM-002-3 because of industry comments on draft 2 citing confusion between the two standards caused
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by different language for the same requirement. The SDT refers you to R1.1.7- it requires the repetitive process until the correct
information is communicated. The entity could account for this in their documented communication protocols (R1 and R2).
Hydro Quebec
TransÉnergie
No
It must be made clear in the requirements that functional entities can incorporate
exceptions (to address emergencies for example) in the protocols that are developed.
Both of these requirements are too prescriptive. The sub-requirements drill down
too deeply into the communications needed to conduct system operations.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language of the requirement R1 and R2 permits the
entity to assess whether variations from the required protocol are valid.
TransAlta Centralia
Generation LLC
No
Clarification is needed regarding what GOP procedures are to cover, ref. our
comments to question #1 above.
Response: The OPCPSDT thanks you for your comments. The GOP is a receiver of Operating Instructions and is subject to R2 and
R4 which are focused on the requirements for entities who only receive Operating Instructions.
ReliabilityFirst
No
Requirements R1 and R2 require the responsible entities to have documented
communication protocols for Operating Instructions, but does not require the
responsible entity to implement the protocols. Absent implementation of the
protocols, there is no need for the protocols themselves if the responsible entity is
not required to follow them. ReliabilityFirst recommends the following wording as
an example for Requirement R1: “Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall have and implement a documented communication
protocols for Operating Instructions...”
Response: The OPCPSDT thanks you for your comments. The SDT has changed the standard. The SDT believes the language
changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
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that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Independent Electricity
System Operator
No
We disagree with the need to repeat and confirm operating instructions (Part 1.6 to
1.9 and R2) meant to be used for normal operating system conditions. As indicated in
our previous comment, the term Reliability Directives and the recently approved
COM-002-3 cover instructions not only emergency conditions but also conditions that
can result in Adverse Reliability Impact. Requiring operating entities to exercise 3part communications (repeating and confirming) for routine operating instructions
that maintain the states or do not change the status of the BES Facilities, or simple
actions such as removing a transmission line which has no impact on the BES, or
simple switching, or adjusting a small amount of generation output, is totally
unnecessary, and can in fact overburden System Operators and harm reliability. And
we respectfully disagree with the SDT’s response to our previous comment regarding
the applicability of the term “Reliability Directive” in which the SDT claims that the
term “Reliability Directive” in the approved version of COM-002-3, “...in the context
of COM-002-3, is specifically for Emergency operating conditions” and “...covers a
very narrow band of low frequency, high impact events. The definition covers not
only emergency, but also Adverse Reliability Impacts” Further, the definition does not
explicitly indicate, nor is it implied, that such conditions are “of low frequency, high
impact events.”To address the BoT’s concerns expressed when approving the
interpretation of COM-002-2, the term Reliability Directive now defined in COM-0023 together with the NERC Operating Committee’s guideline on System Operator
Verbal Communication fully cover the condition under which 3-part communication
need to be (to address Adverse Reliability Impacts) or should be (where deemed
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appropriate) exercised. We do not see the need for having a standard requirement
for 3-part communication for conditions other than when Reliability Directives are
issued. Regarding the other parts in Requirement R1, i.e. 1.1 to 1.5, these are good
operating practices but are not absolutely necessary the “must follow” protocols that
rise up to a continent-wide reliability standard level.
Response: The OPCPSDT thanks you for your comments. The SDT respectfully disagrees that COM-003-1, based on your
comments, is not needed. The interpretation of COM-002-2a, 2R combined with COM-002-3 as a replacement leave a gap that was
covered by COM-002-2a, R2 before the Interpretation. COM-003-1 will cover the gap. Three part communication is an effective
protocol that reduces miscommunication. Removing the wrong transmission line at the wrong time because of a
miscommunication reduces reliability under any operating condition.
Lincoln Electric System
No
LES requests the drafting team provide additional clarification regarding R2.1 as it
relates to “oral two party, person-to-person” communication occurring between the
System Operators and field crews. Does the drafting team intend for the
communication protocols to be used for all communications between the System
Operators and field crews (such as for normal day-to-day switching of distribution
elements) or only as it occurs between defined functional entities? Within the Draft
2 consideration of comments under “Outstanding Unresolved Issues”, the drafting
team states that “The SDT clarified that COM-003-1 only applies to communication
between functional entities. For example, if a TOP System Operator is issuing an
Operating Instruction to an individual that is internal to that TOP, three part
communication is not required by this standard”. Although LES supports this
clarification, it’s incorporation into the requirement is not obvious. Recommend the
drafting team modify R2.1 as follows to ensure this clarification remains evident
within the standard going forward:
R2.1. When receiving an oral two party, person-to-person Operating Instruction
between functional entities, the recipient is required to repeat, restate, rephrase, or
recapitulate the Operating Instruction.
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Yes or No
Question 2 Comment
Response: The OPCPSDT thanks you for your comments. The SDT has added language to R1 and R2 clarify that they are applicable
to Operating Instructions between Functional Entities.
NextEra Energy Inc.
No
NextEra opposes any communication protocol in COM-003-1 that is not mirrored in
COM-002-3. NextEra views the implementation of two different communication
protocols -- one for Reliability Directives and one for Operating Instructions as
problematic and not consistent with the promotion of a reliable Bulk Electric System.
This concern is heightened by the fact that there are more specific protocols for
Operating Instructions which are lower in the communication hierarchy when
compared to Reliability Directives. Such a model is counterintuitive. If implemented,
this model will also likely be counterproductive, increase confusion among System
Operators and may unnecessarily cause a risk to the Bulk Electric System. The
inherent risk caused by the lack of synergy and consistency between COM-003-1 and
COM-002-3 could be resolved by combing the Standard Development projects and
having the SDTs work together to produce one uniform work product. Therefore,
NextEra urges the COM-003-1 SDT to request that the Standards Committee join the
COM-002-3 and COM-003-1 efforts, so that one uniform three-way communication
protocol can be developed and implemented that promotes reliability.
Response: The SDT does not disagree, but that is outside the scope of the SAR for
this project The OPCPSDT has adopted the exact language for three part
communication for COM-003-1 as COM-002-3 to reduce confusion. The
documented communication protocols apply to Reliability Directives that change or
preserve the state, status, output, or input of an Element of the Bulk Electric
System or Facility of the Bulk Electric System.
Further, in addition to comments that NextEra has previously submitted, it asks that
the following changes be made:
R1.1 Delete “between functional entity” as unnecessary and delete the second
sentence altogether (or clarify it), because it is unclear and may add confusion. In the
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context of an Operating Instruction, it is best that English be used between
Transmission Operators and Balancing Authorities for external and internal
communications related to Operating Instruction. To allow for alternative languages
to be used internally when an Operating Instruction is given will likely result in
difficult transitions between internal and external conversations which may
unintentionally result in a risk to the Bulk Electric System via an external
miscommunication using a language other than English. Thus, NextEra prefers that
English be promoted and used for internal and external communications related to
Operating Instructions.
Response: The SDT believes if an entity is externally communicating to you in a
language other than English that entity would be deficient. The receiving entity
should request the issuer use the English language, based on requirement R2. The
SDT added “between functional entities” to the body of both requirements.
R1.4 Add a comma after “Facility” in the fourth line. The
R1.8 Use the term “entities” instead of “parties” in the second line. Entities is a more
widely recognized term than parties in the context of the Reliability Standards. Also,
for clarity, re-write the end of 1.8 to read “. . . confirm receipt from each entity.” The
current wording states “confirmed receipt from one or more receiving parties” seems
to miss the point that what the sender needs is confirmation from each entity that
was sent the message.R1.9 Similarly, replace the term “parties” in line two with
“entities”.
Response: The SDT added the comma and will retain the term “parties” as some
addressees may not be functional entities.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Northeast Utilities
No
R1.2 Prescribed use of a 24 hour clock format seems over-bearing
Response: The SDT believe it provides clarity to the time element.
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R1.3 The use of “functional entities”- includes more entities than the applicability
section and uses terms from the functional model which goes beyond registered
entities, may be some confusion here.
Response: The SDT has deleted the term “functional entities” from R1.3 and has
incorporated it in R1 and R2.
R1.4 Transmission interface Element Transmission interface Facility These terms may
need to be defined. They may be ambiguous to some entities as to what is intended
Response: The SDT believes these are commonly used terms in the electric utility
industry.
R1.5 Use of alpha-numeric clarifiers in some instances inhibit efficient
communication, without increasing the effectiveness of the communication or
reducing the risk to the BES. In keeping with the requirement of entities to document
its protocols, it should be left to the entities of regions to define this.
Response: The SDT believes alpha-numeric clarifiers are important tools for entities
conveying information that contains alpha-numeric identifiers. The SDT also
believes they reduce ambiguity.
R2 Is missing a sub-requirement that requires a clarification of two party
communications that is not understood.
Response: R2.2 contains the clarification language you have referenced.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
American Electric Power
No
AEP disagrees with the concept of requiring three part communications for more
routine operations, and as a result, also disagrees with requiring that entities have
documented communication protocols as proposed.
Response: The OPCPSDT thanks you for your comments. The SDT believes three part communication is a proven, effective tool
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that prevents mistakes caused by miscommunication.
Brazos Elextric Power
Cooperative, Inc.
No
See ACES comments. Additionally, if it is determined that all of the elements need to
be kept in the standard, the list of elements needs to be improved. Some of the
elements are noun phrases (e.g., 1.1 and 1.2) and some are instruction statements.
All elements should be noun phrases. It is grammatically improper for a list to have
more than one type of phrase and, more significantly, may lead to confusion about
compliance obligations. Instruction statements could be construed to require perfect
performance of those elements, but that does appear to be the intent of the SDT.
Response: The OPCPSDT thanks you for your comments. The SDT agrees and has changed the wording of the subparts.
Ameren
No
See response to question 5.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 5.
Essential Power, LLC
No
Clarification is needed regarding what GOP procedures are to cover, ref. our
comments to question #1 above.
Response: The OPCPSDT thanks you for your comments. Please see our response to your comments in question one.
Texas Reliability Entity
No
This Standard does not address electronic Operating Instructions, thus creating a
possible gap. For example, ERCOT (acting as the BA) uses ICCP links to issue electronic
dispatch instructions to generators (ERCOT Protocol 6.5.7.4). The recipient of the
electronic dispatch instruction must acknowledge receipt of the dispatch instruction
to ERCOT electronically, within one minute and must include the receiving operator’s
identification with the electronic acknowledgement (ERCOT Protocol 6.5.7.8(5)).
ERCOT regional rules have similar language as current NERC standards regarding
compliance with dispatch instructions, which include electronic dispatch instructions
(ERCOT Protocol 6.5.7.9).Consider adding “Reliability Coordinator” or “Functional
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Entities” in 1.1 statement where TOPs and BAs are singled out: "Transmission
Operators and Balancing Authorities may use an alternate language for internal
operations.”
Response: The OPCPSDT thanks you for your comments. COM-003-1 deals with people to people not people to machine or
machine to machine communication.
Consumers Energy
No
We believe this is a standard that requires procedures or documents but has nothing
to do with performance. These types of standards lead to auditors making a wide
range of interpretations.
Response: The OPCPSDT thanks you for your comments. The SDT disagrees; it has to do with establishing a process to correct
deficiencies and to improve the effectiveness of an entity’s communications to improve reliability. It permits an entity to correct
deficiencies in an environment without a finding of non compliance for every deficiency.
Xcel Energy
No
See comments under question # 5.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 5.
Public Service Enterprise
Group
No
There should not be a requirement for entities in R1 and R2 to have documented
communications protocols. The subparts specify the protocol requirements. R1
should merely state: “Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall use the following communication protocols for
Operating Instructions:” R2 should be similar involving DP and GOP functions
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 accomplishes this.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
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developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Cowlitz County PUD
No
This requirement will be burdensome to small Distribution Providers where
communications from a System Operator will not ever occur. Requiring entities to
prepare for nonexistent reliability gaps is not acceptable. DPs should be allowed to
document via RC, TO, and BA letters of agreement that establishes System Operator
communication protocol is not required. These small DPs can only shed load in a
reliability emergency, and in some cases would need to do so manually. Further,
such load would be more effectively dropped by the TOP functioning as the DP’s
Transmission Service Provider.
Response: The OPCPSDT thanks you for your comments. If a DP has never or will never receive an Operating Instruction it would
not be an applicable entity. If the DP has or could receive Operating Instruction it must comply with the standard. The DP would
have to confirm their situation with the CEA.
Exelon
No
Exelon agrees with all requiremnts except R1.1.3 and R1.1.4.We disagree that R1.1.3,
“include time zones” when issuing operating instructions is necessary. Operating
instructions are typically issued in real time; an instruction to do something “now” or
at the "top of the hour" does not require the use of time zones. 1.1.4 has the effect of
requiring verbatim use of a specified name; this should not be a requirement as long
as the transmitter and receiver use three way communications effectively to assure
understanding of the element to be operated. Additionally, TOP-002-R18 already
requires use of “uniform line identifiers when referring to transmission facilities of an
interconnected network”. The statement to use the TO specified name or a mutually
agreed to name is not necessary in light of TOP-002.
Response: The OPCPSDT thanks you for your comments. The SDT believes that if an entity uses a clock time a time zone reference
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must be included if entities are in different time zones. Times designated on a relative basis (execute in five minutes) would not
require a time zone.
TOP-002 R18 is being eliminated by another project. The SDT believes neighboring entities should have a clear understanding of
each other’s BES Elements and BES Facilities to increase situational awareness and to shorten response time.
Indiana Municipal Power
Agency
No
IMPA believes it should be made clear that Operating Instructions and the use of
documented communication protocols are required by these two requirements for
when Operating Instructions are given by a Balancing Authority, Reliability
Coordinator, or Transmission Operator to a Distribution Provider or Generator
Operator. The current requirements could apply to a generator station (Generator
Operator) who receives Operating Instructions from its Market Operations (also the
same Generator Operator entity). The Market Operations would not need to follow
the communication protocol since it is issuing the Operating Instructions, but the
generator station would have to follow the communication protocol since it is
receiving the Operating Instruction. IMPA does not believe that the SDT intended to
include communications between a Generator Operator’s Market Operations and its
remote power plant.
Response: The OPCPSDT thanks you for your comments. The GOP is subject to the standard and must comply with applicable
requirements. The SDT believes that is specified in the standard. Market Operations that are not acting as a GOP are not an
applicable entity so communications with its Market Operations is not subject to standard.
MISO
No
MISO does not agree with the proposed requirements of COM-003-1, R1 and R2.
Although MISO agrees that clear communications are important to system reliability,
it respectfully submits that any requirement for System Operators to have a
communication protocol should allow the subject System Operators to define when
and how the protocol would apply. In addition, MISO respectfully submits that
System Operators should retain greater flexibility in deciding which elements to
include in their respective protocols. For instance, the protocols should allow the
System Operator to outline how and when to use blast calls and messaging systems.
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Thus, despite its conceptual support for a communication protocol for System
Operators, MISO is concerned that the requirements currently set forth in COM-0031 are, in many cases, overly-prescriptive, and, rather than enhancing system
reliability, could actually undermine it. As explained above, because the definition of
the term “Operating Instruction” is overly broad and ambiguous, System Operators
may treat most, if not all, communications as Operating Instructions. Applying the
required elements of the communication protocols for Operating Instructions to
most communications would be inefficient and could adversely affect the ability of
System Operators to perform their reliability functions. Indeed, while MISO agrees
that clear communications in system operations are important, an excessive reliance
on the three-way communications protocols detailed in the proposed standard can
be an unnecessary distraction for personnel operating the Bulk Electric System,
hampering as opposed to enhancing overall system reliability.
Response: The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain
a basis for standardizing the type of protocol the entity should develop.
The SDT believes an entity has great flexibility with creating the documented
communication protocols in R1 and R2 to address its own particular situation. The
SDT believes use of the protocols will become natural for System Operators and will
result in consistent, universal communication protocols that will promote reliability
on the BES. The new language in draft 4 addresses your concerns.
MISO’s primary point of disagreement with the current Standard is therefore one of
scope. MISO recommends that the SDT replace “Operating Instruction” with the
existing proposed definition for the term “Reliability Directive” in Project 2006-06,
Reliability Coordination. Limiting the scope of applicability for utilization of the
communication protocol required by COM-003-1, R1 and R2 would prevent System
Operators from applying the communication protocol to virtually all communications
out of an abundance of caution and, unlike the current draft of COM-003-1, would
not be an undue distraction from the reliability functions performed by these
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
operators.
Response: The SDT’s intention is for entities to develop these protocols for all
communications that command changes on the BES. The command to change BES
configuration carries some risk no matter what operating state exists. The SDT
believes such protocols will become routine for operators as they are for pilots, the
military and air traffic controllers.
Further, as explained in its comments on Draft 2 of COM-003, MISO does not support
including certain of the proposed required elements in the communication protocol
for Operating Instructions and does not believe these issues have been sufficiently
addressed by Draft 3. First, MISO does not agree with the proposed requirement to
indicate time zone and Standard or Daylight Saving Time when issuing an oral or
written Operating Instruction between functional entities in different time zones.
This requirement would result in the expenditure of significant time, resources and
attention by System Operators for a minimal benefit to reliability. Accordingly, this
modification appears to place upon operators an unjustified, onerous requirement.
MISO respectfully requests that the SDT reconsider this requirement.
Response: The SDT believes the time element of an Operating Instruction is a
critical component. Switching at the wrong time could create a disastrous event.
The SDT believes such protocols will become routine for operators as they are for
pilots, the military and air traffic controllers.
Second, MISO continues to believe that the requirement to use alpha-numeric
clarifiers when issuing Operating Instructions to or Facilities and Elements in
instances where the nomenclature of Facilities or Elements is in alpha-numeric
format is ambiguous and could lead to unintended compliance burdens. MISO
respectfully submits that if alpha-numeric clarifiers are to be required, NERC should
adopt a uniform set of clarifiers to ensure that all System Operators communicate
efficiently and effectively. However, MISO reiterates its belief that mandating the
use of alpha-numeric clarifiers will have, at most, a minimally beneficial impact on
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
reliability while requiring Registered Entities to expend substantial additional
resources.
Response: The SDT believes the use of clarifiers is important because of human
voice differentiation such as acuity, accents, volumes, pitch and others. Also
communication equipment often has degraded performance that creates
misunderstandings. The SDT originally proposed the NATO radiotelephony phonetic
alphabet which was widely disapproved as too prescriptive by draft 1 commenters.
Finally, MISO disagrees with the proposed requirement that Operating Instructions
reference the name specified by the owner for a Transmission interface Element or
Transmission interface Facility. To date, System Operators have identified equipment
by to/from station and voltage level. Such identification has been sufficient to ensure
the accurate identification of Transmission interface Elements and Facilities.
Additionally, MISO notes that internal identifiers utilized by owners may result from
internal coding or naming conventions that would not be known by or
comprehensible to external entities. Hence, MISO cannot support this requirement,
based on the potential adverse impacts to reliability that could result.
Response: A provision for a separate mutual agreement is contained in R1.1.4.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ERCOT
No
The overarching premise of NERC standards is that they typically establish the “what”
and not the “how” (Order 672 at P 260). The proposal to mandate specific
communication protocols contravenes that approach and undermines the value
inherent therein. Allowing entities to establish their own protocols to meet a desired
end result facilitates means that best suit particular entities and also allows for
improvements based on experience. Prescribing specific protocols would preclude
such benefits. The proposed requirements are better suited as non-binding
illustrative approaches / best practices. These could be presented as suggested
approaches, for example, in an attachment to a standard that establishes a general
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
requirement to have communication protocols in place, but they should not be
mandated. FERC did state that in some cases it may be appropriate to prescribe
specific implementation rules in the standards if the how is inextricably linked to the
standard and may need to be specified by the ERO to ensure the enforcement of the
Reliability Standard. The Commission went on to note that for some standards
leaving out implementation features could:
(1) sacrifice necessary uniformity in implementation of the Reliability Standard;
(2) create uncertainty for the entity that has to follow the Reliability Standard;
(3) make enforcement difficult; and
(4) increase the complexity of the Commission's oversight and review process.
None of these conditions apply to communication protocols. For this matter, a
general requirement relative to reliability directives is adequate with implementation
left to the functional entities. This is already addressed in COM-002 R2, and,
therefore, COM-003 is not needed. Communication protocols are more
appropriately addressed by an entity’s internal controls rather than a Reliability
Standard, because this approach provides the benefits described above (i.e. 1)
application of suitable protocols based on an entity’s structure and relationships and
other relevant rules and 2) flexibility for improvement of such protocols over time).
The proposed standard eliminates these benefits by prescribing specific items for
inclusion in the protocols. Again, the scope of the proposed standard is askew
relative to the reliability concern at issue. The proposed standard is unresponsive to
the issues raised in the Blackout and by FERC. By not addressing the core reliability
issues raised by the very report that drove this Project, the SDT is jeopardizing the
reliability of the power system.
Response: The SDT believes the 4 criteria ERCOT has listed above justify the
inclusion of the elements in R1 and R2. There must be a high degree of
communication uniformity and consistency among applicable entities for
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
communication to be effective. The standard’s draft 3 format permits great
flexibility in developing those protocols and to add more content to accommodate
their own particular circumstance, if entity chooses.
Response: The SAR and 2003 Blackout Report specified consistent and uniform
communication protocols. The parts to the requirement serve as a frame to sustain
a basis for standardizing the type of protocol the entity should develop.
Accordingly, the focus of the proposed standard is misplaced and, if approved, will
do nothing to address the reliability concerns identified in the blackout report and
Order 693, but rather will do nothing but impose ineffective and inappropriate
obligations that will create liability risk with no corresponding reliability benefit.
ERCOT strongly urges the SDT to reconsider this posting and to either rescind the
Project and accept that IRO-016 has adequately responded to the Blackout Report, or
to revise its proposal to directly address the issues noted above. If R1 is not
rescinded as suggested above then the prescriptive subparts 1.1 thru and including
1.6 should be removed, and R1 should be revised to include "applicable
communication protocols".
Response: The SDT believes it is addressing reliability concerns raised by the
Blackout Report, Recommendation 26 and is tightening communications by
consistent application of effective communication protocols. This is further
amplified by FERC order 693 and is memorialized in the SAR. The project was
initiated with the approval of the Standards Committee.
The SDT, respectfully, will not reconsider this posting and will not rescind the
Project and will not accept that IRO-016-1 has adequately responded to the
Blackout Report. The SDT does not have the authority or the inclination to do
either. The SDT requests that you consider the importance of the standard and
assist us in making this an effective and fair standard.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
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Organization
Oncor Electric Delivery
Company LLC
Yes or No
Question 2 Comment
No
According to the 2003 Black Out Report, “Ineffective communications contributed to
a lack of situational awareness and precluded effective actions to prevent the
cascade. Consistent application of effective communication protocols, particularly
during alerts and emergencies, is essential to reliability” Oncor is not aware of any
evidence to support the position that lack of communication protocols contributed to
the NE Black Out of 2003, the 2008 Florida Black Out or the more recent SW Black
Out. Oncor also takes the position that many of the ideas prescribed within the
standard are already being effectively implemented as industry Best Practice. Oncor
is concerned that implementing the specific elements as prescribed in the standard
will result in confusion, and could compromise personnel safety. Oncor offers the
following alternative language.
R1 “When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as an Operating Communication, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as
an Operating Communication to the recipient. “
Oncor also offer the following alternative language for R2”
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Communication shall
repeat, restate, rephrase or recapitulate the Operating Communication.”
Response: The OPCPSDT thanks you for your comments. The SDT believes the excerpt you cite from the 2003 Black Out Report
regarding “Ineffective communications” indicates there is a major concern over communications that requires a higher degree of
communication discipline.
The SDT believes the standard encourages the use of best practices and the entity has the flexibility to include them in its
documented communication protocols.
The SDT believes that communication protocols will eliminate confusion and mistakes.
Thank you for the suggested language, but the OPCPSDT has added clarifying language to the definition for draft 4 which is now:
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Yes or No
Question 2 Comment
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
City of Austin dba Austin
Energy
No
CenterPoint Energy Houston
Electric, LLC.
No
Pepco Holdings Inc
No
Central Lincoln
Yes
We appreciate the work the SDT has done to ensure the standard is not about having
zero communication defects, and is more about process.
Response: The OPCPSDT thanks you for your comments.
Occidental Energy Ventures
Corp.
Yes
Although in general, OEVC does not believe that process documents should be the
primary reliability consideration, it is the appropriate strategy in this case. Clearly, all
of us want to eliminate Operator miscommunications - which make up nearly 20% of
all BES mishaps - but it is impossible to assure 100% compliance over the course of
thousands of System Operator communications. Furthermore, the effort required to
capture the evidence needed by audit teams would overwhelm our resources, as well
as those of the Regional compliance organizations. In our view, the path chosen by
the drafting team is consistent with NERC’s Risk-based Compliance program. It drives
attention in areas that reliability data shows to be deficient, but recognizes that the
benefit of COM-003-1 must outweigh the costs and resources required to implement
it.
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Organization
Yes or No
Question 2 Comment
Response: The OPCPSDT thanks you for your comments.
Idaho Power Co.
Yes
It will require us to write a communications protocol.
Response: The OPCPSDT thanks you for your comments.
The United Illuminating
Company
Yes
R1.3 should allow the use of prevailing time in addition to Daylight Savings and
Standard time. Prevailing time eliminates the need to differentiate between daylight
savings or standard time in notices and reduces confusion since the clocks are
changed at a scheduled time by the US Government.
Response: The OPCPSDT thanks you for your comments.
Detroit Edison
Yes
Tacoma Public Utilities
Yes
MRO NSRF
Yes
APPA, LPPC and TAPS
Yes
Florida Municipal Power
Agency
Yes
Arizona Public Service
Company
Yes
Georgia System Operations
Yes
Southwestern Power
Yes
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Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
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Organization
Yes or No
Question 2 Comment
Administration
US Bureau of Reclamation
Yes
Manitoba Hydro
Yes
NIPSCO
Yes
South Carolina Electric and
Gas
Yes
Salt River Project
Yes
CPS Energy
Yes
Public Service Company of
New Mexico
Yes
Alliant Energy
Yes
The Empire District Electric
Company
Yes
City of Tallahassee
Yes
MidAmerican Energy
Yes
Puget Sound Energy Inc.
Yes
GTC
Yes
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3.
The SDT has proposed requirements (COM-003-1, R3 and R4) for appicable entities to implement a process to identify, assess
and correct deficiencies related to the entity’s documented communication protocols; and to evaluate that process based on
deficiencies found externally from the process. Do you agree with the proposed requirements? If not, please explain in the
comment area of the last question.
Summary Consideration:
Many commenters, even those who voted no on Question 3 supported the SDT’s decision to incorporate internal
controls. Some of their concerns were if regional CEAs are “onboard” with the SDT’s approach. The SDT has collaborated
with NERC compliance and jointly developed the RSAW for COM-003-1. NERC compliance and NERC executives have
been speaking to industry, Regional Entities and regulators to advocate for control based standards citing the absolute
need for this approach to address burdensome and unreasonable requirements and to promote a more efficient use of
resources.
A large number of commenters, for various reasons recommended that the SDT consider using a similar format and
language to emulate the CIP v.5 standards and to address concerns over their understanding of R3 and R4. The
commenters stated that it would be more consistent and less confusing. The SDT discussed the commenters’ concerns
and concluded that adopting the same general format for COM-003-1 would add value by improving consistency and
remaining effective as a standard to improve communication and reliability on the BES.
“R1 (and R2-DP and GOP). Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement, in a manner that identifies, assesses and corrects deficiencies, documented communication protocols for
Operating Instructions between Functional Entities that include the following:”
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an
entity’s implementation of the communication protocols in a manner that identifies, assesses and corrects
deficiencies. The COM-003-1 RSAW has been updated to reflect this change.
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Yes or No
Northeast Power Coordinating
Council
No
Question 3 Comment
It is unclear what identified reliability gap this Standard’s development project is
intending to fulfill given the recent adoption of the new COM-002-3 along with the
OC white paper on communications protocols.
Response: The OPCPSDT thanks you for your comments. The reliability gap is the coverage of communication protocols that cover
Operating Instructions during normal operating levels. COM-002-3 is only applicable to Adverse Reliability Impacts and
Emergencies. The OC White Paper cites studies that put communication mistakes as a significant contributor to BES mishaps.
ACES Power Marketing
Standards Collaborators
No
(1) We support the concept of internal controls that the SDT has proposed. We agree
that finding a violation for each instance is burdensome and unreasonable and
evaluating internal controls is a more efficient use of resources. However, we are
concerned about the evaluation of internal controls from Regional audit staff. How is
NERC planning to train the Regional auditors to ensure consistency during compliance
audits? There is too much room for auditor subjectivity, especially when evaluating
whether a single communication was deficient. There are so many communications
that could occur on a daily basis and there is not clear guidance when the Regions will
find or not find a possible violation in an audit.
Response: During the September 6, 2012 Webinar representatives of the EROs
Compliance group cited ERO’s hiring of career auditors, increased training and
reaching out to industry with the development of the RSAW and the standard
simultaneously.
(2) In the webinar, SDT chair stated that a registered entity that catches a high
percentage of deficiencies, then their process is working, but if the entity is only
catching 50% then the entity needs to correct the process. There is currently no
percentage or other guideline or metric to determine if an entity’s process is
sufficient. If this is the SDT’s intent, please provide further detail.
Response: The SDT did not address the degree of disparity. The auditor does have
some subjectivity. The SDT points out there is not generally a finding of non
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Organization
Yes or No
Question 3 Comment
compliance even when the number of deficiencies is deemed excessive by a CEA.
The entity then must evaluate its process for effectiveness and make modifications
or demonstrate why no modification is necessary.
(3) We recommend the SDT provide additional information in the Rationale and
Technical Justification document to include a guideline to show how the Regional
auditors would assess compliance with a control-based standard. It seems that the
trend in both COM-003-1 and CIP v5 is to find the errors and fix them without the
need to self-report. How are the Regions going to determine when a PV is to be
issued? The Technical Justification and the RSAW do not provide enough information
when a communication deficiency crosses the threshold of becoming a violation.
How does a registered entity know when to self-report?
Response: The SDT believes there is enough information in the standard and the
RSAW to demonstrate when a PV would be issued. A finding of non compliance will
generally occur when an entity fails to implement the modifications it developed
during the evaluation of its process or has not provided a compelling reasoning why
they determined modification was not required.
(4) We recommend adding more detail, perhaps including an application guidelines
section as other risk-based standards, for acceptable remediation of deficient
communications. For example, if an operator failed to use the 24-hour clock during
an Operating Instruction, would a simple reminder be sufficient or would the
operator need to attend a full-blown training session? What documentation would
be required? It seems that a reminder would remedy the deficiency, but then that
would have to be documented. The internal controls used to remedy deficiencies
could turn into another documentation exercise instead of focusing on effective
communication. We recommend the SDT consider ways of satisfying remediation
without creating an unnecessary administrative burden for maintaining compliance.
Response: The SDT leaves this up to the entity as it develops its process. If a simple
reminder to use the 24 hour clock proves effective in eliminating or reducing the
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Organization
Yes or No
Question 3 Comment
deficiency that is acceptable. It would have to be documented but generally most
contemporary performance and training programs have the necessary elements to
determine what internal remedies are required to train individuals to improve
individual performance.
(5) Please clarify R3, part 3.4, “deficiencies found external to Part 3.1.” Does the SDT
mean that there would be deficiencies found in an audit? Who is the external entity
finding these deficiencies? Does the SDT intend for registered entities to hire
external consultants? Is this the RC notifying the DP that it has not communicated
appropriately? Would these externally found deficiencies result in audit report
recommendations?
Response: Generally CEA would be the source of externally found deficiencies.
Neither the SDT nor the standard specify a requirement to hire outside auditors.
Many entities hire outside auditors to provide a third party review of its processes
and for compliance issues. Other entities have separate specialized internal audit
groups that survey a wide range of corporate and operational processes and
activities on behalf of the executive leadership or their board. These would all be
sources external to the entity’s internal processes. The standard requires the entity
to evaluate its process if external deficiencies are found outside the process. The
discovery of externally found deficiencies could possibly result in audit report
recommendations.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Detroit Edison
No
All actions that result in a potential violation must be reviewed and analysed to
identify and correct deficiencies. Communication issues are no different.
Requirements 3 and 4 are not required.
Response: The OPCPSDT thanks you for your comments. The SDT points out in COM-003-1 that the deficiencies that are identified,
assessed and corrected by the entity are not potential violations.
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Yes or No
Question 3 Comment
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
SERC OC Standards Review
Group
No
We would suggest changing R3 and R4 to align with our suggestions for R1 and R2:
“R3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement a process for identifying deficiencies with adherence to their
documented communication protocols that each entity developed in accordance with
Requirement R1 that:”
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
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Organization
Dominion
Yes or No
No
Question 3 Comment
No, Dominion does not agree that these requirements are needed. As part of any
certification to R1 and R2, we would expect the entity to perform some sort of
analysis to determine whether its communication protocols meet the intent of the
purpose stated for this standard. We do not believe imposing a mandatory
requirement to perform this analysis inherently increases reliability.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Hydro One
No
ï€ It is unclear what identified reliability gap this Standard development project is
intending to address, given the recent adoption of the new COM-002-3 along with
the OC white paper on communications protocols.
ï€ Hydro One believes that, as written, the requirements are too prescriptive. We
think that the SDT should concentrate and focus on specifying WHAT is required to
achieve the reliability objective of the standard rather than on HOW to go about
achieving such objective. With this in mind, we recommend deleting R3.1 through
R3.4 and R4.1 through R4.4.
Response: The reliability gap is the coverage of communication protocols that cover
Operating Instructions during normal operating levels. COM-002-3 is only applicable
to Adverse Reliability Impacts and Emergencies. The OC White Paper cites studies
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Organization
Yes or No
Question 3 Comment
that put communication mistakes as a significant contributor to BES mishaps.
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
Additionally, in line with our comment regarding R1 and R2 we believe that these two
requirements should be combined as well. We would like to propose following
wording: “Each responsible entity shall develop and implement a process for
identifying and addressing deficiencies found in the adherence to the documented
communication protocol specified in Requirements R1 and R2.”
Response: The SDT believes that the separated requirements are necessary because
it is the only manner in which to clearly define requirements R1 and R2 for issuerreceivers and for receivers only. It also reduces the opportunity for double jeopardy
if one entity cannot or is not able to comply with the requirement they are
responsible for executing.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
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Organization
ISO/RTO Standards Review
Committee
Yes or No
Question 3 Comment
No
The SRC fully supports the concept that functional entities’ internal controls be used
to monitor the effectiveness of their own protocols. The SRC suggests that any
requirement to implement a plan may significantly reduce the incentives to create
more effective protocols because of the Compliance uncertainty related to measuring
effective internal controls. Requirement 3 requires entities to implement their
process and to identify deficiencies with adherence to the protocol. The less complex
a plan is the lower the number of deficiencies and therefore the lower the number of
reports. Moreover, the RSAW states that the applicable entity could be found noncompliant if the entity did not follow an auditors suggested changes to remedy those
deficiencies. Thus this standard would incent writing simple protocols.
Response: The OPCPSDT thanks you for your comments. The entity has full discretion on how to develop the process required in
R3 and R4. The CEA will gauge effectiveness based on results of the process.
The finding of non compliance can only exist if the entity totally disregards improving its process. The SDT anticipates entities
collectively possess a high level of professionalism and will develop a robust process and strive to continually improve it.
PPL Corporation NERC
Registered Affiliates
No
The PPL Companies agree with the concept of internal controls and/or the
elimination of zero defect requirements. However, the concept of internal controls
to identify, assess, and correct deficiencies related to documented communications
protocols should be imbedded in R1 as proposed in our response to question
2. We do not agree with the specific details in the internal controls/elimination of
zero defect language that is currently included in R3.1 - R3.4 and R4.1 - R4.4.
Incorporating the new language proposed by the PPL Companies in R1 makes COM003 more consistent with the approach being followed in the NERC CIP Version 5
standards. The added language proposed by the SDT in R3 and R4 creates
uncertainty as to whether COM-003 is imposing greater requirements than CIP
Version 5 regarding identifying, assessing, and correcting deficiencies and the
documentary evidence that is required.
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Organization
Yes or No
Question 3 Comment
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
SPP Standards Review Group
No
Delete ‘potential’ in R3.1 and R4.1.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Bonneville Power
Adminstration
No
BPA supports the move to the identify, assess, and correct deficiencies approach that
eliminates the need for the entity to report each deficiency as a potential violation.
BPA believes that based on the current R1 and R2, it is not reasonable to expect
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Organization
Yes or No
Question 3 Comment
entities to review all communications in order to be compliant with R3 and R4. BPA
suggests that the drafting team update R3.1 and R4.1 to state that entities shall
implement a process that “identifies potential deficiencies through sampling”.
Response: The OPCPSDT thanks you for your comments. R1 and R2 do not stipulate that entities review all communications in
order to be compliant with R3 and R4. The SDT developed the standard with the intention of sampling and for the entity to
determine the sample size as a means of identifying potential deficiencies.
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
PacifiCorp
No
PacifiCorp supports the addition of non-zero defect language which follows the CIP
model. [model PacifiCorp suggests that the language in Requirement R3 be
modified and simplified as follows: “R3. Each Balancing Authority, Reliability
Coordinator, and Tranmission Operator shall implement R1 in a manner that
identifies potential deficiencies, assesses deficiencies found, and corrects those
deficiencies.”
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
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that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Liberty Electric Power, LLC
No
There is no statement of periodicity in R4, leaving entities guessing until the time of
audit regarding the criteria for sufficient review. R4 also would appear to require a
great deal of review of communications in order to satisfy the requirement to identify
potential defects. One of the suggestions on the NERC Webinar for COM-003 was to
review a "half-hour of communications" every week. This is especially intrusive on
smaller entities with a single compliance individual, as more than an hour of that
person's work-week would be spent randomizing, retrieving and listening to routine
communications. This effort would reduce the reliability of the bulk power system as
efforts with greater effect are reduced to comply with this requirement. Suggest
requiring an annual review of communications procedures with staff instead.
Response: The OPCPSDT thanks you for your comments. The SDT in draft 3, believes the entity should determine the frequency,
sample size and methodology. The SDT believes the entities should create robust controls to reduce deficiencies and reduce
miscommunication on the BES.
Hydro Quebec Trans Energie
No
It is unclear what identified reliability gap this Standard’s development project is
intending to fulfill given the recent adoption of the new COM-002-3 along with the
OC white paper on communications protocols.
Response: The OPCPSDT thanks you for your comments. The gap is a need to tighten communication protocols in all operating
levels. COM-002-3 is only applicable to Adverse Reliability Impacts and Emergencies. The OC White Paper cites studies that put
communication mistakes as a significant contributor to BES mishaps.
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Occidental Energy Ventures
Corp.
Yes or No
Question 3 Comment
No
OEVC supports the concept underlying R3 and R4, but believe that far more detail
must be provided in the measures and/or the RSAW. In general, we read these
requirements as pertaining to System Operator monitoring and feedback processes
that take place either in real-time or after the fact through the review of recordings.
However, there may be other suitable options such as comprehensive Operator
logging or even regular awareness training. Our concern is that without further
clarification, auditors may choose to interpret these requirements to mean that 100%
of all conversations must be monitored and assessed. This would result in a costprohibitive situation, with little incremental improvement in reliability. Every
effective quality program relies on statistically significant sample assessments - and
there must be an acceptable sample size defined.
Response: The CEA, by direction in the RSAW is supposed to understand the
process, but is limited to the results of the process and testing the effectiveness of
the process. This is all accomplished in a non zero defect environment.
The SDT does not believe it has stipulated that 100% of all conversations must
monitored and assessed. It is not stated as such in the standard and the webinar on
September 6, 2012 where the need for suitable sampling models were discussed.
Furthermore, OEVC would like to see the Cost Effective Analysis Process (CEAP) used
in this initiative. Our initial assessment is that at least one resource will need to be
added at our four generation facilities in order to supplement our Operator quality
monitoring program to accommodate COM-003-1. However, this is based upon our
assumptions of a statistical monitoring method - which is very sensitive to the
number of samples required. If other industry stakeholders come to the same
conclusion, the result could drive upward pressure on electricity rates - and should be
compared to the expected benefits of the initiative.
Response: The SDT does not contemplate applying CEAP to this standard. The SDT
also believes the entity has much license to develop the Identify, Assess and Correct
process including sample sizes based on statistical modeling. Based on the
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resources most entities have for training and auditing the SDT believes the
incremental costs to be minimal.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
TransAlta Centralia
Generation LLC
No
There is no statement of periodicity in R4, leaving entities guessing until the time of
audit regarding the criteria for sufficient review.
Response: The entity is to determine the sample size and frequency of review. The
auditor will understand the entity’s process, but will only validate the results, not
the entities controls.
R4 is also open-ended regarding scope, potentially requiring review of every voice
communication for every plant for the audit period. Everyday communications do
not merit such scrutiny, which would reduce rather than improve the attention that
can be given to matters of significance. All standards (not just COM-003-1) should
clearly specify pass/fail criteria and the associated evidence requirements.
Response: The SDT disagrees. It is up to the entity to develop the process. The CEA
will audit against the results, not the process.
R4 should be split into DP and GOP sections, with the GOP requirement being:
R4. Each Generator Operator shall conduct in each calendar year a review session
with the operations function for registered entities, regarding the documented
communication protocols specified in Requirement
2. Corrective action shall be implemented and documented for any potential
deficiencies coming to light as a result of this review.
Response: The SDT believes the DP and GOP are properly classified under the same
requirements. They are both receivers of Operating Instructions and are subject to
the same communication protocols.
The SDT believes the entity will determine the frequency and sample size under
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draft 3 of the requirement. More robust controls will reduce deficiencies.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ReliabilityFirst
No
ReliabilityFirst believes the words “identifying deficiencies” (within R3 and R4) is
ambiguous and could be open to interpretation. ReliabilityFirst believes the drafting
team should further clarify the deficiencies in which will be required to be identified
in Requirement R3 and R4.
Response: The OPCPSDT thanks you for your comments. Deficiencies are instances where System Operators do not adhere to the
entities documented communication protocols specified in R1 and R2.
Independent Electricity
System Operator
No
We do not see the need for these two requirements at all. Assuming Requirements
R1 and R2 were to stay (which we disagree), Responsible Entities need to comply
with these requirements to develop documented communication protocols for
Operating Instructions that incorporate all parts in R1 and R2. Any deficiencies with
adherence to the documented communication protocols specified in R1 and R2 will
be assessed non-compliance, and sanction and remedial actions will be imposed to
correct such deficiencies. Having two requirements to obligate entities that already
violated the standard is totally unnecessary, and redundant and may result in double
jeopardy.
Response: The OPCPSDT thanks you for your comments. No, you are incorrect. There is no finding of non compliance if the entity
identifies, assesses and corrects the deficiency.
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
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Question 3 Comment
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
NextEra Energy Inc.
No
Although NextEra supports Reliability Standards that are more risk and result based
and provide for a corrective bandwidth or prosecutory discretion for possible
violations, as drafted, R3 and R4 need refinement to meaningfully and clearly
implement any of the above concepts. Therefore, NextEra recommends that R3 and
R4 both be re-written to read as follows:
R3 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R1 and its subrequirements shall be
found, provided that the Balancing Authority, Reliability Coordinator, and
Transmission Operator has implemented a process for identifying deficiencies with
adherence to the documented communication protocols specified in Requirement R1
that: . . .
R4 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R2 and its subrequirements shall be
found, provided that the Distribution Provider and Generator Operator shall
implement a process for identifying deficiencies with adherence to the documented
communication protocols specified in Requirement R2 that: . . .
Response: The OPCPSDT thanks you for your comments.
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
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Question 3 Comment
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Northeast Utilities
No
R3 & R4 As written are confusing and do not convey the intent of the SDT. Below is
recommended re-write:
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement a process that assesses conformance and performance to the R1
documented protocols. This process shall include identifying deficiencies, assessing
the deficiencies and correcting the deficiencies when feasible.
R3.4 & R4.4 This should be removed as a sub-requirement and made its own
requirement. Below is recommended re-write:
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
[insert time period] evaluate its process required by R3 (R4) for deficiencies.
Identified deficiencies shall be assessed and corrected when feasible. If no
deficiencies found this is to be documented.
Response: The OPCPSDT thanks you for your comments. The SDT appreciates your recommended language. The SDT believes the
language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
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RSAW has been updated to reflect this change.
Alliant Energy
No
COM-003 cannot be a zero defect standard. We propose rewording R3 to state:
"Each Reliability Coordinator, Transmission Operator and Balancing Authority shall
implement the requirements in R1 in a manner that identifies, assesses, and corrects
deficiencies, if any. Where the entity is identifying, assessing and correcting
deficiencies, the entity is satisfactorily meeting the requirements or COM-003."If
there is no leeway given, requirement 1 of this standard will generate a very large
number of violations and in our opinion it would become one of the most violated
standards very quickly.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
The Empire District Electric
Company
No
This is redundant with the continual improvement methodologies that the NERC
process already has in place. If a company finds, through a self assessment or NERC
audit, that they are not meeting a requirement in a standard, then the NERC process
is to either self report, or be found in violation. In either case the entity must
complete their defficiency in the standard in order for the mitigation to be approved
by their regional entity. To have to have written process for this in order to meet R3
and R4 is redudant with the requirements on how NERC views the elements of a
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successful compliance program. Smaller entities do not have the man power for
redundancies such as this. I would rather see R3 and R4 dropped from the standard
for the reasons above. Most if not all companies will correct issues through the self
report process and mitigation plan approval process.
Response: The OPCPSDT thanks you for your comments. This is different from the program you described. This is a new approach
to reliability standards that requires entities to develop a process that identifies, assesses and corrects deficiencies in a non zero
defect environment.
The SDT believes the language changes to draft 4 will address your concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
American Electric Power
No
AEP disagrees with the concept of requiring three part communications for more
routine operations, and as a result, also disagrees with R3 and R4 which require that
the entity shall implement a process for identifying deficiencies with adherence to
the documented communication protocols specified in Requirement R1 and R2.
Response: The OPCPSDT thanks you for your comments. The SDT believes three part communications is a proven, effective
protocol that prevents grave operations errors that could compromise the reliability of the BES.
Brazos Elextric Power
Cooperative, Inc.
No
See ACES comments.
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Response: The OPCPSDT thanks you for your comments. Please see our responses to ACES comments.
Ameren
No
See response to question 5.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 5.
Essential Power, LLC
No
There is no statement of periodicity in R4, leaving entities guessing until the time of
audit regarding the criteria for sufficient review.
Response: The entity is to determine the sample size and frequency of review. The
auditor will understand the entity’s process, but will only validate the results, not
the entities controls.
R4 is also open-ended regarding scope, potentially requiring review of every voice
communication for every plant for the audit period. Everyday communications do
not merit such scrutiny, which would reduce rather than improve the attention that
can be given to matters of significance. All standards (not just COM-003-1) should
clearly specify pass/fail criteria and the associated evidence requirements.
Response: The SDT disagrees. It is up to the entity to develop the process. The CEA
will audit against the results, not the process.
R4 should be split into DP and GOP sections, with the GOP requirement being:
R4. Each Generator Operator shall conduct in each calendar year a review session
with the operations function for registered entities, regarding the documented
communication protocols specified in Requirement R2. Corrective action shall be
implemented and documented for any potential deficiencies coming to light as a
result of this review.
Response: The SDT believes the DP and GOP are properly classified under the same
requirements. They are both receivers of Operating Instructions and are subject to
the same communication protocols.
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The SDT believes the entity has the discretion to set the frequency and sample size
under draft 3 of the requirement. More robust controls will reduce deficiencies.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Texas Reliability Entity
No
If a deficiency is identified and then training is provided to attempt to correct it, what
happens if the same deficiency is identified again? Is the entity considered to have
failed to correct its identified deficiency? Does the entity need to file a self report
when the second deficiency occurs? Texas RE agrees with the premise of having a
process for identifying issues, but at some point if a pattern of deficiencies continues,
when does a violation occur?
Response: The OPCPSDT thanks you for your comments. As long as the entity is identifying assessing and correcting the deficiency
there is no need to self report. If the deficiency continues as a result of the entity not evaluating its process or not making
modifications it has identified; or not providing documented justification why modifications are not required, a finding of non
compliance may be awarded, based on specific circumstances.
GTC
No
The current wording necessitates creating a process to evaluate a process that
evaluates protocols. We believe this is unnecessarily cumbersome and confusing.
The addition of extra controls from the last version to this version lends nothing to
improving reliability or improving the function of the standard. Accordingly, the
NERC SC recently approved the SAR for the Paragraph 81 initiative to eliminate
certain requirements from the Reliability Standards with little effect on reliability.
The SAR identifies criteria to be used to identify those requirements that could easily
be identified for removal. It would seem that the draft R3 and R4 would meet the
criteria identified for P81. GTC recommends the deletion of R3 and R4.
Response: The SDT believes the protocols and the required process improve
reliability by creating universal and consistent communication protocols that
prevent miscommunication of Operating Instructions on the BES. The SDT believes
the requirements of COM-003-1 are not trivial or administrative.
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Alternatively, at a minimum, we suggest improvements to requirements R3 and R4
as currently drafted. We suggest changing all instances of the word “process” to
“protocols” in both part 4s and also removing “found external to Part 4.1” from both
part 4s. Finally we suggest removing parts 2 and 3 simply to keep the requirements
from becoming redundant with the changes made to their respective part 4s.
Response: The SDT appreciates the alternative language but implementing it would
preclude the standard from being able to improve communication protocols
outside of a zero defect environment.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Public Service Enterprise
Group
No
These questions apply equally to R3 and R4. In R4.1, what is a “potential” deficiency?
Response: The SDT believes the initial designation of “potential” should describe
the deficiency until the “assessment” confirmed it.
In R4.3, how can one correct a deficiency since that happened in the past?
Response: The SDT intends for the entity to assess and correct the deficiency. The
SDT believes to correct a deficiency means to take measures to correct the cause of
the deficiency in a manner that it is not repetitive. Examples of which are, but not
limited to, training, process change, performance documentation evaluation,
counseling and other measures that would prevent future occurrences.
In R4.4, how does one evaluate the process based on deficiencies identified that are
“external to Part 4.1”? (Part 4.1 is the process for identifying deficiencies.)
Response: The entity compares the deficiencies found externally to determine why
they were not identified by the entities internal process. The entity then makes
proper modifications to its process to improve its performance for finding
deficiencies.
We are also concerned about the draft RSAW for R3 and R4. The RSAW has two
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bullets for R3 and R4. One states
“Where the auditor can verify that the entity is identifying, assessing, and correcting
its own deficiencies, the auditor will not have a finding of nonâ€compliance.” The
second bullet states “If an auditor cannot verify that the entity is adequately
identifying, assessing, and correcting its own deficiencies due to limitations in its
process, the auditor will not have a finding of nonâ€compliance.” The auditor will
provide the entity with recommendations as necessary.”
Per the RSAW for R3 or R4, how will an auditor verify that an entity is not
“adequately identifying, assessing, and correcting its own deficiencies due to
limitations in its process”? In other words, what evidence will be required by the
auditor, and how many months of communications records should be kept?
Response: the auditor for draft 3, R3 and R4 will require the results of the process
and the evidence requirement is 90 days. This is articulated in draft 3 of COM-0031. The RSAW was posted and comments for the RSAW were to be entered there.
Because of the volume of communications, sampling may be required. Unless one
listens to 100% of communications recording, one cannot be sure one is identifying
all deficiencies. Is 100% deficiency detection the goal?
Furthermore, M3 or M4, which only require the entity to provide the results of its
process in R3 and R4, are not mentioned in the RSAW. Measures are supposed to
represent one acceptable from of compliance and should be acceptable in the RSAW.
Response: The standard does not specify a goal. The goal should be a function of
the entities desire to eliminate mistakes caused by miscommunication.
The Measures, M3 or M4, are the results of the process as stated in the standard.
Finally, if R1 and R2 are changed as recommended in #2 above (i.e., remove the
requirement for an entity to have documented communications protocols and just
require it to adhere to protocols n R1 and R2), incidents of non-compliance with the
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protocols will be detected via R3 and R4.
We first recommend that M1 and M3 have the same measures - M1 and M2 would
both read “Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall provide the results of its process developed for Requirement R3.” The
same would apply for M2 and M4, which would both read “Each Distribution Provider
and Generator Operator shall provide the results of its process developed for
Requirement R4.” If this were done, the draft RSAWs two bullets discussed should
have these phrases modified for R3 and R4, with the modification shown in capital
letters:
o In R3, modify “the auditor will not have a finding of nonâ€compliance FOR EITHER
R1 OR R3” in two bullets.
o In R4, modify “the auditor will not have a finding of non†compliance FOR EITHER
R2 OR R4” in two bullets.
Response: The SDT believes the language changes to draft 4 may address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
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Yes or No
Question 3 Comment
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Cowlitz County PUD
No
See response to question two.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 2.
Indiana Municipal Power
Agency
No
IMPA recommends adding clarification to the words “deficiencies found external to
Part 3.1 (4.1)" so that entities and auditors know that these requirements allow
defeciencies found outside of the entitie’s process including deficiencies that had
previously passed the entity’s process) will be able to go through the entity’s process
of assessing and correcting without the auditor giving a finding of non-compliance,
since the entity itself failed to identify the potential deficiency in R3.1. or R4.1. The
clarity can be added in the standard itself or in the RSAW- it currently is not stated in
the standard and it is especially absent in the RSAW under Section 2 on page 4 of 5 or
Section 2 page 5 of 5.It is also not clear how many times an entity will be allowed to
identify, assess, and correct the same deficiency or similar deficiencies before an
auditor can find an enitiy in non-compliance with R3 and R4 (including
subrequirments of each). It appears that the SDT is saying that as long as an entity is
making the changes provided in the feedback by the CEA to its process to identify,
assess and correct that it will not be found non-compliant for all same or similar
deficiencies that continue to occur - there is no set number as long as the entity is
trying to improve its process or communication protocols, is this correct? If so, IMPA
supports this practice and would like to see clarity added.
Response: The OPCPSDT thanks you for your comments. Your comments referring to 3.1 to 3.3 and 4.1 to 4.3 are correct. R3.4 and
R4.4 require the entity to evaluate its process if deficiencies are discovered externally. The entity must implement modifications if
the entity determines modifications are required or justify why the entity determines no modification is required. If the entity
does not comply with these subrequirements it may be subject to a finding of non compliance. The SDT believes the standard
draft3 and the RSAW convey this.
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MISO
Yes or No
Question 3 Comment
No
MISO respectfully submits that COM-003-1, R3 and R4 require clarification in two
regards. MISO first notes that requirements R3.4 and R4.4, which require Registered
Entities to evaluate “the process based on deficiencies found external to
[R3.1/R4.1],” are written in a confusing manner. More specifically, it is not clear what
the phrase “found external to” means and, therefore, Registered Entities cannot
know or understand when their compliance obligations under these requirements are
applicable.
Response: The SDT has changed the language changes to draft 4.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
In addition, MISO respectfully submits that the SDT must add clarifying language to
COM-003-1 to clarify that an individual failure to execute elements of a System
Operator’s communication protocol is not, on its own, a compliance violation,
provided that the System Operator evaluates adherence to its protocol as required by
Requirements R3 and R4.
Response: The SDT believes that is stated in the standard and supported in the
RSAW.
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MISO is concerned that the current draft of COM-003-1 could give rise to double
penalties for individual failures to execute one of the elements of a communication
protocol. Without clarifying language in the Reliability Standard itself, any Registered
Entity that fails to adhere to its communication protocol required by COM-003-1, R1
and R2 would likely self-report this failure, and would subsequently complete a
mitigation plan that addresses -- and implements new processes to prevent the
repetition of -- the failure. An additional requirement to evaluate adherence to the
communication protocol would be redundant and would not increase or bolster
reliability - and, further, would only increase the potential for Registered Entities to
violate yet another requirement of a Reliability Standard. Thus, unless COM-003-1 is
revised to clarify that a Registered Entity’s failure to implement an element of its
communication protocol for Operating Instructions is not a compliance violation in
and of itself and, therefore, is not subject to self-reporting under NERC and Regional
Entities Compliance Monitoring and Enforcement Program (“CMEP”), MISO cannot
support proposed Requirements R3 and R4 at this time.
Response: The SDT believes the language changes to draft 4 may address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM121
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Yes or No
Question 3 Comment
003-1 RSAW has been updated to reflect this change.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ERCOT
No
ERCOT agrees with the SRC comments, and has these additional comments: ERCOT
fully supports the concept that functional entities’ internal controls be used to
monitor the effectiveness of their own protocols. However, these matters are not
suitable for reliability standards. Imposition of mandatory controls applicable to all
functional entities is inappropriate because of the wide variety of organizational
structures that necessarily requires flexibility with respect to developing appropriate
controls for each entity’s specific circumstances.
Response: The SDT believes the draft standard provides great flexibility to all of the
applicable entities and believes that the standard focuses on the results of an
entity’s process for identifying, assessing and correcting deficiencies all in the
interests of improving reliability.
Furthermore, entities’ internal controls are beyond the scope of the Section 215
reliability purview generally, and they are inconsistent with the risk based initiative
being pursued by NERC because they do not impact/are not related to actual
reliability impacts.
Response: The SDT disagrees and does not discern the linkage to Section 215 and
points out the standard is not focused on internal controls, but on improving
communication clarity to avoid problems on the BES which has a dramatic impact
on reliability.
Furthermore, this deficiency review process is ambiguous and, accordingly, lends
itself to inefficient and ineffective CMEP results. As an initial matter, what
constitutes a deficiency will be an issue that is vulnerable to subjective
disagreements. Even assuming there is agreement on that issue, what constitutes an
appropriate remedy for a deficiency in terms of assessment and correction will
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similarly be susceptible to subjective disagreements.
Response: The SDT does not believe the evaluation process is ambiguous and
believes the implementation of this standards approach to standard development
will enhance the effectiveness of NERC’s CMEP program.
Finally, with respect to the obligation to evaluate the deficiency identification process
itself, again, the potential for the introduction of subjective compliance review will be
problematic n practice in terms of reviewing whether the decision whether to
implement a modification or not, and, if a modification is implemented, whether the
revision is adequate.
Response: The SDT believes there has to be a level of accountability for an entity
that cannot or will not take measures to improve its process. The SDT believes the
requirements that require the evaluation are clear and fair. The entity can make
any decision to modify or not to modify; the later requires documented
justification.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Oncor Electric Delivery
Company LLC
No
Oncor also takes the position that all of the ideas prescribed within these
requirements including the implementation, assessment, evaluation and correction
of communication protocols, are already being effectively implemented as industry
Best Practice. In addition, Oncor requests that NERC substitute the CIP v.5 'zero
defects' (Each Responsible Entity shall implement, in a manner that identifies,
assesses, and corrects deficiencies, one or more documented processes) language in
COM-003 in order to minimize potential confusion.
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
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documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
Oncor offers the following substitute language for R3 and R4.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues an Operating Communication shall either:
o
Confirm that the response from the recipient of the Operating Communication
(in accordance with Requirement R2) was accurate, or
• Reissue the Operating Communication to resolve any misunderstandings.
Response: R3 and R4 are eliminated, but the CEA still follows the same guidance with
regard to deficiencies and the quality of an entity’s implementation of the
communication protocols in a manner that identifies, assesses and corrects
deficiencies. The COM-003-1 RSAW has been updated to reflect this change.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Georgia System Operations
No
Center Point Energy Houston
Electric, LLC.
No
Associated Electric
Cooperative Inc - JRO00088
Yes
This could work, were wording per concepts already suggested per questions 1 & 2
and question 5, such that the documented evidence of an effective program,
precludes violations of any individual requirement. In interest of providing our
industry with greater consistency in wording and format throughout future
standards, AECI strongly suggests that this SDT review the current draft release of CIP
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Version 5’s draft (for ballot), and similarly format these requirements. However
please see AECI's general observations concerning COM-003-1 in comment 5 below.
Response: The OPCPSDT thanks you for your comments. The SDT will respond to AECI’s comments and observations in 5 below.
FirstEnergy
Yes
FirstEnergy supports this new concept being introduced by NERC. It allows entities to
sharpen their internal controls while not being penalized for minor non-compliance
situations that do not impact the BES. The only question we raise is how this will be
implemented in the CEAP. The draft RSAW for COM-003-1 is silent on this issue and
we ask that NERC give more guidance on it as this paradigm develops.
Response: The OPCPSDT thanks you for your comments. CEAP at this writing is still under development and to the best of the
SDT’s knowledge is not deployable yet.
Florida Municipal Power
Agency
Yes
we commend the SDT for doing a good job of writing a difficult standard and avoiding
the "zero-defect" problem (the problem of just having just one violation in tens of
thousands be punishable by fines) and we support the approach taken. If we think of
managing operations, we think of the process:
Step 1 - Vision, goals, policies - what do we want to accomplish?
Step 2 - Protocols, plans, procedures, programs, processes, methodologies - how will
we do it and who will do what?
Step 3 - Do it
Step 4 - Measure, monitor - did we accomplish what we set out to do?
Step 5 - Learn, adjust, back to 1.
The problem with the prior draft of COM-003, before this latest draft, is that the
standard essentially micromanaged industry by causing auditors to monitor actual
communications, e.g., the auditors would be doing step 4, which ends up with the
zero-defect problem. We have seen other standards that have this zero defect
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problem, e.g., PRC-005 has a requirement for step 2 of the process above, to have a
program, and then for step 3 of the process, to do it in accordance with the program,
which results in the zero-defect problem. We've seen still other standards avoid the
zero defect problem by only requiring step 2, but with no requirement to actually do
it, e.g., the currently enforceable CIP-001 has requirements for step 2 of the process
above for sabotage reporting procedures, but, has no requirement to actually follow
those procedures if a sabotage event occurs, which leaves questions of
accountability. The SDT for COM-003 is doing the appropriate thing and backing up
one level to measure how effectively we are managing our own operations, and this
is the first time I've seen a standard developed in this clever fashion of developing
requirements for Step 2 (protocols) and Steps 4 & 5 (measure, monitor, learn, adjust)
of the process above, but not Step 3 of the process. However, Step 3 would need to
be performed for the entity to comply with Steps 4&5, meaning we are still
accountable for "doing it".
The method that the SDT is using to ensure we have the appropriate operations
management mechanisms in place seems a clever and pragmatic approach. We have
one suggestion to improve R3. R3 requires entities to “implement” a process for
identifying deficiencies. Use of the word “implement” implies that all deficiencies
must be identified, which means that the auditors would need to independently
identify deficiencies and compare notes, which reintroduces the "zero-defect"
problem. FMPA recommends replacing "implement" with “institute”.
Response: The OPCPSDT thanks you for your comments. The SDT believes the word implement means to develop and initiate the
process. The “how to” of that process will be determined by the entity. We believe R3 provides latitude to determine the means
and methodologies to develop how it will identify, assess and correct deficiencies and does not specify or even imply a 100%
identification of deficiencies. A robust sampling of Operating Instructions based on statistical modeling would be a more efficient
and effective means of developing controls for identifying deficiencies.
Southern Company
Yes
Provided that the SDT incorporate the changes suggested for R1 and R2, Southern
generally agrees with the concept of implementing a process to identify and correct
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deficiencies without compliance exposure for each deficiency. However, this is a new
concept and we do have questions as to how it will be implemented. For example,
how many discrepancies would it take for an entity to identify before requiring a self
report rather than waiting to present the log of deficiencies found and corrected
during an audit?
Response: The OPCPSDT thanks you for your comments. As long as the entity is identifying, assessing and correcting deficiencies
and evaluating its process (R3.4 and R4.4) and improving it to reduce deficiencies there is generally not a finding of non
compliance. The entity must evaluate its process if deficiencies are discovered externally. The entity must implement
modifications if the entity determines modifications are required or justify why the entity determines no modification is required.
If the entity does not comply with these sub requirements it may be subject to a finding of non compliance. The SDT believes the
standard draft3 and the RSAW convey this.
NIPSCO
Yes
These appear to be Internal Controls and they look good.
Response: The OPCPSDT thanks you for your comments.
The United Illuminating
Company
Yes
United Illuminating supports the language in COM-003 R3 and R4. Since the quantity
of Operating Instructions will be very large it is more important to have a process to
monitor the communication protocols and correct deficiencies.
Response: The OPCPSDT thanks you for your comments.
CPS Energy
Yes
The proposed requirements (COM-003-1, R3 and R4) are in line with Risk-Based
Reliability Compliance Monitoring.
Response: The OPCPSDT thanks you for your comments.
Exelon
Yes
Exelon agrees with the proposed requiremnt but thinks it could be improved before
final adoption. The Requirement as written is confusing. For example, R3 is to identify
deficiencies with respect to the entities protocols. R3.1 addresses “potential”
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deficiencies. It is unclear what a potential deficiency is. We suggest using deviations
from the entities protocol in place of deficiencies or potential deficiencies. Similarly
we question how an entity will demonstrate that modifications to their program are
not required in light of the assessment being done in response to deviations from the
protocol. We believe R3.4 should be clarified. We believe its purpose is to direct an
entity to take action if an external entity (auditor) identifies a deviation from the
entity protocol. We do not think the response to identifying a deviation / deficiency
should vary based on how it was identified. Once identified (R3.1), a deviation /
deficiency should be assessed (3.2) Corrected (3.3) and when necessary (3.4) the
program should be modified to account for the deficiency. Since a similar effort to
utilize an internal controls approach is underway in the CIP Version 5 drafting, it may
be valuable for COM-003 to also utilize the same language of “in a manner that
identifies, assesses, and corrects deficiencies.”Exelon supports the effort to utilize an
internal controls approach but remains concerned compliance auditing and the
potential for interpretations related to the requirement. We urge NERC, in
collaboration with the Regional Entities to develop a clear roll out plan prior to
implementation of COM-003 so that stakeholders and auditors understand the
compliance obligations for this new approach.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 may address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
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RSAW has been updated to reflect this change.
Duke Energy
Yes
Tacoma Public Utilities
Yes
MRO NSRF
Yes
APPA, LPPC and TAPS
Yes
Arizona Public Service
Company
Yes
Southwestern Power
Administration
Yes
US Bureau of Reclamation
Yes
Manitoba Hydro
Yes
Central Lincoln
Yes
City of Austin dba Austin
Energy
Yes
Idaho Power Co.
Yes
South Carolina Electric and
Gas
Yes
Salt River Project
Yes
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Lincoln Electric System
Yes
Public Service Company of
New Mexico
Yes
City of Tallahassee
Yes
MidAmerican Energy
Yes
Puget Sound Energy Inc.
Yes
Xcel Energy
Yes
Question 3 Comment
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4.
Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4?
Summary Consideration: The Structure of COM-003-1, draft 4 has changed dramatically. There are now two requirements and the
scope of each is different enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft
4 and request new comments on the VRFs and VSLs. The SDT appreciates industry input on this question for draft 3.
The new draft 4 language is:
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that
identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions
between Functional Entities that include the following:”
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an
entity’s implementation of the communication protocols in a manner that identifies, assesses and corrects
deficiencies. The COM-003-1 RSAW has been updated to reflect this change.
Organization
Yes or No
ACES Power Marketing
Standards Collaborators
No
Question 4 Comment
(1) We agree with the VRF classifications.
(2) We agree with the VSLs for R1 and R2. We note that there is a typo in Severe VSL
for R2 - there is no part 2.3 in the standard.
Response: Thank you, the SDT has corrected the error.
(3) We disagree with the Time Horizons for R1 and R2. Developing documented
communications protocols are not long term planning, these activities are operations
planning.
Response: The SDT believes Long Term Planning is the proper Time Horizon based
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on the NERC guidance document.
(4) We disagree with the VSLs for R3 and R4. In particular, the binary nature of
implementing communication protocols needs to be reconsidered. During the
September 6 webinar, both Gerry Cauley and Mike Moon stated that internal
controls should focus on fixing deficiencies and auditors were not to find PVs for
single instances of noncompliance. Based on these statements, the VSLs should not
be binary if the auditors are not to find PVs for single instances. Also during the
webinar, Mike Moon stated that the auditors are to make recommendations in their
audit reports to improve their processes, and not to be an “enforcement hammer”
for each individual deficiency. The way the VSLs are drafted, each instance will be
severe. We recommend that the SDT revise the VSLs to allow for auditors to make
recommendations instead of findings of potential noncompliance.
Response: The SDT believes that the Standard language supports the correction of
deficiencies rather than finding PVs. The entire identify, assess and correct process
is the core emphasis of the standard.
The finding of non compliance and the commensurate Severe VSLs only occur after
an entity that does not improve its process when it has demonstrated that
improvement is required. This sets the stage for creating a risk for
miscommunication to cause errors on the BES. The SDT believes this will be an
unlikely exception because it would occur only if the entity disregards the poor
performance of their process and their own findings to improve it. To reach this
point would be the result of a long chain of failures and a near complete disregard
of the requirement on the part of the entity.
(5) R3 VSL, “The Responsible Entity did not demonstrate that no modificiation to the
process was necessary to address the deficiencies found external to Part 3.1.” This is
a documentation issue and should not result in a severe VSL classification.
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Question 4 Comment
Response: The SDT does not believe it is a documentation issue. An entity, which
does not improve its process when the process is unable to identify deficiencies, is
creating a risk for miscommunication that will cause errors on the BES. If the entity
disregards or refuses without justification to make those modifications the CEA
must have the authority to elevate level of compliance.
(6) There was a lot of discussion in the webinar about Regional auditors not finding a
violation, but there needs to be clear guidelines describing when an auditor will find a
PV. The VSLs currently describe a violation when a deficiency is not remediated, but
that same instance could result in no finding at all, depending on how the individual
auditor interprets the situation. This level of subjectivity is too high; the SDT needs to
revise the VSL table to reflect a more reasonable approach, perhaps by including
more information and examples of situations that might be viewed as noncompliance (communication breakdown) but because of internal controls, there
should be no finding of non-compliance. In the alternative, the SDT could develop a
guidance document outlining when an auditor is to find a PV and include examples to
ensure consistency. The RSAW does not provide any additional clarity.
Response: The SDT refers to its responses to 4 and 5 above. The SDT does not
believe the level of subjectivity is high. The identify, assess and correct aspect of
the requirement is at the core of the standard. If an entity does this and has a
strong process and controls that capture deficiencies in a manner that can be
verified by external agents, there are generally no findings of non compliance. If an
entity does not make modifications to their process that they have identified or do
not make modifications and do not justify why they believe modifications are not
required they have approached a status where they could be subject to a finding of
non-compliance. This is an area where an entity with a compromised internal
process which the entity is not improving and, therefore, is not realistically
managing the risk of miscommunication that could impact the BES.
(7) In the webinar, there were several references to “systemic or chronic”
communication deficiencies. The VSLs do not reference any types of trends, but that
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Question 4 Comment
seems to be the focus of compliance. We suggest revising the VSLs to focus on
broader issues, such as systemic deficiencies that remain unresolved.
Response: The SDT believes Requirements R part 3.4 and R part 4.4 will be
instrumental in revealing systemic or chronic communication deficiencies. To the
extent an entity modifies the process and strengthens their controls, improvements
to the process and corrections of deficiencies can be generally be accomplished
without a finding of non compliance.
Response: The OPCPSDT thanks you for your comments. The Structure of COM-003-1, draft 4 has changed dramatically there are
only two requirements and the scope of each is different enough to warrant significant changes to the VRFs and VSLs in draft 4.
The SDT will post draft 4 and request new comments on the VRFs and VSLs. The SDT appreciates your input on this question for
draft 3.
Detroit Edison
No
Analysis during Annual Review of work procedure for R1 and R2 automatically
includes an analysis of the process and development of corrective actions.
Response: The OPCPSDT thanks you for your comments. The Structure of COM-003-1, draft 4 has changed dramatically there are
only two requirements and the scope of each is different enough to warrant significant changes to the VRFs and VSLs in draft 4.
The SDT will post draft 4 and request new comments on the VRFs and VSLs. The SDT appreciates your input on this question for
draft 3.
Duke Energy
No
1) Consistent with our comment to Question 2 above regarding changing the word
“incorporate” to “address” in Requirements R1 and R2, this change should also be
made in the VSLs for R1 and R2, changing the word “include” to “address”.2) The
Severe VSL for R2 incorrectly references a Part 2.3, whereas it should just refer to
both Parts 2.1 and 2.2
Response: The OPCPSDT thanks you for your comments. The SDT changed the word to “include” in all cases. There has to be a
level of uniformity of communication protocols among functional entities to create universal communication protocols.
The SDT has corrected the error you indicated. (R2 incorrectly references a Part 2.3, whereas it should just refer to both Parts 2.1 and
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Question 4 Comment
2.2)
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
Dominion
No
For the reasons cited in the comments above
Response: The OPCPSDT thanks you for your comments.
Associated Electric
Cooperative Inc - JRO00088
No
It could be appropriate, were the expectations properly bounded similar to the
wording outlined for Question 5 below.
Response: The OPCPSDT thanks you for your comments.
ISO/RTO Standards Review
Committee
No
The SRC does not agree with the VSLs of R3 and R4 . The SRC feels that it is not
binary and actually fits the Requirements with Parts that Contribute Unequally to the
Requirement in the VSL guideline document. While part 3.3 is the most critical, an
entity would certainly not get any reliability benefit if you don’t do parts 3.1 - 3.3 or
3.3 in itself, which could be a severe VSL. But if an entity performs parts 3.1 - 3.3 and
does not perform part 3.4, it should not be a severe VSL because you are getting a
substantial amount and majority of the reliability benefit from performing 3.1-3.3.
Failure to do part 3.4 should be a high VSL perhaps, but it is not all binary. If an entity
fails to do 3.2, it may be a medium only.
Response: The OPCPSDT thanks you for your comments. The Structure of COM-003-1, draft 4 has changed dramatically there are
only two requirements and the scope of each is different enough to warrant significant changes to the VRFs and VSLs in draft 4.
The SDT will post draft 4 and request new comments on the VRFs and VSLs. The SDT appreciates your input on this question for
draft 3.
SPP Standards Review Group
No
The Severe VSL for R2 contains a typo and should be reworded to read: ‘The
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Question 4 Comment
responsible entity did not include Parts 2.1 to 2.2 of Requirement 2...’We would
suggest that the VRFs for R3 and R4 be reduced to Low. The VRFs for R1 and R2 are
Low. R3 and R4 are processes that monitor R1 and R2; therefore, they should not be
treated more severely than R1 and R2.
Response: The OPCPSDT thanks you for your comments. Thank you for pointing out the error. We have corrected it.
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
Bonneville Power
Adminstration
No
BPA does not agree with the VRFs and VSLs. R3 & R4 should include a range of VSLs.
A documentation error such as a failure to record that modification of a process was
not necessary would not merit a severe VSL if training was implemented as an
appropriate solution to an identified deficiency.
Response: The OPCPSDT thanks you for your comments. The SDT believes it is not just a documentation issue. An entity that does
not improve its process when it has demonstrated that improvement is required is creating a risk for miscommunication that
would contribute to errors on the BES.
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
PacifiCorp
No
It is not clear to PacifiCorp why the VSLs are so much higher for R2 when R1 applies
to Balancing Authorities, Reliability Coordinators, and Transmission Operators, and
thus has a potentially broader application than R2. R2 applies to Distribution
Providers and Generator Operators.
Response: There are more parts in R1 – nine, as opposed to two in R2.
Also, it is not clear why the R2 VSL R2.3, as there is no R2.3 in the current draft.
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Question 4 Comment
Response: Thank you for pointing out the error. We have corrected it.
Response: The OPCPSDT thanks you for your comments.
Independent Electricity
System Operator
No
We do not agree with the need for most if not all of these requirements, and
therefore do not agree with the proposed VRFs and VSLs.
Response: The OPCPSDT thanks you for your comments. The SDT notes your comments. The Structure of COM-003-1, draft 4 has
changed dramatically there are only two requirements and the scope of each is different enough to warrant significant changes to
the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the VRFs and VSLs. The SDT appreciates your
input on this question for draft 3.
NextEra Energy Inc.
No
NextEra does not support VSLs that are checklist or document related. Rather
NextEra favors VSLs that balance results and performance against reliability risk. As
drafted, the current VSLs are a checklist approach to measuring reliability risk and
compliance, which is not particularly helpful or meaningful. Thus, NextEra suggests
that VSLs be re-drafted to measure whether the entity posed an actual risk to the
Bulk Electric System based on how it delivered or received an Operating Instruction.
Response: The OPCPSDT thanks you for your comments.
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
Northeast Utilities
No
VRF R3 & R4 NERC VRF Discussion:
R3 (4) is a requirement that, if violated, could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control
the bulk electric system. However, violation of the requirement is unlikely to lead to
bulk electric system instability, separation, or cascading failures. The VRF for this
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Question 4 Comment
requirement is “Medium” which is consistent with NERC guidelines.
The violation of R3 (R4) does not result in informal communication; it results in not
identifying it. It is not a failure to identify that poses the risk to the BES, but the
actual communication. The process implemented in R3 (R4) identifies, assesses, and
attempts to correct deficient communication practices in an attempt to make future
communications better. The process in R3 (R4) has no real-time impact on the BES, it
aims at having real-time impact on operators who have real-time impact on the BES.
For these reasons the VRF should be “Low”
Response: The SDT disagrees. The purpose of the process is not just to identify non
adherence to protocols, but ultimately to correct it to reduce the opportunity for a
miscommunication which can lead to unintended consequences in the operation of
the BES. The SDT believes the process will have an ultimate effect on real time
communication and elects to maintain the medium VRF.
FERC VRF G1 Discussion:
Discussion references wrong FERC Recommendation; should have referenced
Recommendation 26 rather than 24.
Response: The SDT has corrected the error. Thank you for bringing it to our
attention.
Additionally, the SDT wrongly implies that Recommendation 26 applies to COM-0031. Recommendation 26 “Tighten communications protocols, especially for
communications during alerts and emergencies...” applies to COM-002, thus
removing it from FERC VRF G1 allowing for a VRF of “Low” to be assigned.
Response: The SDT believes Recommendation 26 does apply to tightening
communications and that is what COM-003-1 does – it tightens communications.
FERC VRF G3 Discussion:
Though analogous to R2 of COM-002-2 they are not the same. One can argue that
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the importance of “directive” to the BES is greater than the importance of an
“Operating Instruction” to the BES and thus the risk to the BES is less for R3 (R4) of
COM-003-1, and accordingly should be assigned a lower VRF than R2 of COM-002-2
to promote consistency between the standards, while also elevating the importance
of COM-002-2 over COM-003-2. Said another way (Though each requirement
addresses communication protocol, the potential effects of the failure to follow the
protocol are different in that one deals with Directives and Emergency conditions and
the other with Normal operations. So the VRF's shouldn't necessarily be the same.)
Response: The SDT disagrees. The risk of the same miscommunication either during
an emergency (COM-002 family) or during normal operations can negatively impact
BES reliability. If the issuer of a directive, “Reliability Directive” or “Operating
Instruction” states: “Open switch RA50” and the receiver hears “Open switch
RA15” because “50” and “15” sounded the same and no protocols were utilized, the
resulting impact to the BES would be the similarly disastrous, no matter if the
system was operating under normal, emergency or alert conditions.
FERC VRF G4 Discussion: The violation of R3 (R4) does not result in informal
communication; it results in not identifying it. It is not a failure to identify that poses
the risk to the BES, but the actual communication. The process implemented in R3
(R4) identifies, assesses, and attempts to correct deficient communication practices
in an attempt to make future communications better. The process in R3 (R4) has no
real-time impact on the BES, it aims at having real-time impact on operators who
have real-time impact on the BES. For these reasons the VRF should be “Low”
Response: The COM-003 standard proposes to reduce the risk to the BES by
ensuring operators use communication protocols that clarify important elements of
an Operating Instruction. If operators are not conditioned to utilize the protocols
properly they will not use them properly in a Real Time environment. The SDT has
elected to maintain the medium VRF.
FERC VRF G5 Discussion: The SDT has argued that R3 & R4 each contain only one
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objective (identification of deficiencies).An Alternative read suggests the R3 & R4 as
written each have six objectives:
1.Identify deficiencies in 3-part communication as defined by protocols in R1
2.Assess identified deficiencies in 3-part communication
3.Correct identified deficiencies in 3-part communication
4.Identify deficiencies in process implemented in R3 (R4)
5.Assess identified deficiencies in process implemented in R3 (R4)
6.Correct identified deficiencies in process implemented in R3 (R4)VSL Justification R3
(R4)
The SDT has argued that R3 & R4 each contain only one objective (identification of
deficiencies).An Alternative read suggests the R3 & R4 as written each have six
objectives:1.Identify deficiencies in 3-part communication as defined by protocols in
R12.Assess identified deficiencies in 3-part communication3.Correct identified
deficiencies in 3-part communication4.Identify deficiencies in process implemented
in R3 (R4)5.Assess identified deficiencies in process implemented in R3 (R4)6.Correct
identified deficiencies in process implemented in R3 (R4)
Because there are multiple objectives in R3 (R4) there is an opportunity for more
granularities to the proposed VSL.
Response: The SDT sees only the one objective of reducing communication errors
on the BES.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
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The Empire District Electric
Company
No
Question 4 Comment
See comments from SPP
Response: The OPCPSDT thanks you for your comments. Please see our responses to comments from SPP.
American Electric Power
No
AEP disagrees with the concept of requiring three part communications for more
routine operations, and as a result, has no comment at this time on the proposed
VRFs and VLSs.
Response: The OPCPSDT thanks you for your comments.
Brazos Elextric Power
Cooperative, Inc.
No
See ACES comments.
Response: The OPCPSDT thanks you for your comments. Please see our responses to ACES comments.
Ameren
No
See response to question 5.
Response: The OPCPSDT thanks you for your comments. Please see our responses to question 5.
Essential Power, LLC
No
The VRFs and VSLs are divided into long-term planning and operation planning
categories. These terms are not explained in the standard, so the difference between
them is unclear. They do suggest however that, in accordance with our comment #1
above, this standard is not meant to apply to routine transmission system operatorto-plant communications.
Response: The OPCPSDT thanks you for your comments. The terms are contained on the NERC website. The only way the
standard could be made Real Time is in a zero defect environment. Please see our response to your comments on Question 1.
Texas Reliability Entity
No
R2 Severe VSL references “Parts 2.1 to 2.3 (3)” when a “2.3” does not exist (this issue
is also in the VRF/VSL Justification document). The VSLs for R3 and R4 say nothing
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about assessing and correcting identified deficiencies per 3.2, 3.3, 4.2 and 4.3.
Response: The OPCPSDT thanks you for your comments. The SDT has corrected the error.
The Structure of COM-003-1, draft 4 has changed dramatically there are only two requirements and the scope of each is different
enough to warrant significant changes to the VRFs and VSLs in draft 4. The SDT will post draft 4 and request new comments on the
VRFs and VSLs. The SDT appreciates your input on this question for draft 3.
“R1 (and R2 – DP and GOP). Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions
between Functional Entities that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
GTC
No
The VSLs for requirements R3 and R4 are too severe. We understand that they were
designated as binary, which led them to automatically be designated as severe VSLs.
However, it is our position that these requirements are no more binary than
requirements R1 or R2 and that their VSLs should be rewritten.
We propose:
Moderate VSL: The responsible entity did not include one (1) of the four (4) parts of
Requirement R3 in its implementation of a process for identifying deficiencies with
adherence to documented communication protocols specified in Requirement
R1.High VSL: The responsible entity did not include two (2) of the four (4) parts of
Requirement R3 in its implementation of a process for identifying deficiencies with
adherence to documented communication protocols specified in Requirement
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R1.Severe VSL: The responsible entity did not include three (3) or more of the four
(4) parts of Requirement R3 in its implementation of a process for identifying
deficiencies with adherence to documented communication protocols specified in
Requirement R1 or did not have such a process.
Response: The OPCPSDT thanks you for your comments. The Structure of COM-003-1, draft 4 has changed dramatically there are
only two requirements and the scope of each is different enough to warrant significant changes to the VRFs and VSLs in draft 4.
The SDT will post draft 4 and request new comments on the VRFs and VSLs. The SDT appreciates your input on this question for
draft 3.
MISO
No
MISO appreciates the changes that the SDT has made to the VRFs and VSLs in
response to comments and to ensure that the VRFs and VSLs are consistent with
FERC and NERC guidelines. However, MISO cannot support either the VRF or the VSLs
for R3 and R4 as it does not agree:
(1) that there is a direct impact on reliability that result from an entity’s internal selfassessment and
(2) with the expressed rationale.
Further, MISO notes that COM-003-1, R3 and R4, primarily require internal
administrative processes or documentation thereof. MISO respectfully submits that
internal administrative processes have not previously been linked to direct impacts
on the reliability of the BES.
Response: The OPCPSDT thanks you for your comments. The SDT believes there is a very direct impact on BES reliability from
improved operating communication because there is a reduced opportunity for miscommunication that would harm the BES. The
BES does not see COM-003-1 as simply an administrative process. It is a mechanism to condition and develop System Operators to
a uniform and consistent level of communication discipline utilizing their documented communication protocols. The additional
feature of this standard is that it can be managed normally in a “non-zero defect” environment. The SDT believes the process is
pre-emptive in nature which means an entity develops measures that reduce the risk of mistakes that harm the BES.
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ERCOT
No
Question 4 Comment
ERCOT agrees with the SRC comments.
Response: The OPCPSDT thanks you for your comments. Please see our responses to SRC comments.
Pepco Holdings Inc
No
Georgia System Operations
No
CenterPoint Energy Houston
Electric, LLC.
No
Liberty Electric Power, LLC
No
Oncor Electric Delivery
Company LLC
No
SERC OC Standards Review
Group
Yes
We could agree within the context of our comments listed above.
Response: The OPCPSDT thanks you for your comments. Please see our responses to your previous comments.
Manitoba Hydro
Yes
VSLs for R3 and R4: There is no contemplation of the entity failing to assess
deficiencies (3.2 and 4.2) or failing to correct deficiencies (3.3, 4.3).
Response: The OPCPSDT thanks you for your comments. The SDT has changed the language of the R3 and R4 to mirror that of CIP
v.5 and no longer uses parts 3.2, 3.3, 4.2 and 4.3 in draft 4.
“R1 (and R2 – DP and GOP). Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions
between Functional Entities that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
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developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
Lincoln Electric System
Yes
The Severe VSL for R2 should be modified to instead state “The responsible entity did
not include Parts 2.1 to 2.2 of Requirement R2, in their documented communication
protocols”. The current VSL incorrectly references Part 2.3 of R2 which does not exist.
Response: The OPCPSDT thanks you for your comments. The SDT has corrected the error.
Tacoma Public Utilities
Yes
Hydro One
Yes
FirstEnergy
Yes
Arizona Public Service
Company
Yes
Southern Company
Yes
Southwestern Power
Administration
Yes
US Bureau of Reclamation
Yes
Central Lincoln
Yes
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City of Austin dba Austin
Energy
Yes
Occidental Energy Ventures
Corp.
Yes
Idaho Power Co.
Yes
The United Illuminating
Company
Yes
ReliabilityFirst
Yes
South Carolina Electric and
Gas
Yes
Salt River Project
Yes
CPS Energy
Yes
Public Service Company of
New Mexico
Yes
Alliant Energy
Yes
City of Tallahassee
Yes
MidAmerican Energy
Yes
Puget Sound Energy Inc.
Yes
Question 4 Comment
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Xcel Energy
Question 4 Comment
Yes
Public Service Enterprise
Group
We did not evaluate these.
Indiana Municipal Power
Agency
no comment
5.
Do you have any other comments or suggestions to improve the draft standard?
Summary Consideration:
The SDT refers the reader to the consolidated summary where the key items to Question five covered.
Organization
Yes or No
Texas Reliability Entity
Question 5 Comment
(1) Requirements R2 and R4 should also apply to Load-Serving Entities (TOP-001-2 R1,
VAR-001-3 R5), Purchasing-Selling Entities (VAR-001-3 R5), and Generator Owners
(VAR-001-3 R11, VAR-002-1.1b R5) so that all entities receiving Operating Instructions
are covered. For M3 and M4 the process should be included as well as results.
Response: The originating SAR did not include LSEs, GOs and PSEs. The SDT
discussed their inclusion and could not justify applicability for them.
(2) Capitalize “responsible entity” in VSL language for R1 and R2 as was done in R3
and R4.
Response: Thank you for pointing that out. We have corrected the error.
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(3) RELIABILITY GAP: We believe a reliability gap exists because no standard generally
requires compliance with Operating Instructions, Reliability Directives and other valid
instructions. We realize this issue may be considered to be outside of the scope of
this project, but we are quite concerned that reliability is compromised because
operating entities can elect to ignore valid instructions for economic or other
reasons, and that much more attention is being given to the form of the instructions
than to requiring that they be obeyed.
Response: The SDT believes the standard language and the definition do make it
mandatory for applicable entities to comply with Operating Instructions.
VRF/VSL JUSTIFICATION:
(4) In the VRF/VSL Justification document there is only reference to 3 requirements
in the COM-003-1 Standard (page 5). There are 4 requirements.
Response: The SDT has corrected the error. Thank you for finding it.
(5) The “Low” VRF rating for R1 and R2 seems unjustified based on the following
points:
1) In the VRF/VSL Justification document there is the following
statement at the top of page 5: “Requirements R1, R2 and R3 were
assigned a “Medium” VRF.”
Response: Thank you, that was part of the same error you indicated
previously. The SDT has corrected the error. It now reads:
“R1 and R2 are assigned a “Low” VRF, and R3 and R4 are assigned a
“Medium” VRF.”
2) In the Rationale and Technical Justification document there is the
following statement: “Because Operating Instructions affect Facilities
and Elements of the Bulk Electric System, the communication of those
Operating Instructions must be understood by all involved parties,
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especially when those communications occur between functional
entities. An EPRI study reviewed nearly 400 switching mishaps by
electric utilities and found that roughly 19% of errors (generally
classified as loss of load, breach of safety, or equipment damage) were
due to communication failures. This was nearly identical to another
study of dispatchers from 18 utilities representing nearly 2000 years of
operating experience that found that 18% of the operators’ errors were
due to communication problems.”
If there is not a process, would there not be more errors?
Response: The SDT believes there would most likely be more errors
without the process. The SDT believes that R1 and R2 should be
assigned a “Low” VRF, and R3 and R4 should be assigned a “Medium”
VRF based on NERC and FERC guidelines.
3) In the VRF/VSL Justification document there is the following
statement: “In the VSL Order, FERC listed critical areas (from the Final
Blackout Report) where violations could severely affect the reliability of
the Bulk-Power System” and “Communication protocol and facilities” is
listed. R1 and R2 attempt to address this issue.
Response: The SDT agrees that when integrated into the process, R1
and R2 attempt to address the issue. The SDT believes the low VRF is
appropriate for R1 and R2 because it calls for having Response: The
SDT has corrected the error. a document(s). R3 and R4 fit the criteria
for a medium VRF based on NERC and FERC guidelines.
(6) In the VRF and VSL Justification document, at page 15 and page 20, the FERC VRF
Guideline 3 Discussion is inconsistent with R3 and R4 language respectively (R3 and
R4 do not call for “use of formal three part communication”).
Response: The SDT has corrected the error. Thank you for bringing it our attention.
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Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ACES Power Marketing
Standards Collaborators
(1) If the Regional auditor is to make recommendations to registered entities on how
to improve the COM-003-1 internal controls, would the Regions allow an initial safe
harbor to assess the entity’s program? If Regional auditors find PVs on the initial
audit, that practice would go against the spirit of self-correcting and would stifle the
entity’s actions to monitor, assess, and correct deficiencies. The SDT should consider
this sort of initial assessment in the implementation plan.
Response: The SDT does not believe there will be a need for a safe harbor based on
how the requirements are structured. It would be unlikely the CEA would find PVs
on the initial audit if the entity is identifying, assessing and correcting deficiencies.
If the process was weak the entity would still have an opportunity to evaluate it
and improve it without a finding of non compliance.
(2) If there is discussion of combining COM-002 and COM-003 in the future, why not
combine them now? It would be a better use of the ERO’s resources to produce a
single communication standard while both SDT projects are in development instead
of going back through the entire process at some point in the future.
Response: The SDT does not disagree with your comment, but that is outside the
scope of the SAR for this project. Combining the two standards has been formally
proposed at Standards Committee meetings.
(3) A Reliability Directive appears to be a subset of the Operating Instruction
definition, which is basically an Operating Instruction that occurs during an
Emergency. We suggest collaborating with the RC SDT to clarify the bounds of each
definition to avoid overlap. As discussed above, it would be appropriate to combine
the COM-002 and COM-003 and associated definitions to avoid confusion.
Response: The OPCPSDT has coordinated with the RCSDT and has defined those
boundaries in two webinars and two postings.
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(4) There is no requirement for data retention for R1 or R2. Again, we recommend
striking these requirements.
Response: The entity must have the documented communication protocols. The
evidence is the entity’s documented communication protocols.
Thank you for the opportunity to comment.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Ameren
(1)We believe the drafting team has made some great strides to get this to be a
useful standard for industry. The idea that we have a process for self-correction
instead of self-reporting is a good concept. However, the reasons for our “No” vote is
that the current wordings in the latest draft still need some changes to provide
clarification. In this regard, we agree in principle with alternate language provided by
NextEra (which we have modified slightly) and have also provided additional
clarifying comments and recommendations.
(R1) When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as an Operating Instruction, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as
an Operating Instruction to the recipient.
(R2) Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Instruction shall repeat,
restate, rephrase or recapitulate the Operating Instruction.
(R3) Each Reliability Coordinator, Transmission Operator, and Balancing Authority
that issues an Operating Instruction shall either:
(a)Confirm that the response from the recipient of the Operating Instruction (in
accordance with Requirement (R2) was accurate, or
(b) Reissue the Operating Instruction to resolve any misunderstandings.
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Response: The SDT appreciates your recommendation but adopting it would
dramatically alter the standard making it less effective as an opportunity for
improving communication protocols.
(2)Along with the revised language proposed above, we request the drafting team to
clarify the concept of what constitutes an Operating Instruction (or command)
because the current understanding is too broad. We strongly believe that it should
focus only on instructions related directly to BES reliability and which are not
considered Reliability Directives covered under COM-002, and that it should not
include normal or routine dispatching instructions of generators.
Response: The SDT believes Operating Instructions are very specific as defined. A
command from a System Operator to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System is very explicit. It is focused on actions that dictate changes to the BES that
if misunderstood undermine the reliability of the BES. Also see our response to
your comment below. We have changed the language to achieve more specificity.
(3)Given the revised language proposed in comment (1) above, the definition of
Operating Instruction should be revised to replace the term 'System Operator' with
'Reliability Coordinator, Transmission Operator, or Balancing Authority', since these
functions are the ones who will initiate the Operating Instruction.
Response: The SDT received many comments and Quality Review
recommendations to include the defined term System Operator. The SDT changed
the proposed wording as follows:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not
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considered Operating Instructions.
The italicized portion highlights the proposed changes which the SDT believes will
address Ameren’s comments.
(4)"Transmission interface Element" and "Transmission interface Facility" both are
not in the NERC glossary as defined terms and they need to be added to the NERC
glossary or clearly defined in the standard.
Response: The SDT believes all of those terms, except for “interface,” are in the
NERC glossary. The term “interface” describes the population of Transmission
system Elements and Facilities that are immediately adjoining between neighboring
functional entities and that both entities must refer to when issuing or receiving
“Operating Instructions.” The SDT believes the dictionary definition for “interface”
is clear and unambiguous.
(5)We suggest a 24 month Implementation Plan upon approval of COM-003. This
would allow Registered Entities time to develop their compliance processes.
Response: The SDT has already extended it to 12 months. 24 months is too long.
(6)We request that the drafting team consider the possibility of substituting the CIP
v.5 'zero defects' language in COM-003 in order to minimize potential confusion.
Response: The SDT did evaluate that and has made that change in order to create
consistent language among standards.
(7)We request that any of the "violations" shown in the VSL table on pages 7, 8, and 9
should not qualify for a high or severe level and at the most these should either be
categorized as low or, but no more than, moderate level.
Response: The SDT considered your recommendation but believes the binary
nature of some of the requirements’ parts warrants a severe VSL. There would have
to be a very high disregard by an entity to improve their process to achieve the
“Severe” VSL.
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(8)In the VSL table for R2, in the column under Severe VSL, it states that "The
responsible entity did not include Parts 2.1 to 2.3 (3) of Requirement R2..."
Requirement R2 does not have a Part 2.3, only 2.1 and 2.2.
Response: Thank you for pointing this out. The SDT has corrected the error.
(9)If the drafting team retains the current language we are concerned about the
prescriptive language in R1 and R2. We request that the drafting team in both R1 and
R2 have the word “incorporate” changed to “consider” or “address”, thereby making
the requirements less prescriptive.
Response: The SDT considered your recommendation, but used the word include”
to make it less prescriptive, and to also maintain uniformity. The SDT believes
consistency to be a key element of effective communications
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Central Lincoln
1) We note that per the proposed definition of Operating Instruction, only commands
regarding the states of BES Elements or Facilities are covered. We also note that per
the Statement of Compliance Registry Criteria, Distribution Providers need not own
or operate BES Elements or Facilities in order to be registered as DPs. This puts DPs
without these facilities in the position of documenting protocols for and processes for
finding deficiencies for communications that don’t occur.
We note the SDT stated in the last Consideration of Comments “DPs that operate BES
Facilities or BES Elements and receive Operating Instructions are subject to the need
for clear communication to avoid misunderstandings that could impact the BES”, and
we agree.
We suggest: “4.1.2 Distribution Provider that operates Bulk Electric System Facilities
or Elements and receives Operating Instructions”
Response: The SDT considered your suggested language and has elected not to
incorporate it. The SDT believes that DPs who shed load would also be subject to
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the standard’s Requirements R2 and R4. Those DPs that do not own or operate BES
facilities; do not shed load or would not receive an Operating Instruction would not
be subject to COM-003-1.
2) The references to Part 3.1 in Sub-requirement 3.4 and Part 4.1 in Sub-requirement
4.4 make no sense, since the standard has no such sections. We assume the SDT
meant Sub-requirements 3.1 and 4.1 respectively, and suggest that “Part” be
replaced by “Sub-requirement.”
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
3) We agree with the SDT’s attempt to move away from zero defect compliance, and
Requirements 1 and 2 and the RSAW all support this. We’re afraid the CEA may still
be able to find non-compliance for a single defect based on the language of R3 or R4.
For example a CEA finds a single OI that referred to a 12 hour clock time in violation
of the entity’s protocol developed under R1.2. This is not a violation, but the CEA
goes on to discover that the entity failed to identify the deficiency under R3.1. While
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the entity can show they have a process that has in fact identified and corrected
deficiencies, the CEA maintains they failed to implement the process for this one
instance and finds a violation. When the entity points to the RSAW that states the
CEA should make recommendation rather than finding a violation, the CEA states
they audit to the language of the standard requirement as stated in Footnote 1 of the
very same RSAW.
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
American Electric Power
AEP does not agree with the perceived necessity of this standard, but does support
the overall concept of the drafting team’s building controls into the standards as well
as proposing RSAWs during the comment that perpetuate the ideas and concepts of
the drafting team.
Response: The OPCPSDT thanks you for your comments. The SDT believes COM-003-1 is an important element to improve BES
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reliability.
Northeast Utilities
Applicability Section: Functional Entities Section may not be broad enough to capture
all entities participating in communication for example a TO may have a switchman
receiving Operating Instructions from a TOP; the way the standard is written the TO
would not be required to participate in 3-part communication making it difficult for
the TOP to fully implement its Communication Protocols.
Response: There is much flexibility in how entities may construct their documented
communication protocols to account for arrangements with their own internal
operations as well other entities they must work with to communicate BES
operations. There is nothing to stop an entity from making the document
communication protocols effective internally.
M3 & M4 impose more requirements on the registered entity than are required in R3
& R4 respectively. For example R3 requires the implementation of a process, the
measure looks for the results of the process, and the measure should be measuring
the implementation not the result of the process.
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
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protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
M3 and M4 have been eliminated.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ERCOT
As discussed above, the proposed standard is not consistent with the reliability
issue/concern raised in the blackout report, and, therefore, in Order 693, given that
the 693 discussion was relative to the concern raised in the blackout report. The
mandates in the proposed standard do not provide reliability value. COM-002 and
other standards that address situations that pose actual reliability risks already
requires appropriate entities to communicate with each other during emergencies,
which is the real focus of the blackout report and Order 693. In those circumstances
3-part communications are required in a clear, concise and definitive manner. This
effectively ensures that the recipient understands the communication, which
practically obviates the need for specific, mandatory terminology, practices and
protocols. Accordingly, for these reasons and the reasons discussed above, the need
for COM-003 is suspect. In fact, it is arguable that it provides marginal to nil reliability
value, but yet presents potential liability exposure to the relevant functional entities.
The SDT should consider another approach to addressing the concerns in the
blackout report and Order 693. Specifically, any responsive effort should focus on
ensuring communications occur relative to specific system conditions that truly
reflect reliability concerns, and any such communications should be appropriately
distributed to ensure dissemination is only to appropriate entities that may be
impacted and/or can assist in remedying the situation. In the alternative, the
proposed standard should be revised consistent with these comments, and in
accordance with the principle that a reliability standard should establish the what,
not the how.
Response: The SDT has addressed this comment in the last two postings. These
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documents and the originating agencies that developed them actually sanction the
development of COM-003-1. Additionally the ERO’s governing bodies (the Board of
Trustees and the Standards Committee) have directed the OPCPSDT to proceed
with COM-003-1. The SDT does not have the authority or the inclination to rescind
the standard.
In addition, the ERCOT offers the following specific comments. As noted above, as
drafted the term Operating Instruction is overly broad relative to the scope intended
by FERC and the Blackout Report, and, in fact, could include purely market related
discussions that have no reliability impact. Yet, the proposed standard requires 3part communication for all such interactions. There is no reliability value to 3-part
communications for such interactions. Accordingly, this requirement should be
removed.
Response: The SDT believes the definition is not broad and that the Applicability
section precludes market related discussions as the definition describes a command
from a System Operator.
The proposed standard also requires entities issuing an all-call, or similar multiple
party communication, to receive confirmation, electronic or verbal, from at least one
of the recipients that the message was received. The nature of all calls provides a
structural means to distribute messages to a host of recipients. The mediums used
for this purpose ensure that the messages are delivered. There is no need to require
confirmation as proposed in the standard. Furthermore, there is little reliability
benefit. Accordingly, for these types of communications confirmation should not be
required.
Response: All call messages feature diverse media and technology. The entity has
the flexibility to develop and account for those differences with system
functionality within its documented communication protocols described in COM003-1, draft 3.
Finally, 1.9 requires recipients of multi-party communications to ask for clarification if
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they do not understand the message. It is difficult to understand how compliance
with this requirement will be reviewed, and what value it will have. For example, if
an entity never asks for clarification but an audit determines the entity failed to
follow a directive, the CEA staff may question whether the entity complied with the
obligation to request clarification, but the entity may believe that clarification was
not necessary and failure to follow the instruction was due to some other reason. As
with other aspects of the proposed standard, this lends itself to subjective
disagreements in practice. Furthermore, it is unnecessary, because an entity that
does not understand a directive will ask for clarification.
Response: The SDT believes that whether the receiving entity did or did not request
clarification the CEA at worst case would cite it as a deficiency found external to the
process. If the entity identified, assessed and corrected the deficiency there would
generally not be a finding of non compliance.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
The Empire District Electric
Company
As stated drop requirements R3 and R4 as they seem redundant with the overall
NERC program of reporting and mitigation plan approval.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
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RSAW has been updated to reflect this change.
CenterPoint Energy Houston
Electric, LLC.
CenterPoint Energy appreciates the revisions made to the current draft of COM-003
based on stakeholder feedback; however, the company maintains a negative vote
based on the following:
Requirements 1.1 through 1.5 are overly prescriptive. We recommend deletion of
stated sub requirements as an effort to move away from detailed micro
requirements.
Additionally, CenterPoint Energy recommends deletion of R3 and R4. The “internal
controls” concept can be incorporated into the remaining requirements.
CenterPoint Energy would vote affirmative if the SDT revised the proposed standard
as indicated below:
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement, in a manner that identifies, assesses, and corrects deficiencies,
documented communication protocols for Operating Instructions that incorporate
the following:
1.1 When issuing an oral two party, person-to-person Operating Instruction, require
the issuer to:
o Confirm that the response from the recipient of the Operating Instruction was
accurate, or
o Reissue the Operating Instruction to resolve a misunderstanding
1.2. When receiving an oral two party, person-to-person Operating Instruction,
require the recipient to repeat, restate, rephrase, or recapitulate the Operating
Instruction.
1.3. When issuing an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
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period (e.g. an all call system), verbally or electronically confirm receipt from one or
more receiving parties.
1.4. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
R2. Each Distribution Provider and Generator Operator shall implement, in a manner
that identifies, assesses, and corrects deficiencies, documented communication
protocols for Operating Instructions that incorporate the following.[Violation Risk
Factor: Low] [Time Horizon: Long-term Planning]
2.1 When receiving an oral two party, person-to-person Operating Instruction,
require the recipient to repeat, restate, rephrase, or recapitulate the Operating
Instruction.
2.2 When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
Response: The OPCPSDT thanks you for your comments. The SDT believes the language changes to draft 4 will address some of
your recommendations.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
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RSAW has been updated to reflect this change.
FirstEnergy
 To have clear communication protocols NERC must develop clear and concise
standards that include non-prescriptive language that provides entities with the
latitude to operate their systems as they are accustomed to while requiring a
heightened awareness of the importance of clear communications while operating
those systems. From discussions in various industry forums, there seems to be much
confusion as to the intent of COM-003 versus COM-002. For instance, is a Reliability
Directive as defined by the Project 2006-06 team in COM-002-3 a subset of an
Operating Instruction as defined in COM-003-1? If so, then we recommend the
retirement of COM-002-3 as a standard since COM-003-1 covers all communications.
One standard that requires 3-part communication is sufficient and no reliability gap
would exist if COM-002-3 is retired. FE and the industry want to contribute to
effective reliability and believe tight standardized communication protocols are
critical. But if confusion and needlessly burdensome requirements result from the
development of these COM standards, we believe this could have an adverse affect
on reliability. In COM-002-3, requiring an operator to pause to determine if he or she
should utter the phrase “this is a Reliability Directive” can escalate an emergency
situation and not help alleviate it. Regardless of the situation, when the Operator
issues a command it must be carried out by the receiver with confirmation that the
receiver has understood what needs to be done and when it needs to be done. COM003-1, with some wording adjustments, accomplishes this reliability goal. We support
COM-003-1 Draft 3, on its own without COM-002-3, along with some adjustment to
requirement language to relieve prescriptiveness and needless language while adding
some clearer guidance on the internal control requirements detailed in R3 and R4.
Response: The SDT does not disagree with your comments, but it is beyond the
scope of the SAR for this project.
 The measures as proposed simply reiterate the requirement and provide no
useful information. We suggest they either be removed or be elaborated to include
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useful examples of evidence and possibly incorporate some of the information found
in the RSAW.
Response: The SDT believes the Measures are suitable for each requirement and
adequately support the requirements. Requirement R1 and R2 call for the entity’s
documented communication protocols.
The SDT believes the language changes to draft 4 will address some of your
concerns.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change. M3 and M4 are eliminated.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Indiana Municipal Power
Agency
IMPA believes the best quality of evidence for proving compliance to most of the subrequirements under R1 and for requirement 2.1 will be voice recordings. IMPA
agrees with keeping this evidence for 90 days, but to keep these voice recordings for
potential 6 years (back to our last audit date) will be very costly when it comes to
storage. We understand that other evidence can be used to show compliance back
to our last audit date, but what other quality evidence besides voice recordings will
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be acceptable to prove compliance to these requirements? IMPA recommends
making the data retention of this standard just 90 days regardless of the last audit
date. Performance should be focused on the short past time of 90 days and not what
the entity did five or six years ago, which is irrelevant when one is forward looking or
wanting to improve.
Response: The OPCPSDT thanks you for your comments. The SDT set the standard retention period for the most recent 90 days.
The entity would always have its documented communication protocols required for M1 and M2. Training records, performance
evaluations, disciplinary records, employee counseling records that address deficiencies and corrections would also provide
evidence that would substantiate corrections.
Dominion
Implementation plan - page 1; Revisions or Retirements to Approved Standard Proposed Replacement Requirement(s), states; “COM-003-1 Requirement R1 Part
1.1.1 R1. Each Balancing Authority, Distribution Provider, Generator Operator,
Reliability Coordinator, and Transmission Operator shall have documented
communications protocols that incorporate the following:”Distribution Provider and
Generator Operator needs to be removed, also after communications protocols, ‘for
Operating Instructions’ needs to be added (to match the R1 Requirement, if accepted
as written).
Response: Thank you for pointing out the errors. The SDT has corrected them.
Mapping document, Page 1; Comments, states: “R1 Each Balancing Authority,
Distribution Provider, Generator Operator, Reliability Coordinator, Transmission
Operator, and Transmission Owner shall have documented communications
protocols that incorporate the following: [Violation Risk Factor: Low] [Time Horizon:
Long-term Planning ]” Distribution Provider and Generator Operator needs to be
removed. Also after communications protocols, ‘for Operating Instructions’ needs to
be added (to match the R1 Requirement, if accepted as written).
Response: Thank you for pointing out the errors. The SDT has corrected them.
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Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Associated Electric
Cooperative Inc - JRO00088
In general, AECI believes that NERC and FERC should completely reevaluate the
necessity of COM-003-1. COM-003 still appears to overreach the cited 2003 blackout
recommendation #26, whereas industry-approved changes to COM-002 do meet the
expectation, pertaining to verbal communication protocols: “Tighten communications
protocols, especially for communications during alerts and emergencies..."
Response: The SDT has previously addressed this same comment in previous
postings. The SDT disagrees with the comments and believes COM-003-1 will
properly tighten communication protocols.
However AECI also offers the following observations:
1) Recommendation #26 is hardly top of the list. (Lessons-learned is that future
industry recommendations really must be careful in what they recommend for
improvements, because those can and will be extrapolated into future requirements.)
Response: The SDT respectfully disagrees.
2) Recommendation #26 "especially" highlights alerts and emergencies, not normal
operational communications, yet the scope of COM-003 pertains to any normal
communication that would alter the state of anything BES, including mundane
operational conditions that have questionable effect upon the BES reliability.
Response: The SDT believes there is nothing mundane about actions to reconfigure
the BES. Miscommunication during normal BES operations can create an
unintended risk to reliability.
3) In AECI's opinion, there is greater risk of non-compliance with this standard for the
industry, than non-compliance with the NERC BOT in their insistence to move it
forward. The EEI suggested wording, recited below, helps to mitigate this risk, but
still at cost of additional and often unnecessary communication overhead. Specific to
the wording of COM-003-1 draft, AECI does believe the direction of EEI's wording,
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submitted in comment response to this draft, could help the industry with mitigating
some risk of non-compliance to the proposed standard. In lieu of our being able to
view EEI's posted comments, we recite them below::
========Begin the EEI draft as circulated in emails earlier this week=========
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as an Operating Communication, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as
an Operating Communication to the recipient.
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Communication shall
repeat, restate, rephrase or recapitulate the Operating Communication.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues an Operating Communication shall either:
o
Confirm that the response from the recipient of the Operating Communication
(in accordance with Requirement R2) was accurate, or
o
Reissue the Operating Communication to resolve any misunderstandings.
R4 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R1 or R3 and its sub requirements shall
be found, provided that the Balancing Authority, Reliability Coordinator, and
Transmission Operator has implemented a process for identifying deficiencies with
adherence to the documented communication protocols specified in Requirement R1
and R3 that:
4.1. Identifies potential deficiencies,
4.2. Assesses the deficiencies found,
4.3. Corrects the deficiencies, and
4.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
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∙
implements modifications to the process when the evaluation determines
that modification of the process is necessary to address the deficiencies found; or
∙
demonstrates that no modification to the process is necessary to address
the deficiencies.
R5 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R2 and its subrequirements shall be
found, no violation of R2 and its subrequirements shall be found, provided that the
Distribution Provider and Generator Operator shall implement a process for
identifying deficiencies with adherence to the documented communication protocols
specified in Requirement R2 that:
5.1. Identifies potential deficiencies,
5.2 Assesses the deficiencies found,
5.3. Corrects the deficiencies, and
5.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
r∙
implements modifications to the process when the evaluation determines
that modification of the process is necessary to address the deficiencies found; or
∙
demonstrates that no modification to the process is necessary to address
the deficiencies.
========End the EEI draft as circulated in emails earlier this week=========
Response: The SDT believes many elements of the EEI draft mirror COM-003-1,
draft3. Draft 3 has more parts that not only deal with three part communication but
also deal with communication protocols that provide additional clarity and
uniformity.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
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APPA, LPPC and TAPS
Question 5 Comment
In response to comments received during the last comment period and in an effort to
draft a standard that focuses on risk control rather than zero tolerance metrics, the
drafting team has taken a new approach to COM-003-1. This version requires
responsible entities to establish communication protocols and then implement a
process for identifying, assessing, and correcting deficiencies with adherence to those
communication protocols. This new standard is drafted such that the entity is to
ensure that its process is working, rather than requiring the demonstration of
absolute compliance with communication protocols at all times and identifying each
deficiency as a possible violation. In addition, this version of the standard was drafted
in conjunction with the development of the Reliability Standard Audit Worksheet
(RSAW). The parallel development of the standard and the RSAW provided the
opportunity for the drafting team to consider the compliance implications of the
language in the standard and to offer input into the language of the RSAW. APPA
staff, LPPC and TAPS have reviewed the proposed standard and have not identified
any material concerns and support the drafting team's new approach. We of course
urge the drafting team to give full consideration to all substantive comments on the
proposed standard and RSAW. We do anticipate that commenters will identify
editorial changes that will clarify the proposed standard. Such changes are unlikely to
affect our support for the standard.
Response: The OPCPSDT thanks you for your comments. The comments accurately frame the intent of the standard changes.
PPL Corporation NERC
Registered Affiliates
It appears the SDT may be basing the perceived need for communication protocols
during normal operations on a misunderstanding of the findings in an EPRI report.
The SDT responded to multiple comments questioning the need for communication
requirements during normal operations by quoting a paper (Bilke, T., Cause and
prevention of human error in electric utility operations, Colorado State University,
1998) that cited an EPRI study. The SDT stated, “[w]e believe the more relevant and
significant conclusion to be that, of 400 switching mishaps, 19% were caused [by]
communication failures.”It is concerning that the SDT may be basing their conclusions
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on erroneous data. The EPRI report in fact indicates only 14.5% were “cited” as
“faulty communication”, not necessarily “due to” or “caused” as the SDT response
would indicate. Nearly half of those 58 (14.5%) of the 399 incidents reviewed
resulted from most commonly not communicating “critical information”, i.e. failing to
“call in” or communicate in the first place. The EPRI report reads as follows: “Faulty
communications were cited [emphasis on “cited”] in 58 (14.5%) of the 399 incidents
reviewed. The most common kind of communication error was failure to
communicate critical information, which occurred in 22 (39%) of the 58 cases.
Examples are: failure to conduct a thorough pre-job briefing, failure to call in before
operating a switch, failure to communicate about equipment problems, or failure to
question some unusual aspect of an order. “Mandating “how” communications occur
will not address the failure of “what” critical information needs to be communicated.
Furthermore, it is concerning that the SDT “believes that the potential for risk”
necessitates requirements applicable to all operating communications as stated in
their response to comments during draft 2. It is impossible to eliminate the potential
for risk in all circumstances. What is important is that the SDT assess risk to the BES
as a result of certain actions or inactions and that the Reliability Standard reduce that
risk in an efficient and cost effective manner.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT cited those figures from a commenter who appended an
Industry white paper (by the same author) to the draft comment form. The SDT responded after reading it. Even if the mishap rate
for communication issues is 14.5% that is a significant impact on BES reliability that will be addressed by COM-003-1.
The United Illuminating
Company
It is not clear whether the protocols in COM-003 apply to Reliability Directives in
Com-002. It can be reasoned that a Reliability Directive is a form of Operating
Instruction. A double jeopardy situation is created.
Response: the SDT included exclusionary language in draft 2 of COM-003-1 to
separate the two terms. The SDT presented a Webinar that focused on the
applicability and the relationship between the two terms and standards. The
moment an RC declares a “Reliability Directive” the requirements of COM-002-3 are
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applicable. The functional entity would at that time be subject to a zero tolerance
set of requirements to be compliant with the protocols of COM-002-3. When the
Emergency or ARI ceases COM-003-1 is applicable.
Also the COM-003 R3 and R4 requirements would be inappropriately applied to
Reliability Directives. UI believes there is a difference between Reliability Directives
and Operating Instructions and the difference should be maintained.
A Directive occurs during an Emergency and has a higher risk than an Operating
Instruction. Directives should be limited in occurrences and therefore is not
conducive to sampling or error correction as opposed to Operating Instructions which
occur multiple times in a day and are numerous.
Response: If R3 and R4 are applied to “Reliability Directives” because the entity
created a documented communication protocol to manage the relationship
between the two standards and specified circumstances when each would be used,
consistent with the two standards, that would be acceptable.
Is your use of the capitalized word “Directive” to be understood as “Reliability
Directive?” There is no glossary term “Directive” nor is it referenced in a standard.
It would also be acceptable to include Operating Instructions that happened to be a
Reliability Directive in sampling for R3 and R4. For example, if an RC omitted three
part communication as specified in COM-002-3 during a Reliability Directive with
another functional entity they would likely be found to be non compliant under
COM-002-3. There would be no double jeopardy with COM-003-1 because the same
incident would be a deficiency that would be addressed (identify, assess, correct)
by the process in R3.
The data retention requirement of 90 days is reasonable. But UI is concerned with
the approach to monitoring requiring an inventory of every conversation that
occurred in that 90 day period to identify it as an Operating Instruction.
Response: The entity can select its own sample size to identify deficiencies related
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to Operating Instructions.
Finally UI suuports EEI's comment.
Response: The SDT believes many elements of the EEI draft mirror COM-003-1,
draft3. Draft 3 has more parts that not only deal with three part communication but
also deal with communication protocols that provide additional clarity and
uniformity.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Lincoln Electric System
LES believes additional clarification is needed to more clearly delineate who is
considered to be the Generator Operator (the power plant operator vs. system
operator) responsible for compliance with COM-003-1. As currently drafted, the
Generator Operator, as the recipient of Operating Instruction, must have and utilize
documented communication protocols per R2. In the event generation re-dispatch
were to be requested, is it the power plant operator performing the task or the
system operator requesting the execution of the task responsible for using the
documented communication protocols?
Response: The OPCPSDT thanks you for your comments. The definition specifies a System Operator. R1 and R2 have added
language to specify Operating Instructions between functional entities. The entity may reflect what communication protocols
would be applicable internally.
MidAmerican Energy
MidAmerican would recommend the following changes to R3 as a primary
consideration to allow COM-003-1 to move forward. COM-003 is only acceptable as a
non-zero defect standard.
R3 should be rewritten as follows:
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement R1 in a manner that identifies, assesses, and corrects deficiencies if any.
Where the entity is identifying, assessing, and correcting deficiencies, the entity is
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satisfactorily performing the requirement.
Make similar changes to R4.
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
R3 as posted requires implementing a deficiency process, which puts the focus of R3
on a deficiency process and not on implementing R1. The proposed language
changes focus the requirement to implement R1 and does not require a specific
process for deficiencies. This is consistent with CIP standards Version 5 draft 3 and
Generally Accepted Government Auditing standard strategies (the yellow book or
GAGAS). The proposed second sentence provides clarity on satisfactory performance
expectations in the requirement.
Response: The process is similar, but the need to have protocols developed by the
entity necessitates the difference in language with CIP v.5.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
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Question 5 Comment
Modify R1 accordingly...
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
have and follow documented communication protocols for Operating Instructions
that incorporate the following:
R3 & R4 Delete R3 and R4 and M3 and M4 and associated VRFs and VSLs.
Although R1 and R2 provide for better communications, R3 & R4...
o Have little or no impact to the protection or reliable operation of the BES in the
event that no responsible entity performed the requirement
o Have little, if any, value as a reliability requirement Are requirements for
monitoring and enforcing Reliability Standards and do not provide for Reliable
Operation...
o Including without limiting the foregoing, requirements for the operation of existing
Facilities
o Including cyber security protection, and
o Including the design of planned additions or modifications to such Facilities to the
extent necessary for Reliable Operation
M1 should read...
o M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator,
shall provide its documented communications protocols developed for Requirement
R1 and results of their internal compliance program’s processes which assure that
deficiencies with adherence to the documented communication protocols are
identified, assessed, and corrected.
M2 should read
o M2. Each Distribution Provider and Generator Operator shall provide its
documented communications protocols developed for Requirement R2 and results of
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their internal compliance program’s processes which assure that deficiencies with
adherence to the documented communication protocols are identified, assessed, and
corrected.
In addition, we recommend revision to the RSAW to be reflective of the removal of
both R3 and R4.
Response: The SDT believes the language changes to draft 4 will address your
concern.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
NextEra Energy Inc.
NextEra proposes the following as an alternative approach that more closely mirrors
COM-0002-3 and includes the internal controls language in R4 and R5.
R1. When a Reliability Coordinator, Transmission Operator or Balancing Authority
requires actions to be executed as an Operating Communication, the Reliability
Coordinator, Transmission Operator or Balancing Authority shall identify the action as
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an Operating Instruction to the recipient.
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and
Distribution Provider that is the recipient of an Operating Instruction shall repeat,
restate, rephrase or recapitulate the Operating Instruction.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issues an Operating Instruction shall either:
o
Confirm that the response from the recipient of the Operating Instruction (in
accordance with Requirement R2) was accurate, or
o
Reissue the Operating Instruction to resolve any misunderstandings.
R4 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R1 or R3 and its subrequirements shall
be found, provided that the Balancing Authority, Reliability Coordinator, and
Transmission Operator has implemented a process for identifying deficiencies with
adherence to the documented communication protocols specified in Requirement R1
and R3 that:
4.1. Identifies potential deficiencies,
4.2. Assesses the deficiencies found,
4.3. Corrects the deficiencies, and
4.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
o
implements modifications to the process when the evaluation determines that
modification of the process is necessary to address the deficiencies found; or
o
demonstrates that no modification to the process is necessary to address the
deficiencies.
R5 Absent a possible violation that resulted in (or could have resulted in) a significant
risk to the Bulk Electric System, no violation of R2 and its subrequirements shall be
found, no violation of R2 and its subrequirements shall be found, provided that the
Distribution Provider and Generator Operator shall implement a process for identifying
deficiencies with adherence to the documented communication protocols specified in
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Requirement R2 that:
5.1. Identifies potential deficiencies,
5.2. Assesses the deficiencies found,
5.3. Corrects the deficiencies, and
5.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
o
implements modifications to the process when the evaluation determines that
modification of the process is necessary to address the deficiencies found; or
o
demonstrates that no modification to the process is necessary to address the
deficiencies.
Response: The OPCPSDT thanks you for your comments. The SDT believes this is similar to a draft of language proposed by EEI.
The SDT believes the language changes to draft 4 will address some of your concerns.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating Instructions between Functional Entities
that include the following:”
This change was made to use standard language and methodology for control based standards. It is the same language as
developed in the CIP v.5 standards. The SDT received many comments from industry requesting the CIP format for consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard to deficiencies and the quality of an entity’s
implementation of the communication protocols in a manner that identifies, assesses and corrects deficiencies. The COM-003-1
RSAW has been updated to reflect this change.
ITC Holdings
Nowhere in the Blackout Report, Order 693, nor the SAR does it indicate that
communication protocols used during normal and emergency operations need to be
identical - only that there are standardized communications for normal operations
and standardized protocols for emergency communications.
Response: The SDT believes all of those documents do support the SDT’s
requirements in COM-003-1 for both normal and emergency operations.
The term Operating Instruction as included in the requirements of the draft standard
does not take into consideration that communications during alert or emergency
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conditions have a heightened need to be effective (Blackout Report Recommendation
26). A much better approach is to rely on operating personnel to determine when an
Alert or Emergency condition exists to change from standardized communication
used for normal operation to a different standard protocol for emergency operation.
Operating personnel have substantial training requirements, including explicit
requirements for training on emergency operations, which provide the basis for
allowing operating personnel to make this determination. A standard phrase to
identify that protocols for Alert or Emergency conditions are to be used (such as "I
am issuing a Reliability Directive") would trigger the need to switch from protocols for
normal operation to protocols for emergency conditions. This approach also
addresses concerns that complacency will set in if identical protocols are used for
normal and emergency communications. Active listening is much more likely when
using a protocol that is used only for emergency conditions which occur much less
frequently than normal operations.
Response: The SDT believes that the same communication protocols used during
normal operations enable a focused transition to communications in an emergency.
The comments on page 161 of the 2003 Blackout Report support this.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Pepco Holdings Inc
Operating Instructions are issued in real time and are expected to be implemented
promptly. Including the “time zone” in oral communications is not necessary. COM003 and COM-002 need to fully coordinate.
Response: The OPCPSDT thanks you for your comments. The SDT contends that the time zone reference must be used when an
actual clock time (e.g. 2255 or 0800) is referenced when the communicating functional entities are issuing or receiving Operating
Instructions across two different time zones.
Public Service Enterprise
Group
PSEG fully supports the use of 3-part communications. In our previous comments, we
stated “This standard (COM-003-1) should be combined with COM-002-3 and issued
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as one standard to require ONE 3-part communications protocol for both Reliability
Directives and non-Reliability Directives.” We reiterate that request and believe that
the SDTs should be combined into a single SDT and develop one standard. COM-0023 addresses Reliability Directive communications, while COM-003-1 addresses
Operating Instructions communications. The same Registered Entities are subject to
both standards. Both require 3-part communications (a “protocol”), but COM-003-1
has more extensive requirements.
Having two standards is harmful for these reasons:
o The lack of a common protocol would result in communications confusion among
these entities for this reason: some Operating Instructions are Reliability Directives,
but not all Reliability Directives are Operating Instructions.
o Finally, without a common communications protocol, entities would need to be
concerned about what protocol they are using for compliance purposes; this would
hinder the efficiency of communications and therefore reliability.
The single SDT should be charged with the following tasks:
1. Both draft standards have pluses and minuses listed below, and the SDT shall
consider these and take the best from each to develop a single standard with a
common protocol.
a. Both standards require 3-part communications (a “protocol”), but COM-003-1 has
more extensive requirements, such as the use of alpha-numeric clarifiers and a 24hour clock format. [PSEG prefers the COM-002-1 simplified protocol.]
b. Reliability Directive communications need to be identified as such by the sender as
part of its protocol; Operating Instructions do not contain a similar requirement.
[PSEG prefers that both Reliability Directives and Operating Instructions be identified
by the sender.]
c. The protocol for Operating Instructions explicitly addresses both written and oral
communications; the protocol for Reliability Directives is not specific. [If identified as
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such by the sender, PSEG does not object to written and oral communications being
addressed in a single standard; however, only oral communications should require
the use of 3-part communications.]
d. The protocol for Operating Instructions exempts “one-way burst messaging” from
a requirement for 3-part communications with one practical exception - the receivers
must request clarification from the sender if the communication in not understood;
the protocol for Reliability Directives does not address explicitly exempt such
communications, implying that 3-part communications is required for them. [PSEG
prefers the “one-way burst” language in COM-003-1 for both Reliability Directives
and Operating Instructions.]
e. The Operating Instructions protocol must be separately documented by each
entity; no such documentation is required for Reliability Directives. If documentation
is required in a posted standard developed by the SDT, the SDT shall explain the
reliability benefits of documentation and why the protocols in the standard, which
are themselves communications performance requirements, are insufficient as
“documentation.” [PSEG prefers no documentation of protocols since they are
performance requirements in the standard.]
Response: The SDT does not disagree with PSEG that the standards should be
combined. The SDT has collaborated and cooperated with the RCSDT. The OPCPSDT
believes that both standards can coexist and be mutually supportive.
2. COM-003-1 requires a process for identifying and correcting deficiencies.” COM002-3 does not. [Instead of the COM-003-1 language, PSEG prefers a requirement
that adopts the CIP version 5 language: “R#. Each applicable entity shall have a
process that identifies, assesses, and corrects deficiencies in the use of
communication protocol.”]
Response: The SDT believes the language changes to draft 4 will address some of
your concerns.
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“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
3. The SDT shall describe the potential measure or criteria for success for determining
the successful implementation of the single standard.
Response: The SDT believes it does that presently.
4. “Generator Operator” is included the Glossary definition of “System Operator,”
which in turn is used in the Operating Instruction definition. “System Operator” shall
be replaced by “Balancing Authority, Reliability Coordinator, or Transmission
Operator” in the Operating Instruction definition. Generator Operators receive
Operating Instructions but do not issue them. See also Project 2010-16: Definition of
System Operator - the goal of this project is to remove Generator Operator from the
definition of System Operator.
Response: The SDT has changed the language of the definition to read:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act to change or preserve the state, status,
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output, or input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not
considered Operating Instructions.”
The new language is italicized.
This change is consistent with your recommendation.
(The Standards Committee should consider increasing the priority of this project so
that this problem is addressed systematically in the System Operator definition.)
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Puget Sound Energy Inc.
Puget Sound Energy appreciates the opportunity to submit comments on the
proposed standard, as well as the work of the standards drafting team in developing
a workable approach to the implementation of operating communication protocols.
The purpose statement in the proposed standard uses the term "System Operators".
As defined in the NERC Glossary, System Operators include individuals who work for
Balancing Authorities, Transmission Operators, Generator Operators and Reliability
Coordinators. However, the standard also applies to Distribution Providers, an entity
not covered by the term System Operator. As a result, I recommend that the
standard drafting team expand the purpose statement to accurately reflect the
applicability of the standard. Perhaps the statement could be revised to begin "To
provide individuals who may issue or receive Operating Instructions with uniform
communications protocols...".
Response: The OPCPSDT thanks you for your comments. Some Distribution Providers do own and operate BES Facilities and Elements
and a significant number have load shedding obligations making them subject to Operating Instructions. The SDT has changed the
language of the definition to read:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of potential
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options or alternatives to resolve BES operating concerns are not commands and are not considered Operating Instructions.”
The new language is italicized.
This change is consistent with your recommendation. Note the reference to: “where action must be taken by the recipient.”
City of Austin dba Austin
Energy
Regarding Q2, Austin Energy (AE) believes that parts 1.1 through 1.5 of R1 are
unnecessary. Three-part communication, as described in parts 1.6 through 1.9, is the
preferred method for ensuring that both parties understand an Operating Instruction.
It provides a sufficient mechanism for clear, concise and accurate communication. AE
believes that creating a protocol that requires System Operators to essentially relearn
the way to speak (specifically using alpha-numeric identifiers) will only create
confusion as operators try to follow protocol and catch/correct themselves.
Additionally, the constant use of alpha-numeric identifiers in transmission switching
orders that contain many, many steps will become burdensome. AE believes that its
current use of three-part communication during these switching orders is more
effective.
Response: The SDT agrees with your use of three part communication , but also
believes other protocols that contribute to clarifying communications should be
part of a comprehensive communication standard.
Regarding Q4, the phrase “Parts 2.1 to 2.3 (3)” in the Severe VSL for R2 should be
“Parts 2.1 and 2.2”
Response: Thank you for pointing out the error. The SDT has corrected it.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
South Carolina Electric and
Gas
Regarding R1.4, drafting team should clarify whether "interface" means interfaces
between neighboring entities or between functional entities.
Response: The SDT has added “between functional entities” to R1 and R2 to
encompass Part 1.4.
Regarding R1.8, does the drafting team have an appropriate response time-frame for
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the confirmation to occur from recipients?
Response: The SDT believes that would be too prescriptive. The entities can address
that in their documented communication protocols.
Regarding R1.9 and R2.2, these requirements seem unnecessary and unauditable. An
audit team can evaluate whether the documented communications protocol contains
language to address these requirements; however, evaluating the actual execution
would be subjective. It is not possible to determine whether a recipient understood a
message clearly and whether clarification was required.
Response: The industry asked the OPCPSDT to address all calls in several postings of
previous drafts. The SDT believes it is auditable.
Further, it will be difficult for entities to identify deficiencies with this requirement, as
required by R3, for the same reasons.
Response: The SDT disagrees. Most entities to varying degrees are monitoring the
performance of operators. There are operating guidelines developed by industry
that can provide guidance and develop best practices that support reliability.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
ReliabilityFirst
ReliabiltiyFirst thanks the SDT for their work but has a question related to the
Implementation Plan. The SDT indicated in the consideration of comments report
(from the draft 2 posting) the standard’s six calendar month implementation time
frame has been extended 12 calendar months to provide an adequate amount of
time for training and implementation. As noted above, there is a conflict since the
draft standard does not require implementation of the protocols. ReliabilityFirst
believes absent any implementation requirement, the six calendar month
implementation time frame is adequate for an entity to have documented
communication protocols for Operating Instructions.
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Response: The OPCPSDT thanks you for your comments. The SDT agrees, but wanted to give the industry adequate time to
implement the entire standard. Previous commenters stated that six months was not long enough.
CPS Energy
Requirement R1.5 should be an optional step to assist in resolving any
misunderstanding found in requirement R1.6. Alpha-numeric clarifiers, Requirement
R1.5, in every three part communication of an operating instruction is an activity that
adds little if anything to promote the protection of the BES and can hinder/distract
from the reliable operation of the BES.
Response: The OPCPSDT thanks you for your comments. The SDT believes identifying and accurately communicating nomenclature
of the Facilities and Elements prevents mishaps that compromise the BES.
Manitoba Hydro
Section C. Measures: The measures are unclear as to what exactly the requirement to
‘provide’ entails? Would this be upon request or periodically? Please clarify.
Response: Normally, an entity would provide the results of its process during an
audit, but it could be part of an investigation or a spot check.
Section D. Compliance: Compliance Enforcement Authority is defined as CEA and
then the full term Compliance Enforcement Authority is continually used throughout.
The acronym or words should be used consistently.
Response: The SDT acknowledges your comments.
Section D. Compliance: There is no specification for R1 and R2 retention.
Response: An entity would have to have documented communication protocols in
force in perpetuity. Many entities have those in their existing operations procedure
manuals.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Wisconsin Electric Power Co.
The definition of Operating Instruction introduces a “Command” as opposed to COM185
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002 that defines and requires identification of a “Reliability Directive”, yet there is no
obligation to follow a Command nor to identify the communication as containing a
Command. Fatal flaw with the proposed definition.
Response: The SDT believes when a definition stipulates a command that its
context within a requirement means that a command must be obeyed.
Operating Instruction —A command by a System Operator of a Reliability Coordinator,
or of a Transmission Operator, or of a Balancing Authority, where the recipient of the
command is expected to act to change or preserve the state, status, output, or input of
an Element of the Bulk Electric System or Facility of the Bulk Electric System.
Discussions of general information and of potential options or alternatives to resolve
BES operating concerns are not commands and are not considered Operating
Instructions.
The requirement to have a protocol is likely an ok approach with an objective to
achieve well understood communications and without the laundry list of things that
must be in the document. Then given the RC-BA-TOP have stringent training
requirements in PER-005, duplicating the requirements for good training and
personnel proficiency evaluation lends itself to mandate a how to accomplish this for
a specific task. In addition, the type of oversight implied in COM-003 is overreaching
by NERC.
Response: The parts of the requirement are stipulated in order to ensure entities
have a frame to build protocols that address communications in a uniform and
consistent manner.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Public Service Company of
New Mexico
The issuance of a draft RSAW in combination with the draft standard helped clarify
the audit approach for some of the more subjective requirements such as R3 and R4
and how instances of deficiency will not be considered violations of the standard.
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PNMR, Inc. and its two utility subsidiaries operating in TRE, SPP and WECC would like
to encourage other SDTs to follow the lead of this SDT with respect to understanding
that the RSAW is a critical piece of the Standards Development process.
Response: The OPCPSDT thanks you for your comments. The SDT agrees with your comments.
Liberty Electric Power, LLC
The need for a prescriptive standard remains in doubt. The SDT has responded to
comments questioning this need with a cite of a single study. The applicability of this
study to GOPs is unclear.
Response: The SDT believes it has dramatically reduced the prescriptive nature of
draft 2. The GOP receives Operating Instructions so it is an applicable entity.
We do not know the details, and question the number of cited miscommunications
which involved GOPs. Further, we are unclear as to the number of
miscommunications which involved two entities, as opposed to an entity giving
direction to their own field operator. Such single-entity communications would not
be covered by the proposed standard. Lowering miscommunications is an admirable
goal, and again the SDT deserves commendation for their willingness to rethink the
direction of the proposed standard. However, the standard, if needed, should be
limited to requiring an entity to have communications procedures, and to reinforce
those procedures on a periodic basis. The content of those procedures should
properly be left to the best judgement of the individual entity.
Response: The SDT appreciates your encouragement and believes there is a need
for a collective set of protocols for entities to communicate on the BES which has
become and continues to become more tightly interwoven.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
MRO NSRF
The NSRF would like to thank the SDT for allowing entities to identify, assess, and
correct deficiencies per R3 and R4. The proposed COM-003-1 uses the verb of
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“issuing” in R1.1, 1.2, 1.3, 1.4, 1.5, 1.6, and 1.8, and uses the verb of “receiving” in
R1.7, 1.9, 2.1, and 2.2. Since these are real-time actions and FERC Order 693, section
532 states in part, “This will eliminate ambiguities in communications during normal,
alert, and emergency conditions”, The NSRF recommends that the proposed
definition of Operating Instruction have the words “in Real-time” at the end of the
definition. The definition of System Operator also uses the term in real time in its
definition.
Response: The SDT believes some “Operating Instructions” can be issued outside as
well as in the Real Time horizon.
The SDT has changed the language of the definition to read:
“Operating Instruction —A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not
considered Operating Instructions.”
The new language is italicized.
This change is consistent with your recommendation.
R1.3 Some entities already have an agreed upon time zone standard such as MISO.
MISO operates on Eastern Standard Time (EST) and has a business practice manual
stating that. Suggest the requirement be modified to state: “that unless the
operating entities already have an agreed upon operating time zone” then operations
occurring across time zone boundaries should include a time-zone designation.
Response: The SDT believes an entity can accommodate these type of
arrangements within its documented communication protocols.
R1.5 Naming conventions for terminal equipment can be long. For example, switch,
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P2ZDQEN. In a switching order, this switch name may be mentioned several times
and with each communication there is a required echo. The Alpha-numeric
requirement is a one-size fits all solution and is not needed in all situations.
Recommend the following as an alternative to the above language; The risk of
unclear communication is addressed by R1.6 and R1.7. R1.5 should be reworded to
require alpha-numeric clarifiers when reissuing an Operating Instruction to resolve a
misunderstanding (per R1.6).
Response: The SDT believes the use of proper clarifiers leaves no doubt as to the
content in an Operating Instruction. This would be especially true with switch Papa
– two - Zulu-Delta-Quebec-Echo-November.
R1.4 The SDT has not made the case for the reliability benefit of the requirement for
standardized names. Again, this requirement is being retired from TOP-002. “TOP002-2a Requirement R18 on the basis that “This requirement adds no reliability
benefit. Entities have existing processes that handle this issue.” This requirement
creates a compliance process where one is not needed. Each entity will be required
to document and maintain each facility name and who is the responsible owner for
the facility name. Suggest this requirement be removed. A list would be required for
“every” element of the BES between entities to assure that the proper names are
used in all Operating Instructions. The NSRF does not see the reliability benefit of
using this naming convention since TOP-002 is already enforceable.
Response: TOP-002, R18 is being eliminated by the RTOSDT. The OPCPSDT believes
that an entity’ familiarity with its neighbor’s Facilities and Elements increases
situational awareness and reduces response times.
R.1.8 and R.1.9, The NSRF feels this would create an unnecessary burden to
document routine notifications that rely on a burst messaging system and do not
have any effect on the Bulk Power System. A one-way burst messaging system is
typically used to quickly inform/advise. It is designed as one-way to provide
efficiency and should not be used for Operating Instructions. It would be much
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simpler to state that, “for the communications of Operating Instructions (regardless
of the technology employed), the message must be repeated or confirmed by the
recipient, and validated by the sender.” This approach focuses on “Operating
Instructions” and not the technology employed. The requirement as currently written
does not allow for exceptions due to routine or informative communications.
(Example: NERC Alerts to the Industry based are based on severity level and do not
always require receipt of message by the Registered Entity). R1.8 states in part, “
When issuing an oral Operating Instruction through a one-way burst messaging
system...”. The NSRF does not understand how an oral Operating Instruction can be
made through a one-way messaging system? Unless, the Operating Instruction was
captured on an answering machine or on an un-listened to voice mail message
system. The NSRF views this as an electronic source to electronic source, as
explained in the “note to auditor” within the proposed RSAW states,
“Communication that is generated by an electronic source to another electronic
source is not to be included as “oral or written Operating Instruction”. If the NSRF is
correctly assuming this, then no verbal or electronic confirmation is required. Please
clarify.
Response: Many entities use all call for “Operating Instructions”. Protocols would
not apply to casual notifications and helpful information. The fact that in some
cases it would be difficult, if not detrimental, to wait for responses from multiple
parties. Some all call systems are an automated telephone call that is “shot
gunned” to receivers. Your comments about electronic to electronic (machine to
machine) communication not being addressed in this standard are correct. COM003-1 deals with human to human communication.
R2. As stated in the Purpose statement, “To provide System Operators uniform
communications protocols that reduce the possibility of miscommunication that
could lead to action or inaction harmful to the reliability of BES.” The NSRF concurs
with this statement but questions why “all” DPs and GOPs are included in COM-0031, Applicability section? The NSRF recommends that the Applicability section have
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4.1.2 updated to read “For Distribution Providers, and Generator Operators that
operate BES Elements shall have documented communication protocols for
Operating Instructions that incorporate the following”.
Response: GOPs and DPs are receivers of Operating Instructions and are applicable
entities. If a DP or GOP do not have BES equipment or BES obligations such as load
shedding the requirement would not apply.
On page 7, under Severe VSL it states: “The responsible entity did not include Parts
2.1 to 2.3 (3) of Requirement R2, in their documented communication protocols”,
part 2.3 does not exist; please clarify if this is to mean “part 2.2”?
Response: Thank you for pointing this out. The SDT has corrected the error.
The NSRF recommends R3 to be updated to state: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall implement R1 in a manner
that identifies, assesses, and corrects deficiencies, if any. Where the entity is
identifying, assessing, and correcting deficiencies, the entity is satisfactorily
performing the requirement.
Response: The SDT recognizes the language from CIP v.5. The SDT believes the
language changes to draft 4 will address some of your concerns.
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions between
Functional Entities that include the following:”
This change was made to use standard language and methodology for control
based standards. It is the same language as developed in the CIP v.5 standards. The
SDT received many comments from industry requesting the CIP format for
consistency.
R3 and R4 are eliminated, but the CEA still follows the same guidance with regard
to deficiencies and the quality of an entity’s implementation of the communication
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protocols in a manner that identifies, assesses and corrects deficiencies. The COM003-1 RSAW has been updated to reflect this change.
Justification for R3. The above rewrite requires implementing a deficiency process,
which puts the focus of R3 on a deficiency process and not on implementing R1. The
proposed language changes says to implement R1 and does not require a specific
process for deficiencies. This is consistent with CIP standards Version 5 draft 3 and
Generally Accepted Government Auditing standard strategies (the yellow book or
GAGAS). The proposed second sentence provides clarity on satisfactory performance
expectations in the requirement. Note this proposed language should also be applied
to R4.
Response: The SDT intends that the entity needs to “have” communication
protocols as directed in R1 and R2. The process to identify, assess and correct is the
mechanism for adherence to those protocols. Also see the comment above.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
SPP Standards Review Group
The processes outlined in R3 and R4 would be sufficient in themselves but with the
requirements of PER-005 regarding identifying gaps and training to eliminate those
gaps, it would appear that R3 and R4 add unnecessary duplication. Why do we need
to have the same requirements in two different standards? Do some of the issues
that are being addressed in the Paragraph 81 project come into play here?
Response: The SDT does not believes the context of training gaps is synonymous
with deficiencies based on adherence to communication protocols. The standard
does not specify how the entity corrects the deficiency. This is where PER-005 may
come into play.
The Paragraph 81 Project is still a work in progress. The SDT believes COM-003-1
and its elements would be retained after any paragraph 81 review. The
opportunities for mistakes on the BES due to miscommunication are tremendous. A
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commenter on the COM-003-1, draft 2 posting calculated, after some assumptions
that 35 million Operating Instructions per year occur on the BES. The exposure to
risk should not be trivialized by suggesting these protocols and the process required
in COM-003-1, draft 3 are only administrative and would be grist for elimination.
Given the approval of COM-002-3 which places requirements on the DP and GOP
when receiving a Reliability Directive, there appears to be the possibility of confusion
regarding specific requirements on the DP and GOP in COM-003. During the COM-003
webinar, the comment was made that if COM-003 is approved, there may be a new
project that would attempt to more efficiently coordinate the two standards. We
would be supportive of that effort.
Response: The SDT will not disagree that there is an opportunity to combine the
two standards.
The papers referenced in the Rationale and Technical Justification document
supporting the need for this standard should be made available for review if the
drafting team is using them as support for the justification for COM-003.
Response: The reference the SDT used was contained in a industry white paper
initiated by a member of the OC and was appended in its entirety to the COM-0031, draft 2 comments which is posted on the NERC website for project 2007-02.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Florida Municipal Power
Agency
The RSAW seems to re-introduce the “zero-defect” problem by directing auditors to
sample actual recordings of communications to see if the entity identified all
deficiencies. The RSAW ought to be changed to get away from sampling actual voice
communications altogether and simply review the evidence of the entity doing its
own internal monitoring. For instance, the entity might decide to randomly sample a
few hours a month itself and identify deficiencies in those hours, that should be the
only voice recorded evidence required and not any other hours that the entity did not
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randomly sample. In addition, the evidence for correction of deficiencies is not more
voice recordings, but rather evidence of revised protocols, processes, procedures, or
evidence of disciplinary action. So, FMPA believes the RSAW needs a lot of work.
Response: The OPCPSDT thanks you for your comments. The SDT believes that there has to be a test of the entity’s process to
make sure it is functioning effectively. It makes perfectly good sense for the CEA to sample the evidence over the same period to
see if similar results are obtained. If the CEA discovers many deficiencies are not identified the standard requires the entity to
evaluate its process to improve it. Possible non compliance can only result if the entity does not implement its own identified
modifications or cannot justify why no modifications are required.
MISO
The RSAW states that the applicable entity could be found non-compliant if the entity
did not follow an auditor’s suggested changes to remedy those deficiencies. This
requirement is not found in COM-003-1 itself, and the RSAW therefore includes
requirements that are beyond the scope of the Standard it supports.
Response: Please reference 3.4 and 4.4. The entity can only be found non compliant
when the entity does not implement its own identified modifications or cannot
justify why no modifications are required. For an entity not to legitimately address
these elements it would be a violation.
The draft RSAW also introduces subjective concepts that place uncontrolled
discretion in the hands of auditors. For instance, the RSAW states that the size of the
sample of the entity’s communication activities reviewed to verify whether the entity
is identifying, assessing, communicating and correcting deficiencies “will be based on
the auditor’s confidence in the entity’s ability to identify, assess, and correct its
deficiencies.” MISO submits that sample size should be determined mathematically
and in a manner that can itself be audited. Indeed, NERC’s own Sampling
Methodology Guidelines and Criteria states that "Statistical sampling helps ensure a
high confidence level of compliance for the larger population of documents when a
smaller population is statistically sampled . . . Statistical sampling should be employed
when auditing all processes, procedures and any documentationâ€related evidence
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(documents, logs, voice recordings, etc.) when a sample is required because the
entire population cannot be audited." Allowing an auditor to determine sample size
based on an abstract concept such as confidence is contrary to NERC’s own sampling
methodology; would prevent Registered Entities from challenging such sample sizes;
and could allow auditors to make such decisions punitively.
Response: A statistical modeling approach is what the SDT contemplated in
developing these requirements. NERC compliance and auditing professionals
understand and would welcome such an approach. The SDT does not want to
dictate the process controls but believe the structure you propose is sensible and if
it was found to be effective, could be developed as a best practice by the industry.
The OC has developed operating guidelines that could serve as an incubator for
best practices.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Essential Power, LLC
The SDT received many comments questioning the need for the standard. They are
relying on a single EPRI study that claims 19% of 400 studied switching errors (76
events) resulted from miscommunication, but this statistic is meaningless without
context. Specifically:-Did any of these 76 events involve GOPs? If not, is it
appropriate to make COM-003-1 applicable to these entities at all, much less for
routine communications of minor importance? -How many events involved oral
communication, vs. written miscommunication? Of the oral miscommunications,
how many involved miscommunication between separate entities, as opposed to
internal entity miscommunication? After all, internal miscommunications, which may
be the vast majority of the events, will not be covered by the standard.
Response: The OPCPSDT thanks you for your comments. There were two studies cited by the SDT. Both studies were contained in
the OC White Paper which a commenter appended to the COM-003-1, draft 2 industry comments. The passage discussing the
studies did not go into the detail you request in your comments. The SDT believes any entity is susceptible to communication
errors and that the general percentages over the cases study are clear indicators that communication is a significant factor
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impacting reliability.
SERC OC Standards Review
Group
The SERC OC Standards Review Group does not agree that the
mandatory/prescriptive procedure for three part communications in essentially all
oral communications will improve reliability of the BES. The standard needs to be
changed to better reflect industry comments from this comment period and the
previous ballot. The comments expressed herein represent a consensus of the views
of the above named members of the SERC OC Standards Review Group only and
should not be construed as the position of SERC Reliability Corporation, its board, or
its officers.
Response: The OPCPSDT thanks you for your comments. The SDT believes communication errors reduce reliability on the BES. The
SDT has changed the standard dramatically to reflect industry comments.
ISO/RTO Standards Review
Committee
The SRC requests that the SDT include a milestone in the implementation plan that
requires NERC and the industry to reach agreement on how internal controls will be
monitored by the CEAs BEFORE this standard is effective.
Response: The SDT has integrated the RSAW review to the process. This is a
transparent outreach to industry to create a better standard.
The SRC believes that this standard could be improved by modifying the subparts of
R1 and R2 to include parts that are communication protocols directly relevant to the
improving situational awareness and shortening response time.
Response: The SDT believes most of the protocols do just that. The SDT would
appreciate any recommendations for additional or supplementary protocols from
the ISO/RTO Standards Review Committee.
Requirements R1.1, 1.2 in theory shorten response time by providing a commonly
understood language and clock format for Operating Instructions but are unnecessary
in practice.
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Response: These may be basic protocols but they are important. They should be
relatively easy to implement.
The modification includes the removal of:
o R1.3 as it does not improve situational awareness or shorten response time. This is
such a small population of Operating Instructions and any real time Operating
Instructions will be immediate. This is overly prescriptive and provides little if any
reliability benefit. This is not a documented reliability concern in any investigation,
FERC Order, Blackout report, etc. that the SRC is aware of.
Response: The SDT realizes the population may be small but the time element of an
event is critical to an Operating Instruction.
o R1.4 as it does not improve situational awareness or shorten response time. It may
actually confuse entities that have established practices that may have to make
changes to accommodate this requirement part. This is overly prescriptive and
provides little if any reliability benefit. This is not a documented reliability concern in
any investigation, FERC Order, Blackout report, etc. that the SRC is aware of.
Response: The SDT believes familiarity with a neighboring entity’s Facilities and
Elements shortens response time and improves situational awareness.
o R1.5 as it does not improve situational awareness or shorten response time. It may
actually confuse entities that have established practices that may have to make
changes to accommodate this requirement part. This is overly prescriptive and
provides little if any reliability benefit. This is not a documented reliability concern in
any investigation, FERC Order, Blackout report, etc. that the SRC is aware of.
Response: Clarifiers ensure an accurate issuance and reception of alpha-numeric
information contained in an Operating Instruction. The benefit of which is reduced
errors operating the BES.
o R1.6 and R1.7, and 2.1 as it does not improve situational awareness or shorten
response time. It actually lengthens response time and does not improve situational
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awareness as it does not address the content of the communication. This is already
addressed through COM-002-3 and will only add to confusion for entities to have a
COM-003-1 requirement in the overlap it creates. This is not a documented reliability
concern in any investigation, FERC Order, Blackout report, etc. that the SRC is aware
of where lack of 3 part communication directly contributed to a adverse reliability
impact on the BES. The NERC OC established guidelines that outline best practices
for industry and are sufficient to communicate such best practices. As the drafting
team has communicated in its previous white paper, a significant amount of industry
already employs 3 part communication during normal and emergency situations.
Response: The SDT believes three part communication is an effective and proven
tool that ensures communications are clear and unambiguous.
Requirements R1.8, 1.9, and 2.3 could shorten response time by providing a protocol
for quickly disseminating information from one to multiple parties.
The drafting team should craft the standard to address communication between
functional entities and not within entities to properly address FERC Order and
Blackout Recommendation that clearly speaks to communication protocols between
entities. To not do so is expanding upon the scope of the SAR, creates confusion, and
is not focusing on the reliability concerns cited in the FERC Order 693 and Blackout
Report Recommendation #26.
Response: The SDT has changed the language to Requirement R1 and R2 adding “to
between functional entities” which is consistent with your comment.
The draft RSAW introduces subjective concepts as well as a new requirement.
An auditor is to:
o The CEA is to ...
o Understand the process ....
o The CEA is to review a sample of the entity’s communication activities to verify
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whether the entity is identifying, assessing, communicating and correcting
deficiencies. If the entity had implemented corrections, the sample is to be pulled
from activities conducted after any corrections to the entity’s process were
implemented or, if the correction had been recently implemented, the CEA is to
consider the impact the correction will have when reviewing the samples. This
sample size will be based on the auditor’s confidence in the entity’s ability to identify,
assess, and correct its deficiencies.
o Where the auditor ... o If an auditor cannot verify that the entity is adequately
identifying [SRC: suggest changing “is” to “is not”], assessing, and correcting its own
deficiencies due to limitations in its process, the auditor will not have a finding of
non-compliance. The auditor will provide the entity with recommendations as
necessary. If the CEA finds in subsequent, follow up audits or other compliance
monitoring activities that the same or similar deficiencies continue to occur after the
entity was provided the feedback by the CEA, the CEA will seek to understand what
changes the entity made to their process based on prior recommendations.[“same or
similar deficiencies” is subjective and opens the compliance to CEA vision of what is
“similar”.]
New Requirement: If the CEA finds in subsequent, follow up audits or other
compliance monitoring activities that the same or similar deficiencies continue to
occur after the entity was provided the feedback by the CEA, the CEA will seek to
understand what changes the entity made to their process based on prior
recommendations. If changes to the entity’s process are not implemented to identify,
assess and correct deficiencies, the Auditors may make a determination of possible
non-compliance with Requirement 3, Part 3.4.
Response: The SDT does not interpret this as a new Requirement. It is guidance for
the CEA on how to professionally audit Requirement 3, Part 3.4. This RSAW was
developed in collaboration with the SDT and both parties believe the guidance
provides the auditor specific instructions that actually reduce subjectivity.
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Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Northeast Power Coordinating
Council
The white paper written by the OC addressed the issues covered by this Standard.
Response: The OPCPSDT thanks you for your comments. The SDT believes those documents, while relevant and well written do
not carry the authority of an approved standard.
Hydro One
The white paper written by the OC addressed the issues covered by this Standard.
Response: The OPCPSDT thanks you for your comments. The SDT believes those documents, while relevant and well written do
not carry the authority of an approved standard.
Hydro Quebec TransEnergie
The white paper written by the OC addressed the issues covered by this Standard.
Also the requirements 1.6, 1.7 and 2.1, 2.2 seem to be redundant with the
requirement R2 of COM-002-2. Both touch on the issue of ensuring
misunderstandings by requiring the parties to repeat, restate, rephrase or
recapitulate the information transmitted/received. If adhering to the philosophy of
Project 2013-02 Paragraph 81 of FERC, we should remove unnecessary requirements
as part of NERC,s Find, Fix and Track Process
Response: The OPCPSDT thanks you for your comments. The SDT believes those documents, while relevant and well written do
not carry the authority of an approved standard. COM-002-2a, 2R will be retired when COM-002-3 and COM003-1 are approved by
FERC. Paragraph 81 is still under development and will likely not apply to COM-003-1.
Consumers Energy
This is an attempt to make a requirement for 3 way communication for all operating
communications. Not all operating conversations avail themselves to that format.
The concept is good but allowances must be made for other situations.
Response: The OPCPSDT thanks you for your comments. The SDT has pointed out that these protocols are targeted only for
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Operating Instructions that command direct changes to the BES, not all operating communications and casual conversations.
JEA
We beleive that three-part communications should only be necessary for directives.
Also COM002 and COM003 should be merged into one standard.
Response: The OPCPSDT thanks you for your comments. The term Operating Instruction is a directive in nature. Its definition uses
the term “command” which is a strong form of a directive.
Independent Electricity
System Operator
We do not see the need for this standard. We feel that Reliability Standards should
have performance based objectives, rather than prescriptive requirements that
outline “how” to meet an objective. This draft is not consistent with this approach. If
the majority of the industry also express a similar view, we urge the SDT to bring this
to the Standards Committee’s attention, and seek its advice on way forward,
including stopping this project altogether.
Response: The OPCPSDT thanks you for your comments. The SDT stands by this draft of the standard and has not received any
disapproval from the Standards Committee. The Standards Committee has reaffirmed the present course of the standard at its
October 10, 2012 meeting.
NIPSCO
We want to see COM-002 and COM-003 combined, therefore we voted Negative. The
Internal Controls in R3 & R4 are workable.
Response: The OPCPSDT thanks you for your comments. The SDT cannot disagree with combining the two standards, but it is
outside the scope of the SAR for this project.
Exelon
We would like to point out that the OI definition includes another defined term,
“System Operator”. In the Glossary, this is defined as is an individual at a control
center, including a Generator Operator. Control center is not currently defined but
has a proposed definition in CIP version 5 that puts limits on which generator
operators (# of units) work in “control centers”. If approved as part of CIP version 5,
this definition of Control Center is likely to cause confusion when applying this and
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other standards. Will OI apply to all Generator Operators or just those working in
"Control Centers" as defined by CIP ver. 5. In spite of our concerns with the current
draft, Exelon intends to vote affirmative on this ballot for COM-003. Significant
improvements have been made but there is opportunity to make additional changes
before the final ballot.
Response: The OPCPSDT thanks you for your comments. GOPs that receive Operating instructions from other Functional Entities
would be subject to the protocols .
Southern Company
While Southern agrees that 3-part communications is a good utility practice that has
been used by operating entities for many years, Southern disagrees with the
broadness of the types of communications the SDT is suggesting for requiring 3-part
communications. In some of these cases, 3-part communications are not required to
protect the reliability of the system. In fact, this prescriptive requirement, if used on
all communications that could fall under “Operating Instructions” (which can be very
general information at times), would take System Operators time away from other
tasks that are more critical to maintaining reliability.
Response: Based on the definition of Operating Instructions the SDT cannot see any
remote reference to general information. The SDT has responded to comments in
the last 3 drafts that it applies to a command from a System Operator to change or
preserve the state, status, output, or input of an Element of the Bulk Electric
System or Facility of the Bulk Electric System. The term command is very clear and
distinct in meaning and strength. A command is not a discussion of general
information. The definition has been modified to add clarity.
Please note that there are numerous (i.e. in the millions) of conversations between
operating entities each year and some important tasks could be missed or delayed if
required to follow a standard script for everything.
Response: The SDT believes just the opposite will happen. Communications will be
more structured and focused on a professional exchange of commands to operate
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the BES reliably.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
City of Tallahassee
While TAL is voting affirmative, we still have some reservations that Compliance
Enforcement will cite specific instances of non-3-way communications as violations.
However, we are ready to codify the need for standardized communications as
defined in the purpose of the standard and Blackout recommendation #26 and thank
the drafting team for their hard work in avoiding a “zero-defect” standard.
Response: The OPCPSDT thanks you for your comments. The SDT believes that CEA is supportive of this form of standard and is
confident it will be a superior alternative to zero defects.
Xcel Energy
Xcel Energy feels this new draft of COM-003-1 is greatly improved than prior versions.
We are especially in favor of the internal controls approach the team has taken.
However, while we have identified several areas of concern with this latest draft, our
issue with R1.5 is the single item that is preventing us from voting affirmative. As
indicated in our previous comments, our issue is that we do not believe alphanumeric identifiers should be required for all oral Operating Instructions. Instead, we
feel this should be an optional tool that the operator may use where clarity in the
Operating Instruction is needed or anticipated. (For example, the operator may use
alpha-numeric clarifiers to restate the original Operating Instruction, when it was
apparent from the receiver’s repeat back that the details of the Operating Instruction
were not accurately understood.)
Response: The SDT intends for alpha numeric clarifiers only to be used only when
alpha-numeric information is contained in the “Operating Instruction.” The SDT
believes that use of these clarifiers prevent miscommunication that would
negatively impact the BES. e.g. switch 15 R vs.50 R, “15 and 50” sound alike and
could easily be miscommunicated.
Below are additional issues and modifications Xcel Energy would like to see
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addressed:
1)Since a Distribution Provider may issue Operating Instructions that would impact
the BES, we feel they should be added to the applicability under R1 and R3.
2) We recommend that the term “functional entities” be capitalized in R1.1, and a
reference added to Section A4 of the standard. This way it is clear that the term
includes all entities under the standard (Section 4) and not just the entities under R1.
Response: The SDT believes the DP is a receiver of Operating Instructions. The SDT
would appreciate if you could provide examples of issued Operating Instructions by
a DP the SDT would like to consider the proposal.
The SDT made corrections to R1.1. Thank you for bringing it to our attention.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
Arizona Public Service
Company
no
Response: The OPCPSDT thanks you for your comments.
Southwestern Power
Administration
No additional comments.
Brazos Elextric Power
Cooperative, Inc.
See ACES comments.
Response: The OPCPSDT thanks you for your comments. Please see our responses to ACES Comments.
Edison Electric Institute
EEI generally supports the proposed COM-003 structure and content. We believe that
COM-003 will provide a good response to both FERC Order No. 693 (P. 540) and
Blackout Recommendation #26 in the U.S./Canada joint Blackout Report. EEI
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commends the drafting team for its work and for laying out a pragmatic framework for
tightened communications protocols.
Since the new proposed draft marks a significant change from the previous direction,
EEI understands that some issues need to be considered. Some can be addressed by
the drafting team and others are likely beyond the scope of the team. In general,
companies seek to ensure that mandatory requirements when applied in the future
will avoid causing confusion in real-time. For example, the definition of “Operating
Instruction” in draft COM-003-1(2) may need some clarification to make sure that it
sufficiently differentiates such communications from a “Reliability Directive” issued
under COM-002-3. (3)
Response: The SDT believes the requirements of COM-002-3 define the
circumstances when a Reliability Directive becomes active. The Functional Entity
announces it when an Emergency or Adverse Reliability Impact is occurring or has
occurred. COM-003-1 is focused on having an entity having a process that it uses to
ensure it adheres to its own documented communication protocols by identifying,
assessing and correcting deficiencies.
Clarification may be needed to synchronize the COM-003 process requirements with
protocols in already-approved COM-002-3(4). We view these as relatively minor
changes that would not require substantial changes to the draft COM-003 language.
Response: The OPCPSDT has adopted the same language for three part
communication as written in COM-002-3, R2 and R3 to be consistent and to avoid
2
Proposed COM-003-1: http://www.nerc.com/docs/standards/sar/COM-003-1__20120821_Clean.pdf
“Operating Instruction — Command from a System Operator to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System.”
3
Pending COM-002-3: http://www.nerc.com/docs/standards/sar/COM-002-3_Standard_20120607_Clean.pdf
4
“Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where
action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.”
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confusion.
In addition, companies also have questions regarding language referred to as ‘internal
controls’ or ‘zero defects’ language, and how NERC and the regions will apply various
judgments on potential violations under this new and untested concept. While both
CIP v.5 and draft COM-003 take aim at certain symptoms, it is difficult for companies to
see how NERC will actually perform these tasks since no field experience has been
tested or broadly communicated with stakeholders. Instead of this piecemeal
approach, EEI has strongly believed for several years that NERC should address this
issue as a strategic matter and develop a comprehensive plan that would set both
compliance and enforcement on a more sustainable foundation. The resources being
applied to compliance and enforcement across the electric industry need to be
efficiently applied. EEI continues to urge NERC to make commitments to develop a
comprehensive framework that will redesign the program.
Response: NERC leadership has been communicating the need and intent of control
based standards and is advocating it through CIP v.5 and COM-003-1. The SDT will
pass your comments to NERC executive leadership for further action.
Response: The OPCPSDT thanks you for your comments. Please see our responses above.
END OF REPORT
206
Consideration of Comments Project 2007-02 Operating Personnel Communications Protocols
Posted November 2, 2012
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COM-003-1 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR)
for posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot
closed June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Initial Ballot
closed September 20 2012.
Description of Current Draft:
This is the fourth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Second Successive Ballot of Standards
November 2012
2. Recirculation ballot of standards.
January 2013
3. Board adopts standards.
February 2013
Draft 4
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COM-003-1 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act, to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of general information and
of potential options or alternatives to resolve BES operating concerns are not commands and are
not considered Operating Instructions.
Draft 4
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Page 2 of 9
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COM-003-1 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operators uniform communications protocols that
reduce the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
5.
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
6.
Background:
The SDT has incorporated within this standard a recognition that these requirements
should not focus on individual instances of failure as a basis for violating the standard.
In particular, the SDT has incorporated an approach to empower and enable the
industry to identify, assess, and correct deficiencies in the implementation of certain
requirements. The intent is to change the basis of a violation in those requirements so
that they are not focused on whether there is a deficiency, but on identifying,
assessing, and correcting deficiencies. It is presented in those requirements by
modifying “implement” as follows:
Each … shall implement, in a manner that identifies, assesses, and corrects
deficiencies, . . .
The term documented communication protocols refers to a set of required protocols
specific to the Functional Entity. This term does not imply any particular naming or
approval structure beyond what is stated in the requirements. An entity should include
as much as it believes necessary in their documented protocols, but they must address
all of the applicable parts of the Requirement. The documented protocols themselves
are not required to include the “. . . identifies, assesses, and corrects deficiencies, . . ."
elements described in the preceding paragraph, as those aspects are related to the
manner of implementation of the documented protocols and could be accomplished
through other controls or compliance management activities.
Draft 4
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COM-003-1 Operating Personnel Communications Protocols
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement, in a manner that identifies, assesses and corrects deficiencies, documented
communication protocols for Operating Instructions between Functional Entities that
include the following: [Violation Risk Factor: Medium [Time Horizon: Long-term
Planning ]
1.1. Use of the English language when issuing or responding to an oral or written
Operating Instruction, unless another language is mandated by law or regulation.
1.2. Use of the 24-hour clock format when referring to clock times when issuing an
oral or written Operating Instruction.
1.3. Use of the time, the time zone where the action will occur and indication of
whether the time is daylight saving time or standard time when issuing an oral or
written Operating Instruction that refers to clock times between Functional
Entities in different time zones.
1.4. Use of the name specified by the owner(s) for each Transmission interface
Element or Transmission interface Facility when referring to a Transmission
interface Element or a Transmission interface Facility-in an oral or written
Operating Instruction , unless another name is mutually agreed to by the
Functional Entities.
1.5. Use of alpha-numeric clarifiers when issuing an oral Operating Instruction for
Facilities and Elements in instances where the nomenclature of Facilities or
Elements is in alpha-numeric format (. for example if an entity designated a circuit
breaker “One twoBravo” (12B). One two Bravo would need alpha-numeric
clarifiers if used in an oral Operating Instruction)
1.6. When issuing an oral two party, person-to-person Operating Instruction, require
the issuer to:
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
Reissue the Operating Instruction to resolve a misunderstanding.
1.7. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
1.8. When issuing an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (. for example an all call system), verbally or electronically confirm receipt
from one or more receiving parties.
1.9. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (. for example an all call system), request clarification from the initiator if
the communication is not understood.
Draft 4
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COM-003-1 Operating Personnel Communications Protocols
R2. Each Distribution Provider and Generator Operator shall implement, in a manner that
identifies, assesses and corrects deficiencies, documented communication protocols
for Operating Instructions between Functional Entities that include the following:
[Violation Risk Factor: Medium] [Time Horizon: Long-term Planning ]
2.1. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
2.2. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
C. Measures
M1. Evidence must include each applicable entity’s documented communications protocols
developed for Requirement R1 and must demonstrate that the protocols have been
implemented in a manner that identifies, assesses and corrects deficiencies.
M2. Evidence must include each applicable entity’s documented communications protocols
developed for Requirement R2 and must demonstrate that the protocols have been
implemented in a manner that identifies, assesses and corrects deficiencies.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional Entity.
In such cases the ERO or a Regional Entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence of its manner that identifies, assesses and
corrects deficiencies for Requirement R1 Measure M1 for the most recent 90
days.
Draft 4
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COM-003-1 Operating Personnel Communications Protocols
Each Distribution Provider and Generator Operator shall retain evidence of its
manner that identifies, assesses and corrects deficiencies for Requirement R2
Measure M2 for the most recent 90 days.
If a Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Draft 4
November 9, 2012
Page 6 of 9
COM-003-1 Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long Term
Planning
VRF
Medium
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The Responsible Entity did
not include one (1) of the
nine (9) parts of
Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
The Responsible Entity did
not include two (2) of the nine
(9) parts of Requirement R1,
Parts 1.1 to 1.9 in their
documented communication
protocols
The Responsible
Entity did not include
three (3) of the nine
(9) parts of
Requirement R1, Parts
1.1 to 1.9 in their
documented
communication
protocols
The Responsible Entity did
not include four (4) or more
of the nine (9) parts of
Requirement R1, Parts 1.1 to
1.9 in their documented
communication protocols
OR
The Responsible Entity did
not have documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
documented communication
protocols as required in
Requirement R1
Draft 4
November 9, 2012
Page 7 of 9
COM-003-1 Operating Personnel Communications Protocols
R2
Long Term
Planning
Medium
N/A
N/A
The Responsible
Entity did not include
one (1) of the two (2)
parts of Requirement
R2, Parts 2.1 to 2.2 in
their documented
communication
protocols
The Responsible Entity did
not include Parts 2.1 to 2.2
of Requirement R2, in their
documented communication
protocols
OR
The responsible entity did
not have documented
communication protocols as
required in Requirement R2
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
documented communication
protocols as required in
Requirement R2
E. Regional Variances
None.
Version History
Version
Draft 4
November 9, 2012
Date
Action
Change Tracking
Page 8 of 9
COM-003-1 Operating Personnel Communications Protocols
Draft 4
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COM-003-1 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR)
for posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot
closed June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Initial Ballot
closed September 20 2012.
7.
Description of Current Draft:
This is the third fourth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
July 2012
2. Second Ballot of Standards.
August 2012
3. Successive Ballot of Standards
September 2012
1. Second Successive Ballot of Standards
October November 2012
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August 21 November 9, 2012
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COM-003-1 Operating Personnel Communications Protocols
4.2.Recirculation ballot of standards.
January October 2012 2013
5.3.Board adopts standards.
November February 2012
2013
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COM-003-1 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A Ccommand from by a System Operator of a Reliability Coordinator,
or of a Transmission Operator, or of a Balancing Authority, where the recipient of the command
is expected to act, to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information
and of potential options or alternatives to resolve BES operating concerns are not commands and
are not considered Operating Instructions.
Draft 34
August 21 November 9, 2012
Page 3 of 13
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COM-003-1 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operators uniform communications protocols that
reduce the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
5.
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
6.
Background:
The SDT has incorporated within this standard a recognition that these
requirements should not focus on individual instances of failure as a sole basis for
violating the standard. In particular, the SDT has incorporated an approach to
empower and enable the industry to identify, assess, and correct deficiencies in the
implementation of certain requirements. The intent is to change the basis of a violation
in those requirements so that they are not focused on whether there is a deficiency, but
on identifying, assessing, and correcting deficiencies. It is presented in those
requirements by modifying “implement” as follows:
Each … shall implement, in a manner that identifies, assesses, and corrects
deficiencies, . . .
The term documented communication protocols refers to a set of required
protocols specific to the Functional Entity. This term does not imply any particular
naming or approval structure beyond what is stated in the requirements. An entity
should include as much as it believes necessary in their documented protocols, but
they must address all of the applicable parts of the Requirement. The documented
protocols themselves are not required to include the “. . . identifies, assesses, and
corrects deficiencies, . . ." elements described in the preceding paragraph, as those
aspects are related to the manner of implementation of the documented protocols and
could be accomplished through other controls or compliance management activities.
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COM-003-1 Operating Personnel Communications Protocols
5.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement, in a manner that identifies, assesses and corrects deficiencies, have
documented communication protocols for Operating Instructions between fFunctional
eEntities that incorporate include the following: [Violation Risk Factor: Medium Low]
[Time Horizon: Long-term Planning ]
1.1. Use of the English language when issuing or responding to an oral or written
Operating Instruction between functional entities, unless another language is
mandated by law or regulation. Transmission Operators and Balancing
Authorities may use an alternate language for internal operations.1.2. Use of the 24-hour clock format when referring to clock times when issuing an
oral or written Operating Instruction.
1.3. Use of the time, the time zone where the action will occur and indication of
whether the time is daylight saving time or standard time wWhen issuing an oral
or written Operating Instruction that refers to clock times between functional
Functional entities Entities in different time zones, when referring to clock times
include the time, the time zone where the action will occur and indicate whether
the time is daylight saving time or standard time.
1.4. Use of the name specified by the owner(s) for each Transmission interface
Element or Transmission interface Facility wWhen referring to a Transmission
interface Element or a Transmission interface Facility(when issuing) in an oral or
written Operating Instruction between functional entities, use the name specified
by the owner(s) for that Transmission interface Element or Transmission interface
Facility, unless another name is mutually agreed to by the Ffunctional Eentities.
1.5. Use of alpha-numeric clarifiers when issuing an oral Operating Instruction for
Facilities and Elements in instances where the nomenclature of Facilities or
Elements is in alpha-numeric format (e.g. (for example) if an entity designated a
circuit breaker “One two(12)Bravo” (12B). oOne two Bravo would need alphanumeric clarifiers if used in an oral Operating Instruction)
1.6. When issuing an oral two party, person-to-person Operating Instruction, require
the issuer to:
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
Reissue the Operating Instruction to resolve a misunderstanding.
1.7. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
1.8. When issuing an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
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COM-003-1 Operating Personnel Communications Protocols
period (e.g. (for example) an all call system), verbally or electronically confirm
receipt from one or more receiving parties.
1.9. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. (for example) an all call system), request clarification from the
initiator if the communication is not understood.
R2. Each Distribution Provider and Generator Operator shall implement, in a manner that
identifies, assesses and corrects deficiencies, have documented communication
protocols for Operating Instructions, between fFunctional eEntities ,that incorporate
include the following: [Violation Risk Factor: LowMedium] [Time Horizon: Long-term
Planning ]
2.1. When receiving an oral two party, person-to-person Operating Instruction, require
the recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
2.2. When receiving an oral Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time
period (e.g. an all call system), request clarification from the initiator if the
communication is not understood.
R3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement a process for identifying deficiencies with adherence to the documented
communication protocols specified in Requirement R1 that: [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning ]
3.1. Identifies potential deficiencies,
3.2. Assesses the deficiencies found,
3.3. Corrects the deficiencies, and
3.4. Evaluates the process based on deficiencies found external to Part 3.1 and either
implements modifications to the process when the evaluation
determines that modification of the process is necessary to
address the deficiencies found; or
demonstrates that no modification to the process is necessary to
address the deficiencies.
R4. Each Distribution Provider and Generator Operator shall implement a process for
identifying deficiencies with adherence to the documented communication protocols
specified in Requirement R2 that: [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning ]
4.1. Identifies potential deficiencies,
4.2. Assesses the deficiencies found,
4.3. Corrects the deficiencies, and
4.4. Evaluates the process based on deficiencies found external to Part 4.1 and either
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COM-003-1 Operating Personnel Communications Protocols
implements modifications to the process when the evaluation
determines that modification of the process is necessary to
address the deficiencies found; or
demonstrates that no modification to the process is necessary to
address the deficiencies.
C. Measures
M1. Evidence must include each applicable entity’s documented communications protocols
developed for Requirement R1 and must demonstratinge that the protocols have been
implemented in a manner that identifies, assesses and corrects deficiencies. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator, shall provide
its documented communications protocols developed for Requirement R1.
M1.M2. Evidence must include each applicable entity’s documented communications
protocols developed for Requirement R2 and must demonstrate that the protocols have
been implemented in a manner that identifies, assesses and corrects deficiencies.
M2. demonstratinge Each Distribution Provider and Generator Operator , shall provide its
documented communications protocols developed for Requirement R2.
M3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide the results of its process developed for Requirement R3.
M4. Each Distribution Provider and Generator Operator shall provide the results of its
process developed for Requirement R4.
M5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve as the Compliance Enforcement Authority (CEA)
unless the applicable entity is owned, operated, or controlled by the Regional Entity.
In such cases the ERO or a Regional Entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
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COM-003-1 Operating Personnel Communications Protocols
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence of its manner that identifies, assesses and
corrects deficiencies for Requirement R3 R1 Measure M3 M1 for the most
recent 90 days.
Each Distribution Provider and Generator Operator shall retain evidence of its
manner that identifies, assesses and corrects deficiencies forfor Requirement
R4 R2 Measure M4 M2 for the most recent 90 days.
If a Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Draft 34
August 21 November 9, 2012
Page 8 of 13
COM-003-1 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long Term
Planning
LowMed
ium
The responsible
Responsible entity Entity
did not include one (1) of
the nine (9) parts of
Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
Moderate VSL
High VSL
Severe VSL
The Responsible Entity
responsible entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
The Responsible
Entity responsible
entity did not include
three (3) of the nine
(9) parts of
Requirement R1, Parts
1.1 to 1.9 in their
documented
communication
protocols
The Responsible Entity
responsible entity did not
include four (4) or more of
the nine (9) parts of
Requirement R1, Parts 1.1 to
1.9 in their documented
communication protocols
OR
The Responsible Entity
responsible entity did not
have documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
documented communication
protocols as required in
Requirement R1
Draft 34
August 21 November 9, 2012
Page 9 of 13
COM-003-1 Operating Personnel Communications Protocols
R2
Long Term
Planning
LowMed
ium
N/A
N/A
The Responsible
Entity responsible
entity did not include
one (1) of the two (2)
parts of Requirement
R2, Parts 2.1 to 2.2 in
their documented
communication
protocols
The Responsible Entity
responsible entity did not
include Parts 2.1 to 2.3 2
(3) of Requirement R2, in
their documented
communication protocols
OR
The responsible entity did
not have documented
communication protocols as
required in Requirement R2
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
documented communication
protocols as required in
Requirement R2
Draft 34
August 21 November 9, 2012
Page 10 of 13
COM-003-1 Operating Personnel Communications Protocols
R3
Operations
Planning
Medium
N/A
N/A
N/A
The Responsible Entity does
not have a process for
identifying deficiencies with
adherence to the
documented communication
protocols specified in
Requirement R1;
Or
The Responsible Entity did
not evaluate their process
based on deficiencies found
external to Part 3.1 to
determine whether
modification of the process
is necessary;
Or
The Responsible Entity did
not implement modifications
to the process when the
evaluation determined that
modification of the process
was necessary to address the
deficiencies found;
Or
The Responsible Entity did
not demonstrate that no
modification to the process
was necessary to address the
deficiencies found external
to Part 3.1.
Draft 34
August 21 November 9, 2012
Page 11 of 13
COM-003-1 Operating Personnel Communications Protocols
R4
Operations
Planning
Medium
N/A
N/A
N/A
The Responsible Entity does
not have a process for
identifying deficiencies with
adherence to the
documented communication
protocols specified in
Requirement R2;
Or
The Responsible Entity did
not evaluate their process
based on deficiencies found
external to Part 4.1 to
determine whether
modification of the process
is necessary;
Or
The Responsible Entity did
not implement modifications
to the process when the
evaluation determined that
modification of the process
was necessary to address the
deficiencies found;
Or
The Responsible Entity did
not demonstrate that no
modification to the process
was necessary to address the
deficiencies found external
to Part 4.1.
Draft 34
August 21 November 9, 2012
Page 12 of 13
COM-003-1 Operating Personnel Communications Protocols
E. Regional Variances
None.
Version History
Version
Date
Draft 34
August 21 November 9, 2012
Action
Change Tracking
Page 13 of 13
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Revisions or Retirements to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and
Balancing Authority shall use English as the
language for all communications between and
among operating personnel responsible for the
real-time generation control and operation of
COM-003-1 Requirement R1 Part 1.1
R1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator
shall implement, in a manner that
identifies, assesses and corrects
deficiencies, documented communication
protocols for Operating Instructions
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
the interconnected Bulk Electric System.
Transmission Operators and Balancing
Authorities may use an alternate language for
internal operations
between Functional Entities that include
the following: [Violation Risk Factor:
Medium] [Time Horizon: Long-term
Planning ]
1.1. Use of the English language when issuing
an oral or written Operating Instruction
between functional entities, unless
another language is mandated by law or
regulation.
Conforming Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-001-2 in the particular Jurisdiction in which COM-001-2 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Command from a System Operator to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Revisions or Retirements to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and
Balancing Authority shall use English as the
language for all communications between and
COM-003-1 Requirement R1 Part 1.1
R1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator
shall implement, in a manner that
identifies, assesses and corrects
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
among operating personnel responsible for the
real-time generation control and operation of
the interconnected Bulk Electric System.
Transmission Operators and Balancing
Authorities may use an alternate language for
internal operations
deficiencies, documented communication
protocols for Operating Instructions
between Functional Entities that include
the following: [Violation Risk Factor: Low
Medium] [Time Horizon: Long-term
Planning ]
R1.
Each Balancing Authority, , Reliability
Coordinator, and Transmission Operator shall have
documented communications protocols for
Operating Instructions that incorporate the
following:
1.1. Use of the English language when issuing
an oral or written Operating Instruction
between functional entities, unless
another language is mandated by law or
regulation. Transmission Operators and
Balancing Authorities may use an
alternate language for internal operations.
Conforming Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-001-2 in the particular Jurisdiction in which COM-001-2 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
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Project 2007-02 Operating Personnel
Communications Protocols
Unofficial Comment Form for Standard COM-003-1
Operating Personnel Communications Protocols
Please DO NOT use this form to submit comments. Please use the electronic comment form to submit
comments on the proposed draft COM-003-1 Operating Personnel Communications Protocols standard.
Comments must be submitted by 8 p.m. ET December 13, 2012.
If you have questions please contact Joseph Krisiak at [email protected] or by telephone at 609651-0903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information
Effective communication is critical for real time operations. Failure to successfully communicate clearly
can create misunderstandings resulting in improper operations increasing the potential for failure of the
Bulk Electric System (BES).
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and approved
by the Standards Committee on June 8, 2007. It established the scope of work to be done for Project
2007-02 Operating Personnel Communications Protocols (OPCP). The scope described in the SAR is to
establish essential elements of communications protocols and communications paths such that
operators and users of the North American BES will efficiently convey information and ensure mutual
understanding. The August 2003 Blackout Report, Recommendation Number 26, calls for a tightening
of communications protocols. FERC Order 693 paragraph 532 amplifies this need and applies it to all
Operating Instructions. This proposed standard’s goal is to ensure that effective communication is
practiced and delivered in clear language and standardized format via pre-established communications
paths among pre-identified operating entities.
The SAR indicated that references to communication protocols in other NERC Reliability Standards may
be moved to this new standard. The SAR instructed the standard drafting team to consider
incorporating the use of Alert Level Guidelines and three-part communications in developing this new
standard to achieve high level consistency across regions. The OPCP Standards Drafting Team (SDT)
believes the Alert Level Guidelines, while valuable, belong in a separate standard and has petitioned the
Standards Committee to approve the transfer to another standard or to start a separate project.
The upgrade of communication system hardware where appropriate is not included in this project (it is
included in NERC Project 2007-08 Emergency Operations).
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The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators (GOPs), and Distribution Providers (DPs). These requirements
ensure that communications include essential elements such that information is efficiently conveyed
and mutually understood for communicating changes to real-time operating conditions and responding
to directives, notifications, directions, instructions, orders, or other reliability related operating
information.
The Purpose statement of COM 003-1 states: “To provide system operators uniform communications
protocols that reduce the possibility of miscommunication that could lead to action or inaction harmful
to the reliability of BES.”
1. New NERC Glossary terms: The SDT has changed the definition of “Operating Instructions”
proposed in the Standard version 3 and added additional language to clarify its meaning and
intent.
Operating Instructions differentiates the broad class of communications that deal with changing or
altering the state of the BES from general discussions of options or alternatives. Changes to the BES
operating state with unclear communications create increased opportunities for events that could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures.
This term is proposed for addition to the NERC Glossary to establish meaning and usage within the
electricity industry.
2. R3 and R4 are eliminated, there is proposed new language for R1 and R2: “Implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for
Operating Instructions between Functional Entities that include the following:” The OPCP SDT is
proposing this language change because of strong industry comment requesting it, because it is
consistent with language in other control based standards and because it conveys the same
approach to identifying, assessing and correcting deficiencies. The SDT would also note the
reference to “for Operating Instructions between Functional Entities” for additional industry
comment.
3. Documented Communication Protocols: The OPCP SDT has incorporated a requirement for an
applicable entity to implement documented communication protocols that incorporate the
following elements:
a)
English language: Use of the English language when issuing an oral or written Operating
Instruction between functional entities, unless another language is mandated by law or
regulation.
Unofficial Comment Form
(Standard) | Project 2007-02.0 - Operating Personnel Coomunication Protocols
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b) 24 hour clock R1 Part 1.2 and Time zone reference R1 Part 1.3: Use the 24-hour clock format
when referring to clock times when issuing an oral or written Operating Instruction.
Use of the time, the time zone where the action will occur and indication of whether the time is
daylight saving time or standard time when issuing an oral or written Operating Instruction that
refers to clock times between Functional Entities in different time zones.
The OPCP SDT proposed this change to address comments by industry while adhering to the
recommendations of the August 14th, 2003 task force report.
c) Line and Equipment Identifiers: Use of the name specified by the owner(s) for each
Transmission interface Element or Transmission interface Facility when referring to a
Transmission interface Element or a Transmission interface Facility (when issuing) in an oral or
written Operating Instruction , unless another name is mutually agreed to by the Functional
Entities.
d) Alpha-numeric clarifiers: Use of alpha-numeric clarifiers when issuing an oral Operating
Instruction for Facilities and Elements in instances where the nomenclature of Facilities or
Elements are in alpha-numeric format (e.g. if an entity designated a circuit breaker “12B”, 12B –
one two bravo – would need alpha-numeric clarifiers if used in an oral Operating Instruction).
e) Three-part Communication:
When issuing an oral two party, person-to-person Operating Instruction, require the issuer to:
•
Confirm that the response from the recipient of the Operating Instruction was accurate, or
•
Reissue the Operating Instruction to resolve a misunderstanding.
When receiving an oral two party, person-to-person Operating Instruction, require the
recipient to repeat, restate, rephrase, or recapitulate the Operating Instruction.
f) One-way burst messaging system to multiple parties (all call): When receiving an oral
Operating Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system), request
clarification from the initiator if the communication is not understood.
g) Three-part Communication: For DPs and GOPs: When receiving an oral two party, person-toperson Operating Instruction, require the recipient to repeat, restate, rephrase, or recapitulate
the Operating Instruction.
h) One-way burst messaging system to multiple parties (all call): For DPs and GOPs: When
receiving an oral Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g. an all call
system), request clarification from the initiator if the communication is not understood.
Unofficial Comment Form
(Standard) | Project 2007-02.0 - Operating Personnel Coomunication Protocols
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4. Violation Severity Level (VSL) and Violation Risk Factor (VRF) Changes from version three: The
OPCP SDT reviewed the VRFs and VSLs associated with R1, R2, and made changes to more closely
conform to NERC and FERC guidelines.
The SDT is proposing to retire Requirement R4 from COM-001 and incorporate it into Requirement R2
of this draft COM-003-1. Since Requirement R4 from COM-001-1 carries over essentially unchanged
there is no specific question related to it in this Comment Form.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of a
miscommunication during Operating Instructions. Requirements R1 and R2 are assigned a Medium
Violation Risk due to their potential direct impact on BES reliability.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R1 and R2 must be implemented in long term planning operations and therefore were
assigned a Time Horizon of Long Term Planning.
Unofficial Comment Form
(Standard) | Project 2007-02.0 - Operating Personnel Coomunication Protocols
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Questions:
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
Please review the request for an interpretation, the associated standard, and the draft interpretation
and then answer the following questions.
1. Do you agree with the changes made to the proposed definition “Operating Instruction” (now
proposed as a “A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act, to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and
of potential options or alternatives to resolve BES operating concerns are not commands and are
not considered Operating Instructions. ”) to be added as a term for the NERC Glossary? If not,
please explain in the comment area of the last question.
Yes
No
Comments:
2. The SDT has proposed new language in COM-003-1, R1 and R2: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating
Instructions between Functional Entities that include the following:” R3 and R4 from draft 3 are
eliminated. Do you agree with these proposed requirement changes? If not, please explain in
the comment area of the last question.
Yes
No
Comments:
3. Do you agree with the VRFs and VSLs for Requirements R1 and R2?
Yes
No
Comments:
4. Do you have any other comments or suggestions to improve the draft standard?
Comments:
Unofficial Comment Form
(Standard) | Project 2007-02.0 - Operating Personnel Coomunication Protocols
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Project 2007-02, COM-003-1 Operating
Personnel Communication Protocols
Rationale and Technical Justification
Justification for Requirements in Draft 4
Rationale and Technical Justification
The Quality Review team for the draft 2 posting of COM-003-1 highly recommended that the
OPCPSDT provide a justification or rationale document to aid reviewers in their examination of this
draft of COM-003-1. The OPCPSDT agrees with the QR recommendation and has developed the
following to support the standard and to help stakeholders understand the intent and scope of the
standard. This version of the standard features a non traditional approach to standards that could
alleviate concerns that surfaced in comments in drafts one, two and three.
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to
implement documented communication protocols in a manner that identifies, assesses, and
corrects deficiencies. Because Operating Instructions affect Facilities and Elements of the Bulk
Electric System, the communication of those Operating Instructions must be understood by all
involved parties, especially when those communications occur between functional entities. An
EPRI study reviewed nearly 400 switching mishaps by electric utilities and found that roughly 19%
of errors (generally classified as loss of load, breach of safety, or equipment damage) were due to
communication failures.1 This was nearly identical to another study of dispatchers from 18 utilities
representing nearly 2000 years of operating experience that found that 18% of the operators’
errors were due to communication problems. 2The necessary protocols include the use of the
1
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
2
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
English language (from COM-001-1.1 R4), time formatting, mutually agreed nomenclature for
Transmission interface Elements, alpha-numeric clarifiers, and three part communications.
Requirement R2
Requirement R2 requires entities that only receive Operating Instructions to implement documented
communication protocols in a manner that identifies, assesses, and corrects deficiencies .
The two protocols (R2 , Parts 2.1 and 2.2) required are repeat back for three part communication and
clarification if an “all call” communication is unclear.
Rationale
The SDT has incorporated within this standard a recognition that these requirements should not focus
on individual instances of failure as a basis for violating the standard. In particular, the SDT has
incorporated an approach to empower and enable the industry to identify, assess, and correct
deficiencies in the implementation of certain requirements. The intent is to change the basis of a
violation in those requirements so that they are not focused on whether there is a deficiency, but on
identifying, assessing, and correcting deficiencies. It is presented in those requirements by modifying
“implement” as follows:
Each … shall implement, in a manner that identifies, assesses, and corrects deficiencies, . . .
The term documented communication protocols refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. This term does not imply any
particular naming or approval structure beyond what is stated in the requirements. An entity should
include as much as it believes necessary in their documented protocols, but they must address all of the
applicable parts of the Requirement. The documented protocols themselves are not required to include
the “. . . identifies, assesses, and corrects deficiencies, . . ." elements described in the preceding
paragraph, as those aspects are related to the manner of implementation of the documented protocols
and could be accomplished through other controls or compliance management activities.
Project 2007-02 Operating Personnel Communications Protocols (COM-003-1) | Rationale and Technical Justification
2
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects
deficiencies, documented communication
protocols for Operating Instructions between
Functional Entities that include the following::
1.1.
Use of the English language when issuing an
oral or written Operating Instruction
between functional entities, unless another
language is mandated by law or regulation.
Project 2007-02 02: Operating Personnel
Communication Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects
deficiencies, documented communication
protocols for Operating Instructions between
Functional Entities that include the following:Each
Balancing Authority, Distribution Provider,
Generator Operator, Reliability Coordinator, and
Transmission Operator shall have documented
communications protocols that incorporate the
following:
1.1.
Use of the English language when issuing an
oral or written Operating Instruction
between functional entities, unless another
language is mandated by law or regulation.
Requirement in Approved Standard
Translation to
New Standard or
Other Action
Comments
Transmission Operators and Balancing
Authorities may use an alternate language
for internal operations.
Project 2007-02 Operating Personnel Communications Protocols | Mapping Document
2
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
2
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
3
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
4
VRF for COM-003-1:
There are two requirements in COM-003-1, draft 4. Requirements R1 and R2 are assigned a “Medium” VRF. The elimination of
draft 3 R3 and R4 and the language change to R1 and R2, which now reads:”Each ….. shall implement, in a manner that
identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions between
Functional Entities that include the following: “, warrants raising the VRF to “Medium” because it makes the requirement more
than just administrative as it now features an evaluative process that would have a deeper impact on the reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
5
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
6
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Medium
NERC VRF Discussion
R1 is a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system. However, violation of this requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition. The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the implementation of documented communication protocols that reduce the
possibility of miscommunication which could eventually lead to action or inaction harmful to the reliability
of BES.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
7
VRF and VSL Justifications – COM 003-1, R1
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Medium ” which is consistent with
NERC guidelines
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
include one (1) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
Moderate
The Responsible Entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
High
The Responsible Entity did not
include three (3) of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
Severe
The Responsible Entity did not
include four (4) or more of the
nine (9) parts of Requirement R1,
Parts 1.1 to 1.9 in their
documented communication
protocols
OR
The Responsible Entity did not
have documented communication
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
8
VRF and VSL Justifications – COM 003-1, R1
protocols as required in
Requirement R1.
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
communication protocols as
required in Requirement R1
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
9
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
10
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
11
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Low
NERC VRF Discussion
R2 is a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or
restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or
capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk
electric system. However, violation of this requirement is unlikely, under emergency, abnormal, or
restoration conditions anticipated by the preparations, to lead to bulk electric system instability,
separation, or cascading failures, nor to hinder restoration to a normal condition. The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the implementation of documented communication protocols that reduce the
possibility of miscommunication which could eventually lead to action or inaction harmful to the reliability
of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC
guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
12
VRF and VSL Justifications – COM 003-1, R2
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
The Responsible Entity did not
include one (1) of the two (2) parts
of Requirement R2, Parts 2.1 to 2.2
in their documented
communication protocols
Severe
The Responsible Entity did not
include Parts 2.1 to 2.2 (2) of
Requirement R2, in their
documented communication
protocols
OR
The responsible entity did not
have documented communication
protocols as required in
Requirement R2.
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
communication protocols as
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
13
VRF and VSL Justifications – COM 003-1, R2
required in Requirement R1
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
14
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed two VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
15
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
16
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
2
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
3
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
4
VRF for COM-003-1:
There are three two requirements in COM-003-1, draft 41. Requirements R1, and R2 are assigned a “Medium” VRF,. and R3
were assigned a “Medium” VRF.
The elimination of draft 3 R3 and R4 and the language change to R1 and R2 which now reads:”Each ….. shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions
between Functional Entities that include the following: “ may warrants raising the VRF to “Medium” because it makes the
requirement more than just administrative as it now features an evaluative process that would have a deeper impact on the
reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
5
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
6
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
LowMedium
NERC VRF Discussion
R1 is a requirement in a planning time frame that, if violated, would notcould, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to directly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of this requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to bulk electric
system instability, separation, or cascading failures, nor to hinder restoration to a normal condition. The
VRF for this requirement is “MediumLow” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “MediumLow”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the establishment implementation of documented communication protocols
that reduce the possibility of miscommunication which could eventually lead to action or inaction harmful
to the reliability of BES.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
7
VRF and VSL Justifications – COM 003-1, R1
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Medium Low” which is consistent with
NERC guidelines
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
include one (1) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols The
responsible entity did not
include one (1) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
Moderate
The Responsible Entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocolsThe
responsible entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
High
The Responsible Entity did not
include three (3) of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
The responsible entity did not
include three (3) of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
Severe
The Responsible Entity
responsible entity did not include
four (4) or more of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
OR
The Responsible Entity responsible
entity did not have documented
8
VRF and VSL Justifications – COM 003-1, R1
communication protocols
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
communication protocols as
required in Requirement R1.
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
communication protocols as
required in Requirement R1
9
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
10
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
11
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
LowMedium
NERC VRF Discussion
R2 is a requirement in a planning time frame that, if violated, would notcould, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected todirectly and adversely
affect the electrical state or capability of the bulk electric system, or the ability to effectively monitor,
control, or restore the bulk electric system. However, violation of this requirement is unlikely, under
emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to bulk electric
system instability, separation, or cascading failures, nor to hinder restoration to a normal condition. The
VRF for this requirement is “MediumLow” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “MediumLow”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the establishment implementation of documented communication protocols
that reduce the possibility of miscommunication which could eventually lead to action or inaction harmful
to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “MediumLow” which is consistent with
NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
12
VRF and VSL Justifications – COM 003-1, R2
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
The Responsible Entity responsible
entity did not include one (1) of
the two (2) parts of Requirement
R2, Parts 2.1 to 2.2 in their
documented communication
protocols
Severe
The Responsible Entity responsible
entity did not include Parts 2.1 to
2.3 2 (32) of Requirement R2, in
their documented communication
protocols
OR
The responsible entity did not
have documented communication
protocols as required in
Requirement R2.
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
13
VRF and VSL Justifications – COM 003-1, R2
communication protocols as
required in Requirement R1
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
14
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four two VSLs based on misapplication or absence of
common communication protocols. If no communication protocols are used at all or if the number of
required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
15
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
16
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Medium
NERC VRF Discussion
R3 is a requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for use of formal three part communication, among other communication
protocols. This requirement is analogous to R2 of COM-002-2, which describes a communication protocol
required for operating personnel to use when given a directive. The VRF for this requirement (COM-0022, R2) is “Medium” which is consistent with COM-003-1 R3 at a “Medium”. The SDT considers “Medium”
as the proper assignment because it is consistent with NERC and FERC guidelines.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of the requirement is unlikely to lead to bulk electric system instability, separation, or
cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to implement a process for identifying
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
17
VRF and VSL Justifications – COM 003-1, R3
deficiencies with adherence to the documented communication protocols. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Responsible Entity does not
have a process for identifying
deficiencies with adherence to the
documented communication
protocols specified in Requirement
R1;
Or
The Responsible Entity did not
evaluate their process based on
deficiencies found external to Part
3.1 to determine whether
modification of the process is
necessary;
Or
The Responsible Entity did not
implement modifications to the
process when the evaluation
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
18
VRF and VSL Justifications – COM 003-1, R3
determined that modification of
the process was necessary to
address the deficiencies found;
Or
The Responsible Entity did not
demonstrate that no modification
to the process was necessary to
address the deficiencies found
external to Part 3.1.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
19
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Since R3 represents a new approach that does not currently exist, the VSL does not lower the current level
of compliance.
Guideline 2a:
The VSL assignment for R3 is binary and Severe.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
20
VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
21
VRF and VSL Justifications – COM 003-1, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement that, if violated, could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 24 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls foruse of formal three part communication, among other communication protocols.
This requirement is analogous to R2 of COM-002-2, which describes a communication protocol required
for operating personnel to use when given a directive. The VRF for this requirement (COM-002-2, R2) is
“Medium” which is consistent with COM-003-1 R4 at a “Medium”. The SDT considers “Medium” as the
proper assignment because it is consistent with NERC and FERC guidelines.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize formal communication protocols could directly affect the electrical state or the capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
However, violation of the requirement is unlikely to lead to bulk electric system instability, separation, or
cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R4 contains only one objective which is to implement a process for identifying
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
22
VRF and VSL Justifications – COM 003-1, R4
deficiencies with adherence to the documented communication protocols. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
High
N/A
Severe
The Responsible Entity does not
have a process for identifying
deficiencies with adherence to the
documented communication
protocols specified in Requirement
R2;
Or
The Responsible Entity did not
evaluate their process based on
deficiencies found external to Part
4.1 to determine whether
modification of the process is
necessary;
Or
The Responsible Entity did not
implement modifications to the
process when the evaluation
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
23
VRF and VSL Justifications – COM 003-1, R4
determined that modification of
the process was necessary to
address the deficiencies found;
Or
The Responsible Entity did not
demonstrate that no modification
to the process was necessary to
address the deficiencies found
external to Part 4.1.
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
24
VRF and VSL Justifications – COM 003-1, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Since R4 represents a new approach that does not currently exist, the VSL does not lower the current level
of compliance.
Guideline 2a:
The VSL assignment for R4 is binary and Severe.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
25
VRF and VSL Justifications – COM 003-1, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
Project 2007-02 Operating Personnel Communications Protocols | VRF and VSL Justifications
26
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols
Successive Ballot and Non-binding Poll now open through Thursday, December 13, 2012
Now Available
A successive ballot of COM-003-1 – Operating Personnel Communication Protocols and a non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) is now open
through 8 p.m. Eastern on Thursday, December 13, 2012.
In response to comments received during the last comment period and other input, the drafting team
has adopted many of the recommendations of commenters and incorporated them into draft 4 of
COM-003-1, as summarized below:
Combined Requirements R1 and R3, and R2 and R4 to emulate CIP version 5. The language calls
for an applicable entity to “implement documented communication protocols in a manner that
identifies, assesses and corrects deficiencies…….”
Added additional language to clarify the definition of “Operating Instructions,” as commenters
expressed concerns over the scope of the term.
Clarified that R1 and R2 now apply to Operating Instructions between Functional Entities.
This version was drafted in conjunction with the development of the Reliability Standard Audit
Worksheet (RSAW). Changes were made to the RSAW to reflect the changes in draft 4 of COM-003-1
and changes suggested by some commenters. The RSAW is posted for an informal comment period
along with COM-003-1.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
Standard and opinion in the non-binding poll of the associated VRFs and VSLs by clicking here.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a
recirculation ballot.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination standard drafting team (RC SDT) has limited the scope of
its modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act, to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols
Formal Comment Period Now Open:
November 14, 2012 – December 13, 2012
RSAW Posted for Industry Comments:
November 14, 2012 – December 13, 2012
Upcoming:
Successive Ballot and Non-binding Poll: December 4 – December 13, 2012
Now Available
A formal comment period for COM-003-1 – Operating Personnel Communication Protocols is open
through 8 p.m. Eastern on Thursday, December 13, 2012.
A successive ballot of COM-003-1 and a non-binding poll of the associated Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) will be conducted Tuesday, December 4, 2012 through 8 p.m.
Eastern on Thursday, December 13, 2012.
In response to comments received during the last comment period and other input, the drafting team
has adopted many of the recommendations of commenters and incorporated them into draft 4 of
COM-003-1, as summarized below:
Combined Requirements R1 and R3, and R2 and R4 to emulate CIP version 5. The language calls
for an applicable entity to “implement documented communication protocols in a manner that
identifies, assesses and corrects deficiencies…….”
Added additional language to clarify the definition of “Operating Instructions,” as commenters
expressed concerns over the scope of the term.
Clarified that R1 and R2 now apply to Operating Instructions between Functional Entities.
This version was drafted in conjunction with the development of the Reliability Standard Audit
Worksheet (RSAW). Changes were made to the RSAW to reflect the changes in draft 4 of COM-003-1
and changes suggested by some commenters. The RSAW is posted for an informal comment period
along with COM-003-1.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Thursday,
December 13, 2012. Please use this electronic form to submit comments. If you experience any
difficulties in using the electronic form, please contact Wendy Muller at [email protected]. An
off-line, unofficial copy of the comment form is posted on the project page.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Thursday, December 13,
2012. The draft RSAW is posted on the NERC Compliance Reliability Standard Audit Worksheet page.
Please submit comments on the draft RSAW by using the RSAW feedback form on the project page and
sending to: [email protected].
Next Steps
A second successive ballot of COM-003-1 and a non-binding poll of the associated VRFs and VSLs will be
conducted beginning on Tuesday, December 4, 2012 through 8 p.m. Eastern on Thursday, December
13, 2012.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act, to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols
Formal Comment Period Now Open:
November 14, 2012 – December 13, 2012
RSAW Posted for Industry Comments:
November 14, 2012 – December 13, 2012
Upcoming:
Successive Ballot and Non-binding Poll: December 4 – December 13, 2012
Now Available
A formal comment period for COM-003-1 – Operating Personnel Communication Protocols is open
through 8 p.m. Eastern on Thursday, December 13, 2012.
A successive ballot of COM-003-1 and a non-binding poll of the associated Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) will be conducted Tuesday, December 4, 2012 through 8 p.m.
Eastern on Thursday, December 13, 2012.
In response to comments received during the last comment period and other input, the drafting team
has adopted many of the recommendations of commenters and incorporated them into draft 4 of
COM-003-1, as summarized below:
Combined Requirements R1 and R3, and R2 and R4 to emulate CIP version 5. The language calls
for an applicable entity to “implement documented communication protocols in a manner that
identifies, assesses and corrects deficiencies…….”
Added additional language to clarify the definition of “Operating Instructions,” as commenters
expressed concerns over the scope of the term.
Clarified that R1 and R2 now apply to Operating Instructions between Functional Entities.
This version was drafted in conjunction with the development of the Reliability Standard Audit
Worksheet (RSAW). Changes were made to the RSAW to reflect the changes in draft 4 of COM-003-1
and changes suggested by some commenters. The RSAW is posted for an informal comment period
along with COM-003-1.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Thursday,
December 13, 2012. Please use this electronic form to submit comments. If you experience any
difficulties in using the electronic form, please contact Wendy Muller at [email protected]. An
off-line, unofficial copy of the comment form is posted on the project page.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Thursday, December 13,
2012. The draft RSAW is posted on the NERC Compliance Reliability Standard Audit Worksheet page.
Please submit comments on the draft RSAW by using the RSAW feedback form on the project page and
sending to: [email protected].
Next Steps
A second successive ballot of COM-003-1 and a non-binding poll of the associated VRFs and VSLs will be
conducted beginning on Tuesday, December 4, 2012 through 8 p.m. Eastern on Thursday, December
13, 2012.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination drafting team (RC SDT) has limited the scope of its
modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act, to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
3
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Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
Successive Ballot and Non-binding Poll Results
Now Available
A successive ballot for COM-003-1 – Operating Personnel Communication Protocols and a non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) concluded at 8
p.m. Eastern on Thursday, December 13, 2012.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results.
Approval
Non-binding Poll Results
Quorum: 76.78%
Quorum:
77.22%
Approval: 53.57%
Supportive Opinions: 57.91%
Next Steps
The drafting team will consider all comments received during the formal comment period to determine
the next steps.
Background
The purpose of this project is to require that real-time system operators use standardized
communication protocols during normal and emergency operations to enhance the clarity of
communications, improve situational awareness, shorten response time and ultimately serve reliability.
As requested in the SAR, in the development of this proposed standard, the drafting team reviewed
communication protocols in other NERC standards and considered the use of alert level guidelines and
three-part communications to achieve consistency across regions. The proposed standard is designed
to ensure that reliability-related information is conveyed effectively, accurately, consistently and in a
timely manner to ensure mutual understanding by all key parties, both during alerts and emergencies
and during the communication of routine operating instructions.
There are two projects that include the modification of the COM family of standards in the scope of
their SAR. This project, Project 2007-02 – Operating Personnel Communications Protocols, is
concerned with communication protocols for normal and emergency operations. The other project,
Project 2006-06 – Reliability Coordination, is concerned with ensuring that the reliability-related
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
requirements applicable to the Reliability Coordinator are clear, measurable, unique, enforceable, and
sufficient to maintain reliability of the Bulk Electric System.
The Project 2006-06 Reliability Coordination standard drafting team (RC SDT) has limited the scope of
its modifications to those that address communication during emergency operations. The RC SDT has
developed a new term, “Reliability Directive,” to specifically address those communications, and this
term has been approved by the ballot pool. The proposed definition of Reliability Directive is “A
communication initiated by a Reliability Coordinator, Transmission Operator or Balancing Authority
where action by the recipient is necessary to address an Emergency or Adverse Reliability Impact.” The
RC SDT is proposing to require three-part communication for Reliability Directives, with a High Violation
Risk Factor for those requirements.
Since Project 2007-02 – Operating Personnel Communications Protocols addresses communication
protocols for normal and emergency operations, the drafting team has proposed a new term,
“Operating Instruction,” to define the scope of communications to which the COM-003-1 protocols
would apply. The proposed definition of Operating Instruction is:
“Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act, to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.”
The two standards complement each other. COM-003 establishes the practice of using communication
protocols for all Operating Instructions, and provides for an entity to identify, assess and correct any
deficiencies with that practice. COM-002 is focused on communications during emergency situations.
Additional information is available on the project page.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
3
NERC
Standards
20140514-5129
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Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-02 Successive Ballot COM-003-1 November 2012_in
Password
Ballot Period: 12/4/2012 - 12/13/2012
Ballot Type: Initial
Log in
Total # Votes: 334
Register
Total Ballot Pool: 435
Quorum: 76.78 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
53.57 %
Vote:
Ballot Results: The drafting team will review comments received.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
110
11
103
39
93
53
0
12
5
9
435
#
Votes
1
0.7
1
1
1
1
0
0.5
0.2
0.6
7
#
Votes
Fraction
48
2
39
15
35
21
0
2
1
5
168
Negative
Fraction
0.565
0.2
0.574
0.6
0.486
0.525
0
0.2
0.1
0.5
3.75
Abstain
No
# Votes Vote
37
5
29
10
37
19
0
3
1
1
142
0.435
0.5
0.426
0.4
0.514
0.475
0
0.3
0.1
0.1
3.25
4
1
6
3
6
3
0
0
0
1
24
21
3
29
11
15
10
0
7
3
2
101
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Member
Ballot
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Comments
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Affirmative
Abstain
Abstain
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Negative
Affirmative
Affirmative
Affirmative
Michael Moltane
Negative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
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Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
1
3
3
3
3
3
3
3
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Rod Noteboom
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Negative
Dave Markham
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Negative
Affirmative
Negative
Abstain
NERC
Standards
20140514-5129
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
NW Electric Power Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
David McDowell
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Rick Paschall
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
NERC
Standards
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Turlock Irrigation District
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Steve Eldrige
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
Keith Morisette
Steven C Hill
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
Affirmative
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
ICF International
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Brent B Hebert
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
David Gordon
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Affirmative
Abstain
Michiko Sell
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
APX
INTELLIBIND
JDRJC Associates
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Lujuanna Medina
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Negative
Affirmative
Peter H Kinney
Affirmative
David F Lemmons
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Michael Johnson
Kevin Conway
Jim Cyrulewski
Frederick R Plett
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Donald Nelson
Affirmative
Diane J. Barney
Negative
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=2329f1e1-a2fe-4d69-9346-da00e58256d0[12/14/2012 10:48:50 AM]
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
Project 2007-02
Non-binding Ballot Results
Non-binding Poll
Project 2007-02 Non-binding Poll COM-003-1 November 2012_in
Name:
Poll Period: 12/4/2012 - 12/13/2012
Total # Opinions: 305
Total Ballot Pool: 395
77.22% of those who registered to participate provided an opinion or an abstention;
Summary Results: 57.91% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
1
1
1
1
1
1
1
1
1
1
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric,
LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
CPS Energy
Dairyland Power Coop.
1
1
1
1
1
1
1
1
1
1
1
Non-binding Poll Results: Project 2007-02
Member
Kirit Shah
Paul B. Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
Opinions
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Abstain
Kevin Smith
Abstain
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
Abstain
John Brockhan
Affirmative
Affirmative
Negative
Michael B Bax
Marco A Sustaita
Negative
Affirmative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Comments
Negative
Affirmative
Negative
Negative
Abstain
Negative
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Non-binding Poll Results: Project 2007-02
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Negative
Affirmative
Affirmative
Affirmative
Michael Moltane
Abstain
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Marvin E VanBebber
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Rod Noteboom
Affirmative
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Independent Electricity System
Barbara Constantinescu
Operator
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Non-binding Poll Results: Project 2007-02
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Negative
Abstain
Abstain
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Non-binding Poll Results: Project 2007-02
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Kent Kujala
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Affirmative
Negative
Abstain
Abstain
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Daniel D Kurowski
Abstain
Charles A. Freibert
Stephen D Pogue
Negative
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
Non-binding Poll Results: Project 2007-02
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Michael Schiavone
Affirmative
Skyler Wiegmann
Negative
William SeDoris
David McDowell
David Burke
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Abstain
Affirmative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
City of New Smyrna Beach Utilities
Tim Beyrle
Commission
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri
John Allen
Consumers Energy
David Frank Ronk
Cowlitz County PUD
Rick Syring
Detroit Edison Company
Daniel Herring
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Cairo Vanegas
Georgia System Operations Corporation Guy Andrews
Illinois Municipal Electric Agency
Bob C. Thomas
Imperial Irrigation District
Diana U Torres
Indiana Municipal Power Agency
Jack Alvey
LaGen
Richard Comeaux
Madison Gas and Electric Co.
Joseph DePoorter
Modesto Irrigation District
Spencer Tacke
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Oklahoma Municipal Power Authority
Ashley Stringer
Old Dominion Electric Coop.
Mark Ringhausen
Public Utility District No. 1 of Douglas
Henry E. LuBean
County
Public Utility District No. 1 of Snohomish
John D Martinsen
County
Sacramento Municipal Utility District
Mike Ramirez
Seattle City Light
Hao Li
Seminole Electric Cooperative, Inc.
Steven R Wallace
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
WPPI Energy
Todd Komplin
AEP Service Corp.
Brock Ondayko
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
Arizona Public Service Co.
Edward Cambridge
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc. Shari Heino
Calpine Corporation
Phillip Porter
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
Non-binding Poll Results: Project 2007-02
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Non-binding Poll Results: Project 2007-02
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Abstain
Affirmative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Non-binding Poll Results: Project 2007-02
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Negative
Affirmative
Abstain
Abstain
Negative
Affirmative
Abstain
Abstain
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Abstain
Affirmative
Negative
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
9
9
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
APX
JDRJC Associates
Massachusetts Attorney General
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Non-binding Poll Results: Project 2007-02
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
John J. Ciza
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Abstain
Affirmative
Peter H Kinney
Affirmative
James A Maenner
Roger C Zaklukiewicz
Edward C Stein
Michael Johnson
Jim Cyrulewski
Frederick R Plett
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Donald Nelson
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
9
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
9
10
10
10
10
10
10
10
10
10
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Non-binding Poll Results: Project 2007-02
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (64 Responses)
Name (45 Responses)
Organization (45 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (10 Responses)
Comments (64 Responses)
Question 1 (46 Responses)
Question 1 Comments (54 Responses)
Question 2 (47 Responses)
Question 2 Comments (54 Responses)
Question 3 (40 Responses)
Question 3 Comments (54 Responses)
Question 4 (0 Responses)
Question 4 Comments (54 Responses)
Group
Southern Company
Antonio Grayson
No
The proposed definition can be improved by clarifying some of the language. First, a command is
given in order to direct a recipient to take one of two actions - to either change or preserve the state,
status, output or input of an Element or Facility. However, as drafted, it appears that there may be
three responses: (i) to act; (ii) to change; or (iii) to preserve. Therefore, in order to avoid any
ambiguity or confusion, Southern suggests the following change to the first sentence: “A command by
a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a Balancing
Authority, where the recipient of the command is expected to act, in order to change or preserve the
state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System.” In addition, the last sentence is helpful to clarify that certain activities are not considered
“commands” under this definition. However, this sentence may create ambiguity beyond this
definition by stating that certain actions are not “commands”. In fact, these actions may be
“commands” in other contexts. Therefore, in order to not create ambiguity between definitions or
standards, Southern suggests that this sentence should be re-worded to avoid any future ambiguity
or confusion. “For purposes of this definition, the term “command” shall not include discussions of
general information and of potential options or alternatives to resolve BES operating concerns are not
commands and are not considered Operating Instructions.” Lastly, the Operating Instruction definition
does not place an eminent time frame on the action. A communication could take place with the
action expected to take place days or weeks later. Three part communication in this instance should
not be required.
No
Southern believes that the requirements should clearly list which Functional Entities may issue and
receive Operating Instructions (See COM-002-3). As currently drafted, it is not clear what happens
when one of the five Functional Entities listed in these two requirements give an Operating Instruction
to an entity not listed. The 9 requirements in R1 remain too prescriptive. A more acceptable solution
would be for R1 to require "a plan" and for that plan to either address those 9 requirements or to
refer to the guideline document that was developed at NERC’s direction. Furthermore, we continue to
believe a prescriptive use of the word “include” should be removed. We would suggest using the word
“consider” or “address.” Southern suggests that R2 is not necessary because the issuer of an
Operating Instruction is required per sub part 1.6 to confirm that the response from the recipient of
the Operating Instruction was accurate, or reissue the Operating Instruction to resolve a
misunderstanding. As such this standard should not be applicable to a DP or GOP. From a compliance
perspective, the new language proposed for R1 and R2 is consistent with the manner in which internal
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
controls have been incorporated into Version 5 of the CIP Standards. While Southern believes that
internal controls are an integral element of an effective internal compliance program, we are generally
not in favor of incorporating internal controls into the NERC Reliability Standards on a requirementby-requirement basis. Southern believes a more effective way to ensure that Registered Entities
develop and implement effective internal controls is to address the issue holistically and provide
guidance to the industry. This guidance may very well provide examples of internal controls on a
requirement-by-requirement basis, but ultimately the make-up and implementation of internal
controls should be decided by the Registered Entity. Note that the question incorrectly references R2
which includes the DP and GOP.
No
Southern disagrees with the explanation of why the VRF for both R1 and R2 were changed from “Low”
to “Medium” and believes that these continue to be administrative requirements justifying a “Low”
VRF.
Southern agrees with the SDT that each area should have a protocol that is uniform and clear and
that increases reliability. Moreover, Southern agrees with the SDT that when a Balancing Authority,
Reliability Coordinator or Transmission Operator operates in two different time zones it should
establish in its documented communications protocol the applicable time zone (see, e.g., SDT
Consideration of Comments dated November 2, 2012, pp 60-61). However, with regard to
Requirement R1, subpart 1.3, Southern believes that the standard is too prescriptive when it requires
the use of “the time zone where the action will occur”. Southern operates across multiple time zones
utilizing a common EMS system. This provides for a uniform and clear understanding for all functional
entities. However, to require the use of the time zone in which the functional entity resides could
require the use of instructions that require the use of different time zones. This would not increase
reliability, but would increase the risk to reliability. Further, if the time zone (including whether
daylight savings time or standard time is used) is defined in the communications protocol, the BA, RC
or TOP should not be required to expressly state the time zone and indicate whether the time is
daylight savings time or standard time when issuing an Operating Instruction. Southern utilizes a
common EMS system and “Operating Time” (which addresses the applicable time zone and whether
daylight savings time or standard time is used) for operational communications. This “Operating
Time” is understood by the entities within the Southeastern RC area. Thus, this established protocol
provides for a uniform and clear understanding for all functional entities. As such, Southern suggest
that if entities have mutually agreed upon a protocol (e.g., an “Operating Time”) and this operating
time is defined in the documented communications protocols, the BA, RC or TOP should not be
required to expressly state the time zone when issuing an Operating Instruction. Therefore, in order
to remove any ambiguity, an unnecessary risk to reliability and to insure that the standard is
consistent with the SDT’s statements, we suggest the following language: “Use of a mutually agreed
upon operating time, or in the absence of a mutually agreed upon operating time, use of the time, the
time zone and indication of whether the time is daylight saving time or standard time when issuing an
oral or written Operating Instruction that refers to clock times between Functional Entities in different
time zones.” In addition, Southern believes that the requirements under Requirement R1, subpart 1.5
are too prescriptive and may create an unnecessary burden on Balancing Authorities, Reliability
Coordinators and Transmission Operators. Instead, it would be more appropriate to require that the
protocol clearly address the format to be used when communicating oral Operating Instructions. In
the event the issuer must reissue the Operating Instruction under subpart 1.6, at that point, if the
Facility or Element is in alpha-numeric format as set forth in subpart 1.5 (i.e., “12B”), the issuer
would then be obligated to say “one-two Bravo”.
Individual
David Jendras
Ameren
No
(1) We request for the SDT to clarify the portion of the definition of Operating Instruction which reads
“Discussions of general information and of potential options or alternatives to resolve BES operating
concerns are not commands and are not considered Operating Instructions”. (2) We believe that an
Operating Instruction should serve a reliability need. For example, instructions given that are based
on economics, should not be included. To be absolutely clear, each Operating Instruction should
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
always be identified, by BA, RC, or TOP, that, “this is an Operating Instruction" when issuing such an
instruction.
No
(1) We request that this be re-written to clarify what "implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols" means? What is required of
an entity? Does the SDT mean the communication protocols or the manner that identifies assesses
and corrects deficiencies? Can this be broken into two sentences? We would also note that
implementing in a manner that identifies assesses and corrects deficiencies implies two requirements;
implementation and deficiency correction. If that is required of entities for compliance in an RSAW or
audit, the SDT should separate these two requirements in order to explicitly define what is necessary.
(2) In addition we believe that the nine subsections in R1 are too prescriptive. The wording "that
includes the following" should be changed to say ", that address the following".
No
(1)We believe that the VSLs for the requirement are too severe. We request that the VSL table for
VRF #2, the Violation Severity Levels should read as follows: (a) Lower VSL - The Responsible Entity
documentation protocol does not include one of the following in R2: a manner that identifies or
assesses or corrects deficiencies for R2.1 and/or R2.2. (b) Moderate VSL - The Responsible Entity
documentation protocol does not include two or more of the following in R2: a manner that identifies
or assesses or corrects deficiencies for R2.1 and/or R2.2. (c) High VSL - The Responsible Entity
documentation protocol does not include R2.1 or R2.2. (d) Severe VSL - The Responsible Entity does
not have a documented communication protocol. (2) In addition, we disagree with the explanation of
why the VRF for both R1 and R2 were changed from "Low" to "Medium" and believe that these
continue to be administrative requirements justifying a "Low" VRF.
(1) The Responsible Entities addressed in R1 should be directed to state when giving an Operating
Instruction (OI) to a GOP or DP in R2 whether or not a requested action would be deemed an OI. (a)
The reason for this is that GOPs receiving OIs are not able to see the BES and therefore would not
know if a call by the TOP, RC or BA would be considered an Operating Instruction. (b) If this is not
stated a GOP or DP could consider all communications received from the RC, BA and TOP as Operating
Instructions and this would create an undue burden on both RE’s in R1 and R2. We do not believe this
was the intent of the SDT or of this standard. (2) It is not clear from the proposed RSAW what will be
audited and how it relates to the actual requirements; the RSAW states: “Review a sample of the
entity's Operating Instructions to verify whether the entity is implementing its documented
communication protocols”. Are the Operating Instructions actually being audited? We are under the
impression that the entities "identifying, assessing and correcting", was the requirement. We believe
what is being audited is not clear between the Standard and the RSAW and the requirement should be
re-written for clarity of intent.
Group
Northeast Power Coordinating Council
Guy Zito
No
The proposed definition as worded can be misconstrued to mean a command made by System
Operator to a Reliability Coordinator, or to a Transmission Operator, or to a Balancing Authority.
Propose to change the wording to the following: Operating Instruction —A command by a Reliability
Coordinator System Operator, a Transmission Operator System Operator, or a Balancing Authority
System Operator, where the recipient of the command is expected to act, to change or preserve the
state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. Discussions of general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating Instructions.
Yes
Yes
Functional entity is capitalized throughout the Standard, yet functional entity is not a defined term in
the NERC Glossary. Propose changing the wording in Requirement R1 to the following: R1. Each
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Balancing Authority, Reliability Coordinator, and Transmission Operator shall have documented
communication protocols that include identification, assessment, and correction of deficiencies for
Operating Instructions between functional entities that include the following: [Violation Risk Factor:
Medium [Time Horizon: Long-term Planning ] The Sub-requirements introduce too much detail into
the Standard. This detail dictates “how” something is to be done, rather than “what” is to be done.
Following are comments to be considered on the sub-requirements should they remain in the
Standard. Propose changing the wording in Sub-requirement 1.1 to the following: 1.1. Use of the
English language when issuing or responding to an oral or written Operating Instruction, unless
another language is mandated by law or regulation or agreement. Propose changing the wording in
Sub-requirement 1.3 to the following: 1.3. Use of the time, the time zone where the action will occur
and indication of whether the time is daylight saving time or standard time when issuing an oral or
written Operating Instruction that refers to clock times between functional entities in different time
zones, unless time protocols are defined in written agreements between the functional entities.
Regarding Sub-requirement 1.5, the use of alpha-numeric clarifiers should be no more than a best
practice. In case of uncertainty, 3 part communication as specified in Sub-requirement 1.6 would
catch any ambiguities. Propose changing the wording in Sub-requirement 1.8 to the following: 1.8.
When issuing an oral Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (for example an all call
system), verbally or electronically confirm receipt or that communications paths were established to
receive the message from one or more receiving parties. Regarding the Time Horizons for
Requirements R1 and R2, they should be Real-time Operations since the communications are
occurring in real time, and the implementation of the protocol is the intent of R1 and R2. Suggest that
the Standard be further clarified so that the intended purpose is to ensure that an entity has
implemented a communications protocol with various core attributes, such as three part
communication. We believe that it is not the SDT's intent that an entity will be found out of
compliance for instances when an operating instruction was given which did not conform to its
implemented protocol. Compliance will only be assessed if the Protocol procedure itself was not
formally implemented and not to individual violations of such procedure which will be handled by
internal controls to track and address any deficiency. In the context of implementation, sufficient
implementation as used in this Standard could be demonstrated by management approved protocol
procedures issued to the appropriate individuals in the organization and documented training. The
Standard is not envisioned to be a zero-defect Standard however, and unless entities and audit staff
have clear understandings of what "implement" means there may be instances when an auditor may
find non-compliance beyond the intent of the Standard's Purpose and the Reliability Assurance
Initiative concept being brought forward with this Standard. Suggest clarification to the word
implement as it is used in the Standard and what activities in the compliance area will ensure proper
audit expectations are set.
Individual
Thad Ness
American Electric Power
No
While AEP would not argue against the definition of “Operating Instruction” as proposed, we object to
its inclusion as we disagree with the concept of requiring three part communications for more routine
operations. Our efforts in this regard should first be focused solely on Reliability Directives before
expanding this work, and creating similar requirements for all other Operating Communications.
Requiring three part communications for every scenario might be considered a best practice by some,
but making it a mandatory practice for routine operations emphasizes the manner of communications
rather than the operations themselves. In addition, requiring three part communication in such a
broader scope could actually diminish the perceived urgency during more urgent situations where
such communications are more appropriate. In any event, requiring three part communications for
Reliability Directives will likely result in more widespread usage for more routine operating
communications, without making it a requirement.
No
AEP disagrees with the concept of requiring three part communications for more routine operations,
and as a result, also disagrees with requiring both that entities have documented communication
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
protocols, as well as implement a process for identifying deficiencies with adherence to the
documented communication protocols specified.
No
AEP disagrees with the concept of requiring three part communications for more routine operations,
and as a result, has no comment at this time on the proposed VRF's and VLS's.
AEP does not agree with the perceived necessity of this standard, but does support the overall
concept of the drafting team’s building controls into the standards as well as proposing RSAWs during
the comment that perpetuate the ideas and concepts of the drafting team. As stated in the previous
comment period, AEP believes that there should not be multiple project teams proposing concurrent
changes to COM-001, COM-002, and COM-003. Unless there are overwhelming reasons for not doing
so, these efforts should be consolidated and managed by a single project team. In addition, current
efforts on COM-003 need to be co-located with the proposed changes to COM-002 within a single
standard. Having multiple project teams proposing concurrent changes results in problems such as
this, where a) changes are proposed to the same standard or b) similar changes are proposed to
separate standards. AEP cannot support revisions on these matters until they are managed by a
single project team.
Individual
Greg Froehling
Rayburn Country Electric Cooperative
No
I feel that an additional term is unnecessary. The defined term "Reliability Directive" should be
sufficent to accomplish the goal.
No
I feel that this could lead to very inconsistent auditing on not only this standard but CIP version 5 as
well. My thoughts on identification, assessment and correction of deficiencies may certainly not be
that of the auditors thus leading to the potential for a NOPV. I suggest language to the affect "shall
implement communication protocols in accordance with NERC guidelines for internal controls......."
No
The Responsible Entity did not implement, in a manner that identifies, assesses and corrects
deficiencies, their documented communication protocols as required in Requirement R2 Suggest to
allow for a less subjective audit envitronment. The Responsible Entity did not include methods for,
identifying, assessing and correcting deficiencies, in their documented communication protocols as
required in Requirement R2
Combine with COM-002 ASAP Really take a close look at how R2.2 is worded. State clearly the
recipient is to call the sender back after the call if they did not understand. Require the sender of the
blast call to issue contact information if questions arise. Blast calls do not fit Mcdonalds three part
communication model so often used.. Blast calls are very efficient just that not a precision
communication tool by any means..
Group
pacificorp
ryan millard
Yes
Yes
No
It is not clear to PacifiCorp why the VSLs are so much higher for R2 when R1 applies to Balancing
Authorities, Reliability Coordinators, and Transmission Operators, and thus has a potentially broader
application than R2. R2 applies to Distribution Providers and Generator Operators.
PacifiCorp does not feel that the requirements listed in R1.5 regarding the use of alpha-numeric
clarifiers when issuing an oral Operating Instruction is warranted. The requirements listed in R1.6,
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and R1.7 requiring the strict use of three-way communication should alleviate any possibility of
miscommunication, which PacifiCorp understands to be the drafting team’s intent in the development
of separate Requirement R1.5. Also, implementing the use of alpha-numeric clarifiers poses additional
risk due to the introduction of ambiguous language.
Group
Tennessee Valley Authority
DeWayne Scott
Agree
SERC OC Standards Review Group
Individual
Russ
Flathead Electric Cooperative, Inc.
Agree
Support previous comments submitted by Central Lincoln, do not believe the comments were
adequately addressed as the SDT refused to incorporate language suggested for DPs with few BES
assets.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery - NERC Reliability Compliance Coordinator
No
While AECI deeply appreciates and has carefully considered this SDT's latest effort to contain scope of
this definition, we feel it still fails to appropriately balance the risk to the BES, against anticipated
Industry compliance assurance costs as well as non-compliance risks. This is primarily due to an
anticipated high-volume of very low BES impact Operating Instructions within our own operating
environment.
Yes
AECI appreciates the SDT's willingness to move away from zero-defect language.
No
So long as DPs, GOs, small TOs and small BAs are within the scope of this Standard, and the scope of
Operating Instruction does not necessarily impact BES reliability, any Severity or Risk assessment
greater than Low, forces an Entity's risk of non-compliance with documentation far above actual risk
to the Bulk Electric System. AECI cannot agree with such inequity.
AECI remains resolute that COM-002 provides a more appropriate balance between BES reliability
risks associated with human-to-human communications within our industry, and industry costs to
monitor for compliance with required communication practices.
Group
ACES Standards Collaborators
Ben Engelby
No
(1) We appreciate all of the efforts the drafting team has expended in developing this proposed
standard The drafting team has done an excellent job in balancing the various diverse opinions and
interests. We believe the standard is moving in the right direction; however, we still believe there are
additional needed improvements. Another round of commenting and balloting may be necessary to
capture all stakeholder viewpoints. (2) The current definition of Operating Instruction, particularly
“command from a System Operator” is too similar to a Reliability Directive. (3) We recommend the
standard drafting team revise the SAR of COM-003-1 to retire the definition of Reliability Directive and
COM-002-3. There is no better time to rewrite the standards than when they are in development. (4)
There is no delineation between when COM-003-1 and COM-002-3 would apply, which could
potentially subject registered entities to double jeopardy. Assume a switching order is an Operating
Instruction; would those communications become a Reliability Directive if the switching order resulted
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in an emergency or was part of a standing operating guide to resolve the emergency, or would it still
be an Operating Instruction? There is still gray area in this standard that needs to be clarified. We
appreciate the slides that were shared during the recent webinar; however, the words in the current
definitions do not clearly state when an Operating Instruction ends and a Reliability Directive begins.
(5) A “command” is a synonym of a directive, not an instruction. We recommend revising the
definition to capture the proper intent of the standard. (6) We find the use of input of an Element odd
in the Operating Instruction definition. We understand the output of an Element such as the MW
output of a generator? However, we are not sure what is intended by the input of an Element? What
would the input be on Element? For a generation unit, does the fuel supply constitute input? It would
be unusual for a TOP, BA, or RC to issue an operating instruction regarding fuel. For what would be
the input on a transformer, transmission line, circuit break, bus section, etc. that a TOP, RC or BA
would issue an operating instruction? (7) The “expected to act” and “preserve the state, status, …”
parts of the definition conflict with one another. If an entity is preserving the state or status, action
often is not required. For example, would an operating instruction ever be issued to maintain a circuit
breaker in the closed position? No action is required in such a situation? When would the drafting
team anticipate action to be required to maintain the state, status, output or input? Are these parts
intended to cover anticipation by the BA, TOP or RC that the state, status, output or input may move?
For instance, if a generator is expected to ramp up based on the unit commitment and dispatch plan
but the BA, TOP, or RC determines that the units needs to maintain its current output. We think some
explanation and/or examples in a guideline section would be helpful.
No
(1) We agree with the drafting team’s decision to remove Requirements R3 and R4, as they were
unnecessary. However, we still have concerns with the standard as our comments explain below. (2)
We recommend that the SDT consider removing or revising the sub-parts of R1 and R2 to allow
registered entities flexibility to define their own communications protocols based on internal policies
and procedures. The registered entity should have the freedom to decide what elements are to be
included in its communication protocols based on its system, location and configurations. A large
entity may have more elements in their communication protocol than the 9 sub-parts, while a small
cooperative may need less because of their impact on the BES. We would like the SDT to reconsider
each sub-part and revise the requirements in such a way that allows more flexibility for smaller
entities, while possibly requiring other registered functions, such as an RC to have more elements in
their communication protocols. There is more discussion on each sub-part below. (3) R1, part 1.1,
use of the English language. This Part either needs to be eliminated or restructured to place the
burden only on those entities that are from areas of North America where English is not the
predominant language. The amount of resources expended documenting compliance with this
requirement simply is not commensurate with the reliability benefit. There have been audits
conducted in which every piece of evidence was presented in English, all audit participants used
English exclusively, and control room conversations witnessed by auditors were in English. Yet, when
the time came to sign off on compliance with this requirement, auditors expected to find inclusion of a
statement in procedures that the English language was not used. Please eliminate this unnecessary
expenditure of resources by eliminating the requirement or only requiring those areas where English
is not the predominant language to include this in their communication protocols. (4) R1, part 1.3,
Use of time zone and Daylight Savings or Standard Time. Contrary to the statements in the response
to comments this sub-part prevents the use of relative time, such as “perform an action in 5 minutes”
or at the very least complicates it with superfluous information. Specifically, this requirement compels
the use of the time zone and daylight savings times in all Operating Instructions. While its does not
specifically exclude that RC, BA or TOP from stating that an action must be performed in 5 minutes, it
would require the RC to include the time zone and whether it is Daylight Savings or Standard time.
For example, the TOP would have to say, “Open breaker one in five minutes in the CST time zone.”
This does not make sense. (5) R1, part 1.4, Transmission interface Element or Facility. The language
used in this sub-part is overly complex. Specifically, the statement “unless another name is mutually
agreed by the Functional Entities” is problematic. If that is the case, the mutually-agreed upon name
obviates the need for having the sub-part. Also, Project 2007-03 eliminated TOP-002 R18 which
referred to the same concept as part 1.4, “uniform line identifiers when referring to transmission
facilities.” The reason the Real-time TOP SDT removed the language from the new standard was
because the “requirement adds no reliability benefit. There has never been a documented case of the
lack of uniform line identifiers contributing to a System reliability issue.” To be consistent with other
approved standards, we recommend striking this sub-part in its entirety. (6) R1, part 1.8 and 1.9,
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One-way Burst Messaging. The drafting team should revise this sub-part to state that compliance with
this sub-part is optional, depending on whether the entity utilizes burst messages. These sub-parts
need additional information for clarity. Same comment for DP/GOP below.
No
(1) We disagree with the VRF classifications being medium. We ask the drafting team to clarify why
they decided to raise the risk factor when the requirement still addresses the same activity. Further,
with internal controls, this requirement should be low because the majority of deficiencies would not
have an adverse impact on the reliability of the BES and would not result in a violation. It appears
that the VRF was raised to medium because R3 and R4 were medium and now are incorporated into
R1 and R2. We disagree with the justification that correcting deficiencies warrants a medium risk
factor. This is illogical and argues that every requirement that includes the “assess, correct, identify”
language should be medium. Further, it does not seem consistent with the next paragraph. (2) We
disagree with the Time Horizons for R1 and R2. Implementing communications protocols are not long
term planning, these activities are operations planning. The requirement is no longer a documentation
requirement, this is an operations planning requirement. Furthermore, the communications that are
governed by the document occur in the real-time operations time frame. Using the logic that is
applied to identify long-term planning as the time frame means that every requirement that will be
monitored via internal controls and subject to the “identifies, assesses and corrects” language will be
long term planning. This makes no sense and is inconsistent with the approach of the CIP SDT. CIP
standards have requirements that did not have the long-term planning horizon. CIP-003-5 R2 is one
example. (3) There was a lot of discussion in the recent drafting team webinar about Regional
auditors not finding a violation, but there needs to be clear guidelines describing when an auditor will
find a PV. The VSLs currently describe a violation when a procedure is deficient, but does not clearly
explain when a communication deficiency is not remediated. A deficient communication could result in
no finding at all, depending on how the individual auditor interprets the situation. This level of
subjectivity is too high; the SDT needs to revise the VSL table to reflect a more reasonable approach,
perhaps by including more information and examples of situations that might be viewed as noncompliance (communication breakdown) but because of internal controls, there should be no finding
of non-compliance. In the alternative, the SDT could develop a guidance document outlining when an
auditor is to find a PV and include examples to ensure consistency. The RSAW does not provide any
additional clarity. (4) In the webinar, there were several references to “systemic or chronic”
communication deficiencies. The VSLs do not reference any types of trends, but that seems to be the
focus of compliance. We suggest revising the VSLs to focus on broader issues, such as systemic
deficiencies that remain unresolved. Furthermore, this would make the VSLs more consistent with the
data retention section which focuses on retaining “evidence of its manner that identifies, assesses,
and correct deficiencies.”
(1) In the Background section of the standard, we would like the standard drafting team to provide
more details on what “compliance management activities” include as stated in the last sentence of the
section. We would like the team to provide examples of these activities for clarity. (2) We support the
concept of internal controls that the SDT has proposed. We agree that finding a violation for each
instance of deviation from the requirement is burdensome and unreasonable and evaluating internal
controls is a more efficient use of resources. However, we are concerned about the consistent
evaluation of internal controls. How is NERC planning to ensure that all Regional auditors consistently
evaluate internal controls during compliance audits? Currently, there is too much room for auditor
subjectivity, especially when evaluating whether a single communication was deficient. There are so
many communications that could occur on a daily basis and there is no clear guidance when the
Regional Entities will find or not find a possible violation in an audit. (3) In the webinar, SDT chair
stated that a registered entity that catches a high percentage of deficiencies, then their process is
working, but if the entity is only catching 50% then the entity needs to correct the process. There is
currently no percentage or other guideline or metric to determine if an entity’s process is sufficient. If
this is the SDT’s intent, please provide further detail. (4) We recommend the SDT provide additional
information in the Rationale and Technical Justification document or in an application guidelines
section of the standard to include a guideline to show how the Regional auditors would assess
compliance with a control-based standard. It seems that the trend in both COM-003-1 and CIP v5 is
to find the errors and fix them without the need to self-report. How are the Regions going to
determine when a PV is to be issued? The Technical Justification and the RSAW do not provide enough
information when a communication deficiency crosses the threshold of becoming a violation. How
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does a registered entity know when to self-report? (5) We recommend adding more detail, perhaps
including an application guidelines section as other risk-based standards, for acceptable remediation
of deficient communications. What evidence is necessary that the registered entity identified,
assessed, and corrected a deficiency with the communications protocol? The data retention section
only requires the manner in which the entity identifies, assesses, and corrects to be documented. It
does not require retention of any actual instances. We believe this is appropriate and that a few
examples of corrections as supporting evidence may be warranted. However, there is no explanation
in the standard that makes this clear. An application guideline would be useful in providing an
explanation. Without these explanations, the internal controls used to remedy deficiencies could turn
into another documentation exercise instead of focusing on effective communication. We recommend
the SDT consider ways of satisfying remediation without creating an unnecessary administrative
burden for maintaining evidence of compliance. (6) If the Regional auditor is to make
recommendations to registered entities on how to improve the COM-003-1 internal controls, would
the Regions allow an initial safe harbor to assess the entity’s program? If Regional auditors find PVs
on the initial audit, that practice would go against the spirit of self-correcting and would stifle the
entity’s actions to monitor, assess, and correct deficiencies. The SDT should consider this sort of
initial assessment in the implementation plan. (7) The response to comments regarding combining
COM-002 and COM-003 beyond the scope of the SAR. The comments also cited that the Standards
Committee considered combining them. It is our understanding that the Standards Committee
rejected SARs to consider combining the standard projects because they were not driven from within
the standards drafting team. Scopes can be adjusted by submitting new SARs and SDTs have
authority to submit new SARs. If the SDT agrees that combining the standards makes the most sense
for reliability, please submit a SAR to combine the standards. (8) Thank you for the opportunity to
comment.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
Yes
Yes
AZPS has no other comments.
Individual
Randi Nyholm
Minnesota Power
No
Minnesota Power supports moving away from zero-defect Requirements, but as currently written the
language “in a manner that identifies, assesses and corrects deficiencies” does not allow for the
identification of deficiencies without the assessment of a severe severity level within the VSLs. We
recommend that, at a minimum, the VSLs be modified to allow for this flexibility similar to what was
done in the CIP Version 5 Standards.
No
The Standard does not state that switching is only required when issuing instructions for
interconnected systems and not for the day to day switching on our system as was stated during the
recent COM-003 webinar. Additionally, we do not support the use alpha numeric identifiers to solve a
perceived problem that does not exist on our system.
Individual
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andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
ATC respectfully submits the following comment for SDT’s consideration regarding Draft #4 of COM003-1: (Ref. Redline for Requirement 1.3 below) 1.3. Use of the time, the time zone where the action
will occur and indication of whether the time is daylight saving time or standard time wWhen issuing
an oral or written Operating Instruction that refers to clock times between functional Functional
entities Entities in different time zones, when referring to clock times include the time, the time zone
where the action will occur and indicate whether the time is daylight saving time or standard time.
ATC recommends Requirement 1.3 above be revised and/or rewritten as follows: 1.3. “Use of a
mutually agreed, prevailing system time zone when issuing an oral or written Operating Instruction
between Functional Entities in different time zones.” Basis for the comment • The need for time
conversion when Operating the BES, injects an opportunity for an error that could potentially cause
unintended System configuration, or even an Adverse Reliability Impact. Protocols should be set to
eliminate those negative opportunities.
Individual
Larry Watt
City of Lakeland
Agree
Florida Municipal Power Agency (FMPA)
Individual
Jim Cyrulewski
JDRJC Associates
Agree
Midwest ISO
Group
Imperial Irrigation District (IID)
Jesus Sammy Alcaraz
Yes
Yes
Yes
Revise the following sub-requirement. 1.4. Delete "name" and include...Uniform Line Identifier(s)
specified by the owner(s) for each Transmission interface Element or Transmission interface Facility
when referring to a Transmission interface Element or a Transmission interface Facility-in an oral or
written Operating Instruction , unless another name is mutually agreed to by the Functional Entities.
Individual
Patrick Brown
Essential Power, LLC
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1. The expression, “repeat, restate, rephrase, or recapitulate,” in R. 1.7 and R2.1 would be clearer if
shortened to, “repeat or summarize.” 2. The revised standard is much improved by focusing on
continuous improvement instead of making each communication imperfection a violation, but no
guidance is provided as to how rigorous the improvement program must be to be deemed sufficient.
M1 and M2 should have added at the end the statement, “Acceptable means of identifying, assessing
and correcting deficiencies include the following: • Review of voice logs, for at least one hour per year
for each person issuing commands or responses (as applicable) • Personal monitoring of
communications, for at least one hour per year for each person issuing commands or responses (as
applicable) • Annual refresher training, including a quiz on proper commands or responses, for each
person issuing commands or responses (as applicable) (as applicable) 3. Failures of GO and DP
operators to repeat or summarize Operating Instructions are easily detectable (R2.1); but it would
not ordinarily be possible for a person monitoring COM-003 compliance to detect a lack of
understanding accompanied by failure to request a clarification (R2.2), since the resultant silence on
the part of the operator is the same reaction associated with clearly understanding the Operating
Instruction. M2 should be shortened to, “Evidence must include each applicable entity’s documented
communications protocols, which must include a provision requiring the recipient of an operating
instruction to seek clarification from the initiator in the event of an unclear instruction.” 4. From the
RSAW: “If the CEA finds in subsequent audits or other compliance monitoring activities that the same
or similar deficiencies continue to occur after the entity was provided the feedback by the CEA, the
CEA will seek to understand what changes the entity made based on prior recommendations. If the
entity did not implement changes to identify, assess and correct deficiencies, the CEA may make a
determination of possible non-compliance” The issue here is potential for disagreement on
“deficiencies”. There are some conversations between GOPs and TOPs which are market driven, but
could be read by an auditor as an “operating instruction”. Some adjustment to the definition of
“operating instruction”, or some adjustment to the requirement that an entity address the
“recommendation” from the region, may be in order here.
Individual
John Falsey
Inevenergy LLC
Yes
Yes
Yes
Individual
Daniel Duff
Liberty Electric Power
No
This needs further work. As written, there is still potential for a TO to call a GOP to address a market
concern, and trigger the standard. Discussions which are purely for market concerns are not properly
part of the standards, but an auditor could read such conversations as "Operating Instructions".
Suggest that there be a specific clause excluding such discussions from the definitions.
No
The revisions proposed are a significant positive step, and I thank the SDT for their work. However,
there are still some issues with the proposed requirements. Requirement 2.2 states "When receiving
an oral Operating Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all call system), request
clarification from the initiator if the communication is not understood.". This requirement cannot be
audited as written, as there is no way to determine if a communication is understood by a particular
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operator. Further, the concept of three-part is to allow the initiator to determine if the instruction is
understood. Instructions disseminated across an All-Call are understood to be crafted in such a way
as to avoid such misunderstandings. Suggest elimination of R 2.2, and suggest adding language to
the RSAW that considers protocols for resolving misunderstandings as a mitigating factor in
determining the sample size pulled for audit purposes. R1.8 as written would only require the issuing
entity to confirm receipt from one entity. Receipt confirmation is not needed in a standard written to
cover understanding communications, and the requirement should be eliminated.
No
A BA who excludes three-part communication requirements from their communication protocols is
assessed a lower VSL. A GOP who does exactly the same thing is assessed a High VSL.
The need for this standard still has not been demonstrated, and will merely add paperwork and
confusion due to the existence of COM-002, and the questions which will inevitably arise over which
standard, or if any standard, covers any particular conversation. The SAR should be withdrawn and a
new SAR requiring a communications protocol designed to "mitigate the possibility of
misunderstandings during communications between entities" should be added.
Individual
Michael Falvo
Independent Electricity System Operator
No
The IESO does not have an opinion on whether or not the definition is proper; the IESO is opposed to
having this term defined and added to the NERC Glossary. As indicated in our previous comments, the
term does not need to be defined. For years, system operators deal with operating instructions on a
daily if not minute basis. Having a defined term, and calling such communication as “Command” is
unnecessary, and can confuse operators from what they understand to be the meaning of operating
instructions. We appreciate the SDT’s response to our previous comments, and its effort to add
clarifying language by adding the second, qualifying sentence. In fact, the additional clarifying
language may cause more confusion to the operators than the purpose it is intended to serve. We
therefore continue to respectfully disagree with the need for this definition and the standard as a
whole, in particularly the requirement on 3-part communication for operating instructions. We
continue to disagree with the need for this standard on the basis that the industry-approved COM-002
together with the NERC OC’s operating guide on operator communication already provide the
necessary requirements and guideline to fill any potential reliability gaps that may arise due to
operator communication. Requiring 3-part communication for routine operating instructions, despite
the additional wording in R1 (“in a manner that identifies, assesses and corrects deficiencies”) and
provisions made in the RSAW, is still a zero defect requirement that would add undue burden to the
operators, which is a potential cause of unreliable operations. We therefore continue to disagree with
the need for this standard as it adds little to reliability over what COM-002 and the operating guide
have already accomplished.
No
Notwithstanding our disagreement with the need for this standard, the phrase “in a manner that
identifies, assesses and corrects deficiencies” is vague, not measurable and inconsistent with the
results-based standard concept which emphasizes the inclusion of a performance or reliability
outcome in the requirement. A more direct and clear requirement would be to simple require
“implement documented communication protocol….”. We appreciate the SDT’s intent for adding this
phrase, but it does little to ease the concerns of the commenters. Instead, the addition introduces an
immeasurable phrase that may in fact make the requirement more ambiguous and unclear.
No
As expressed previously, we continue to respectfully disagree with this standard and therefore we
continue to disagree with the VRFs and VSLs.
a) We appreciate the SDT’s hard work and dedication to develop this standard in response to the SAR
and the recent BoT directives. Unfortunately, the need for this standard has been overtaken by event
(the definition of Reliability Directives and COM-002-3, and the OC’s operating guide on operator
communication). The BoT, unfortunately, is still under the perception that COM-003 is the answer to
the potential reliability gap that was discussed when it approved the COM-002 R2 interpretation. The
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two balloting results and the two sets of industry comments suggest that many in the industry share
our view. Hence, we believe the industry should attempt to convince the BoT that the potential
reliability gap has been duly addressed and therefore COM-003 is no longer needed. We understand
the SDT has little to no option, we therefore suggest that the SDT present the results of this round of
ballot, if it still fails to make the 2/3 approval rate, to the Standards Committee and ask for its
permission to put a hold on further work until the BoT has heard the industry’s concern and makes a
policy decision on the way forward. Further revision to this standard and posting for industry
commenting and balloting will only waist the SDT’s effort and industry resource, without a fruitful
outcome. b) Notwithstanding the above, the proposed implementation plan conflicts with Ontario
regulatory practice respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after “applicable regulatory approval” in
the Effective Dates Section (P. 2 of the Implementation Plan) and in Section A5 of the standard, to
the following effect: “, or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.”
Group
Duke Energy
Greg Rowland
No
The revised definition still lacks clarity needed to distinguish Operating Instructions from Reliability
Directives. The SDT revised definition of Operating Instruction is too wordy and adds significance by
using the word “command” versus “communication” as is used in the definition of Reliability Directive.
Including the phrase “preserve the state” also adds significance and could be interpreted as an
Emergency and take on the meaning of a Reliability Directive. The definition should not include the
second part regarding what is not considered an Operating Instruction. The definition of Operating
Instruction should be patterned after the BOT approved definition of Reliability Directive, with the only
difference being that Operating Instructions address normal system conditions and Reliability
Directives address an Emergency or Adverse Reliability Impact. Suggested wording: “Operating
Instruction — A communication initiated by a Reliability Coordinator, Transmission Operator, or
Balancing Authority, where the recipient responds to a request to take action by changing the status,
output, or input of an Element or Facility of the Bulk Electric System under normal system
conditions.”
No
In Requirements R1 and R2, the word “include” should be changed to “address”. This change will align
the language of the requirements with the language of the RSAW, providing flexibility to entities in
how their communications protocols will be structured. For example, on page 3 of the Comments
Report, in reference to use of the 24-hour clock, the SDT states: “The SDT points out in this response
that these protocols are to be used only when a specific clock time is cited. The SDT accepts relative
time such as: “ in the next 10 minutes, on the hour or half hour” as clear and unambiguous and not
requiring the use of the 24 hour clock and time zone references.” However it’s not clear to us that
R1.2 and R1.3 allow that flexibility.
No
Consistent with our comment to Question 2 above regarding changing the word “include” to “address”
in Requirements R1 and R2, this change should also be made in the VSLs for R1 and R2, changing the
word “include” to “address”.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
SCE&G's supports the SERC OC in the following response "We believe that the definition should
indicate the timeframe in which the entity “is expected to act.” We believe that this language is too
wide and can be interpreted in many ways. Furthermore, we continue to believe that prescriptive
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communications protocols are unnecessary for routine Operating Instructions. Many Operating
Instructions, such as economic loading of resources, do not have a reliability impact to the BES and
the entities should not be held accountable to the requirements of this standard."
No
SCE&G support the SERC OC in the following response" We believe that the requirements should
clearly list which Functional Entities when the communications protocols should be utilized, for
example, what happens when one of the five Functional Entities listed in these two requirements give
an Operating Instruction to an entity not listed. Note that the question incorrectly references R2 which
include the DP and GOP. Furthermore, while we agree with the concept of identifying, assessing, and
correcting deficiencies, we continue to believe a prescriptive use of the word “include” should be
removed. We would suggest using the word “consider” or “address.”
No
SCE&G supports the SERC OC in the following response "We disagree with the explanation of why the
VRF for both R1 and R2 were changed from “Low” to “Medium” and believe that these continue to be
administrative requirements justifying a “Low” VRF."
SCE&G is concerned with similarities between Operating Instructions and Reliability Directives. It also
appears that the language in the RSAWs would require an entity to keep a log of all Operating
Instruction. This would be overly burdensome to the industry and is not included in the requirements.
Individual
Patricia Metro
National Rural Electric Cooperative Association (NRECA)
No
NRECA is concerned that the proposed definition of an “Operating Instruction” is too similar to the
definition of a “Reliability Directive” specifically with the inclusion of “command from a System
Operator”.
No
NRECA agrees with the decision to remove R3 and R4 from COM-003 draft 4, but is concerned with
the incorporation of the internal controls language in R1 and R2. These changes don’t resolve the
concerns provided in comments to the previous draft of the standard. Although internal controls are
important, NRECA believes that before such language is added to standards guidance/criteria needs
to be developed on how Regional Entities will consistently review internal controls during compliance
audits. NRECA suggest removing the language “implement, in a manner that identifies, assesses and
corrects deficiencies” until the Reliability Assurance Initiative (RAI) effort to change the
compliance/enforcement process to be more focused on a risk-based model and the effectiveness of a
registered entity’s internal controls/compliance program is implemented.
Individual
Wryan Feil
Northeast Utilities
Agree
Northeast Power Coordinating Council Inc. (NPCC) 1040 Avenue of the Americas 10th Floor New York,
NY 10018
Group
Dominion
Connie Lowe
Yes
Yes
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Individual
Anthony Jablonski
ReliabiltiyFirst
Yes
Yes
a. ReliabilityFirst generally agrees with the language in R1 and R2, but believes the intent would be
clarified if the structure of the words were shifted around. ReliabilityFirst recommends the following
language for R1 for consideration (R2 would be similar): “Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall implement its documented communication protocols for
Operating Instructions, in a manner that identifies, assesses, and corrects deficiencies, between
Functional Entities that include the following:”
Yes
ReliabilityFirst abstains and offers the following addtional comments for consideration: 1. Requirement
R1 and R2 Time Horizons a. ReliabilityFirst believes the Time Horizons (Long-term Planning) for
Requirement R1 and R2 are incorrect. Requirement R1 and R2 deal with implementing communication
protocols for Operating Instructions which is more of a real time activity. Thus ReliabilityFirst
recommends changing the Time Horizons to “Real-time Operations” or at a minimum “Same-day
Operations” or “Operations Planning”. 2. The term Functional Entity a. Since the term “Functional
Entity” is used throughout the standard, ReliabilityFirst recommends adding the word “applicable” in
front of it to help clarify that it is referring to the Functional Entities as outlined in the Applicability
Section. Without this distinction, individuals my think this term is referring to all Functional Entities as
outlined in the NERC Function Model.
Individual
Michelle R. D'Antuono
Occidental Energy Ventures Corp (OEVC)
Yes
OEVC believes that the clarifications that the drafting team has added to the definition of Operating
Instruction are helpful. First they have eliminated ambiguity concerning which entities would issue
such instructions – in a manner consistent with their function. In addition, we agree with the addition
of the statement excluding those conversations which would not be considered an Operating
Instruction. This allows us to differentiate between those communications which require action from
those which are less consequential; improving the chances that the proper care is applied when
reliability information is exchanged.
Yes
OEVC agrees that reliability is not best served by Compliance focus on the execution of every
Operating Instruction in 100% accordance with the communications protocol documents. The
attainment of perfection is always the ideal, but not realistic in any operating environment.
Conversely, the establishment of high, but attainable, internal controls effectiveness goals is a proven
method used in other industries to drive down process defects.
Yes
Since the execution of the internal controls process is part of COM-003-1’s intent, OEVC believes it is
appropriate that R1 and R2 be assigned a Medium VRF.
Although we believe that the latest version of COM-003-1 is ready for adoption by the NERC BOT,
OEVC cannot approve the standard until the RSAW is also completed. In our view, the addition of the
new risk-based language is the only reason that COM-003-1 is acceptable – but is incomplete without
a fully vetted RSAW. There are still too many questions that remain about the audit process – and the
success of the entire program hinges on its implementation.
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Individual
Melissa Kurtz
US Army Corps of Engineers
Agree
MRO NSRF
Group
seattle city light
paul haase
Yes
No
Seattle City Light commends the Standard Drafting Team on the changes to draft Standard COM-0031, in particular the use of non-zero defect language that is the same as used in the CIP v5 Standards.
Use of common language will help entities apply the new “identify, assess, and correct” approach
consistently across Standards. Common language also will help ensure that regulators audit the new
approach consistently. Seattle City Light is concerned, however, with the Standard Drafting Team’s
use of the term “Functional Entity” as establishing the bodies among which communications must
meet the requirements of COM-003-1. Seattle has several objections. First, although “Functional
Entity” is capitalized in the draft Standard, this term is not defined in the NERC Glossary of Terms. It
appears the Standards Drafting Team may have used the term in error, because they were not aware
it was not a Glossary-defined term during the COM-003-1 webinar held November 27, 2012. A second
objection is that “Functional Entity” in this role does not add clarity to the Standard. “Functional
Entity” is defined in the NERC Reliability Functional Model as “the term used in the Functional Model
which applies to a class of entity that carries out the Tasks within a Function.” This definition refers to
other terms defined only with the Functional Model document (“Task,” “Function”). It is not
illuminating as to defining the bodies among which communications must meet COM-003-1. The third
and strongest objection is that use of the term “Functional Entity” in requirements of the draft
Standard is incorrect and inconsistent with the NERC Functional Model, and as such creates confusion
about Standard obligations for entities registered for more than one function. The NERC Functional
Mode Version 5 (November 30, 2009) explicitly does not require any particular organization or
assignment of functional Tasks for any multi-function entity. Functional tasks exist undifferentiated
across an entity as a whole, and the NERC Functional Model document states clearly that no further
differentiation is expected, required, or implied. (See, for example, p. 7 “The Functional Model
describes a functional entity envisioned to ensure that all of the Tasks related to its Function are
performed. The Model, while using the term ‘functional entity’, is a guideline and cannot prescribe
responsibility” and p.8 “The Model is independent of any particular organization or market structure.”)
Seattle City Light, for example, is a vertically integrated municipal utility registered for 11 functions:
BA, DP, GO, GOP, LSE, PC, PSE, RP, TO, TOP, and TP. Registration is made without differentiation: no
particular sub-organization within Seattle City Light is identified as performing BA tasks, as
performing TOP tasks, and so on. The Model is simply that Seattle City Light or any other multifunction entity performs these Tasks as a unit. By contrast the draft Standard relies upon
differentiation of Functions within an entity, so that it can be determined if a communication occurs
between the Functional Entities covered by COM-003-1 or not. Such differentiation is outside the
Model and introduces complexities and unintended consequences not envisioned by the Functional
Model and the term “Functional Entity.” The suggestion made by a member of the Standard Drafting
Team during the November 27, 2012, webinar, that the nature of the communications would indicate
if COM-003-1 applies or not (i.e., that an Operating Instruction from a System Operator to a Field
Operator both working within the same vertically integrated entity could be presumed to be a
communication from a TOP to a TO), is neither a sound nor clear basis to resolve the confusion
introduced by the incorrect use of “Functional Entity” in the draft. Under such an approach an
Operator of a multi-function entity has the extra burden of having to parse with limited or no
guidance each communication as to applicability to COM-003-1. Such a burden does not promote
timely communications nor reliable, consistent operations. Auditors and regulators assessing
compliance with COM-003-1 will face the same confusion, and there is no assurance that different
auditors and regulators from different regions will interpret communications the same way, even from
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one Operating Instruction to another. It is simply a misreading, tempting as it may be, to presume
that Functional Entity Tasks are assigned with greater granularity than to an organization as a whole.
To resolve the matter, Seattle City Light recommends simply that the term “Functional Entity” be
deleted from within the Requirements of COM-003-1, with the end result that Operating Instructions
will apply to BES Facilities and Elements regardless of entity involvement. The term “Functional
Entity” is superfluous to the Standard. This suggestion involves changes to R1, R1.3, R1.4, and R2, as
follows: R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement, in a manner that identifies, assesses and corrects deficiencies, documented
communication protocols for Operating Instructions ... that include the following 1.3. Use of the time,
the time zone where the action will occur and indication of whether the time is daylight saving time or
standard time when issuing an oral or written Operating Instruction that refers to clock times ... in
different time zones. 1.4. Use of the name specified by the owner(s) for each Transmission interface
Element or Transmission interface Facility when referring to a Transmission interface Element or a
Transmission interface Facility-in an oral or written Operating Instruction , unless another name is
mutually agreed to ... . R2. Each Distribution Provider and Generator Operator shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for
Operating Instructions ... that include the following… (where ... indicates removal of "between
Functional Entities" language)
No
The term "Responsible Entity" is not defined within the NERC Glossary and should not be capitalized in
the VSLs. It is a leftover term from earlier versions of the NERC Functional Model (see discussion in
Version 5, footnote pp.7-8 regarding use of Functional Entity and Responsible Entity).
Group
Midwest Reliability Organization NERC Standards Review Forum
Joseph DePoorter
No
See last question for comments.
Yes
The NSRF agrees with the language “…shall implement, in a manner that identifies, assesses and
corrects deficiencies,…” However, the NSRF has concerns on how CEA’s will audit to this requirement.
The NSRF requests the SDT to provide information or a guideline that would demonstrate how a
Regional Entity would assess and the type of evidence a registered entity would be required to show
to demonstrate compliance. Please provide guidance on this topic.
No
For the VSLs, the NSRF is seeking clarification how an auditor will assess the “…identifies, assess and
corrects deficiencies…” The VSL is severe if any one of the elements is missing and the NSRF believes
that further guidance is needed to understand how a CEA will assess compliance on the control
elements of this standard. For example, when would a CEA find a PV for a process that identifies,
assess and corrects, however a System Operator does not follow their operating communication
protocols on given Operating Instruction. The time horizon – Long-term Planning is incorrect, suggest
Real-time Operations or Same-Day Operations. System Operator instructions will pertain to Real-Time
or near Real-Time operations.
The NSRF understands that the SDT has discussed the combining of COM-002-3 and COM-003-1 issue
(and still unresolved) in the past however the NSRF recommends the standard drafting team amend
the SAR of COM-003-1 to combine or withdraw Reliability Standard COM-002-3 protocols. Having two
standards covering System Operator communications can lead to confusion and have the unintended
consequence of reducing clarity of System Operator communications thus, not supporting the
reliability of the BES. For example, when does an Operating Instruction end and a Reliability Directive
begin? The registered entity is now faced with possibility of double jeopardy. COM-003-1 has the
language “…shall implement, in a manner that identifies, assesses and corrects deficiencies,
documented communication protocols for Operating Instructions.” However, COM-002-3 does not
have the same language. This presents a conflict when managing compliance for each of these
standards. For example, a mistake with one of COM-003-1, R1 protocols does not automatically result
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in a possible violation, however, in COM-002-3 each and every error would result in a possible
violation. As COM-002-3 is written, when a Reliability directive is given, it does not need to follow any
of the protocols established in COM-003-1. Again, the NSRF urges the drafting team to combine COM002-3 and COM-003-1 into one standard. Issue: Defined term of Operating Instruction: “planning
instructions verse orders in real-time” concerning issuing a start and stop times of a generation unit.
In the draft 3 comments, the NSRF requested that the words “Real-time” be added to the definition of
“Operating Instruction” and the OPCPSDT stated on page 186 of the Consideration of Comments that
“The SDT believes some Operating Instructions can be issued outside as well as in the Real Time
horizon”. Please clarify the difference between a planning instruction and a real-time Operating
Instruction. Without the proper wording within this Standard, all CEA's may interpret this however
they see fit. Recommend that “real-time” be added top the definition of Operating Instruction. R1.3:
As written, R1.3 does not allow for any entities to have a documented communication protocol to
address the issuing of an Operating Instruction between Functional Entities in different time zones
without stating the time and time zone where the action is to occur. The NSRF recommends that R1.3
be worded parallel to R1.4 by adding the wording of; “unless there has been an established time and
time zone protocol between Functional Entities in different time zones” or “unless a pre-defined
approach is used for communicating time and time zones is within an established communication
protocol”. The above addition would allow different Functional Entities to agree beforehand of what
timing system will be used. The NSRF believes that the intent of R1.3 is to have two separate
Functional Entities (in two different time zones) in synch with each other so that there can be no
misunderstanding of when an Operating Instruction is to occur. There are many Entities who already
have these protocols established. Further, R1.3 states, “Use of the time, the time zone where the
action will occur…” An RC operating across several time zones will need to know which time zone the
entity is in that is receiving the Operating Instruction. Switching from an entity in one time-zone to
another entity in another time-zone opens the door for more confusion than using an already
established and documented protocol. R1.4 The NSRF recommends removal of sub-requirement 1.4.
It has been establish over several commenting periods that Project 2007-03 eliminated TOP-002 R18
which referred to common names and line identifiers, The TOP SDT removed the language from the
new standard was because the “This requirement adds no reliability benefit. Entities have existing
processes that handle this issue.” R1.5 The Alpha-numeric requirement is a one-size fits all solution
and is not needed in all situations. The NSFR recommends removing the sub requirement or as an
alternative,R1.5 should be reworded to state, “require alpha-numeric clarifiers when reissuing an
Operating Instruction to resolve a misunderstanding”. The risk of unclear communication is addressed
by R1.6 and R1.7. Currently there is not a definition for “…is in alpha-numeric format”. The NSRF
requests clarification on where and how to apply alpha-numeric clarifiers. For example: Current
System Operator communication: RC to GOP – Move generation from 500MW on Big Lake to 350MW
at 1200 - time zone understood to be EST from established and documented protocol. Under COM003-1. Move generation from five, zero, zero on Big Lake to three, five, zero at one, two, hundred
hour central daylight time or Move generation from Big Lake to three, five, zero at one, two o’clock,
charlie, delta, tango. GOP – is that two o’clock? Again, the purpose is to “reduce the possibility of
miscommunication” Is ok to say twelve hundred (1200) ? Or only ok to be used for time? Is ok to say
three hundred and fifty (350) MW? Is 350MW and alpha-numeric number? The NSRF agrees with the
language “…shall implement, in a manner that identifies, assesses and corrects deficiencies,…”
However, the NSRF has concerns on how CEA’s will audit to this requirement. The NSRF requests the
SDT to provide information or a guideline that would demonstrate how a Regional Entity would assess
and the type of evidence a registered entity would be required to show to demonstrate compliance.
Individual
Catherine Wesley
PJM Interconnection
No
PJM supports revising the VRFs and VSLs for both requirements back to a Low Violation Risk. We view
these requirements as administrative.
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Individual
Nazra Gladu
Manitoba Hydro
No
Some clarity in the definition of Operating Instruction is necessary. The definition suggests that only a
System Operator, Reliability Coordinator, Transmission Operation or a Balancing Authority could issue
an Operating Instruction. Are Distribution Providers and Generator Operations only recipients? Also, is
an Operating Instruction limited to communications between Functional Entities? The requirements
state this, but the definition does not.
No
Use of the phrase “implement in a manner that detects, assesses and corrects deficiencies…” is
difficult to interpret and therefore creates uncertainty as to what is required. The Background section
of the standard indicates that the SDT intended the phrase to be aimed at “deficiencies in the
implementation of certain requirements”. However, it is inconsistent to require “implementation” in a
manner that does not require implementation, leaving the interpretation of this standard unclear. It
appears also that the SDT did not want implementation failures to constitute violations. However, as
drafted, the standard can still be interpreted to require an entity to implement its policies. It simply
places an additional obligation on a Responsible Entity to detect and correct implementation failures.
If the SDT wishes to eliminate violations for failure to implement a policy, then there should be a
requirement to simply adopt a policy (covering specific subject matter) and a separate requirement to
detect, assess and correct deficiencies in implementation.
Yes
No comment.
(1) R1 1.3 – The word ‘and’ should replace the comma between ‘time, the time zone’. (2) R1, 1.8 –
We believe that confirmation of receipt should be required from ALL receiving parties, not ‘one or
more’. (3) R1, 1.9 – The word ‘issuer’ could replace ‘initiator’ to be more consistent with the wording
of the other requirements. (4) Measures – Both M1 and M2 are awkwardly worded. We suggest that
they be rephrased to read ‘Each Functional Entity, as applicable, must provide evidence of….’ (5)
Measures – Further to the comment in (4), we would be concerned about how an entity would be able
to demonstrate that the protocols have been implemented in a manner that identifies, assesses and
corrects. How exactly could it be demonstrated that a deficiency has been corrected through the
manner in which the protocol was implemented? (6) Compliance, Data Retention – The statements
that entities should retain evidence ‘of its manner that identifies, assesses and corrects deficiencies’
does not seem complete. The statements should line up with the language of the
requirement/measure. For example, that the entities shall retain evidence that the documented
communications protocols were implemented in a manner that…..
Individual
Bob Thomas
Illinois Municipal Electric Agency
Agree
Florida Municipal Power Agency, and SERC Operating Committee Standards Review Group
Individual
Chris Mattson
Tacoma Power
Yes
Yes
Yes
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Individual
Eric Salsbury
Consumers Energy
No
We believe this is a standard that requires procedures or documents but has nothing to do with
performance. These types of standards lead to auditors making a wide range of interpretations.
This is an attempt to make a requirement for 3 way communication for all operating communications.
Not all operating conversations avail themselves to that format. The concept is good but allowances
must be made for other situations.
Individual
Scott McGough
Georgia System Operations Corporation
Yes
No
Although GSOC supports the revisions and clarifications made in R1 & R2 sub requirements, GSOC
continues to have concerns with the revised language applied to internal controls. Fundamentally,
GSOC believes internal controls should be part of the compliance monitoring process. Although
internal controls are important, GSOC believes that before such language is added to standards
guidance/criteria need to be developed on how Regional Entities will consistently review internal
controls during compliance audits. GSOC suggests removing the language “implement, in a manner
that identifies, assesses and corrects deficiencies” until the Reliability Assurance Initiative (RAI) effort
to change the compliance/enforcement process to be more focused on a risk-based model and the
effectiveness of a registered entity’s internal controls/compliance program is implemented. GSOC
supports many of the comments made by both NRECA and Georgia Transmission Corporation.
Yes
Although GSOC supports the revisions and clarifications made in R1 & R2 sub requirements, GSOC
continues to have concerns with the revised language applied to internal controls. Fundamentally,
GSOC believes internal controls should be part of the compliance monitoring process. Although
internal controls are important, GSOC believes that before such language is added to standards
guidance/criteria need to be developed on how Regional Entities will consistently review internal
controls during compliance audits. GSOC suggests removing the language “implement, in a manner
that identifies, assesses and corrects deficiencies” until the Reliability Assurance Initiative (RAI) effort
to change the compliance/enforcement process to be more focused on a risk-based model and the
effectiveness of a registered entity’s internal controls/compliance program is implemented. GSOC
supports many of the comments made by both NRECA and Georgia Transmission Corporation.
Individual
Donald Weaver
New Brunswick System Operator
No
Technically the definition is an improvement. The issue is with the need for this definition. The NBSO
is opposed to having this term defined and added to the NERC Glossary. The term operating
instruction does not need to be defined. System operators deal with operating instructions on a daily
if not minute basis. Having a defined term, and calling such communication as “Command” is
unnecessary, and can confuse operators from what they understand to be the meaning of operating
instructions. The NBSO prefers that the objectives of the SAR (communications protocols) be handled
through means other than a Standard (e.g. the Operating Committee’s Reliability Guidelines on
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Communications). Industry, NERC and the Regional Entities should focus on more productive
reliability issues.
No
The requirement still includes the verb “implement”. That phrase, as part of a mandatory standard,
will require a zero-defect environment. The phrase “in a manner that identifies, assesses and corrects
deficiencies” is vague, not measurable and inconsistent with the results-based standard concept which
emphasizes the inclusion of a performance or reliability outcome in the requirement. A more direct
and clear requirement would be to simple require “implement documented communication
protocol….”.
The SDT has been effective in responding to the Industry’s concerns on the issue of “one-way”
messaging. Communications Protocols are not documents that are suitable as “Standards” for a
mandatory reliability standard. The zero-defect, self-reporting nature of such standards conflicts with
the nature and impact of the violations that get reported. Protocols are internal controls that an entity
imposes on itself. Protocols allow an entity to self-regulate itself and to decide if the monitored
deviations from their own protocols warrant further action. To mandate such protocols are
implemented removes the allowance for “impact to reliability”. To mandate that an entity have
protocols is a better approach. To create a new category for Protocols that do not carry the same level
of monitoring and reporting as standards is an even better approach.
Individual
Barbara Kedrowski
Wisconsin Electric Power Company
No
NO do not support the revised definition. Although the addition of the last sentence helps, the drafting
team has yet to differentiate an Operating Instruction command, from the already approved
standards that refer to “directive, direct, direction” which may not be a “Reliability Directive” and will
fall under, for instance IRO-001 R1 & R2. There needs to be a clear bright line between command and
direct, direction…. The expression, “repeat, restate, rephrase, or recapitulate,” in R. 1.7 and R2.1
would be clearer if shortened to, “repeat or summarize.”
No
The revised standard is much improved by focusing on continuous improvement instead of making
each communication imperfection a violation, but no guidance is provided as to how rigorous the
improvement program must be to be deemed sufficient. M1 and M2 should have added at the end the
statement, “Acceptable means of identifying, assessing and correcting deficiencies include the
following: • Review of voice logs, for at least one hour per year for each person issuing commands or
responses (as applicable) • Personal monitoring of communications, for at least one hour per year for
each person issuing commands or responses (as applicable) • Annual refresher training, including a
quiz on proper commands or responses, for each person issuing commands or responses (as
applicable) (as applicable)
The revised standard, an improvement, yet falls short by opening the door for compliance
enforcement to have a mechanism to apply communications and performance from other standards to
commands issued under COM-003. Failures of GO and DP operators to repeat or summarize Operating
Instructions are easily detectable (R2.1); but it would not ordinarily be possible for a person
monitoring COM-003 compliance to detect a lack of understanding accompanied by failure to request
a clarification (R2.2), since the resultant silence on the part of the operator is the same reaction
associated with clearly understanding the Operating Instruction. M2 should be shortened to,
“Evidence must include each applicable entity’s documented communications protocols, which must
include a provision requiring the recipient of an operating instruction to seek clarification from the
initiator in the event of an unclear instruction.” From the RSAW: “If the CEA finds in subsequent
audits or other compliance monitoring activities that the same or similar deficiencies continue to occur
after the entity was provided the feedback by the CEA, the CEA will seek to understand what changes
the entity made based on prior recommendations. If the entity did not implement changes to identify,
assess and correct deficiencies, the CEA may make a determination of possible non-compliance” The
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issue here is potential for disagreement on “deficiencies”. There are some conversations between
GOPs and TOPs which are market driven, but could be read by an auditor as an “operating
instruction”. Some adjustment to the definition of “operating instruction”, or some adjustment to the
requirement that an entity address the “recommendation” from the region, may be in order here.
Individual
Don Schmit
Nebraska Public Power District
Agree
MRO NSRF [Midwest Reliability Organization - NERC Standards Review Forum]
Individual
Richard Bachmeier
Gainesville Regional Utilities
Yes
Yes
Yes
The problem is that Reliability Directives will have two inconsistent standards applicable to them, i.e.,
all Reliability Directives (COM-002) are Operating Instructions (COM-003), so, Reliability Directives
will need to comply with both COM-002 and COM-003. COM-003’s implementation plan should retire
COM-002. FMPA is voting negative because two inconsistent standards applying to the same action,
especially one as important as a Reliability Directive, is bad for reliability. The most glaring
inconsistency for Reliability Directives are one-way burst communications (e.g., Party lines, or All
Call), where COM-002 and COM-003 would treat the communications differently. If a Reliability
Directive is given to all BAs in the region something like “due to capacity energy emergency, we need
X MW shed within Y minutes in accordance with our previously approved allocations in procedure Z”,
COM-002 seems to say that each BA in the region would need to separately perform 3-part
communication with the RC, whereas COM-003 would only require 3 part communication if the
message was not understood. It would seem that during an Emergency, speed is of the essence, so,
should the RC and BAs (who then need to spend time directing the DPs) spend the time doing
separate 3 part communication with each BA, or should a one-way burst messaging occur with
clarification only for those who do not understand? If there are dozens of BAs within an RC, COM-002
mode of communication could consume all the time of the Emergency and bad things can happen.
FMPA recommends that COM-003 address Reliability Directives, which are a subset of Operating
Instructions in a similar fashion to IROLs being a subset of SOLs and how they are treated throughout
the standards. BY doing so, COM-003 can retire COM-002 such that only one standard applies to
Reliability Directives.
Individual
Ken Gardner
AESO
The AESO maintains that “alpha-numeric clarifiers” may be part of good operating practices, but the
AESO does not support mandating the use of these identifiers as included in requirement R1.5 to be a
mandatory obligation enforceable by law.
Individual
Michael Moltane
ITC
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Agree
MRO NSRF
Individual
Jonathan Appelbaum
The United Illuminating Company
Agree
Northeast Power Coordinating Council - NPCC
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
The proposed definition of an “Operating Instruction” continues to require clarification. First, the focus
of COM-003 is on operations, and therefore the communications subject to the COM-003 requirement
should be those requiring action in the Real-time operations time horizon — i.e., actions required
within one hour or less. (See definition provided in a NERC document at:
http://www.nerc.com/files/Time_Horizons.pdf). During the Q/A portion of the November 27th
conference call hosted by the SDT, the SDT stated that they intended to narrow the focus of the
timeframe of an Operating Instruction to the real time operating horizon. Nevertheless, the definition
has not been so revised. Second, a “Reliability Directive” under COM-002 will necessarily fall within
the definition of an “Operating Instruction” under COM-003. Because of this overlap, entities subject
to the standard would be subject to two Reliability Standard violations – one under COM-002 and
another under COM-003 – should the entity deviate from required protocols when either issuing or
responding to a Reliability Directive. To avoid this overlap, the SDT should exclude a COM-002
Reliability Directive from the definition of an Operating Instruction under COM-003. Accordingly, PPL
Companies suggest the following definition to address the above issues: “Operating Instruction” –
Command, other than a Reliability Directive, from a System Operator to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System in which action must be taken within one hour. Alternatively, the SDT could recommend
retirement of COM-002 upon the effectiveness of COM-003. If COM-002 is retired then the need to
exclude “Reliability Directives” from the definition of an “Operating Instruction” would be
unnecessary.
Group
Hydro One Networks Inc.
Sasa Maljukan
No
Hydro One continues to disagree with the need for this standard on the basis that the industryapproved COM-002 together with the NERC OC’s operating guide on operator communication already
provide the necessary requirements and guideline to fill any potential reliability gaps that may arise
due to operator communication (see our response to Question #4 for more details). Notwithstanding
above, we’d like to submit following comment in relation to this question. We believe that the
proposed definition as worded can be misconstrued to mean a command made by System Operator to
a Reliability Coordinator, or to a Transmission Operator, or to a Balancing Authority. Hydro One
proposes the following wording: Operating Instruction —A command by a Reliability Coordinator
System Operator, a Transmission Operator System Operator, or a Balancing Authority System
Operator, where the recipient of the command is expected to act, to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. Discussions of general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating Instructions.
No
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Hydro One appreciates the SDT’s introduction of additional language in order to effectively make this
standard not zero-defect. Unfortunately, since our issues are with the core need for this standard
rather than its details we feel that the above mentioned change is not sufficient for us to reconsider
our position.
Yes
- Hydro One continues to disagree with the need for this standard on the basis that the industryapproved COM-002 together with the NERC OC’s operating guide on operator communication already
provide the necessary requirements and guideline to fill any potential reliability gaps that may arise
due to operator communication. Requiring 3-part communication for routine operating instructions,
despite the additional wording in R1 (“in a manner that identifies, assesses and corrects deficiencies”)
and provisions made in the RSAW, is still a zero defect requirement that would add undue burden to
the operators, which is a potential cause of unreliable operations. We therefore continue to disagree
with the need for this standard as it adds little to reliability over what COM-002 and the operating
guide have already accomplished. - We appreciate the SDT’s hard work and dedication to develop this
standard in response to the SAR and the recent BoT directives. Unfortunately, the need for this
standard has been overtaken by event (the definition of Reliability Directives and COM-002-3, and the
OC’s operating guide on operator communication). The BoT, unfortunately, is still under the
perception that COM-003 is the answer to the potential reliability gap that was discussed when it
approved the COM-002 R2 interpretation. The two balloting results and the two sets of industry
comments suggest that many in the industry share our view. Hence, we believe the industry should
attempt to convince the BoT that the potential reliability gap has been duly addressed and therefore
COM-003 is no longer needed. We understand the SDT has little to no option, we therefore suggest
that the SDT present the results of this round of ballot, if it still fails to make the 2/3 approval rate, to
the Standards Committee and ask for its permission to put a hold on further work until the BoT has
heard the industry’s concern and makes a policy decision on the way forward. Further revision to this
standard and posting for industry commenting and balloting will only waist the SDT’s effort and
industry resource, without a fruitful outcome. - Notwithstanding the above, the proposed
implementation plan conflicts with Ontario regulatory practice respecting the effective date of the
standard. It is suggested that this conflict be removed by appending to the implementation plan
wording, after “applicable regulatory approval” in the Effective Dates Section (P. 2 of the
Implementation Plan) and in Section A5 of the standard, to the following effect: “, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.” - Functional
entity is capitalized throughout the Standard, yet functional entity is not a defined term in the NERC
Glossary. - Propose changing the wording in Requirement R1 to the following: R1. Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall implement, have documented
communication protocols that include identification, assessment, and correction of deficiencies in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols for
Operating Instructions between functional entities that include the following: [Violation Risk Factor:
Medium [Time Horizon: Long-term Planning ] - The Sub-requirements introduce too much detail into
the Standard. This detail dictates “how” something is to be done, rather than “what” is to be done.
Following are comments to be considered on the sub-requirements should they remain in the
Standard. - Propose changing the wording in Sub-requirement 1.1 to the following: 1.1. Use of the
English language when issuing or responding to an oral or written Operating Instruction, unless
another language is mandated by law or regulation or agreement. - Propose changing the wording in
Sub-requirement 1.3 to the following: 1.3. Use of the time, the time zone where the action will occur
and indication of whether the time is daylight saving time or standard time when issuing an oral or
written Operating Instruction that refers to clock times between functional entities in different time
zones., unless time protocols are defined in written agreements between the functional entities. Regarding Sub-requirement 1.5, the use of alpha-numeric clarifiers should be no more than a best
practice. In case of uncertainty, 3 part communication as specified in Sub-requirement 1.6 would
catch any ambiguities. - Propose changing the wording in Sub-requirement 1.8 to the following: 1.8.
When issuing an oral Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (for example an all call
system), verbally or electronically confirm receipt or that communications paths were established to
receive the message from one or more receiving parties. - Regarding the Time Horizons for
Requirements R1 and R2, they should be Real-time Operations since the communications are
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occurring in real time, and the implementation of the protocol is the intent of R1 and R2.
Individual
John D. Brockhan
CenterPoint Energy Houston Electric, LLC
Yes
Yes
No
CenterPoint Energy appreciates the revisions made to the current draft of COM-003 based on
stakeholder feedback and has voted AFFIRMATIVE. However we remain concerned over the final
manner in which this standard will be audited. The determination of the appropriate identification,
assessment, and correction of deficiencies necessary to meet compliance can be subjective.
Additionally, if an entity does not identify any deficiencies during its review process, there’s the
concern that an auditor may interpret that as insufficient Internal Controls rather than exemplary
entity performance.
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
Yes
Yes
The problem is that Reliability Directives will have two inconsistent standards applicable to them, i.e.,
all Reliability Directives (COM-002) are Operating Instructions (COM-003), so, Reliability Directives
will need to comply with both COM-002 and COM-003. COM-003’s implementation plan should retire
COM-002. FMPA is voting negative because two inconsistent standards applying to the same action,
especially one as important as a Reliability Directive, is bad for reliability. The most glaring
inconsistency for Reliability Directives are one-way burst communications (e.g., Party lines, or All
Call), where COM-002 and COM-003 would treat the communications differently. If a Reliability
Directive is given to all BAs in the region something like “due to capacity energy emergency, we need
X MW shed within Y minutes in accordance with our previously approved allocations in procedure Z”,
COM-002 seems to say that each BA in the region would need to separately perform 3-part
communication with the RC, whereas COM-003 would only require 3 part communication if the
message was not understood. It would seem that during an Emergency, speed is of the essence, so,
should the RC and BAs (who then need to spend time directing the DPs) spend the time doing
separate 3 part communication with each BA, or should a one-way burst messaging occur with
clarification only for those who do not understand? If there are dozens of BAs within an RC, COM-002
mode of communication could consume all the time of the Emergency and bad things can happen.
FMPA recommends that COM-003 address Reliability Directives, which are a subset of Operating
Instructions in a similar fashion to IROLs being a subset of SOLs and how they are treated throughout
the standards. BY doing so, COM-003 can retire COM-002 such that only one standard applies to
Reliability Directives.
Individual
Don Jones
Texas Reliability Entity
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No
1. We voted against this draft because the relationship between Reliability Directive in COM-002-3
and Operating Instruction remains a serious problem and needs to be clarified. Is a Reliability
Directive also an Operating Instruction, or is it a distinct type of communication? Do the provisions of
COM-003-1 apply to Reliability Directives, or are they subject only to COM-002? 2. The added
sentence added to the end of the definition is unnecessary, it is potentially ambiguous, and it provides
no enhancement to reliability. The sentence will open the door for disputes about whether
communications are Operating Instructions or something else.
Group
SERC OC Standards Review Group
Gerry Beckerle
No
We believe that the definition should indicate the timeframe in which the entity “is expected to act.”
We believe that this language is too wide and can be interpreted in many ways. Furthermore, we
continue to believe that prescriptive communications protocols are unnecessary for routine Operating
Instructions. Many Operating Instructions, such as economic loading of resources, do not have a
reliability impact to the BES and the entities should not be held accountable to the requirements of
this standard.
No
We believe that the requirements should clearly list which Functional Entities when the
communications protocols should be utilized, for example, what happens when one of the five
Functional Entities listed in these two requirements give an Operating Instruction to an entity not
listed. Note that the question incorrectly references R2 which include the DP and GOP. Furthermore,
while we agree with the concept of identifying, assessing, and correcting deficiencies, we continue to
believe a prescriptive use of the word “include” should be removed. We would suggest using the word
“consider” or “address.”
No
We disagree with the explanation of why the VRF for both R1 and R2 were changed from “Low” to
“Medium” and believe that these continue to be administrative requirements justifying a “Low” VRF.
We continue to believe that this standard is too prescriptive as noted in question #2 above and in its
current draft appears to us to be not much different than when issuing Reliability Directives. We have
discussed in our group that if this standard is implemented as proposed that there would no longer be
a need for COM-002-3. In addition, in the proposed standard Background section it states “that these
requirements should not focus on individual instances of failure as a basis for violating the standard.“
But, the draft RSAW states that the CEA: “Review a sample of the entity’s Operating Instructions to
verify whether the entity is implementing its documented communication protocols,” which appears to
be contradicting the language in the Background section. It also appears that the language in the
RSAWs would require an entity to keep a log of all Operating Instruction. This would be overly
burdensome to the industry and is not included in the requirements. The reference in R1 Part 1.3 to
specify different time zones is indicative of the overly prescriptive nature of all nine parts of the
requirement. Entities that already have protocols of handling different time zones may have negative
reliability impacts when required to use a different convention. For example, entities operating across
different time zones may rely on their EMS time and requiring the use of a different time zone
convention would be confusing. Entities should be able to determine what works best.
Group
National Grid / Niagara Mohawk (A National Grid Company)
Michael Jones
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Suggested improvement: We recommend separate requirements for: 1. Documentation and
implementation of communication protocols. 2. Documentation and implementation of control
processes for the identification, assessment, and correction of deficiencies. In addition, we
recommend adding the following to the draft standard: 1. It should be noted that individual failures to
use the documented communication protocols should not be considered violations of the
implementation of communication protocols. 2. It should be noted that individual failures of control
processes for the identification, assessment, and correction of deficiencies should not be considered
violations of the implementation of the control processes for the identification, assessment, and
correction of deficiencies.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, ,Inc.
No
ERCOT supports the SRC comments and has additional comments. For this question, see the
comments in the comment area of question 4.
No
ERCOT supports the SRC comments and has additional comments. For this question, see the
comments in the comment area of question 4.
No
The VSL’s do not match up with CIP v5 standards. Listing “The Responsible Entity did not implement,
in a manner that identifies, assesses and corrects deficiencies, their documented communication
protocols as required in Requirement R1” as a severe VSL distinguishes the activities as a singular
and separate activity which is inappropriate. CIP v5 more appropriately incorporates it at each VSL
level as a part of each VSL which reflects the language in the requirement “in a manner that”. If the
standard passes, VSLs should be modified like those in CIP v5. Example: The Responsible Entity did
not include one (1) of the nine (9) parts of Requirement R1, Parts 1.1 to 1.9 in their documented
communication protocols and did not identify, assess, or correct the deficiencies.
1.) While the proposed definition of “Operating Instruction” reflects improvement in that it helps to
clarify exclusion of particular communications not intended to be regulated by the standard, the
definition still should not be included because it is unnecessary to address the SAR. This definition
supports this standard which is solely focused on reducing miscommunication (incorrect
communications) and does not, in ERCOT’s opinion, address the Blackout Recommendation and FERC
Order which this project is intended to address, as identified in the SAR. As proposed, the term
"Operating Instruction" could include communications that have nothing to do with reliability - e.g.
communications that are market related and have no impact on system reliability. That outcome is
inconsistent with FERC's direction in Order No.693. FERC's discussion of this issue in Order 693
focuses on alerts and emergencies as follows- "We adopt our proposal to require the ERO to establish
tightened communication protocols, especially for communications during alerts and emergencies..."
(693 at P 531) "Accordingly, we direct the ERO to either modify COM-002-2 or develop a new
Reliability Standard that requires tightened communications protocols, especially for communications
during alerts and emergencies." (693 at P 535) In addition, the scope of FERC's concerns is limited to
communications that impact the reliability of the BPS - "We note that the ERO's response to the Staff
Preliminary Assessment supports the need to develop additional Reliability Standards addressing
consistent communications protocols among personnel responsible for the reliability of the Bulk-Power
System." (693 at P 531) "...we believe, and the ERO agrees, that the communications protocols need
to be tightened to ensure Reliable Operation of the Bulk-Power System." (693 at P 532) During the
recent webinar, it was evident that confusion still exists and that this proposed standard does not
resolve the confusion. In fact, the proposed standard and definition contribute to the confusion.
Primarily, the definition should not be made applicable to system operators within the same company
and control room who are registered as multiple functions. ERCOT ISO does not have separate desks
or operating personnel that perform a single function but performs its functions simultaneously by
multiple system operators. The functional entity is not an individual but the entity registered for that
function. 2.) ERCOT fully supports the concept that functional entities' internal controls should be
used to monitor the effectiveness of their own protocols. However, these matters are not suitable for
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reliability standards. Imposition of mandatory controls applicable to all functional entities is
inappropriate because of the wide variety of organizational structures that necessarily requires
flexibility with respect to developing appropriate controls for each entity’s specific circumstances.
Furthermore, entities' internal controls are beyond the scope of the Section 215 reliability purview
generally, and they are inconsistent with the risk-based initiative being pursued by NERC because
they do not impact/are not related to actual reliability impacts. Furthermore, the deficiency review
process is ambiguous and, accordingly, lends itself to inefficient and ineffective CMEP results. As an
initial matter, what constitutes a deficiency will be an issue that is vulnerable to subjective
disagreements. Even assuming there is agreement on that issue, what constitutes an appropriate
remedy for a deficiency in terms of assessment and correction will similarly be susceptible to
subjective disagreements. Finally, with respect to the obligation to evaluate the deficiency
identification process itself, again, the potential for the introduction of subjective compliance review
will be problematic in practice in terms of reviewing the decision whether to implement a modification
or not to implement a modification; and, if a modification is implemented, whether the revision is
adequate. ERCOT is encouraged to see NERC’s willingness to explore new ways to move away from a
zero defect mentality, but does not understand nor agree with the approach of including such
provisions in the standards. The reliability standards should be left as performance-based, not be
administrative or prescriptive, and have clear measures. This standard is administrative, prescriptive,
and solely focused on miscommunications (incorrect communications) which is a subset, if that, of the
“communication protocols” intended by the FERC Order 693 and subsequent Blackout
Recommendation. This disconnect is specifically why it has been difficult to garner industry support on
this proposed standard. 3.) If the standard were based on effective communication protocols and not
specifically miscommunication (incorrect communication) protocols, it would be clearer and more
supported than what has been presented to industry for comment and each of the ballots. The SDT,
while being very responsive to certain comments that keep its focus on miscommunications, has not
been responsive to the industry comments supporting that the proposed requirements are
unnecessary and a call for requirements directly responsive to FERC Order 693 and the subsequent
Blackout Recommendation related to this project which are related to “effective” communications. The
SDT has repeatedly focused on miscommunications rather than on “effective” communications
protocols. Effective protocols would constitute communications protocols related to what information
needs to be communicated, who needs the information, when they need it particularly during alerts
and emergencies. Common phrases, terms, means, etc. can be employed to produce uniformity. As
the Blackout Recommendation stated “Ineffective communications contributed to a lack of situational
awareness and precluded effective actions to prevent the cascade. Consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability.” When
the Blackout report is read it is evident, this had no stated relationship to miscommunications, but
instead to the reliability content of the communications, responsibilities, and speed at which
communications occurred. This proposed standard also gives no emphasis to Alerts and Emergencies
which is another indicator that it has missed the intended objective of the FERC Order and subsequent
Blackout Recommendation. ERCOT respectfully recommends a renewed focus on communication
protocol requirements related to promoting “effective” communications and not solely focused on
miscommunications. Recent event investigations have only continued to support this concept as
recommendations have been made to improve communication protocols that do not have any relation
to preventing miscommunications. Examples below: Feb 2, 2008 Cold Weather Event Report
Recommendations: 21.) Balancing Authorities should improve communications during extreme cold
weather events with Transmission Owner/Operators, Distribution Providers, and other market
participants. (page 218) 22.) ERCOT should review and modify its Protocols as needed to give
Transmission Service Providers and Distribution Service Providers in Texas access to information
about loads on their systems that could be curtailed by ERCOT as Load Resources or as Emergency
Interruptible Load Service. (page 218) 23. WECC should review its Reliability Coordinator procedures
for providing notice to Transmission Operators and Balancing Authorities when another Transmission
Operator or Balancing Authority within WECC is experiencing a system emergency (or likely will
experience a system emergency), and consider whether modification of those procedures is needed to
expedite the notice process. (page 219) 24. All Transmission Operators and Balancing Authorities
should examine their emergency communications protocols or procedures to ensure that not too
much responsibility is placed on a single system operator or on other key personnel during an
emergency, and should consider developing single points of contact (persons who are not otherwise
responsible for emergency operations) for communications during an emergency or likely emergency.
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(page 219) Arizona San Diego Outage Report Recommendations 15. On September 8, 2011, at least
one affected TOP lost the ability to conduct RTCA more than 30 minutes prior to and throughout the
course of the event due to the failure of its State Estimator to converge. The entity did not notify
WECC RC or any of its neighboring TOPs, preventing this entity from regaining situational awareness.
Individual
Mike Hirst
Cogentrix Energy Power Management, LLC
1. The expression, “repeat, restate, rephrase, or recapitulate,” in R. 1.7 and R2.1 would be clearer if
shortened to, “repeat or summarize.” 2. The revised standard is much improved by focusing on
continuous improvement instead of making each communication imperfection a violation, but no
guidance is provided as to how rigorous the improvement program must be to be deemed sufficient.
M1 and M2 should have added at the end the statement, “Acceptable means of identifying, assessing
and correcting deficiencies include the following: • Review of voice logs, for at least one hour per year
for each person issuing commands or responses (as applicable) • Personal monitoring of
communications, for at least one hour per year for each person issuing commands or responses (as
applicable) • Annual refresher training, including a quiz on proper commands or responses, for each
person issuing commands or responses (as applicable) (as applicable) 3. Failures of GO and DP
operators to repeat or summarize Operating Instructions are easily detectable (R2.1); but it would
not ordinarily be possible for a person monitoring COM-003 compliance to detect a lack of
understanding accompanied by failure to request a clarification (R2.2), since the resultant silence on
the part of the operator is the same reaction associated with clearly understanding the Operating
Instruction. M2 should be shortened to, “Evidence must include each applicable entity’s documented
communications protocols, which must include a provision requiring the recipient of an operating
instruction to seek clarification from the initiator in the event of an unclear instruction.” 4. From the
RSAW: “If the CEA finds in subsequent audits or other compliance monitoring activities that the same
or similar deficiencies continue to occur after the entity was provided the feedback by the CEA, the
CEA will seek to understand what changes the entity made based on prior recommendations. If the
entity did not implement changes to identify, assess and correct deficiencies, the CEA may make a
determination of possible non-compliance” The issue here is potential for disagreement on
“deficiencies”. There are some conversations between GOPs and TOPs which are market driven, but
could be read by an auditor as an “operating instruction”. Some adjustment to the definition of
“operating instruction”, or some adjustment to the requirement that an entity address the
“recommendation” from the region, may be in order here.
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
Yes
Austin Energy is pleased the SDT changed the internal control language to be consistent with CIP v5
language.
Yes
(1) The SDT requested industry comment on the reference to “Operating Instructions between
Functional Entities.” Industry discussions indicate that entities interpret this phrase in different ways.
Austin Energy (AE) agrees the use of the term “Functional Entity” is confusing. As noted during the
11/27/12 webinar, Functional Entity is not defined in the NERC Glossary but, instead, only in the
functional model. As described by the speakers at the webinar, this language requires protocols for
communication between RC and TOP entities or TOP and TO entities, but does not require the same
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protocols for TOP-to-TOP communications. This implies that vertically integrated companies should
designate certain employees as part of one Functional Entity and other employees as part of another
Functional Entity. In the case of AE, this would show up as some employees being “TOP” and others
being “TO” and still others as “DP” or “GOP.” In reality, all employees are AE employees and it is
impractical and confusing to designate them any other way. AE holds one registration with NERC for
five different functions (TO, TP, DP, LSE and TOP) and a second registration for the GO and GOP
functions. This is due to Regional Entity requirements at the time of registration. AE, as a municipal
utility, performs all of those functions but is not organized in a way as to label each employee as
fitting under a particular function. The confusion continues when considering communications
between companies. In the ERCOT Region, approximately 15 local control centers and ERCOT are all
registered as “TOP.” One might interpret the webinar discussion to require that communications
between neighboring TOPs or ERCOT and one of the local control centers are not subject to the
requirements of COM-003-1 because these are TOP-to-TOP communications. AE suggests the SDT
greatly simplify COM-003-1 and require entities to “implement, in a manner…, protocols that include
three-part communication for Operating Instructions.” In other words, omit the reference to
Functional Entity. Alternatively, if the SDT wants to limit the protocols to communications between
companies (another common interpretation), simply state the requirement that way. (2) AE believes
the specificity in the subparts of R1 is unnecessary. Three-part communication is the preferred
method for ensuring that both parties understand an Operating Instruction. It provides a sufficient
mechanism for clear, concise and accurate communication. AE believes that creating a protocol
requiring System Operators to essentially re-learn how to speak (specifically using alpha-numeric
identifiers) will only create confusion as operators try to follow protocol and catch/correct themselves.
Individual
Marie Knox
MISO
No
The definition of “Operating Instruction” as proposed in this draft standard is overly broad and
ambiguous and will result in everyday operations communications being subject to each entity’s
“documented communications protocols” unnecessarily, diverting real-time operations resources from
monitoring BES reliability and ensuring that changes necessary for reliability are properly understood
and implemented. In particular, based on the definition, it is unclear as to whether a discussion
regarding implementation of an operating guide would be an “Operating Instruction”. More
specifically, an operating guide is a common, known, and agreed upon operational action that an
entity will take in response to identified system conditions. However, such guide is not normally
implemented until the condition manifests itself. Accordingly, based on the definition of “Operating
Instruction”, it is unclear as to whether a discussion between entities regarding implementation of
such an operating guide once the associated condition manifests itself would be considered a
“command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System”. This
uncertainty can only result in affected entities being overly conservative and applying the
requirements of COM-003 to a vast majority of communications, resulting in a significant divergence
of resources as described above. MISO cannot support the proposed draft standard given the current
level of ambiguity, the potential impact upon real-time operations, and the potential for such impact
to detract from BES reliability.
No
It is unclear what is meant by “shall implement, in a manner that identifies, assesses and corrects
deficiencies, documented communication protocols for Operating Instructions between Functional
Entities”. In particular, there is no established criteria regarding what constitutes “a manner that
identifies, assesses and corrects deficiencies”. Further, there is no documentation nor rationale
provided to support the assignment of a severe VSL to the failure of a Registered Entity to implement
its docuemnted communication protocols in “a manner that identifies, assesses and corrects
deficiencies”. Without a clear criteria, the potential for subjective interpretation of this portion of the
requirement is significant and such subjectivity would be associated the most severe VSL possible
without justification. Accordingly, MISO cannot support this portion of R1 within this draft proposed
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standard.
No
Requirement 1 and 2 do not have a direct effect on the reliability of the BES. Requirement 1 provides
clarity for Operating Instructions and Requirement 2 ensures implemented communication protocols
are documented. Because R1 and R2 are administrative in nature, we recommend the “Lower” instead
of “Medium.
MISO appreciates the time and effort expended by the SDT in revising the proposed draft standard in
response to prior comments. However, the ambiguity and absence of justification still present within
and associated with this draft, proposed standard prevent MISO from providing its support for COM003. Additional comments regarding specific sub-requirements are provided below: R1.1 provides
that English shall be used “unless another language is mandated by law or regulation. This
requirement should be modified to require that operators use English for oral Operating Instructions,
even if it is not the required primary language pursuant to law or regulation. R1.2 requires the use of
a 24-hour clock for all times. This requirement would result in the expenditure of significant time,
resources and attention by System Operators for a minimal benefit to reliability. To date, the use of
the 12-hour clock time has not been demonstrated as problematic or as having an adverse impact on
reliability. MISO notes that the use of the 24-hour clock time in communication is inconsistent with
the 12-hour clock time currently utilized by most systems. The system time characteristics, which are
primarily based on 12-hour clock time, should inform the communication protocols regarding time.
Accordingly, this requirement appears to place upon operators a requirement that is not justified and
onerous. MISO respectfully requests that the SDT consider removal of this requirement. R1.3 states:
Use of the time, the time zone where the action will occur and indication of whether the time is
daylight saving time or standard time when issuing an oral or written Operating Instruction that refers
to clock times between Functional Entities in different time zones. We recommend this be clarified.
The requirement should say that the time zone be specified when communicating across zones
"unless a pre-defined approach is used for communicating time in the protocols". R1.4 requires the
use of the name specified by the owner(s) for each Transmission interface Element or Transmission
Interface Facility in an oral or written Operating Instruction. MISO respectfully submits that this
requirement is already addressed in TOP-002-2b, R18. Further, MISO respectfully comments that, to
date, System Operators have identified equipment by to/from station and voltage level. Such
identification has been sufficient to ensure the accurate identification of Transmission interface
Elements and Facilities. Additionally, MISO notes that internal identifiers utilized by owners may result
from internal coding or naming conventions that would not be known by or comprehensible to
external entities. Hence, MISO cannot support this requirement based on the potential adverse
impacts to reliability that could result. R1.5: MISO reiterates it comments in Round 2 and 3 that the
requirement to use alpha-numeric clarifiers format is ambiguous and could lead to unintended
compliance burdens. For instance, it is ambiguous whether alpha-numeric clarifiers would be
necessary when referring to commonly-accepted voltage levels, such as 138kv (alpha-numerically as
follows: “One-tree-eight-kilo-victor”). MISO argues that in this case that the communication would be
less clear and more likely to be misunderstood or misconstrued. MISO also respectfully points out that
there is an extra period and space at the beginning of the parenthetical in the draft version of the
R1.5. R1.6 and R1.7: Given the broad applicability of R1.6 and R1.7 as a result of the definition of
Operating Instruction, the split of compliance obligations into multiple sub-requirements may result in
entities being assessed violations for multiple requirements as a result of 1 (one) communication or
operating event. While MISO appreciates the clarity in roles and responsibilities the split provides, it is
concerned about the future application and feasibility thereof. Please refer to MISO’s comments
regarding the definition of Operating Communication for more detail on the likely adverse impact to
reliability that will result from the diversion of time and resources the split will require. Overall, MISO
supports the need to ensure good communications among users, owners, and operators of the grid,
but believe the standard, as drafted is misdirected. As drafted, this standard can actually impede
reliability as there are, at times, better ways to communicate when group action is needed and there
are times when speed or “give and take” are needed. The definition of Operating Instruction could be
construed and is sufficiently ambiguous to results in the applicability of COM-003 to common
operational communications including non-requests / non-directives diverting time and attention away
from ensuring that changes necessary for reliability are properly understood and implemented. MISO
cannot support the current version of COM-003-1. Though MISO is voting negative this round, we
would respectfully request that the SDT add the following language for the next round of comment
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consideration and balloting: “Electronic means of communication can be used in lieu of oral when the
clarity of the electronic communication is sufficient to reduce the possibility of miscommunication that
could lead to action or inaction harmful to the reliability of BES.”
Individual
Greg Travis
Idaho Power Company
Yes
Yes
Yes
Individual
Richard Vine
California Independent System Operator
No
Comments already provided through the ISO/RTO Standards Review Committee
No
Comments already provided through the ISO/RTO Standards Review Committee
It is not clear why the Time Horizon is identified as "Long-term Planning" for requirements R1 and R2,
since this seems to be a "Real-Time" communication standard.
Group
ISO RTO Standards Review Committee Group
Albert DiCaprio
No
Technically the definition is an improvement and the SRC would agree with the proposed changes, if
the definition were needed. The issue is with the need for this definition, and the continuing debate
this definition is generating. The SRC is opposed to having this term defined and added to the NERC
Glossary. The term operating instruction does not need to be defined. For years, system operators
deal with operating instructions on a daily if not minute basis. Having a defined term, and calling such
communication as “Command” is unnecessary, and can confuse operators from what they understand
to be the meaning of operating instructions. While the SDT has found that their previous definitions
were not appropriate for a NERC standard, and subsequent incremental changes are useful, the
debate itself does not seem to be a productive use of the SDT’s or the Industry’s time. The SRC would
prefer that the objectives of the SAR (communications protocols) be handled through means other
than a Standard (e.g. the Operating Committee’s Reliability Guidelines on Communications). The
reason being, a standard requires zero-defect compliance, data retention, self-reporting, and requires
these debates over the proposed terms such as “Operating instruction” which diverts the Industry,
NERC and the Regional Entities from focusing on more productive reliability issues.
No
The SRC appreciates the SDT’s initiative but points out that the requirement still includes the verb
“implement”. That phrase, as part of a mandatory standard, will require a zero-defect environment.
The phrase “in a manner that identifies, assesses and corrects deficiencies” is vague, not measurable
and inconsistent with the results-based standard concept which emphasizes the inclusion of a
performance or reliability outcome in the requirement. A more direct and clear requirement would be
to simple require “implement documented communication protocol….”. We appreciate the SDT’s intent
for adding this phrase, but it does little to ease the concerns of the commenters. Instead, the addition
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introduces an immeasurable phrase that may in fact make the requirement more ambiguous and
unclear. The SRC realizes the SDT is trying to mandate a Communications Protocol, and would
therefore suggest if the SDT still believes a Standard is necessary, then the SDT need only require
each entity “have communications protocols, that include periodic monitoring, assessments, and
procedures for mitigating violations of those protocols.”
The SDT has been effective in responding to the Industry’s concerns on the issue of “one-way”
messaging. Communications Protocols are not documents that are suitable as “Standards” for a
mandatory reliability standard. The zero-defect, self-reporting nature of such standards conflicts with
the nature and impact of the violations that get reported. Protocols are internal controls that an entity
imposes on itself. Protocols allow an entity to self-regulate itself and to decide if the monitored
deviations from their own protocols warrant further action. To mandate such protocols are
implemented removes the allowance for “impact to reliability”. To mandate that an entity have
protocols is a better approach. To create a new category for Protocols that do not carry the same level
of monitoring and reporting as standards is an even better approach. The SRC recognizes that the
SDT has submitted an RSAW that is designed to mitigate the zero-defect impacts. However, as is
stressed by NERC, RSAWs are not requirements. The only requirements are those in the approved
standard itself.
Individual
Gregory Campoli
New York Independent System Operator
NPCC RSC
No
We support the comment submitted by the NPCC RSC. It is unclear if a definition of operating
instruction is necessary as many entities may use this term and apply it for each unique
organizaation. However NPCC has proposed an alternate definition that should be considered.
Yes
We agree with the proposal to remove R3 and R4. The revisions to R1 and R2 are an improvement.
However, it remains unclear whether a communication protocal should be a standard or a guideline.
We continue to look for evidence that this type of requirement would have directly provented a
previous event, as there is no published reports today.
We support the set of comments provided by the NPCC RSC and are repeated below: Functional entity
is capitalized throughout the Standard, yet functional entity is not a defined term in the NERC
Glossary. Propose changing the wording in Requirement R1 to the following: R1. Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall have documented communication
protocols that include identification, assessment, and correction of deficiencies for Operating
Instructions between functional entities that include the following: [Violation Risk Factor: Medium
[Time Horizon: Long-term Planning ] The Sub-requirements introduce too much detail into the
Standard. This detail dictates “how” something is to be done, rather than “what” is to be done.
Following are comments to be considered on the sub-requirements should they remain in the
Standard. Propose changing the wording in Sub-requirement 1.1 to the following: 1.1. Use of the
English language when issuing or responding to an oral or written Operating Instruction, unless
another language is mandated by law or regulation or agreement. Propose changing the wording in
Sub-requirement 1.3 to the following: 1.3. Use of the time, the time zone where the action will occur
and indication of whether the time is daylight saving time or standard time when issuing an oral or
written Operating Instruction that refers to clock times between functional entities in different time
zones, unless time protocols are defined in written agreements between the functional entities.
Regarding Sub-requirement 1.5, the use of alpha-numeric clarifiers should be no more than a best
practice. In case of uncertainty, 3 part communication as specified in Sub-requirement 1.6 would
catch any ambiguities. Propose changing the wording in Sub-requirement 1.8 to the following: 1.8.
When issuing an oral Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (for example an all call
system), verbally or electronically confirm receipt or that communications paths were established to
receive the message from one or more receiving parties. Regarding the Time Horizons for
Requirements R1 and R2, they should be Real-time Operations since the communications are
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occurring in real time, and the implementation of the protocol is the intent of R1 and R2. Suggest that
the Standard be further clarified so that the intended purpose is to ensure that an entity has
implemented a communications protocol with various core attributes, such as three part
communication. We believe that it is not the SDT's intent that an entity will be found out of
compliance for instances when an operating instruction was given which did not conform to its
implemented protocol. Compliance will only be assessed if the Protocol procedure itself was not
formally implemented and not to individual violations of such procedure which will be handled by
internal controls to track and address any deficiency. In the context of implementation, sufficient
implementation as used in this Standard could be demonstrated by management approved protocol
procedures issued to the appropriate individuals in the organization and documented training. The
Standard is not envisioned to be a zero-defect Standard however, and unless entities and audit staff
have clear understandings of what "implement" means there may be instances when an auditor may
find non-compliance beyond the intent of the Standard's Purpose and the Reliability Assurance
Initiative concept being brought forward with this Standard. Suggest clarification to the word
implement as it is used in the Standard and what activities in the compliance area will ensure proper
audit expectations are set.
Individual
Michiko Sell
Public Utility District No. 2 of Grant County, WA
Yes
No
The term Functional Entities is not a defined term within the NERC glossary nor is it a newly defined
term in the proposed Standard language. Grant echos Seattle City Lights concern with the use of this
term.
No
Grant only has concern with the use of "Responsible Entity" within the VSL language since it also is
not a recognized defined term.
Grant recognizes the tremendous effort set forth by the Standards Drafting Team in response to
comments received on this Standard. Grant is also appreciative of the inclusion of non-zero defect
language promoting entities to identify, assess and correct deficiencies in support of reliability
improvement.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
Yes
Xcel Energy is voting negative, again, because we continue to believe that some of the individual
protocols are too prescriptive. We strongly believe that some of these protocols would be more
effective if used in certain circumstances, instead of at all times. In particular, we do not agree with
1.5 being required on all Operating Instructions. Here are some specific perspectives: 1) If field
personnel are working from a written copy of a switching request, and they confirm the switching
request number, revision, etc., we believe there should be an exception from the use of alphanumeric clarifiers when the operator and field person are confirming the steps. Do they consider this
“oral” communication and thus meeting compliance of 1.5? 2) The use of alpha-numeric clarifiers
does not always make a communication more clear. The intent of the standard is to improve a
misunderstanding, not create misunderstanding when giving the instruction. As stated previously, we
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feel that the use of alpha-numeric clarifiers should be a tool available to the operator when the
original communication was not correctly understood. We recommend that R1.5 be reworded to
something like this: 1.5 Circumstances where personnel should use alpha-numeric clarifiers, when
issuing an oral Operating Instruction for Facilities and Elements in instances where the nomenclature
of Facilities or Elements is in alpha-numeric format.
Individual
Jason Snodgrass
Georgia Transmission Corporation
No
GTC is concerned that the proposed definition of an “Operating Instruction” is too similar to the
definition of a “Reliability Directive” specifically with the inclusion of “command from a System
Operator”. GTC recommends an additional statement such as “The term does not include commands
specified as Reliability Directives”.
No
GTC agrees with the decision to remove R3 and R4 from COM-003 draft 4, but is concerned with the
incorporation of the internal controls language in R1and R2. These changes don’t resolve the concerns
submitted on the previous draft of the standard. GTC believes that internal controls should be
implemented based on a registered entities' assessment of risk and should not be subject to fines and
penalties if a regional entity does not agree with a registered entity's control design or control
effectiveness. We also question whether the current set of auditors have the appropriate skill set to
assess internal control. We believe an assessment of internal controls is appropriate in determining
the depth and breadth of audit testing, but strongly disagree that regional entity's should have the
authority to, in effect, dictate internal control design. Furthermore, if this language is incorporated,
GTC believes that there is too much uncertainty on how Regional Entities will audit internal controls
during compliance audits and what a violation will look like. For example, suppose a Registered Entity
confirmed that its Operating Instructions between Functional Entities were implemented correctly
100% of the time during a specified reporting period. Would this entity then be designated as noncompliant since zero deficiencies were identified via the control method and thus there wasn’t a need
to correct? As such, GTC strongly encourages that the internal controls language “in a manner that
identifies, assesses and corrects deficiencies” be removed from COM-003 in order to allow the
Reliability Assurance Initiative (RAI) effort to be fully developed and implemented with industry
involvement to define how a risk-based model will work and how a registered entity’s internal controls
will be assessed.
No
See example above identifying the possibility that an entity could perform Operating Instructions
100% correctly, yet could be designated as a Severe VSL since the control manner didn’t identify any
deficiencies.
Group
Boneville Power Administration
Jamison Dye
Yes
No
BPA does not agree with the use of the phrase “between Functional Entities” in R1 and R2 because
one organization can have multiple Functional Entities within it. BPA believes that an organization
should be able to establish its own internal communication protocols. In consideration of comments,
the drafting team stated “The SDT agrees that these communication protocols apply only to external
communications between system operators for the TOP, GOP, and BA. It would only make sense to
have them apply internally but that is the entity’s option. Most entities use all or some of these
communication protocols already.” However, the language of the standard and the November 27
webinar indicate otherwise. During the webinar an industry representative asked, “Consider a
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vertically integrated utility performing functional roles of a BA, TOP, and GOP. Is it required to have
communication protocols for operating instructions between the different system operator desks.”
Both presenters answered “Yes,” and explained that separate functional entities within a company
would need to comply with this requirement. (11/27 Webinar recording at 1:04/1:30) BPA suggests
that the term “external” be added before “functional entities” or another phasing change be
incorporated into the standard to eliminate this potential interpretation.
Yes
Individual
Warren Rust
Colorado Springs Utilities (CSU)
No
CSU appreciates the difficulty the SDT faces in drafting and pursuing approval of this Standard and its
Requirements and the hard work of the members. “Operating Order” is a better term than “Operating
Instruction” as “instruction” has the connotation of advice or guidance, where I believe the SDT
means to convey a sense of “being told to do something … as in, this is an ‘order’.” System Operator
is already defined in the NERC glossary as, “An individual at a control center <> (Balancing
Authority, Transmission Operator, Generator Operator, Reliability Coordinator) whose responsibility it
is to monitor and control that electric system in real time.” Therefore, the first sentence of the
definition is redundant. If the point is to exclude Generator Operators at Control Centers (not sure
why that should be), then it would seem easier to simply state that. Facility is also already defined in
the NERC glossary as, “A set of electrical equipment that operates as a single Bulk Electric System
Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)” and, so, should already
be covered by the phrase, “of an Element of the Bulk Electric System,” in that, by operating an
Element, one would, of necessity, be operating one or more of any Facilities comprising that Element.
Also, it is possible that the recipient may not be the person actually taking the action, but may need
to pass the Operating Order on for action. Suggest that a more concise definition might be along the
lines, “Operating Order – A command by a System Operator with the expectation that the recipient is
to take or ensure action is taken to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System. Discussions of general information and of potential operations or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.” *Control Center is a defined term.
Yes
Specifically, agree with the removal of R3 & R4.
No
Having and implementing a “communications protocol” are administrative in nature and the mere fact
of not having or implementing such a protocol is not sufficient to “directly affect the electrical state or
the capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system.” The VRFs for these two requirements should be LOW. The VSLs, as drafted, focus
specifically on the contents of the “communications protocol,” but they should address
implementation, since that is the active verb in both of the requirements; “shall implement.”
Again, I appreciate the hard work required of the members of this SDT to formulate these drafts in
the midst of wildly differing expectations and also appreciate the opportunity to express my opinions
in this comment. 1) In Consideration of Comments to Draft 3, the SDT stated“… COM-003-1 only
applies to communication between functional entities. For example, if a TOP System Operator is
issuing an Operating Instruction to an individual that is internal to that TOP, three part
communication is not required by this standard. If a TOP System Operator is issuing an Operating
Instruction to an individual in another TOP or another functional entity (e.g. Distribution Provider,
Generator Operator), then three part communication is required by this standard. If a TOP System
Operator is issuing an Operating Instruction to an individual that is not in a functional entity, then
three part communication is not required by this standard.” and; In response to Bonneville Power
Authority comment, “In R1.5, BPA disagrees with the mandatory use of alpha numeric communication
protocols for internal communications ...” Response: The SDT agrees that these communication
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protocols apply only to external communications between system operators for the TOP, GOP, and BA
…” [Comment] It is not clear in the language of the standard that the requirements apply only to
external communications. The standard should explicitly state so. The requirement should apply only
to communications between separate Registered Entities, vice Functional Entities. Within a single
control room (same room) there may be Transmission System Operators, Distribution System
Operators, and Generator Operators. If the CEA considers that those individuals represent different
Functional Entities (even though all work for the same Registered Entity), and takes into consideration
the above guidance, one “TSO” could issue an instruction to another “TSO” or to an individual in the
field (ostensibly not a Functional Entity) without needing to show compliance with any of the
minimum Communication Protocol requirements, but would have to show compliance when giving an
order to the “DSO” or “GSO” at the next desk over. And, does the SDT have a suggestion for how the
various “Communications Protocol” requirements be evidenced for compliance when communication
between “in-house” Functional Entities is face-to-face? 2) From the Consideration of Comments,
Summary p.4, “Commenters in draft 3 argued that “alpha-numeric clarifiers” are of no value and
could only lead to confusion and delays by System Operators. The SDT has chosen to retain the
inclusion of alpha-numeric clarifiers as a means of clarifying Operating Instructions. The use of such
clarifiers, which an entity can develop to suit their preferences, eliminates the ambiguity of similar
sounding letters and numbers. Their use, based on the experience of other organizations that use
them, becomes a natural part of communication language.” [Comment] There are situations where
the use of such clarifiers would exacerbate ambiguity or unnecessarily complicate or burden the
communication leading to just as much risk of misunderstanding. Does “develop to suit their
preferences” give room for an entity to state in its Communications Protocol that the use of “clarifiers”
is required in Operating Instructions only when it is obvious they are necessary to ensure clarity?
From the Consideration of Comments, in response to ACES Power Marketing Standards Collaborators
comment; “Response: The requirement does allow an entity to develop its own protocol around alpha
numeric clarifiers. The protocol should be uniform, clear and must increase reliability. “ [Comment] It
appears, from the language in the draft, that the only flexibility might be in deciding what “clarifiers”
are to be used (Alpha vs Adam, etc.). Is it the SDT’s intention that an Entity could address alphanumeric clarifiers in its Protocol by stating they do not need to be used, or only as necessary to
ensure clarity? Also, in my opinion, it is not sufficiently clear that such clarifiers are necessary to
increase BES reliability in the first place. CSU agrees with the numerous commentators on the
previous draft as well as any on the current one that the use of “alpha-numeric identifiers," while
appropriate in certain, if not many, circumstances; may not be appropriate in all and may, indeed, be
counter to productive and clear communication in some, if not many, circumstances. 3) And, in
response to PPL Corporation NERC Registered Affiliates’ comment in regards to the use of the EPRI
study, “Response: The OPCPSDT thanks you for your comments. The OPCPSDT cited those figures
from a commenter who appended an Industry white paper (by the same author) to the draft
comment form. The SDT responded after reading it. Even if the mishap rate for communication issues
is 14.5% that is a significant impact on BES reliability that will be addressed by COM-003-1.” The SDT
continues, in their consideration of comments to Draft 3, to rely on an EPRI study which does not
support the conclusions they wish to draw from it. “Failure to use ‘alpha-numeric clarifiers’” was not
one of the identified communications deficiencies in the EPRI study and therefore it is misguided to
cite this study in defense of requiring the use of such ‘clarifiers’ in Operating Instructions. Indeed,
none of the proposed requirements can be found as cited deficiencies in that report. The study
depended on voluntary reporting by only a portion of EPRI members, and was not designed to be
scientifically valid study. The introduction to the study itself acknowledged that the sample was selfselected and not random, so, therefore, “not representative of the industry as a whole, or even the
membership of EPRI.” The report also goes on to state there may be reporting bias in the data
submitted (e.g, utilities may have been motivated to participate by their own high error rates, while
those with low rates may have chosen not to participate). Also, the data submitted were a result of
each utility’s internal investigations – not necessarily consistently performed even within the same
utility, and most probably not between different utilities. The SDT is relying on the contribution of
communications deficiencies in 14.5% of the reported events (which, by the way, is not an error
RATE, much less an “impact to BES” rate) to justify communications protocols that will not address
the majority of the communications error types which made up that contribution in that report. 4) The
OPCPSDT, in my opinion, has not adequately justified retaining R1.4 in the face of the elimination of
the exact same requirement in TOP-002 R18.
Individual
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Jen Fiegel
Oncor Electric Delivery
Yes
No
Oncor supports the shift in compliance to the internal controls approach and we looks forward to
NERC providing a programmatic/principles framework in a collaborative approach with the industry. In
the absence of this framework, it is unknown how the concept of "identify, assess and correct" will
evolve. As the framework is developed including the "identify, assess and correct" concept, Oncor
requests that continuous focus be placed on implementing principles including this concept and not
requiring or specifying internal controls which would place additional compliance burden on entities.
The internal controls principles/framework should enable entities to establish internal controls model
utilizing deficiency correction approach but should not mandate the approach at the
Standard/Requirement level. Internal Controls Program needs to be defined by an Entity, it is not a
“One Size Fits All”. The standards/RSAWs should reflect this understanding.
Yes
The SDT requested industry comment on the reference to “Operating Instructions between Functional
Entities.” Industry discussions show that entities interpret this in different ways, and Oncor agrees
that the use of the term “Functional Entity” is confusing. Functional Entity is not defined in the NERC
Glossary. The NERC Webinar 11/27/12 stated this language requires protocols for communication
between RC and TOP entities or TOP and TO entities, but it does not require the same protocols for
TOP to TOP communications. This would require entities with multiple registration functions to
designate personnel by functional entity and in turn, personnel would have to identify which
functional entity each person they interface with. It is impractical and inefficient to require Entities to
re-organize all personnel which would foster an inefficient structure and could potentially lead teams
to not communicate effectively. In addition, this could have a negative impact on communications
between companies. For example, in the ERCOT region, there are approximately 15 local control
centers and ERCOT who are all registered as TOPs. One might interpret the webinar discussion to say
that communications between neighboring TOPs or ERCOT and one of the local control centers are not
subject to the requirements of COM-003-1 since these are TOP to TOP communications. We strongly
recommend the SDT review this to greatly simplify COM-003-1. Potential alternative to the current
language would be “require entities to implement, in a manner …, protocols that include three-part
communication for Operating Instructions” and eliminate the reference to Functional Entity.
Alternatively, if the SDT is trying to limit the protocols to communications between companies
(another common interpretation), simply state it as such. In addition, Oncor believes the specificity in
the subparts of R1 is unnecessary. Three-part communication is the preferred method for ensuring
that both parties understand an Operating Instruction and it provides a sufficient mechanism for
clear, concise and accurate communication. In creating a protocol that requires System Operators to
essentially relearn the way to speak (specifically using alpha-numeric identifiers) will only create
confusion and inefficiency as operators try to follow protocol and catch/correct themselves.
Additional Comments Received:
Brett Holland
KCPL – Operations Compliance
1. Do you agree with the changes made to the proposed definition “Operating Instruction” (now
proposed as a “A command by a System Operator of a Reliability Coordinator, or of a Transmission
Operator, or of a Balancing Authority, where the recipient of the command is expected to act, to change
or preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility of the
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Bulk Electric System. Discussions of general information and of potential options or alternatives to
resolve BES operating concerns are not commands and are not considered Operating Instructions. ”) to
be added as a term for the NERC Glossary? If not, please explain in the comment area of the last
question.
Yes
No
Comments: Would suggest the language read as follows: “An order by a System Operator of a Reliability
Coordinator, Transmission Operator, or of a Balancing Authority, where the recipient of the order is
expected…” for clarity. Operating Instructions, this term should not be added to the NERC Glossary to
bring all Operating Instructions into scope.
2. The SDT has proposed new language in COM-003-1, R1 and R2: “Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall implement, in a manner that identifies, assesses and
corrects deficiencies, documented communication protocols for Operating Instructions between
Functional Entities that include the following:” R3 and R4 from draft 3 are eliminated. Do you agree with
these proposed requirement changes? If not, please explain in the comment area of the last question.
Yes
No
Comments:
R1.8, R1.9, and R2.2 need further clarification. The specific vehicle for information delivery in these 3
particular requirements is via “one-way burst messaging” systems, which obviously do not allow for 2
way communication. Acceptable means of verbal and/or electronic confirmations and clarification
requests need more definition.
R1.8 addresses confirmation requirements when utilizing one-way burst messaging systems for
communication with multiple parties. We are not sure why we would only request one or more
confirmations in this case as it is possible that one or more parties, but not all, would receive the
intended message. This leaves the possibility open for potential mis-understanding or lacks of
information for one or more of the potential multiple parties receiving the message.
This language (identifies, assesses and corrects deficiencies) should not be added to the
standard as it introduces internal controls into the requirements. Internal controls are a strengthening
of a compliance program and support a strong culture of compliance, however, are not mandatory and
enforceable. This will introduce a precedent that we are not prepared as an industry to deal with or
respond to in order to satisfy compliance and enforcement.
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Albert DiCaprio
PJM
IRC Standards Review Committee Group
Ben Li
IESO NPCC segment 2
Ali Miremadi
CAISO WECC segment 2
Steve Myers
ERCOT ERCOT segment 2
Charles Yeung
SPP
SPP
segment 2
1. Do you agree with the changes made to the proposed definition “Operating Instruction”
(now proposed as a “A command by a System Operator of a Reliability Coordinator, or of
a Transmission Operator, or of a Balancing Authority, where the recipient of the command
is expected to act, to change or preserve the state, status, output, or input of an Element
of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general
information and of potential options or alternatives to resolve BES operating concerns are
not commands and are not considered Operating Instructions. ”) to be added as a term for
the NERC Glossary? If not, please explain in the comment area of the last question.
Yes
No
Comments:
Technically the definition is an improvement and the SRC would agree with the
proposed changes, if the definition were needed. The issue is with the need for this
definition, and the continuing debate this definition is generating. The SRC is
opposed to having this term defined and added to the NERC Glossary. The term
operating instruction does not need to be defined. For years, system operators deal
with operating instructions on a daily if not minute basis. Having a defined term, and
calling such communication as “Command” is unnecessary, and can confuse
operators from what they understand to be the meaning of operating instructions.
While the SDT has found that their previous definitions were not appropriate for a
NERC standard, and subsequent incremental changes are useful, the debate itself
does not seem to be a productive use of the SDT’s or the Industry’s time.
The SRC would prefer that the objectives of the SAR (communications protocols) be
handled through means other than a Standard (e.g. the Operating Committee’s
Reliability Guidelines on Communications). The reason being, a standard requires
zero-defect compliance, data retention, self-reporting, and requires these debates
over the proposed terms such as “Operating instruction” which diverts the Industry,
NERC and the Regional Entities from focusing on more productive reliability issues.
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2. The SDT has proposed new language in COM-003-1, R1 and R2: “Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication
protocols for Operating Instructions between Functional Entities that include the
following:” R3 and R4 from draft 3 are eliminated. Do you agree with these proposed
requirement changes? If not, please explain in the comment area of the last question.
Yes
No
Comments:
The SRC appreciates the SDT’s initiative but points out that the requirement still
includes the verb “implement”. That phrase, as part of a mandatory standard, will
require a zero-defect environment.
The phrase “in a manner that identifies, assesses and corrects deficiencies” is
vague, not measurable and inconsistent with the results-based standard concept
which emphasizes the inclusion of a performance or reliability outcome in the
requirement. A more direct and clear requirement would be to simple require
“implement documented communication protocol….”. We appreciate the SDT’s
intent for adding this phrase, but it does little to ease the concerns of the
commenters. Instead, the addition introduces an immeasurable phrase that may in
fact make the requirement more ambiguous and unclear.
The SRC realizes the SDT is trying to mandate a Communications Protocol, and
would therefore suggest if the SDT still believes a Standard is necessary, then the
SDT need only require each entity “have communications protocols, that include
periodic monitoring, assessments, and procedures for mitigating violations of those
protocols.”
3. Do you agree with the VRFs and VSLs for Requirements R1 and R2?
Yes
No
Comments:
4. Do you have any other comments or suggestions to improve the draft standard?
Comments:
The SDT has been effective in responding to the Industry’s concerns on the issue of
“one-way” messaging.
Communications Protocols are not documents that are suitable as “Standards” for a
mandatory reliability standard. The zero-defect, self-reporting nature of such
standards conflicts with the nature and impact of the violations that get reported.
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Protocols are internal controls that an entity imposes on itself. Protocols allow an
entity to self-regulate itself and to decide if the monitored deviations from their own
protocols warrant further action. To mandate such protocols are implemented
removes the allowance for “impact to reliability”. To mandate that an entity have
protocols is a better approach. To create a new category for Protocols that do not
carry the same level of monitoring and reporting as standards is an even better
approach.
The SRC recognizes that the SDT has submitted an RSAW that is designed to
mitigate the zero-defect impacts. However, as is stressed by NERC, RSAWs are not
requirements. The only requirements are those in the approved standard itself.
Group Name
SPP Standards Review Group
Lead Contact Robert Rhodes
Contact Organization Southwest Power Pool
Segment
2
Additional Member
Leo Bernier
Doug Callison
Albert Campbell
Michelle Corley
Greg Froehling
Jonathan Hayes
Bo Jones
Allen Klassen
Tiffany Lake
Additional Organization
AES Shady Point LLC
Grand River Dam Authority
Grand River Dam Authority
Cleco Power LLC
Rayburn Country Electric
Cooperative
Southwest Power Pool
Westar Energy
Westar Energy
Westar Energy
Region
SPP
SPP
SPP
SPP
Segment
5
1,3,5
1,3,5
1,3,5
SPP
SPP
SPP
SPP
SPP
3
2
1,3,5,6
1,3,5,6
1,3,5,6
1. Do you agree with the changes made to the proposed definition “Operating Instruction”
(now proposed as a “A command by a System Operator of a Reliability Coordinator, or of
a Transmission Operator, or of a Balancing Authority, where the recipient of the command
is expected to act, to change or preserve the state, status, output, or input of an Element
of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general
information and of potential options or alternatives to resolve BES operating concerns are
not commands and are not considered Operating Instructions. ”) to be added as a term for
the NERC Glossary? If not, please explain in the comment area of the last question.
Yes
No
Comments:
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2. The SDT has proposed new language in COM-003-1, R1 and R2: “Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication
protocols for Operating Instructions between Functional Entities that include the
following:” R3 and R4 from draft 3 are eliminated. Do you agree with these proposed
requirement changes? If not, please explain in the comment area of the last question.
Yes
No
Comments:
While we are glad to see an effort on the part of the drafting team and NERC to move away
from ‘zero tolerance’ requirements and move toward internal controls to address
deficiencies, we are concerned as to how this process will be implemented if it is approved.
For example, if our process calls for a 2% sampling size and the sample is presented to the
CEA, what prevents the CEA from saying that the sample size is too small and finds us in
violation because of it. Also, if our process does not uncover any discrepancies is it because
there are no discrepancies or is it because our process is flawed and we missed something?
We are concerned about how a CEA will respond to such a situation. Perhaps we need a
more descriptive methodology of how this process will actually work in the field.
3. Do you agree with the VRFs and VSLs for Requirements R1 and R2?
Yes
No
Comments:
The third component of the Severe VSLs of R1 and R2 should read:
“The Responsible Entity did not implement documented communication protocols in a
manner that identifies, assesses and corrects deficiencies in those protocols as required in
Requirement 1.”
“The Responsible Entity did not implement documented communications protocols in a
manner that identifies, assesses and corrects deficiencies in those protocols as required in
Requirement 2.”
4. Do you have any other comments or suggestions to improve the draft standard?
Comments:
- We are not sure which time zone is required in R1.3. For example, if two facilities are
physically located side-by-side in the Mountain Time Zone but are controlled by
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different GOPs, one in the Central Time Zone and the other in the Eastern Time Zone,
which time zone should be used in the Operating Instruction?
-
Delete the extra space following ‘Instruction’ in the 4th line of R1.4.
R1.5 should be read:
“Use of alpha-numeric clarifiers when issuing an oral Operating Instruction for Facilities and
Elements in instances where the nomenclature of Facilities or Elements is in alpha-numeric
format. (For example, if an entity designated a circuit breaker “One two Bravo” (12B), one
two Bravo would need alpha-numeric clarifiers if used in an oral Operating Instruction.)”
-
Delete the “. “ in the parentheticals in the 3rd lines of both R1.8 and R1.9
R1.9 and R2.2 should be expanded to clarify what the recipient should do in the event
the communication via a burst messaging system is not understood. We propose the
following for both R1.9 and R2.2.
“When receiving an oral Operating Instruction through a one-way burst messaging system
used to communicate a common message to multiple parties in a short time period (e.g. an
all call system), if the communication received is not understood, subsequent to the call,
the recipient is to call the initiator and request clarification.”
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COM-003-1 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot closed
June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Ballot closed
September 22, 2012.
9. Version 4 draft of Standard posted November 2012 for Formal Comments, Ballot closed
December 13, 2012.
Description of Current Draft:
This is the fifth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
February 2013
2. Third Successive Ballot of Standards
March 2013
3. Recirculation ballot of standards.
April 2013
4. Board adopts standards.
May 2013
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COM-003-1 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act, to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of general information and
of potential options or alternatives to resolve BES operating concerns are not commands and are
not considered Operating Instructions.
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COM-003-1 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operators predefined communications protocols that
reduce the possibility of miscommunication that could lead to action or inaction
harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval, or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities; or, in those
jurisdictions where no regulatory approval is required, the first day of the first calendar
quarter twelve (12) calendar months from the date of Board of Trustee adoption.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall develop and
implement documented communication protocols
that outline the communications expectations of its
System Operators. The documented communication
protocols will address, where applicable, the
following:[Violation Risk Factor: Low] [Time
Horizon: Long-term Planning ]
Implementation means (in R1, R2 R3 and R4)
incorporating the communication protocols
into processes, policies, procedures, training
programs and assessment programs to support
setting and attaining the communication
expectations of operators (R3) and System
Operators (R1).
1.1. Use of the English language when issuing or responding to an oral or written
Operating Instruction or Reliability Directive, unless another language is
mandated by law or regulation.
1.2. Instances that require time identification when issuing an oral or written Operating
Instruction or Reliability Directive, and the format for that time identification.
1.3. Nomenclature for Transmission interface Elements and Transmission interface
Facilities when issuing an oral or written Operating Instruction or Reliability
Directive.
1.4. Instances where alpha-numeric clarifiers are necessary when issuing an oral
Operating Instruction or Reliability Directive, and the format for those clarifiers.
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COM-003-1 Operating Personnel Communications Protocols
1.5. Instances where the issuer of an oral two party, person-to-person Operating
Instruction is required to:
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
Reissue the Operating Instruction to resolve a misunderstanding.
1.6. Require the recipient of an oral two party, person-to-person Operating Instruction
to repeat, restate, rephrase, or recapitulate the Operating Instruction, if requested
by the issuer.
1.7. Instances where the issuer of an oral Operating Instruction or Reliability Directive
using a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) is required to
verbally or electronically confirm receipt from at least one receiving party.
1.8. Require the receiver of an oral Operating Instruction or Reliability Directive using
a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request
clarification from the issuer if the communication is not understood.
1.9. Coordination with affected Reliability Coordinators’, Balancing Authorities’,
Transmission Operators’, Distribution Providers’, and Generator Operators’
communication protocols.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop method(s) to assess System Operators’ communication practices and
implement corrective actions necessary to meet the expectations in its documented
communication protocols developed for Requirement R1. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning, Operations Assessment ]
R3. Each Distribution Provider and Generator Operator shall develop and implement
documented communication protocols that outline the communications expectations
of its operators. The documented communication protocols will address, where
applicable, the following: [Violation Risk Factor: Low] [Time Horizon: Long-term
Planning ]
3.1. Use of the English language when responding to an oral or written Operating
Instruction or Reliability Directive, unless another language is mandated by law or
regulation.
3.2. Require the recipient of an oral two party, person-to-person Operating Instruction
to repeat, restate, rephrase, or recapitulate the Operating Instruction, if requested
by the issuer.
3.3. Require the receiver of an oral Operating Instruction or Reliability Directive using
a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request
clarification from the issuer if the communication is not understood.
R4. Each Distribution Provider and Generator Operator shall develop method(s) to assess
operators’ communication practices and implement corrective actions necessary to
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COM-003-1 Operating Personnel Communications Protocols
meet the expectations in its documented communication protocols developed for
Requirement R3. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning /Operations Assessment ]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence that it implemented its documented communication protocols that it
developed for Requirement R1 which may include, but is not limited to, its policies,
procedures, and or operator training.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide the results of its periodic assessment and of any corrective actions (if any
corrective actions were implemented) developed for Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R3. Each Distribution Provider,
and Generator Operator shall provide evidence that it implemented its documented
communication protocols that it developed for Requirement R3 which may include, but
is not limited to, its policies, procedures, and or operator training.
M4. Each Distribution Provider and Generator Operator shall provide the results of its
periodic assessment and of any corrective actions (if any corrective actions were
implemented) developed for Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
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COM-003-1 Operating Personnel Communications Protocols
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R1 Measure M1 for the most
recent 90 days.
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R2 Measure M2 for the most
recent 180 days.
Each Distribution Provider and Generator Operator shall retain evidence for
Requirement R3 Measure M3 for the most recent 90 days.
Each Distribution Provider and Generator Operator shall retain evidence for
Requirement R4 Measure M4 for the most recent 180 days.
If a Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
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Page 6 of 11
COM-003-1 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long Term
Planning
Low
The Responsible Entity did
not address one (1) of the
nine(9) parts of
Requirement R1in their
documented communication
protocols as required in
Requirement R1
OR
The Responsible Entity did
not implement one (1) of the
nine (9) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1
Draft 5
February 28, 2013
Moderate VSL
High VSL
Severe VSL
The Responsible Entity did
not address two (2) of the
nine (9) parts of Requirement
R1 in their documented
communication protocols as
required in Requirement R1
The Responsible
Entity did not address
three (3) of the nine
(9) parts of
Requirement R1 in
their documented
communication
protocols as required
in Requirement R1
The Responsible Entity did
not address four (4) or more
of the nine (9) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1
OR
OR
The Responsible Entity did
not implement two (2) of the
nine (9) parts of Requirement
R1 in their documented
communication protocols as
required in Requirement R1
The Responsible
Entity did not
implement three (3) of
the nine (9) parts of
Requirement R1 in
their documented
communication
protocols as required
in Requirement R1
Page 7 of 11
OR
The Responsible Entity did
not have any documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did
not implement any
documented communication
protocols as required in
Requirement R1
COM-003-1 Operating Personnel Communications Protocols
R#
R2
Time
Horizon
Operations
Planning
Operations
Assessment
Draft 5
February 28, 2013
VRF
Medium
Violation Severity Levels
Lower VSL
Moderate VSL
The Responsible Entity
performed periodic
assessments of its
System Operators’
communication practices
and implemented 50 %
or more but not all
corrective action
identified in
Requirement R2
necessary to meet the
expectations in its
documented
communication protocols
developed for
Requirement R1.
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented
less than 50 % of the
corrective actions identified
in Requirement R2 necessary
to meet the expectations in
its documented
communication protocols
developed for Requirement
R1.
High VSL
The Responsible
Entity performed
periodic assessments
of its System
Operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R2
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement R1.
Page 8 of 11
Severe VSL
The Responsible Entity did
not perform periodic
assessments of its System
Operators’ communication
practices identified in
Requirement R2 necessary
to meet the expectations in
its documented
communication protocols
developed for Requirement
R1.
COM-003-1 Operating Personnel Communications Protocols
R3
Long Term
Planning
Low
The Responsible Entity did
not address one (1) of the
three(3) parts of
Requirement R3in their
documented communication
protocols as required in
Requirement R3
The Responsible
Entity did not address
two (2) of the three(3)
parts of Requirement
R3 in their
documented
communication
protocols as required
in Requirement R3
OR
OR
The Responsible Entity did
not implement one (1) of the
three(3) parts of
Requirement R3
in their documented
communication protocols as
required in Requirement R3
Draft 5
February 28, 2013
The Responsible
Entity did not
implement two (2) of
the three(3) parts of
Requirement R3 in
their documented
communication
protocols as required
in Requirement R3
Page 9 of 11
The Responsible Entity did
not address three (3) of the
three(3) parts of
Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
The Responsible Entity
did not develop any
documented communication
protocols as required in
Requirement R3
OR
The Responsible Entity
did not implement any
documented communication
protocols as required in
Requirement R3
COM-003-1 Operating Personnel Communications Protocols
R4
Operations
Planning
Operations
Assessment
Draft 5
February 28, 2013
Medium
The Responsible Entity
performed periodic
assessments of its
operators’
communication practices
and implemented 50 %
or more but not all
corrective action
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication protocols
developed for
Requirement R3.
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 %
of the corrective actions
identified in Requirement R4
necessary to meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
The Responsible
Entity performed
periodic assessments
of its operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement R3
Page 10 of 11
The Responsible Entity did
not perform assessments of
its operators’
communication practices
and did not meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
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COM-003-1 Operating Personnel Communications Protocols
E. Regional Variances
None.
Version History
Version
Draft 5
February 28, 2013
Date
Action
Change Tracking
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COM-003-1 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot closed
June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Initial Ballot
closed September 2022, 2012.
9. Version 4 draft of Standard posted November 2012 for Formal Comments, Ballot closed
December 13, 2012.
Description of Current Draft:
This is the fourthfifth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Drafting team considers comments, makes conforming
changes, and requests SC approval to proceed to pre-ballot
comment period.
February 2013
1.2.SecondThird Successive Ballot of Standards
November 2012 March 2013
2.3.Recirculation ballot of standards.
January April 2013
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COM-003-1 Operating Personnel Communications Protocols
3.4.Board adopts standards.
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COM-003-1 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act, to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of general information and
of potential options or alternatives to resolve BES operating concerns are not commands and are
not considered Operating Instructions.
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COM-003-1 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operators uniformpredefined communications
protocols that reduce the possibility of miscommunication that could lead to action or
inaction harmful to the reliability of BES.
4.
Applicability:
COM-003-1
4.1. Functional Entities
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
5.
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
6.
Background:
The SDT has incorporated within this standard a recognition that these requirements
should not focus on individual instances of failure as a basis for violating the standard.
In particular, the SDT has incorporated an approach to empower and enable the
industry to identify, assess, and correct deficiencies in the implementation of certain
requirements. The intent is to change the basis of a violation in those requirements so
that they are not focused on whether there is a deficiency, but on identifying,
assessing, and correcting deficiencies. It is presented in those requirements by
modifying “implement” as follows:
Each … shall implement, in a manner that identifies, assesses, and corrects
deficiencies, . . .
The term documented communication protocols refers to a set of required protocols
specific to the Functional Entity. This term does not imply any particular naming or
approval structure beyond what is stated in the requirements. An entity should include
as much as it believes necessary in their documented protocols, but they must address
all of the applicable parts of the Requirement. The documented protocols themselves
are not required to include the “. . . identifies, assesses, and corrects deficiencies, . . ."
elements described in the preceding paragraph, as those aspects are related to the
manner of implementation of the documented protocols and could be accomplished
through other controls or compliance management activities.
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COM-003-1 Operating Personnel Communications Protocols
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop and implement, in a manner that identifies, assesses and corrects
deficiencies, documented communication protocols for Operating Instructions
between Functional Entities that includethat outline the communications expectations
of its System Operators. The documented communication protocols will address,
where applicable, the following: [:[Violation Risk Factor: Medium Low] [Time
Horizon: Long-term Planning ]
1.1. Use of the English language when issuing or responding to an oral or written
Operating Instruction or Reliability Directive, unless another language is
mandated by law or regulation.
1.
Use of the 24-hour clock format when referring to clock timesInstances that
require time identification when issuing an oral or written Operating Instruction.
1.2. Use of the time, the or Reliability Directive, and the format for that time zone
where the action will occur and indication of whether the time is daylight saving
time or standard time identification.
1.2.1.3.
Nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction that
refers to clock times between Functional Entities in different time zonesor
Reliability Directive.
2.
Use of the name specified by the owner(s) for
each Transmission interface Element or
Transmission interface Facility when referring to a
Transmission interface Element or a Transmission
interface Facility-in an oral or written Operating
Instruction , unless another name is mutually
agreed to by the Functional Entities.
Implementation means (in R1, R2 R3 and R4)
incorporating the communication protocols
into processes, policies, procedures, training
programs and assessment programs to support
setting and attaining the communication
expectations of operators (R3) and System
Operators (R1).
1.3.1.4.
Use of Instances where alpha-numeric
clarifiers are necessary when issuing an oral
Operating Instruction for Facilities and Elements
in instances where the nomenclature of Facilities or Elements is in alpha-numeric
or Reliability Directive, and the format (. for example if an entity designated a
circuit breaker “One twoBravo” (12B). One two Bravo would need alphanumericthose clarifiers if used in an oral Operating Instruction).
1.4.1.5.
When issuingInstances where the issuer of an oral two party, person-toperson Operating Instruction, require the issuer is required to:
Confirm that the response from the recipient of the Operating Instruction was
accurate, or
Reissue the Operating Instruction to resolve a misunderstanding.
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COM-003-1 Operating Personnel Communications Protocols
1.5.1.6.
When receiving Require the recipient of an oral two party, person-toperson Operating Instruction, require the recipient to repeat, restate, rephrase, or
recapitulate the Operating Instruction, if requested by the issuer.
1.6.1.7.
When issuingInstances where the issuer of an oral Operating Instruction
throughor Reliability Directive using a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (. for
example(e.g. an all callAll Call system),) is required to verbally or electronically
confirm receipt from at least one or more receiving partiesparty.
1.8. When receivingRequire the receiver of an oral Operating Instruction throughor
Reliability Directive using a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (. for
example(e.g. an all callAll Call system),) to request clarification from the initiator
issuer if the communication is not understood.
1.7.1.9.
Coordination with affected Reliability Coordinators’, Balancing
Authorities’, Transmission Operators’, Distribution Providers’, and Generator
Operators’ communication protocols.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop method(s) to assess System Operators’ communication practices and
implement corrective actions necessary to meet the expectations in its documented
communication protocols developed for Requirement R1. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning, Operations Assessment ]
R2.R3. Each Distribution Provider and Generator Operator shall develop and implement,
in a manner documented communication protocols that identifies, assesses and
corrects deficiencies,outline the communications expectations of its operators. The
documented communication protocols for Operating Instructions between Functional
Entities that includewill address, where applicable, the following: [Violation Risk
Factor: MediumLow] [Time Horizon: Long-term Planning ]
3.1. When receivingUse of the English language when responding to an oral or written
Operating Instruction or Reliability Directive, unless another language is
mandated by law or regulation.
3.1.3.2.
Require the recipient of an oral two party, person-to-person Operating
Instruction, require the recipient to repeat, restate, rephrase, or recapitulate the
Operating Instruction, if requested by the issuer.
3.2.3.3.
When receivingRequire the receiver of an oral Operating Instruction
throughor Reliability Directive using a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g. an
all callAll Call system),) to request clarification from the initiator issuer if the
communication is not understood, if required by the issuer.
R4. Each Distribution Provider and Generator Operator shall develop method(s) to assess
operators’ communication practices and implement corrective actions necessary to
meet the expectations in its documented communication protocols developed for
Requirement R3. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning /Operations Assessment ]
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COM-003-1 Operating Personnel Communications Protocols
C. Measures
M1. Evidence must include each applicable entity’sEach Balancing Authority, Reliability
Coordinator, and Transmission Operator shall provide its documented communications
protocols developed for Requirement R1 and must demonstrate. Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall provide evidence
that the protocols have beenit implemented in a manner its documented communication
protocols that identifies, assesses and corrects deficiencies. it developed for
Requirement R1 which may include, but is not limited to, its policies, procedures, and
or operator training.
M2. Evidence must include each applicable entity’sEach Balancing Authority, Reliability
Coordinator, and Transmission Operator shall provide the results of its periodic
assessment and of any corrective actions (if any corrective actions were implemented)
developed for Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R2 and must demonstrateR3.
Each Distribution Provider, and Generator Operator shall provide evidence that the it
implemented its documented communication protocols have been implemented in a
manner that identifies, assesses and corrects deficienciesit developed for Requirement
R3 which may include, but is not limited to, its policies, procedures, and or operator
training.
M2.M4. Each Distribution Provider and Generator Operator shall provide the results of its
periodic assessment and of any corrective actions (if any corrective actions were
implemented) developed for Requirement R4.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Regional Entity shall serve asAs defined in the NERC Rules of Procedure,
“Compliance Enforcement Authority (CEA) unless ” means NERC or the
applicable entity is owned, operated, or controlled byRegional Entity in their
respective roles of monitoring and enforcing compliance with the Regional Entity.
In such cases the ERO or a Regional Entity approved by FERC or other applicable
governmental authority shall serve as the CEA.
NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
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COM-003-1 Operating Personnel Communications Protocols
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence of its manner that identifies, assesses and
corrects deficiencies for Requirement R1 Measure M1 for the most recent 90
days.
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R2 Measure M2 for the most
recent 180 days.
Each Distribution Provider and Generator Operator shall retain evidence of its
manner that identifies, assesses and corrects deficiencies for Requirement
R2R3 Measure M2M3 for the most recent 90 days.
Each Distribution Provider and Generator Operator shall retain evidence for
Requirement R4 Measure M4 for the most recent 180 days.
If a Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator or Distribution Provider is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Draft 45
November 9, 2012 March 1, 2013
Page 8 of 15
COM-003-1 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Draft 5
February 28, 2013
Moderate VSL
High VSL
Page 9 of 15
Severe VSL
COM-003-1 Operating Personnel Communications Protocols
R1
Long Term
Planning
Low
The Responsible Entity did
not includeaddress one (1) of
the nine (9) parts of
Requirement R1, Parts 1.1 to
1.9 inR1in their documented
communication protocols as
required in Requirement R1
The Responsible Entity did
not includeaddress two (2) of
the nine (9) parts of
Requirement R1, Parts 1.1 to
1.9 in their documented
communication protocols as
required in Requirement R1
The Responsible
Entity did not
includeaddress three
(3) of the nine (9)
parts of Requirement
R1, Parts 1.1 to 1.9 in
their documented
communication
protocols as required
in Requirement R1
OR
OR
The Responsible Entity did
not implement two (2) of the
nine (9) parts of Requirement
R1 in their documented
communication protocols as
required in Requirement R1
The Responsible
Entity did not
implement three (3) of
the nine (9) parts of
Requirement R1 in
their documented
communication
protocols as required
in Requirement R1
OR
The Responsible Entity did
not implement one (1) of the
nine (9) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1
Draft 5
February 28, 2013
Page 10 of 15
The Responsible Entity did
not include address four (4)
or more of the nine (9)
parts of Requirement R1,
Parts 1.1 to 1.9 in their
documented communication
protocols as required in
Requirement R1
OR
The Responsible Entity did
not have any documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
any documented
communication protocols as
required in Requirement R1
COM-003-1 Operating Personnel Communications Protocols
R2
Long Term
Planning
Low
N/A
N/A
The Responsible
Entity did not include
one (1) of the two (2)
parts of Requirement
R2, Parts 2.1 to 2.2 in
their documented
communication
protocols
The Responsible Entity did
not include Parts 2.1 to 2.2
of Requirement R2, in their
documented communication
protocols
OR
The responsible entity did
not have documented
communication protocols as
required in Requirement R2
OR
The Responsible Entity did
not implement, in a manner
that identifies, assesses and
corrects deficiencies, their
documented communication
protocols as required in
Requirement R2
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Draft 5
February 28, 2013
Moderate VSL
High VSL
Page 11 of 15
Severe VSL
COM-003-1 Operating Personnel Communications Protocols
R2
Operations
Planning
Operations
Assessment
Draft 5
February 28, 2013
Medium
The Responsible Entity
performed periodic
assessments of its
System Operators’
communication practices
and implemented 50 %
or more but not all
corrective action
identified in
Requirement R2
necessary to meet the
expectations in its
documented
communication protocols
developed for
Requirement R1.
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented
less than 50 % of the
corrective actions identified
in Requirement R2 necessary
to meet the expectations in
its documented
communication protocols
developed for Requirement
R1.
The Responsible
Entity performed
periodic assessments
of its System
Operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R2
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement R1.
Page 12 of 15
The Responsible Entity did
not perform periodic
assessments of its System
Operators’ communication
practices identified in
Requirement R2 necessary
to meet the expectations in
its documented
communication protocols
developed for Requirement
R1.
COM-003-1 Operating Personnel Communications Protocols
R3
Long Term
Planning
Low
The Responsible Entity did
not address one (1) of the
three(3) parts of
Requirement R3in their
documented communication
protocols as required in
Requirement R3
The Responsible
Entity did not address
two (2) of the three(3)
parts of Requirement
R3 in their
documented
communication
protocols as required
in Requirement R3
OR
OR
The Responsible Entity did
not implement one (1) of the
three(3) parts of
Requirement R3
in their documented
communication protocols as
required in Requirement R3
Draft 5
February 28, 2013
The Responsible
Entity did not
implement two (2) of
the three(3) parts of
Requirement R3 in
their documented
communication
protocols as required
in Requirement R3
Page 13 of 15
The Responsible Entity did
not address three (3) of the
three(3) parts of
Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
The Responsible Entity
did not develop any
documented communication
protocols as required in
Requirement R3
OR
The Responsible Entity
did not implement any
documented communication
protocols as required in
Requirement R3
COM-003-1 Operating Personnel Communications Protocols
R4
Operations
Planning
Operations
Assessment
Draft 5
February 28, 2013
Medium
The Responsible Entity
performed periodic
assessments of its
operators’
communication practices
and implemented 50 %
or more but not all
corrective action
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication protocols
developed for
Requirement R3.
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 %
of the corrective actions
identified in Requirement R4
necessary to meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
The Responsible
Entity performed
periodic assessments
of its operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement R3
Page 14 of 15
The Responsible Entity did
not perform assessments of
its operators’
communication practices
and did not meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
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COM-003-1 Operating Personnel Communications Protocols
E. Regional Variances
None.
Version History
Version
Draft 5
February 28, 2013
Date
Action
Change Tracking
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Revisions or Retirements to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
COM-003-1 Requirement R1 Part 1.1
R4.Unless agreed to otherwise, each
R1. Each Balancing Authority, Reliability
Reliability Coordinator, Transmission
Coordinator, and Transmission Operator
Operator, and Balancing Authority shall use
shall develop and implement documented
English as the language for all communications
communication protocols that outline the
between and among operating personnel
communications expectations of its
responsible for the real-time generation
System Operators. The documented
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
control and operation of the interconnected
Bulk Electric System. Transmission Operators
and Balancing Authorities may use an
alternate language for internal operations
communication protocols will address,
where applicable, the following:[Violation
Risk Factor: Low] [Time Horizon: Long-term
Planning ]
1.1.
Use of the English language when issuing or
responding to an oral or written Operating
Instruction or Reliability Directive, unless
another language is mandated by law or
regulation
Conforming Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval, or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-003-1 in the particular Jurisdiction in which COM-003-1 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is expected to
act to change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Revisions or Retirements to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
COM-003-1 Requirement R1 Part 1.1
R4.Unless agreed to otherwise, each
R1. Each Balancing Authority, Reliability
Reliability Coordinator, Transmission
Coordinator, and Transmission Operator
Operator, and Balancing Authority shall use
shall develop and implement documented
English as the language for all communications
communication protocols that outline the
between and among operating personnel
communications expectations of its
responsible for the real-time generation
System Operators. The documented
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
control and operation of the interconnected
Bulk Electric System. Transmission Operators
and Balancing Authorities may use an
alternate language for internal operations
communication protocols will address,
where applicable, the following:[Violation
Risk Factor: Low] [Time Horizon: Long-term
Planning ]
R1.
Each Balancing Authority, Reliability
Coordinator, and Transmission Operator
shall implement, in a manner that identifies,
assesses and corrects deficiencies,
documented communication protocols for
Operating Instructions between Functional
Entities that include the following: [Violation
Risk Factor: Medium] [Time Horizon: Longterm Planning ]
1.1.
Use of the English language
when issuing or responding to an oral or
written Operating Instruction or Reliability
Directive, unless another language is
mandated by law or regulation.
Use of the English language when issuing an oral
or written Operating Instruction between
functional entities, unless another language
is mandated by law or regulation.
Conforming Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval, or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-0031-12 in the particular Jurisdiction in which COM-0031-12 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
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Unofficial Comment Form
Project 2007-02 Operating Personnel Communications
Protocols COM-003-1
Please DO NOT use this form. The drafting team is posting the draft COM-003-1 Operating Personnel
Communications Protocols standard for industry comment for a 30-day comment period. Please use the
electronic comment form located at the link below to submit comments. Comments must be submitted
by April 5 , 2013. If you have questions please contact Joseph Krisiak at [email protected] or by
telephone at 609-651-0903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information:
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and approved
by the Standards Committee on June 8, 2007. It established the scope of work to be done for Project
2007-02 Operating Personnel Communications Protocols (OPCP). The scope described in the SAR is to
establish essential elements of communications protocols and communications paths such that
operators and users of the North American Bulk Electric System will efficiently convey information and
ensure mutual understanding. The August 2003 Blackout Report, Recommendation Number 26, calls
for a tightening of communications protocols. This proposed standard’s goal is to ensure that effective
communication is practiced and delivered in clear language and standardized format via pre-established
communications paths among pre-identified operating entities.
The SAR indicated that references to communication protocols in other NERC Reliability Standards may
be moved to this new standard. The SAR instructed the standard drafting team to consider
incorporating the use of Alert Level Guidelines and three-part communications in developing this new
standard to achieve high level consistency across regions. The Standard Drafting Team (SDT) believes
the Alert Level Guidelines, while valuable, belong in a separate standard and has petitioned the
Standards Committee to approve the transfer to another standard or to start a separate project.
The upgrade of communication system hardware where appropriate is not included in this project (it is
included in NERC Project 2007-08 Emergency Operations).
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Project 2007-02.0 - Operating Personnel Coomunication Protocols
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators (GOPs), and Distribution Providers (DPs). These requirements
ensure that communications include essential elements such that information is efficiently conveyed
and mutually understood for communicating changes to real-time operating conditions and responding
to directives, notifications, directions, instructions, orders, or other reliability related operating
information.
The Purpose statement of COM 003-1 states: “To provide System Operators predefined
communications protocols that reduce the possibility of miscommunication that could lead to action or
inaction harmful to the reliability of BES.”
1) New NERC Glossary terms: The SDT has maintained the definition of “Operating Instructions”
proposed in the Standard version 4.
Operating Instructions differentiate the broad class of communications that deal with changing
or altering the state of the BES from general discussions of options or alternatives. Changes to
the BES operating state with unclear communications create increased opportunities for events
that could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures.
This term is proposed for addition to the NERC Glossary to establish meaning and usage within
the electricity industry.
2)
COM-003-1, Draft 5 now features 4 requirements: The “Implement, in a manner that identifies,
assesses and corrects deficiencies, documented communication protocols for Operating
Instructions between Functional Entities” language has wide acceptance within industry, but
concerns over compliance with internal controls caused great concern for some draft 4
commenters. The requirement structure and language has been changed in draft 5 based on
changes to the standard recommended by Industry representatives at the “Communications in
Operations Conference” of February 14-15, 2013 in Atlanta to allow applicable entities more
flexibility to develop their communication protocols and to develop methods to assess
operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols. Implementation means
incorporating the communication protocols into policies, procedures, training programs and
assessment programs to support setting and attaining the communication expectations of
operators (R3) and System Operators (R1). The OPCP SDT believes draft 5 shifts the focus to
improving the entity’s communication protocols, from a focus on whether the entity’s internal
controls are “compliant”.
Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols COM-003-1
2
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Project 2007-02.0 - Operating Personnel Coomunication Protocols
3)
Documented Communication Protocols: The OPCP SDT has incorporated requirements R1 and
R3, for an applicable entity to develop and implement documented communication protocols
that address, where applicable, the following elements: ( note: the word address was
recommended by draft 4 commenters and by a consensus at the “Communications in
Operations Conference” of February 14-15, 2013 in Atlanta).
a) English language: Use of the English language when issuing an oral or written Operating
Instruction between functional entities, unless another language is mandated by law or
regulation.
b) Time Identification: Instances that require time identification when issuing an oral or written
Operating Instruction or Reliability Directive, and the format for that time identification.
c) Line and Equipment Identifiers: Nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating Instruction or
Reliability Directive.
d) Alpha-numeric clarifiers: Instances where alpha-numeric clarifiers are necessary when
issuing an oral Operating Instruction or Reliability Directive, and the format for those
clarifiers.
e) Three-part Communication:
Instances where the issuer of an oral two party, person-to-person Operating Instruction, is
required to:
•
Confirm that the response from the recipient of the Operating Instruction was accurate,
or
•
Reissue the Operating Instruction to resolve a misunderstanding.
Require the recipient of an oral two party, person-to-person Operating Instruction to repeat,
restate, rephrase, or recapitulate the Operating Instruction, if requested by the issuer.
One-way burst messaging system to multiple parties (all call): Instances where the issuer of
an oral Operating Instruction or Reliability Directive using a one-way burst messaging system
to communicate a common message to multiple parties in a short time period (e.g. an All Call
system) is required to verbally or electronically confirm receipt from at least one receiving
party.
Require the receiver of an oral Operating Instruction or Reliability Directive using a one-way
burst messaging system to communicate a common message to multiple parties in a short
time period (e.g. an All Call system) to request clarification from the initiator if the
communication is not understood.
Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols COM-003-1
3
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Project 2007-02.0 - Operating Personnel Coomunication Protocols
f)
Three-part Communication: For Distribution Providers (DP) and Generator Operators (GOP):
Require the recipient of an oral two party, person-to-person Operating Instruction to repeat,
restate, rephrase, or recapitulate the Operating Instruction, if requested by the issuer.
g) One-way burst messaging system to multiple parties (all call): For Distribution Providers
(DP) and Generator Operators (GOP): Require the receiver of an oral Operating Instruction or
Reliability Directive using a one-way burst messaging system to communicate a common
message to multiple parties in a short time period (e.g. an All Call system) to request
clarification from the initiator if the communication is not understood, if required by the
issuer.
h) Uniformity of communication protocols among entities: Coordination with affected
Reliability Coordinators’, Balancing Authorities’, Transmission Operators’, Distribution
Providers’, and Generator Operators’ communication protocols.
4) Violation Risk Factor (VRF) and Violation Severity Level (VSL) changes from version three: The
OPSDT reviewed the VRFs and VSLs associated with R1, R2, R3, R4 and made changes to more
closely conform to NERC and FERC guidelines.
The SDT is proposing to retire Requirement R4 from COM-001-1.1 and incorporate it into Requirement
R1 and R3 of this draft COM-003-1. Since Requirement R4 from COM-001-1.1 carries over essentially
unchanged there is no specific question related to it in this Comment Form.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of a
miscommunication during Operating Instructions. Requirements R2 and R4 are assigned a Medium
Violation Risk due to their potential direct impact on BES reliability.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R1 and R3 must be implemented in long term planning operations and therefore were
assigned a Time Horizon of Long Term Planning. R2 and R4 must be implemented in Operations
planning and Operations Assessment Time Horizons.
Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols COM-003-1
4
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Project 2007-02.0 - Operating Personnel Coomunication Protocols
Questions
1. The SDT has proposed new language in COM-003-1, R1 and R3: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall develop and implement documented
communication protocols that outline the communications expectations of its System Operators.
The documented communication protocols will address, where applicable, the following:” (the same
language exists for R3, except DPs and GOPs listed as applicable entities and the use of “operators”
instead of “System Operators”). Do you agree with the changes made to the proposed definition
“Operating Instruction” (now proposed as a “A command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the recipient of the
command is expected to act, to change or preserve the state, status, output, or input of an Element
of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information
and of potential options or alternatives to resolve BES operating concerns are not commands and are
not considered Operating Instructions. ”) to be added as a term for the NERC Glossary? Do you
agree with these proposed requirement changes? If not, please explain in the comment area of the
last question.
Yes
No
2. The SDT has proposed new language in COM-003-1, R2 and R4: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall develop method(s) to assess System
Operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols. (the same language exists for R3, except
DPs and GOPs listed as applicable entities and the use of “operators” instead of “System
Operators”). ” Do you agree with these proposed requirement changes? If not, please explain in
the comment area of the last question.
Yes
No
3. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4?
Yes
No
4. Do you have any other comments or suggestions to improve the draft standard?
Comments:
Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols COM-003-1
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project 2007-02, COM-003-1 Operating
Personnel Communication Protocols
Rationale and Technical Justification
Justification for Requirements in Draft 5
Rationale and Technical Justification
The Quality Review team for the draft 2 posting of COM-003-1 highly recommended that the
OPCPSDT provide a justification or rationale document to aid reviewers in their examination of this
draft of COM-003-1. The OPCPSDT agrees with the QR recommendation and has developed the
following to support the standard and to help stakeholders understand the intent and scope of the
standard. This version of the standard features a non traditional approach to standards that could
alleviate concerns that surfaced in comments in drafts one, two, three and four.
Background
Because Operating Instructions affect Facilities and Elements of the Bulk Electric System, the
communication of those Operating Instructions must be understood by all involved parties, especially
when those communications occur between functional entities. An EPRI study reviewed nearly 400
switching mishaps by electric utilities and found that roughly 19% of errors (generally classified as loss
of load, breach of safety, or equipment damage) were due to communication failures.1 This was nearly
identical to another study of dispatchers from 18 utilities representing nearly 2000 years of operating
experience that found that 18% of the operators’ errors were due to communication problems. 2
1
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
2
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to develop
and implement documented communication protocols that outline the communications expectations
of its operators. The protocols address the use of the English language (from COM-001-1.1 R4), time
formatting, nomenclature for Transmission interface Elements, alpha-numeric clarifiers, and three part
communications. There are added protocols to address operator training periodicity and to address
the need for entities to coordinate their protocols for consistency among affected applicable entities.
Only applicable protocols need to be addressed.
Requirement R2
Requirement R2 requires entities that both issue and receive Operating Instructions to develop
method(s) to assess System Operators’ communication practices and implement corrective actions
necessary to meet the expectations in its documented communication protocols developed for
Requirement R1.
Requirement R3
Requirement R3 requires entities that only receive Operating Instructions to develop and implement
documented communication protocols that outline the communications expectations of its operators.
Only applicable protocols need to be addressed. The first protocol requires the use of the English
language. The two other protocols (R3, Parts 3.2 and 3.3) are repeat back for three part
communication and clarification if an “all call” communication is unclear.
Requirement R4
Requirement R4 requires entities that only receive Operating Instructions to develop method(s) to
assess operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols developed for Requirement R3.
Rationale
The SDT has maintained within this standard a recognition that these requirements should not focus on
individual instances of failure as a basis for violating the standard. In particular, the SDT has
incorporated an approach to empower and enable the industry to assess and correct deficiencies in the
communication practices. The intent is to change the basis of a violation in those requirements so that
they are not focused on whether there is a deficiency, but on assessing communication practices and
correcting deficiencies to reduce the possibility of miscommunication.
The term implement means incorporating the communication protocols into, but not limited to policies,
procedures, training programs and assessment programs to support setting and attaining the
communication expectations of operators (R3) and System Operators (R1).
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
The term documented communication protocols refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. This term does not imply any
particular naming or approval structure beyond what is stated in the requirements. An entity should
include as much as it believes necessary in their documented protocols, but they must address all of the
applicable parts of the Requirement. The documented protocols themselves are not required to include
the “. . . assessment and correction , . . ." elements, as those aspects are related to the manner of
implementation of the documented protocols and could be accomplished through other controls or
compliance management activities.
The changes and rationale for draft 5 were a result of stakeholder comment and participation in the
Communications in Operations Conference held on February 14 and 15, 2013. Stakeholders and the
ERO conducted informational sessions, expressed concerns and conducted a workshop that provided
guidance to the OPCPSDT to prepare draft 5. The changed language was a collaborative effort between
industry and ERO.
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Project 2007-02, COM-003-1 Operating
Personnel Communication Protocols
Rationale and Technical Justification
Justification for Requirements in Draft 35
Rationale and Technical Justification
The Quality Review team for the draft 2 posting of COM-003-1 highly recommended that the
OPCPSDT provide a justification or rationale document to aid reviewers in their examination of this
draft of COM-003-1. The OPCPSDT agrees with the QR recommendation and has developed the
following to support the standard and to help stakeholders understand the intent and scope of the
standard. This version of the standard features a non traditional approach to standards that could
alleviate concerns that surfaced in comments in drafts one, two, and three and four.
Background
Because Operating Instructions affect Facilities and Elements of the Bulk Electric System, the
communication of those Operating Instructions must be understood by all involved parties, especially
when those communications occur between functional entities. An EPRI study reviewed nearly 400
switching mishaps by electric utilities and found that roughly 19% of errors (generally classified as loss
of load, breach of safety, or equipment damage) were due to communication failures.1 This was nearly
identical to another study of dispatchers from 18 utilities representing nearly 2000 years of operating
experience that found that 18% of the operators’ errors were due to communication problems. 2
1
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
2
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to develop
and implement documentedimplement documented communication protocols that outline the
communications expectations of its operatorsin a manner that identifies, assesses, and corrects
deficiencies. The necessary protocols include address the use of the English language (from COM-0011.1 R4), time formatting, mutually agreed nomenclature for Transmission interface Elements, alphanumeric clarifiers, and three part communications. There are added protocols to address operator
training periodicity and to address the need for entities to coordinate their protocols for consistency
among affected applicable entities. Only applicable protocols need to be addressed.
Requirement R2
Requirement R2 requires entities that both issue and receive “Operating Instructions” to develop
method(s) to assess System Operators’ communication practices and implement corrective actions
necessary to meet the expectations in its documented communication protocols developed for
Requirement R1.perform a quarterly assessment of its System Operators’ communication practices
and implement corrective actions necessary to meet the expectations in its documented
communication protocols developed for Requirement R1.
Requirement R2 R3
Requirement R2 R3 requires entities that only receive “Operating Instructions” to develop and
implement documented communication protocols that outline the communications expectations of its
operatorsimplement documented communication protocols in a manner that identifies, assesses, and
corrects deficiencies . Only applicable protocols need to be addressed.
The first (R3, Part 3.1) protocol includesrequires the use of the English The twolanguage. The tTwo
other protocols (protocols (R2 ,R3, Parts 23.1 2 and 23.23) required are repeat back for three part
communication and clarification if an “all call” communication is unclear. There is an added protocol to
address the training periodicity.
Requirement R4
Requirement R4 requires entities that only receive Operating Instructions to develop method(s) to
assess operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols developed forperform a quarterly
assessment of its operators’ communication practices and implement corrective actions necessary to
meet the expectations in its documented communication protocols developed for Requirement R3.
Rationale
The SDT has incorporated maintained within this standard a recognition that these requirements should
not focus on individual instances of failure as a basis for violating the standard. In particular, the SDT
has incorporated an approach to empower and enable the industry to identify, assess, and correct
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
deficiencies in the communication practicesimplementation of certain requirements the standard’s
requirements. The intent is to change the basis of a violation in those requirements so that they are not
focused on whether there is a deficiency, but on identifying, assessing communication
practicesoperator performance, and correcting deficiencies to reduce the possibility of
miscommunicationimprove operator performance. It is presented in those requirements by modifying
“implement” as follows:
Each … to perform a quarterly assessment of its System Operators’ communication practices and
implement corrective actions necessary shall implement, in a manner that identifies, assesses, and
corrects deficiencies, . . .
The term implement means incorporating the communication protocols into, but not limited to policies,
procedures, training programs and assessment programs to support setting and attaining the
communication expectations of operators (R3) and System Operators (R1).
The term documented communication protocols refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. This term does not imply any
particular naming or approval structure beyond what is stated in the requirements. An entity should
include as much as it believes necessary in their documented protocols, but they must address all of the
applicable parts of the Requirement. The documented protocols themselves are not required to include
the “. . . identifies, assessesassessment , and correction s deficiencies, . . ." elements described in the
preceding paragraph, as those aspects are related to the manner of implementation of the documented
protocols and could be accomplished through other controls or compliance management activities.
The changes and rationale for draft 5 were a result of stakeholder comment and participation in the
Communications in Operations Conference held on February 14 and 15, 2013. Stakeholders and the
ERO conducted informational sessions, expressed concerns and conducted a workshop that provided
guidance to the OPCPSDT to prepare draft 5. The changed language was a collaborative effort between
industry and ERO.
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
3
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1.1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1.
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall develop and
implement documented communication protocols
that outline the communications expectations of its
System Operators. The documented communication
protocols will address, where applicable, the
following:[Violation Risk Factor: Low] [Time Horizon:
Long-term Planning ]
1.1.
Use of the English language when issuing or
responding to an oral or written Operating
Instruction or Reliability Directive, unless
another language is mandated by law or
regulation.
Project YYYY-##.# -
Project Name
Requirement in Approved Standard
Mapping Document
: Operating Personnel Communication Protocols
Translation to
New Standard or
Other Action
Comments
2
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1.1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1.
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall develop and
implement documented communication protocols
that outline the communications expectations of its
System Ooperators. The documented
communication protocols will address, where
applicable, the following:[Violation Risk Factor: Low]
[Time Horizon: Long-term Planning ]
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall implement, in a
manner that identifies, assesses and corrects
deficiencies, documented communication
protocols for Operating Instructions between
Functional Entities that include the following::
1.1.
Use of the English language when issuing or
Project YYYY-##.# -
Project Name
Requirement in Approved Standard
Project 2007-02 - Project Name: Operating Personnel Communication Protocols
Translation to
New Standard or
Other Action
Comments
responding to an oral or written Operating
Instruction or Reliability Directivebetween
functional entities, unless another language
is mandated by law or regulation.
Mapping DocumentMapping Document
2
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL Justifications
2
Project YYYY-##.# - Project Name
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL Justifications
3
Project YYYY-##.# - Project Name
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL Justifications
4
Project YYYY-##.# - Project Name
VRF for COM-003-1:
There are four requirements in COM-003-1, draft 5 with the addition of R3 and R4. Requirements R1 and R3 are assigned a
“Low” VRF. R1 and R3 now read:”Each ….. shall develop and implement documented communication protocols that outline the
communications expectations of its operators. The documented communication protocols will address, where applicable, the
following: “. Requirements R2 and R4 are assigned a “Medium” VRF. and the language change to R2 and R4, which now
reads:”Each ….. shall perform a quarterly assessment of its System Operators’ communication practices and implement
corrective actions necessary to meet the expectations in its documented communication protocols developed for Requirement RX
“, warrants raising the VRF to “Medium” because it features evaluation and correction of operating performance that would
have a deeper impact on the reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
VRF and VSL Justifications
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
5
Project YYYY-##.# - Project Name
requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
VRF and VSL Justifications
6
Project YYYY-##.# - Project Name
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low” which is
consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development and implementation of documented communication protocols
by entities that will both issue and receive “Operating Instructions” that reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL Justifications
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Low” which is consistent with NERC
guidelines for similar requirements.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
address one (1) of the nine(9)
parts of Requirement R1in
their documented
communication protocols as
required in Requirement R1
Moderate
The Responsible Entity did not
address two (2) of the nine (9)
parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
High
The Responsible Entity did not
address three (3) of the nine (9)
parts of Requirement R1 in their
documented communication
protocols as required in
Requirement R1
Severe
The Responsible Entity did not
address four (4) or more of the
nine (9) parts of Requirement R1
in their documented
communication protocols as
required in Requirement R1
OR
OR
The Responsible Entity did not
implement one (1) of the nine
VRF and VSL Justifications
OR
The Responsible Entity did not
implement three (3) of the nine
(9) parts of Requirement R1 in
OR
The Responsible Entity did not
have any documented
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
(9) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
VRF and VSL Justifications
The Responsible Entity did not
implement two (2) of the nine
(9) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
their documented communication
protocols as required in
Requirement R1
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
implement any documented
communication protocols as
required in Requirement R1
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols were addressed at all or if the number of
required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Medium
NERC VRF Discussion
R2 is a requirement in an Operations planning and Operations Assessment time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the assessment and correction of System Operators‘performance with
documented communication protocols by entities that will both issue and receive “Operating Instructions”
to reduce the possibility of miscommunication which could eventually lead to action or inaction harmful
to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to assess and correct System Operators’ performance with proper utilization of communication
protocols could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of the requirement is
unlikely to lead to bulk electric system instability, separation, or cascading failures. The VRF for this
requirement is “Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented 50
% or more but not all corrective
action identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
VRF and VSL Justifications
Moderate
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented less
than 50 % of the corrective
actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
High
The Responsible Entity performed
periodic assessments of its System
Operators’ communication
practices but did not implement
any corrective actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
Severe
The Responsible Entity did not
perform periodic assessments of
its System Operators’
communication practices
identified in Requirement R2
necessary to meet the
expectations in its documented
communication protocols
developed for Requirement R1.
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on quarterly assessments of an entity’s
System Operators’ communication practices and the administration of corrective actions. If no quarterly
assessments of an entity’s System Operators’ communication practices are conducted , then the VSL is
Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
14
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The VRF for this requirement is “Low” which is
consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development and implementation of documented communication protocols
by entities that will only receive “Operating Instructions” that reduce the possibility of miscommunication
which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Low” which is consistent with NERC
guidelines for requirements that are administrative.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
16
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
Moderate
Severe
The Responsible Entity did not
address one (1) of the three(3)
parts of Requirement R3in
their documented
communication protocols as
required in Requirement R3
The Responsible Entity did not
address two (2) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
The Responsible Entity did not
address three (3) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
OR
OR
The Responsible Entity did not
implement one (1) of the
three(3) parts of Requirement
R3
The Responsible Entity did not
implement two (2) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
The Responsible Entity did not
develop any documented
communication protocols as
required in Requirement R3
in their documented
communication protocols as
required in Requirement R3
VRF and VSL Justifications
High
OR
The Responsible Entity did not
implement any documented
communication protocols as
required in Requirement R3
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
19
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement in an Operations planning and Operations Assessment time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the assessment and correction of operators’ performance with documented
communication protocols that reduce the possibility of miscommunication which could eventually lead to
action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to assess and correct operators’ performance with proper utilization of communication protocols
could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. However, violation of the requirement is unlikely
to lead to bulk electric system instability, separation, or cascading failures. The VRF for this requirement is
“Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R4 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
20
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented 50 % or more but
not all corrective action
identified in Requirement R4
necessary to meet the
expectations in its documented
communication protocols
developed for Requirement R3.
VRF and VSL Justifications
Moderate
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 % of
the corrective actions identified
in Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3.
High
The Responsible Entity performed
periodic assessments of its
operators’ communication
practices but did not implement
any corrective actions identified in
Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3
Severe
The Responsible Entity did not
perform assessments of its
operators’ communication
practices and did not meet the
expectations in its documented
communication protocols
developed for Requirement R3.
21
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of quarterly
assessments or correction of an entity’s System Operators’ communication practices. If no quarterly
assessments of an entity’s System Operators’ communication practices are conducted, then the VSL is
Severe.
Guideline 2a:
The VSL assignment for R4 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
22
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
23
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL JustificationsVRF and VSL Justifications
2
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL JustificationsVRF and VSL Justifications
3
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL JustificationsVRF and VSL Justifications
4
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF for COM-003-1:
There are two four requirements in COM-003-1, draft 4 5 with the addition of R3 and R4. Requirements R1 and R2 R3 are
assigned a “Low” VRF. because they are now administrative. R1 and R3 now read:”Each ….. shall develop and implement
documented communication protocols that outline the communications expectations of its operators. The documented
communication protocols will address, where applicable, the following: “. Requirements R2 and R4 are assigned a “Medium”
VRF. The elimination of draft 3 R3 and R4 and the language change to R1 R2 and R2R4, which now reads:”Each ….. shall
perform a quarterly assessment of its System Operators’ communication practices and implement corrective actions necessary to
meet the expectations in its documented communication protocols developed for Requirement RX shall implement, in a manner
that identifies, assesses and corrects deficiencies, documented communication protocols for Operating Instructions between
Functional Entities that include the following: “, warrants raising the VRF to “Medium” because it makes the requirement more
than just administrative as it now features evaluative evaluation and correction of operating performance process that would
have a deeper impact on the reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
VRF and VSL JustificationsVRF and VSL Justifications
5
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
full intent of the
requirement.
significant value in meeting
the intent of the
requirement.
The performance or product
has limited value in meeting
the intent of the
requirement.
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VRF and VSL JustificationsVRF and VSL Justifications
6
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “MediumLow”
which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communication protocols, falls under Recommendation 24 26 of the Blackout Report. The
VRF for this requirement is “MediumLow” because of its administrative nature, which is consistent with
FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
FERC VRF G2 Discussion
FERC VRF G3 Discussion
VRF and VSL JustificationsVRF and VSL Justifications
7
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R1
FERC VRF G4 Discussion
FERC VRF G5 Discussion
This requirement calls for the development and implementation of documented communication protocols
by entities that will both issue and receive “Operating Instructions” that reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Medium ”Low” which is consistent
with NERC guidelines for similar requirements that are administrative.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
address one (1) of the nine(9)
parts of Requirement R1in
their documented
communication protocols as
required in Requirement R1
Moderate
The Responsible Entity did not
address two (2) of the nine (9)
parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
VRF and VSL JustificationsVRF and VSL Justifications
8
High
The Responsible Entity did not
address three (3) of the nine (9)
parts of Requirement R1 in their
documented communication
protocols as required in
Requirement R1
Severe
The Responsible Entity did not
address four (4) or more of the
nine (9) parts of Requirement R1
in their documented
communication protocols as
required in Requirement R1
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R1
OR
OR
The Responsible Entity did not
implement one (1) of the nine
(9) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
The Responsible Entity did not
include one (1) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
OR
The Responsible Entity did not
implement two (2) of the nine
(9) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
The Responsible Entity did not
include two (2) of the nine (9)
parts of Requirement R1, Parts
1.1 to 1.9 in their documented
communication protocols
VRF and VSL JustificationsVRF and VSL Justifications
9
The Responsible Entity did not
implement three (3) of the nine
(9) parts of Requirement R1 in
their documented communication
protocols as required in
Requirement R1
The Responsible Entity did not
include three (3) of the nine (9)
parts of Requirement R1, Parts 1.1
to 1.9 in their documented
communication protocols
OR
The Responsible Entity did not
have any documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
implement any documented
communication protocols as
required in Requirement R1
The Responsible Entity did not
include four (4) or more of the
nine (9) parts of Requirement R1,
Parts 1.1 to 1.9 in their
documented communication
protocols
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R1
OR
The Responsible Entity did not
have documented communication
protocols as required in
Requirement R1.
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
communication protocols as
required in Requirement R1
VRF and VSL JustificationsVRF and VSL Justifications
10
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used were addressed at all or if the number
of required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
VRF and VSL JustificationsVRF and VSL Justifications
11
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL JustificationsVRF and VSL Justifications
12
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Low Medium
NERC VRF Discussion
R2 is a requirement in an Operations planning and Operations Assessment time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 24 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements that are of equal importance and similarly address
communication protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the assessment and correction of System Operators‘performance with
documented communication protocols by entities that will both issue and receive “Operating Instructions”
to reduce the possibility of miscommunication which could eventually lead to action or inaction harmful
to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize assess and correct System Operators’ performance with proper utilization of
communication protocols properly could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL JustificationsVRF and VSL Justifications
13
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R2
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented 50
% or more but not all corrective
action identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.N/A
Moderate
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented less
than 50 % of the corrective
actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.N/A
High
The Responsible Entity performed
periodic assessments of its System
Operators’ communication
practices but did not implement
any corrective actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.The Responsible
Entity did not include one (1) of
the two (2) parts of Requirement
R2, Parts 2.1 to 2.2 in their
documented communication
protocols
Severe
The Responsible Entity did not
perform periodic assessments of
its System Operators’
communication practices
identified in Requirement R2
necessary to meet the
expectations in its documented
communication protocols
developed for Requirement
R1.The Responsible Entity did not
include Parts 2.1 to 2.2 (2) of
Requirement R2, in their
documented communication
protocols
OR
The responsible entity did not
have documented communication
protocols as required in
Requirement R2.
VRF and VSL JustificationsVRF and VSL Justifications
14
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R2
OR
The Responsible Entity did not
implement, in a manner that
identifies, assesses and corrects
deficiencies, their documented
communication protocols as
required in Requirement R1
VRF and VSL JustificationsVRF and VSL Justifications
15
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed two four VSLs based on quarterly assessments of an
entity’s System Operators’ communication practices and the administration of corrective
actionsmisapplication or absence of common communication protocols. If no quarterly assessments of an
entity’s System Operators’ communication practices communication protocols are usedconducted at all
or if the number of required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
VRF and VSL JustificationsVRF and VSL Justifications
16
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL JustificationsVRF and VSL Justifications
17
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The requirement R3 is administrative The VRF for
this requirement is “Low” which is consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 establishes communication protocols, which is consistent with FERC guideline G1.falls under
Recommendation 26 of the Blackout Report. The VRF for this requirement is “Low” because of its
administrative nature, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development and implementation of documented communication protocols
by entities that will only receive “Operating Instructions” that reduce the possibility of miscommunication
which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Low” which is consistent with NERC
guidelines for requirements that are administrative.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL JustificationsVRF and VSL Justifications
18
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R3
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
Moderate
High
Severe
The Responsible Entity did not
address one (1) of the three(3)
parts of Requirement R3in
their documented
communication protocols as
required in Requirement R3
The Responsible Entity did not
address two (2) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
The Responsible Entity did not
address three (3) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
OR
OR
The Responsible Entity did not
implement one (1) of the
three(3) parts of Requirement
R3
The Responsible Entity did not
implement two (2) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
The Responsible Entity did not
develop any documented
communication protocols as
required in Requirement R3
in their documented
communication protocols as
required in Requirement R3
VRF and VSL JustificationsVRF and VSL Justifications
19
OR
The Responsible Entity did not
implement any documented
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R3
communication protocols as
required in Requirement R3
VRF and VSL JustificationsVRF and VSL Justifications
20
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
VRF and VSL JustificationsVRF and VSL Justifications
21
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL JustificationsVRF and VSL Justifications
22
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement in an Operations planning and Operations Assessment time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the assessment and correction of operators’ performance with documented
communication protocols that reduce the possibility of miscommunication which could eventually lead to
action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to assess and correct operators’ performance with proper utilization of communication protocols
could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. However, violation of the requirement is unlikely
to lead to bulk electric system instability, separation, or cascading failures. The VRF for this requirement is
“Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R4 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL JustificationsVRF and VSL Justifications
23
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R4
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented 50 % or more but
not all corrective action
identified in Requirement R4
necessary to meet the
expectations in its documented
communication protocols
developed for Requirement R3.
Moderate
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 % of
the corrective actions identified
in Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3.
VRF and VSL JustificationsVRF and VSL Justifications
24
High
The Responsible Entity performed
periodic assessments of its
operators’ communication
practices but did not implement
any corrective actions identified in
Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3
Severe
The Responsible Entity did not
perform assessments of its
operators’ communication
practices and did not meet the
expectations in its documented
communication protocols
developed for Requirement R3.
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of quarterly
assessments or correction of an entity’s System Operators’ communication practices. If no quarterly
assessments of an entity’s System Operators’ communication practices are conducted, then the VSL is
Severe.
Guideline 2a:
The VSL assignment for R4 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
VRF and VSL JustificationsVRF and VSL Justifications
25
Project YYYY-##.# - Project NameProject 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications – COM 003-1, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL JustificationsVRF and VSL Justifications
26
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Frequently Asked Questions – Addendum
COM-003, Draft 5
This document is being provided to assist commenters’ understanding of COM-003-1, draft 5 based on
inquiries received by the drafting team and the Standards Committee.
1. How would you differentiate between slips of the tongue and “deficient communication practices”
without involving subjective judgments? The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of
making before-and-after voice recordings comparisons.
Response: The criteria for System Operator/operator performance should be established by the
applicable entity. The Operating Personnel Communications Protocols Standard Drafting Team
(OPCPSDT) believes it is the discretion of the applicable entity to set its expectations of its
operating personnel with regard to communication protocols and then to monitor and if necessary
improve their performance. There will be less subjective judgment if the entity develops strong
communication protocols and structured programs to evaluate and improve System
Operator/operator performance. The OPCPSDT acknowledges there are many forms of programs
and methods an entity might employ to accomplish this, but it does not want to dictate a one size
fits all process.
2. If the goal is to have strong internal controls where the detective control of periodically sampling
conversations allows the Generator Operator (GOP) to detect and correct communications, why
would the GOP need documentation other than to note they found nothing, or to note they found
one issue and made the operator retake training?
Response: If the entity, in this case a GOP, during the audit period, found nothing or they found
one issue and made the operator retake training, the documentation supporting those
circumstances would suffice. M4 only asks for “the results of its periodic assessment and of any
corrective actions (if any corrective actions were implemented)”.
3. Does R4 leave GOPs open to the auditor’s interpretation of the sufficiency of the corrective
program? Or is it intended that GOP and Distribution Provider (DP) have the authority to develop
their own programs without the risk an audit will find it insufficient.
Response: The OPCPSDT intended that entities develop their own programs that support the
requirements of COM-003-1. There are many methods available to entities to accomplish this and
the OPCPSDT does not want to dictate a one size fits all approach to monitoring and improving
operator communication protocol performance. M4 only asks for “the results of its periodic
assessment and of any corrective actions (if any corrective actions were implemented)” The
important focus are the results of its periodic assessment and of any corrective actions. The
OPCPSDT believes entities will develop or already possess evaluation and training programs and
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
would advocate for improving operator communication protocol performance on the Bulk Electric
System (BES) based on the desire to avoid communication mishaps.
4. The Reliability Standard Audit Worksheet requires the GOP to turn over records of monitoring
communications (which is a large compliance burden, especially for smaller entities) as well as
records of corrective actions and then proof the “problem” is not still in place. Turn over records to
whom? How many records? How do you prove it has stopped? Where does the paperwork stop?
Response: The records are to be provided to the CEA for review and verification. The CEA needs to
review and understand the entity’s monitoring program(s) and to review the instances where
corrective action was warranted. The CEA should expect to see evidence needed to be assured
that the assessment and corrective program exists and is being implemented. Such evidence could
consist of review logs noting the communications that were reviewed (e.g. date, time, and
reviewer) and descriptions and evidence of the corrective actions take, if any. The entity should
establish its own measure of effectiveness to determine if an operator meets the entity’s
expectations. This makes it less murky for the CEA and reduces subjectivity.
5. Who determines the GOP and DP personnel who are subject to R3 and R4? Are the GOP personnel
those in a control room in the plant? For a DP are they distribution dispatches? Is there a way to
clarify who the Standard is applicable to?
Response: The criteria for which GOP and DP personnel subject to R3 and R4 of COM-003-1 would
be an operator who would receive either a:
Operating Instruction: A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act, to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. Discussions of general information and of
potential options or alternatives to resolve BES operating concerns are not commands and are not
considered Operating Instructions or a
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator,
or Balancing Authority where action by the recipient is necessary to address an Emergency or
Adverse Reliability Impact.
Response part two: Distribution system dispatches by a DP would not be applicable. COM-003-1 is
applicable to BES communications as defined by Operating Instructions and Reliability Directives.
The OPCPTSDT would encourage communication protocols for verbal switching on the distribution
system because they improve reliability.
6. How can three-way communication be used for “a one-way burst messaging system to
communicate a common message to multiple parties in a short time period (e.g. an All Call
system)” -- to those on the receiving end, it does not seem possible under the current technology
used for these oral messaging systems to have three way. Please explain how three-way can be
used for one way burst messaging systems?
COM-003 FAQ
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Response: The Standard does not require three part communication for “a one-way burst
messaging system to communicate a common message to multiple parties in a short time
period (e.g. an All Call system)” because obtaining a response from all of the multiple receivers
would create considerable delays and potential confusion defeating the speed and efficiency an
all call type of message provides.
R1 Part 1.8 and R3 Part 3.3 require the receiver of an oral Operating Instruction or Reliability
Directive using an all call system to request clarification from the initiator if the communication is
not understood, if required by the issuer.
7. It appears consistent with Order 743 and FERC’s ruling that only generator dispatch operators be
trained on implementing directives and instructions to also limit COM-003 to FERC’s ruling in Order
743, which would apply COM-003 generation dispatchers who (at a centrally-located generation
dispatch center or at a dispatch center at the same site as a single generation plant) either:
a. Receive direction and then develop specific dispatch instructions for plant operators under
their control or
b. Determine the best way to deliver that generation from its portfolio of units. Was this the
intent of COM-003 to be consistent with Order No. 743 and the work on PER-005?
Response: COM-003-1 is compliant with the FERC’s ruling in Oder 743. The standard is clear
that generator operators that receive or will receive Operating Instructions and Reliability
Directives from a Balancing Authority, Reliability Coordinator or Transmission Operator are
applicable entities and must be compliant.
The issue of how communication protocols are established and managed within the GOP’s
organization can be addressed within the scope of the entity’s documented communication
protocols. The GOP is encouraged to make them uniform to prevent confusion within its
organization.
8. The latest version of COM-003-1 appears to introduce a potential conflict with COM-002-3 related
to use of one-way burst messaging systems to issue a Reliability Directive. In other words, COM003-1 allows one-way burst messaging to be used for Reliability Directives and prescribes:
a. issuer to confirm receipt from at least one receiving party
b. receiver to request clarification from the issuer if the communication is not understood
However, COM-002-3 has the following requirements:
R2. Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution
Provider that is the recipient of a Reliability Directive shall repeat, restate, rephrase, or recapitulate
the Reliability Directive.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issues a
Reliability Directive shall either:
a. Confirm that the response from the recipient of the Reliability Directive (in accordance with
Requirement R2) was accurate, or
COM-003 FAQ
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
b. Reissue the Reliability Directive to resolve a misunderstanding.
In other words, in the case of a one-way burst messaging used for Reliability Directives, COM-002-3
does not appear to allow for only those responses required in COM-003-1 but instead requires a
full 3 way communication from all parties. This potentially sets up both the issuer and receiver for
violating COM-002-3 if they respond to a one-way burst messaging Reliability Directive as the
requirements indicate in COM-003-1. In order to be fully compliant with both standards, the
receiver would have to contact the issuer, repeat what was said on the original burst message, and
then the issuer would confirm that the response was accurate before acting on the message. Is this
correct?
Response: The COM-002 team addressed the Reliability Directive “all call” issue in the
consideration of comments for COM-002-3, found on the project page:
http://www.nerc.com/filez/standards/Reliability_Coordination_Project_2006-6.html
The COM-002-3 drafting team envisioned that Reliability Directives could/would be issued using
“blast call”/”all call” capability. They also clearly tied their response to COM-003-1, saying that
Project 2007-02 would resolve the issue. The current draft of COM-003-1 resolves the issue by
allowing entities to create a procedure to allow flexibility on how this will be achieved. The
procedure must require an issuer of a “blast call”/”all call” to confirm receipt from at least one
receiving party (R1.7) and for the receiver to request clarification from the issuer if the
communication is not understood (R1.8). The consideration of comments will be filed with COM002-3 and will become part of the development record of COM-002-3, and as such can be
referenced by entities for their compliance in COM-002-3 and COM-003-1. For COM-003-1 to not
cover “all call” scenarios for Reliability Directives would leave a gap for entities in compliance with
COM-002-3.
For draft 5 of COM-002-3, the following comment and response was provided:
Comment: The Standard is not clear as to what each entity is to do when more than one entity
receives a Reliability Directive at the same time (e.g. during a RC area teleconference call). Is, for
example, a roll call of receiving entities expected to be held so that they individually can repeat,
restate, rephrase or recapitulate the Reliability Directive followed by individual confirmation
required in R3?
Response: The question about whether a roll call of receiving entities is expected to be held is
asking for prescription of “how” to accomplish what is required. The RCSDT recognizes that there is
more than one way to accomplish the confirmation when more than one entity received a
Reliability Directive at the same time. What is required is for the recipient to respond in such a way
that the issuer may determine whether the message has been properly understood. One way for
that to occur would be, as you suggest, for the entities to individually respond. Another way would
be for a pre-established protocol or procedure (e.g. roll-call, all-call, etc.) to be in place and used in
such cases. The RCSDT has determined that prescribing “how” to ensure that “what” is required
has been accomplished is not required and that the individually adopted procedures or protocols
could offer many different ways to ensure effectiveness. No change made. The RCSDT concept is
COM-003 FAQ
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
that “All Call” compliance is related to having a document that explains how the entity responds.
No change made.
http://www.nerc.com/docs/standards/sar/Project_2006_06_Response_to_Comments_2012_06_1
2.pdf (page 173)
For draft 4 of COM-002-3, the following comments and responses were provided:
Comment: Requirements for using three-part communication: It is our opinion that the standard
needs language that clearly states that during a Blast Call three-part communication is not
required. Blast Calls are used when information needs to be disseminated quickly to a large number
of entities. Strictly enforcing the use of three-part communication under these circumstances has
the potential to be more harmful to reliability than helpful.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is
efficient and effective. The RCSDT believes Reliability Directives issued in mass should be defined
by procedure, and that the procedure would establish a method of affirmation and notice of
implementation. As envisioned, communications protocols would be addressed in the COM-003
standard being developed in Project 2007-02.
http://www.nerc.com/docs/standards/sar/Consideration_of_Comments_Initial_Ballot_200606_071411.pdf (page 44)
Comment: We also are concerned about the need to conduct three-part communications for a
Reliability Directive issued through a blast call. Under these circumstances, the need for immediate
action of multiple parties may require a blast call and there may not be time for all parties to
complete three-part communications before initiating actions. Thus, we believe blast calls should be
treated separately and that should be made clear.
Response: The RCSDT agrees that the use of Blast Calls to issue Reliability Directives, in mass, is
efficient and effective. However the essence of accurately implementing Reliability Directives is
accomplished by use of 3-part communications. The RCSDT believes Reliability Directives issued in
mass should be defined by procedure, and that the procedure would establish a method of
affirmation and notice of implementation. As envisioned, communications protocols requiring for
issuing alerts will be addressed in the COM-003 standard being developed in Project 2007-02.
http://www.nerc.com/docs/standards/sar/Consideration_of_Comments_Initial_Ballot_200606_071411.pdf (page 56)
COM-003 FAQ
5
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Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-003-1
Successive Ballot and Non-binding Poll now open through April 5, 2013
Now Available
A successive ballot of COM-003-1 and a non-binding poll of the associated Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) is now being conducted through 8 p.m. Eastern on Friday, April 5,
2013.
In response to comments received during the last comment period and other input, the drafting team
has adopted many of the recommendations of commenters and attendees of the “Communications in
Operations Conference” of February 14-15, 2013, in Atlanta, and incorporated them into to COM-0031, draft 5.
The Operating Personnel Communications Protocols Standard Drafting Team has created four
requirements for COM-003-1, draft 5. Requirements R1, R2, R3, and R4. The new R1 and R3 language
calls for an applicable entity to “develop and implement documented communication protocols that
outline the communications expectations of its System Operators. The documented communication
protocols will address, where applicable, the following: (protocols)”. The new R2 and R4 language calls
for an applicable entity to “develop method(s) to assess System Operators’ communication practices
and perform corrective actions necessary to meet the expectations in its documented communication
protocols”
This version was drafted in conjunction with the development of the Reliability Standard Audit
Worksheet (RSAW). Changes were made to the RSAW to reflect the changes in COM-003-1, draft 5 and
changes suggested by some commenters. The RSAW is posted for informal comments along with COM003-1.
Background information for this project can be found on the project page.
Instructions
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a
recirculation ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02 Operating Personnel Communications Protocols
2
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Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
Formal Comment Period and RSAW Posted for Industry Comments:
Successive Ballot and Non-binding Poll:
March 7 – April 5, 2013
March 27 – April 5, 2013
Now Available
A formal comment period for COM-003-1 – Operating Personnel Communication Protocols (OPCP) is
open through 8 p.m. Eastern on Friday, April 5, 2013.
A successive ballot of COM-003-1 and a non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted beginning on Wednesday, March 27, 2013 through 8 p.m.
Eastern on Friday, April 5, 2013.
In response to comments received during the last comment period and other input, the drafting team
has adopted many of the recommendations of commenters and attendees of the “Communications in
Operations Conference” of February 14-15, 2013, in Atlanta, and incorporated them into to COM003-1, draft 5.
The OPCP Standard Drafting Team (SDT) has created four requirements for COM-003-1, draft 5.
Requirements R1, R2, R3, and R4. The new R1 and R3 language calls for an applicable entity to “develop
and implement documented communication protocols that outline the communications expectations of
its System Operators. The documented communication protocols will address, where applicable, the
following: (protocols)”. The new R2 and R4 language calls for an applicable entity to “develop method(s)
to assess System Operators’ communication practices and perform corrective actions necessary to meet
the expectations in its documented communication protocols”
This version was drafted in conjunction with the development of the Reliability Standard Audit
Worksheet (RSAW). Changes were made to the RSAW to reflect the changes in COM-003-1, draft 5 and
changes suggested by some commenters. The RSAW is posted for informal comments along with COM003-1.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller at [email protected]. An off-line, unofficial copy of
the comment form is posted on the project page.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
A comment period on the draft RSAW is open through 8 p.m. Eastern on Friday, April 5, 2013. The
draft RSAW is posted on the NERC Compliance RSAW page. Please submit comments on the draft
RSAW using the RSAW comment form to [email protected].
Next Steps
A successive ballot of COM-003-1 and a non-binding poll of the associated VRFs and VSLs will be
conducted beginning on Wednesday, March 27, 2013 through 8 p.m. Eastern on Friday, April 5, 2013.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement | Project 2007-02 OCPC COM-003-1
2
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Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols COM-003-1
Successive Ballot and Non-binding Poll Results
Now Available
A successive ballot of COM-003-1 and a non-binding poll of the associated Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) concluded at 8 p.m. Eastern on Friday, April 5, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results for
the successive ballot.
Approval
Quorum: 78.39%
Approval: 57.50%
Non-binding Poll Results
Quorum: 77.97%
Supportive Opinions: 54.28%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a recirculation ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC
Standards
20140514-5129
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Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007 -02 COM-003-1 Successive Ballot
Password
Ballot Period: 3/25/2013 - 4/8/2013
Ballot Type: Successive
Log in
Total # Votes: 341
Register
Total Ballot Pool: 435
Quorum: 78.39 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
57.50 %
Vote:
Ballot Results: The drafting team will review comments received.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
110
11
103
39
93
53
0
12
5
9
435
#
Votes
1
1
1
1
1
1
0
0.4
0.2
0.8
7.4
#
Votes
Fraction
47
7
40
8
38
19
0
4
2
6
171
Negative
Fraction
0.573
0.636
0.556
0.32
0.507
0.463
0
0.4
0.2
0.6
4.255
Abstain
No
# Votes Vote
35
4
32
17
37
22
0
0
0
2
149
0.427
0.364
0.444
0.68
0.493
0.537
0
0
0
0.2
3.145
7
0
4
0
5
4
0
0
0
1
21
21
0
27
14
13
8
0
8
3
0
94
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Member
Kirit Shah
Paul B Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Ballot
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Comments
NERC
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Chang G Choi
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Affirmative
Michael Moltane
Affirmative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Affirmative
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Negative
Negative
NERC
Standards
20140514-5129
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
1
3
3
3
3
3
3
3
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Affirmative
Negative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Abstain
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Dave Markham
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Affirmative
Negative
Negative
Negative
Abstain
NERC
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
NW Electric Power Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
David McDowell
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Rick Paschall
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Turlock Irrigation District
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Steve Eldrige
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
Keith Morisette
Steven C Hill
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
ICF International
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Brent B Hebert
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Michiko Sell
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
APX
INTELLIBIND
JDRJC Associates
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Lujuanna Medina
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Negative
Negative
Peter H Kinney
Affirmative
David F Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Michael Johnson
Kevin Conway
Jim Cyrulewski
Frederick R Plett
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Diane J. Barney
Affirmative
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=c7b806c5-936c-49f9-aa7c-b045cbd667b2[4/9/2013 1:27:37 PM]
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
Project 2007-02 COM-003-1
Non-binding Poll Results
Non-binding Poll
Project 2007-02 COM-003-1 Non-binding Poll
Name:
Poll Period: 3/25/2013 - 4/8/2013
Total # Opinions: 308
Total Ballot Pool: 395
77.97% of those who registered to participate provided an opinion or an abstention;
Summary Results: 54.28% of those who provided an opinion indicates support of the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
1
1
1
1
1
1
1
1
1
1
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric,
LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
CPS Energy
1
1
1
1
1
1
1
1
1
1
1
Member
Kirit Shah
Paul B Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
Kevin Smith
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Chang G Choi
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Ballot
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Comments
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Non-binding Poll Results – Project 2007-02 COM-003-1
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Affirmative
Michael Moltane
Abstain
Affirmative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
Affirmative
Affirmative
Negative
John Burnett
Affirmative
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Kevin White
Affirmative
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Marvin E VanBebber
Negative
Abstain
Affirmative
Negative
Abstain
Negative
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
2
2
2
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Independent Electricity System
Barbara Constantinescu
Operator
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Southwest Power Pool, Inc.
Charles H. Yeung
Non-binding Poll Results – Project 2007-02 COM-003-1
Affirmative
Negative
Abstain
Negative
Abstain
Abstain
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Abstain
3
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3
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3
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3
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3
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3
3
3
3
3
3
3
3
3
3
3
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Non-binding Poll Results – Project 2007-02 COM-003-1
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Kent Kujala
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Affirmative
Affirmative
4
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3
3
3
3
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
Non-binding Poll Results – Project 2007-02 COM-003-1
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Michael Schiavone
Skyler Wiegmann
Affirmative
William SeDoris
David McDowell
David Burke
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Tim Beyrle
Abstain
Abstain
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
City of Redding
Nicholas Zettel
City Utilities of Springfield, Missouri
John Allen
Consumers Energy
David Frank Ronk
Cowlitz County PUD
Rick Syring
Detroit Edison Company
Daniel Herring
Flathead Electric Cooperative
Russ Schneider
Florida Municipal Power Agency
Frank Gaffney
Fort Pierce Utilities Authority
Cairo Vanegas
Georgia System Operations Corporation Guy Andrews
Illinois Municipal Electric Agency
Bob C. Thomas
Imperial Irrigation District
Diana U Torres
Indiana Municipal Power Agency
Jack Alvey
LaGen
Richard Comeaux
Madison Gas and Electric Co.
Joseph DePoorter
Modesto Irrigation District
Spencer Tacke
Northern California Power Agency
Tracy R Bibb
Ohio Edison Company
Douglas Hohlbaugh
Oklahoma Municipal Power Authority
Ashley Stringer
Old Dominion Electric Coop.
Mark Ringhausen
Public Utility District No. 1 of Douglas
Henry E. LuBean
County
Public Utility District No. 1 of Snohomish
John D Martinsen
County
Sacramento Municipal Utility District
Mike Ramirez
Seattle City Light
Hao Li
Seminole Electric Cooperative, Inc.
Steven R Wallace
South Mississippi Electric Power
Steven McElhaney
Association
Tacoma Public Utilities
Keith Morisette
Wisconsin Energy Corp.
Anthony Jankowski
WPPI Energy
Todd Komplin
AEP Service Corp.
Brock Ondayko
AES Corporation
Leo Bernier
Amerenue
Sam Dwyer
Arizona Public Service Co.
Edward Cambridge
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc. Shari Heino
Calpine Corporation
Phillip Porter
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
City of Tallahassee
Karen Webb
City Water, Light & Power of Springfield Steve Rose
Cleco Power
Stephanie Huffman
Non-binding Poll Results – Project 2007-02 COM-003-1
Affirmative
Negative
Negative
Negative
Abstain
Negative
Abstain
Abstain
Abstain
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
6
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Non-binding Poll Results – Project 2007-02 COM-003-1
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Abstain
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Kenneth Silver
Affirmative
Mike Laney
S N Fernando
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard Kinas
Richard J. Padilla
Sandra L. Shaffer
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Non-binding Poll Results – Project 2007-02 COM-003-1
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Abstain
Negative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
8
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
9
9
9
10
10
10
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
APX
JDRJC Associates
Massachusetts Attorney General
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Non-binding Poll Results – Project 2007-02 COM-003-1
Paul Shipps
Eric Ruskamp
Negative
Affirmative
Brad Packer
Affirmative
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Negative
Negative
Negative
Negative
Affirmative
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Negative
Abstain
Negative
Peter H Kinney
Affirmative
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Michael Johnson
Jim Cyrulewski
Frederick R Plett
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Affirmative
Affirmative
Affirmative
Affirmative
Donald Nelson
Affirmative
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Affirmative
Affirmative
Affirmative
9
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10
10
10
10
10
10
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Non-binding Poll Results – Project 2007-02 COM-003-1
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Name (50 Responses)
Organization (50 Responses)
Group Name (28 Responses)
Lead Contact (28 Responses)
Contact Organization (28 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (16 Responses)
Comments (78 Responses)
Question 1 (52 Responses)
Question 1 Comments (62 Responses)
Question 2 (53 Responses)
Question 2 Comments (62 Responses)
Question 3 (44 Responses)
Question 3 Comments (62 Responses)
Question 8 (0 Responses)
Question 8 Comments (62 Responses)
Individual
Scott Bos
Muscatine Power and Water
Yes
Yes
Yes
Individual
Herb Schrayshuen
Self
Yes
Yes
Yes
Individual
Scott McGough
Georgia System Operations Corporation
Yes
No
Internal controls-like language was first introduced into draft 3, R3 and R4. We note that after the
technical conference held in Atlanta – Feb 2013, draft 5, R2 and R4 appear to still have remnants of
this control language. As discussed in length, it is not appropriate to have such control language in
reliability requirements. As GSOC recalls, insertion of R2 and R4 was not discussed or agreed upon at
the conference. GSOC recalls that statements were made by participants that it was pre-mature to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
include controls language in the standard/requirement at this time. So it appears that revisions to the
contrary when were made when in fact NERC statements were made that the full RAI process would
not be in place until 2016. GSOC still supports the RAI as it “proposes to transition away from a
process-driven enforcement strategy to a proactive, risk-based strategy that clearly defines,
communicates, and promotes desired entity behavior in an effort to improve the reliability of the
BPS.” However, this transition has not been implemented yet. Until NERC transitions the Compliance
Monitoring and Evaluation Program (CEMP) to the risk-based strategy, we are still under the
past/current process-driven enforcement strategy. A primary concern of GSOC is that until the RAI is
developed and provides audit guidance regarding treatment of entity control measures, then auditor
subjectivity may creep into the audit process. GSOC believes that once a transition to a risk-based
strategy is complete, only then will there be an established “set of parameters” to “guide the exercise
of enforcement discretion.” “The parameters that would guide the exercise of discretion as well as the
protections” “would be in place to ensure due process and to ensure that enforcement decisions are
sound and reflect a consistent application of the ERO enterprise enforcement strategy.” More
specifically, The “decline to pursue option” will have replaced Find, Fix, and Track “after necessary
training of [NERC and Regional] personnel, industry and stakeholder outreach, and development of
process improvements.” At that time, “for those violations that pose a serious or substantial risk, or
are not proper candidates for the exercise of enforcement discretion, the ability to impose penalties
up to the statutory maximum or adopt increased monitoring and broader audit scope must be
retained.” At that time, internal controls will be the way to do business (operations/planning) and the
process-driven zero-tolerance enforcement process will only apply to those serious or substantial
risks. Regarding zero tolerance, some in industry have the false perception that putting internal
controls-like language in a reliability requirement NOW will subsequently allow auditors to apply nonzero tolerance. To the contrary, GSOC believes the current process-driven CMEP inclusive of
requirements with controls-like language actually requires zero-tolerance treatment. If this standard
is passed in its present form an auditor will not have the discretion to “decline to pursue” and must
treat every possible violation the same. Of course, NERC/Regional compliance enforcement can now
treat some possible violations as applicable to Find, Fix, Track. But that does not require controls
language in a requirement. Accordingly, mitigating COMPLIANCE risk has been and still is a driver for
the industry’s compliance programs. Once the CMEP is transitioned to the risk-based strategy, then
such language will be in place with the CMEP and the industry can focus more on RELIABILITY risk
and less on COMPLIANCE risk. In addition, GSOC notes that controls-like language is a requirement
which is administrative and therefore meets the criteria under P81 for exclusion from reliability
requirements. It is not a risk-based reliability requirement. A reliability requirement is one that is (as
the statutory definition says) a requirement to provide for reliable operation of the bulk-power
system. A reliability requirement includes requirements for the operation of existing bulk-power
system facilities, including cyber-security protection, and the design of planned additions or
modifications to such facilities to the extent necessary to provide for reliable operation of the bulkpower system. This administrative requirement does not meet the criteria for being a reliability
requirement.
No
R2 & R4 - we believe without any definitive guidance from NERC's still-undeveloped RAI, auditors will
apply subjective judgment as to the adequacy of controls used to perform periodic assessments and
therefore VRF and VSL are not appropriate.
GSOC recommends that only R1 and R3 survive; eliminate R2 and R4.
Individual
Greg Travis
Idaho Power Company
No
Yes for R1 and R3. No for the definition of "Operating Instructions". It is not written very well and is
difficult to understand. The language below is offered as a suggestion to simplify the definition.
Operating Instruction —A command by a System Operator of a Reliability Coordinator, Transmission
Operator, or Balancing Authority where the recipient is instructed to change or preserve the state,
status, output, or input of any portion of the Bulk Electric System. Discussions of general information
and of potential options or alternatives to resolve BES operating concerns are not commands and are
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
not considered Operating Instructions.
Yes
Yes
Individual
Robert W. Kenyon
NERC
No
This will require each entity to develop its own unique protocol. This will not "tighten up"
communications. Having each entity follow its own protocol will complicate and confuse
communications. One entity will be attempting to communicate with another entity which is not
familiar with the protocol being used by the first entity because the second entiy uses a diferent
protocol. Protocols if required should be standardized. Moreover, the proposed language requires a
protocol that "meets the expectations of its System Operators". The plain meaning of that sentence
as writtem is that the protocol meet the expectations of the individual workers, not the entity itself. If
this change is going to be approoved, should not it read "Each (entity) shall develop protocols that
PROVIDE ITS expections of its System Operators"?
Yes
Yes
Requirement (R1.5) provides inadequate protection against a misunderstanding when directives are
issued. Granted, the Requirement does obligate the party receiving the directive to repeat back the
directive. However, if the recipient repeats the directive back to the person issuing the directive, and
the "repeat back" indicates the recipient has misunderstood the directive, this Requirement merely
obligates the person issuing the directive to state the directive again. The Requirement places no
obligation on the person issuing the directive, who knows he has been misunderstood, to explicitly
and clealy bring to the attention of the recipient that the recipient has misunderstood. All the party
issuing the directive has to do is repeat what he has already said. The party issuing the directive is
under no obligation to make it clear that there has been a misunderstanding. With respect, I suggest
having the person issuing the directive merely repeat it if he's been misunderstood, with no explicit
statement that there has been a mistake, leaves open the potential for the recipient to be unaware he
has misunderstood and to execute a misunderstood directive.
Individual
Thad Ness
American Electric Power
No
Due to the manner in which the sub-requirements for R1 are written, there could be misinterpretation
at which entities plan would require those sub-requirements. We assume that requirements R1.6 and
R1.8 apply to an entity that in that instance is *receiving* an Operating Instruction where
Requirement R1.2, R1.3, R1.4, R1.5, R1.7 are reserved for only those cases where an entity is
*issuing* the Operating Instruction. As currently drafted, R1.6 and R1.8 could be interpreted as
somehow requiring an entity that would normally be issuing an instruction (such as an RC) to
implement documented communication protocols for an outside receiving entity (such as a Balancing
Authority). A potential solution would be to restructure R1 and R3 in such a way that it is based on
entities that would be issuing instructions in one requirement and entities that would be receiving
instructions in a separate requirement. AEP strongly disagrees with R 1.9, requiring coordination with
affected Reliability Coordinators’, Balancing Authorities’, Transmission Operators’, Distribution
Providers’, and Generator Operators’ communication protocols. For AEP, this requirement would
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require coordination among numerous entities, and keeping all those protocols in sync would be a
significant logistical challenge that does not appear to proportionately improve reliability. In addition,
exactly what kind of coordination is needed? R1.1 through are robust enough that adding R1.9 is
totally redundant and unnecessary. If beyond R1.1 through 1.8 there are additional, specific needs
that still need to be addressed, those should be identified so that specific requirements could be
developed if necessary. For this requirement alone, AEP must vote negative on this proposed draft.
No
If an entity has a control in place, but that control is somehow not viewed favorably during an audit,
is that entity potentially in violation of an additional requirement? R2 and R4 appear to have potential
double jeopardy implications.
It needs to be acknowledged by the project team that there are overlapping requirements between
COM-003-1 and COM-002-3. Although the project webpage states that “COM-003-1 establishes the
practice of using communication protocols for all Operating Instructions”, COM-003-1 explicitly
includes Reliability Directives along with the Operating Instructions. We understand Reliability
Directives to be a subset of Operating Instructions, so with respect to Reliability Directives, there are
unnecessary overlaps which will only cause confusion in adhering to the standard. In short, COM-0031 should only be adopted with the understanding that the overlapping requirements in COM-002
would then be retired. AEP supports the forward-looking approach advocated by NERC’s Reliability
Assurance Initiative. We believe this proposed standard puts “the cart before the horse” in that it
mandates internal controls for a limited number of requirements rather than taking a wholistic
approach where internal controls are generally required for all standards and where that language is
housed outside of the standard itself. AEP believes this R 1.3 is redundant with TOP-002 R18. Other
requirements in this proposed standard are already in place to drive clarity of communication.
Individual
John Seelke
Public Service Enterprise Group
No
We found what we believe to be a typo in the definition of "Operating Instruction." The defined term
“Operating Instruction” has this phrase: “…where the recipient of the command is expected to act, to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.” The comma after “act” should be removed because it is not
grammatically correct. If removed, the phrase would become: “…where the recipient of the command
is expected to act to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System.
Yes
The purpose statement needs to have “System Operators” limited to just those of RCs, TOPs, and
BAs. The definition of “System Operators” in the NERC Glossary includes GOPs. The capitalizd
language added to the Purpose statement below would clarify this: Purpose: To provide System
Operators OF RELIABILITY COORDINATORS, TRANSMISSION OPERATORS, AND BALANCING
AUTHORITIES predefined communications protocols that reduce the possibility of miscommunication
that could lead to action or inaction harmful to the reliability of BES.
Individual
Andrew Gallo
City of Austin dba Austin Energy
No
The latest version of COM-003 introduces a potential conflict with COM-002 related to the use of oneway burst messaging systems to issue a Reliability Directive. In COM-003, the follow Requirements
apply: R1.7 Instances where the issuer of an oral Operating Instruction or Reliability Directive using a
one-way burst messaging system to communicate a common message to multiple parties in a short
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time period (e.g. an All Call system) is required to verbally or electronically confirm receipt from at
least one receiving party. R1.8 Require the receiver of an oral Operating Instruction or Reliability
Directive using a one-way burst messaging system to communicate a common message to multiple
parties in a short time period (e.g. an All Call system) to request clarification from the issuer if the
communication is not understood. R3.3 Require the receiver of an oral Operating Instruction or
Reliability Directive using a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request clarification from the issuer
if the communication is not understood. In other words, COM-003 allows one-way burst messaging
for Reliability Directives and prescribes: • the issuer confirm receipt from at least one receiving party
• the receiver request clarification from the issuer if the communication is not understood However,
COM-002 has the following requirements: R2. Each Balancing Authority, Transmission Operator,
Generator Operator, and Distribution Provider that is the recipient of a Reliability Directive shall
repeat, restate, rephrase, or recapitulate the Reliability Directive. R3. Each Reliability Coordinator,
Transmission Operator, and Balancing Authority that issues a Reliability Directive shall either: •
Confirm that the response from the recipient of the Reliability Directive (in accordance with
Requirement R2) was accurate, or • Reissue the Reliability Directive to resolve a misunderstanding. In
other words, in the case of a one-way burst message used for Reliability Directives, COM-002 does
not allow for only those responses required in COM-003 but instead requires a full 3 way
communication from all parties. This potentially sets up both the issuer and receiver for violating
COM-002 if they respond to a one-way burst message Reliability Directive as the requirements
indicate in COM-003. In order to fully comply with BOTH standards, the receiver would have to
contact the issuer and repeat what was said on the original burst message; then, the issuer would
confirm the response was accurate before acting on the message.
Yes
Yes
Group
Salt River Project
Bob Steiger
Electric Reliability Compliance
Yes
Yes
No
The VSLs give a higher violation to a GO than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GO who fails to require 3-part responses when
requested is tagged with a Moderate violation, the BA with a lower. We believe the VRF should be Low
rather than Medium for R4.
R4 should be eliminated and R3 should end after the first sentence. GOs do not issue Operating
Instructions. They only receive instructions from others. GOs should have a communications
procedure as part of their operations. However, the methods used are properly business decisions
made by the GO. The content, thoroughness and effectiveness of a communications plan are excellent
items to consider when assessing an internal compliance program.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
Yes
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No
Requirement 3 is an administrative requirement that does little to benefit the reliable operation of the
BES. By specifically calling out “Directives” in the requirement it creates the potential for double
jeopardy with other requirements such as COM-002, IRO-001 and TOP-001 which all speak to
following Directives. Requiring a documented communications protocol when the only responsibility is
repeat back the instruction as received and seek clarification if the directive is misunderstood is
beyond the intended scope of the reliability program in general. This requirement should be removed.
Requirement 4 should be removed because it is unnecessary and excessive. The smaller entities that
this will affect do not record phone conversations and it would be difficult to assess performance
based on the very low number of “Operating Instructions” or “Directives” that these entities actually
receive. The performance of “Operating Instructions” should be the proof. A better approach would be
to amend the above mentioned standards (IRO, TOP, COM) to include “Operating Instructions” along
with Directives. The term “All Call” is used in Requirement 1 Part 1.8. It should be defined in the
NERC Glossary. If it isn’t to be defined, then it should not be capitalized. Regarding Requirement 1
Part 1.8, and Requirement 3 Part 3.3, the receiver of an oral Operating Instruction or Reliability
Directive from a one-way burst messaging system is “to request clarification from the issuer is the
communication is not understood.” What if the receiver never gets the issued Operating Instruction or
Reliability Directive? Regarding Requirement 1 Part 1.8, and Requirement 3 Part 3.3, suggest
changing “using” to “from” to make them read “Require the receiver of an Oral Operating Instruction
or Reliability Directive from a one-way burst…”
Individual
John Brockhan
CenterPoint Energy Houston Electric L.L.C.
No
See comments below
No
See comments below
CenterPoint Energy appreciates the opportunity to comment. The Company recognizes the work of the
SDT however CenterPoint Energy still has large concerns with Draft 5. Specifically: 1) The addition of
the term “Reliability Directive” to COM-003-1. 2) R1.9 coordination with other entities. 3) The addition
of specifying the alpha-numeric format in R1.4. 4) The VSL’s. 1) The addition of the term “Reliability
Directive” to COM-003-1 introduces a potential conflict with the already industry and NERC BOD
approved COM-002-3. Requirements R1.7 of the current draft of COM-003-1 states: “Instances where
the issuer of an oral Operating Instruction or Reliability Directive using a one-way burst messaging
system to communicate a common message to multiple parties in a short time period (e.g. an All Call
system) is required to verbally or electronically confirm receipt from at least one receiving party.”
(emphasis added) Requirements R1.8 and R3.3 of the current draft of COM-003-1 allow the recipient
of a Reliability Directive from a one way burst messaging system communication to “…request
clarification from the issuer if the communication is not understood.” (emphasis added) COM-002-3
makes no such distinctions regarding the issuing or receiving of Reliability Directives. COM-002-3 is
clear; whether an entity is issuing or receiving a Reliability Directive 3-part communication must be
employed. The Company firmly believes this conflict could easily cause entities to follow COM-003-1
yet be non-compliant with COM-002-3. In addition, since COM-002-3 already addresses emergency
communications and has been reviewed and approved by industry stakeholders as well as the NERC
BOD CenterPoint Energy believes there is no additional reliability benefit to adding “Reliability
Directive” to COM-003-1. CenterPoint Energy strongly recommends deleting “Reliability Directive”
from COM-003-1. 2) CenterPoint Energy has strong concerns regarding the addition of R1.9 to Draft 5
of COM-003-1. R1.9 requires that an entity’s documented communication protocols address
coordination with affected RC’s, BA’s, TOP’s, DP’s, and GOP’s communication protocols. For
responsible entities that have interconnections with multiple entities, this will be the equivalent of
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“herding cats”. The Company does not believe it will be possible to coordinate with and come to a
common agreement regarding the items in R1.1 – R1.8 with multiple parties. For example: R1.4
requires the documented communication protocols to address the format to be used when alphanumeric clarifiers are necessary. Where a responsible entity is a TOP and is interconnected with
multiple other TOP’s, DP’s, GOP’s as well as its RC, and BA, it will be extremely difficult for all parties
to agree to a common alpha-numeric format. In addition, coordination will become an issue when any
of the parties decide to revise or amend its communication protocols. This will be an on-going
management issue for all entities. CenterPoint Energy strongly recommends R1.9 be deleted from
COM-003-1. 3) CenterPoint Energy believes the addition to R1.4 requiring a responsible entity to
specify the format to be used where alpha-numeric clarifiers are necessary is an unnecessary and
burdensome requirement. The Company agrees with the SDT’s decision to add to R1 and R3 language
that allows an entity to address, where applicable, the items in the sub-requirements instead of
requiring these items to be in the communication protocols as it was in Draft 4. However, the addition
of specifying the format for those clarifiers is a step backwards. Draft 4 did not require documenting a
specific format and therefore would have allowed an entity the flexibility to use, for example, “Baker”
or “Bravo” for the letter “B”. The Draft 5 version now sets up an operator for a possible violation if the
protocol specifies “Baker” and the operator inadvertently uses “Bravo”. The purpose of using alphanumeric clarifiers is to ensure the recipient understands that the alpha component, in this case, is the
letter “B” and not “E” or “D”. The use of “Baker” or “Bravo” accomplishes that purpose. The Company
believes having to specify a format to use does not result in any reliability benefit and therefore
CenterPoint Energy strongly recommends the deletion of the format requirement from R1.4. 4)
CenterPoint Energy firmly believes there should be no High or Severe VSL for simply failing to
document a process, policy, or procedure. High or Severe VSL’s should only apply to the most
egregious violations that have a high impact on the reliability of the BES. As NERC has stated on
many occasions, the purpose of the Reliability Standards is to enhance the reliable operation of the
BES. Where an entity is performing the process, procedure, or task required in an applicable Standard
and therefore is reliably operating its portion of the BES, yet has failed to document that process,
procedure, or task, penalizing that entity with a High or Severe VSL will not result in improved reliable
operation of the BES. CenterPoint Energy recommends no VSL’s higher than Moderate. CenterPoint
Energy supported Draft 4 of COM-003-1 however, the changes made by the SDT in Draft 5 has
caused the Company to rethink its position. If the SDT were to make the recommended changes
CenterPoint Energy would be able to support the Standard.
Individual
John Bee on behalf of Exelon and its' affiliates
Exelon
Yes
No
See comment #3 in the comment area of the last question
1) In the COM-003 FAQ document the response to question 5 states that R3 and R4 apply to the
“recipient of the command” where the recipient is “expected to act, to change or preserve the state,
status, output, or Element of the [BES] of Facility of the [BES]. In many Registered Entity
organizations, the commands from a TOP, BA or an RC typically go through an intermediary dispatch
control center. Then, if necessary, the commands are passed through to the associated DP or GOP.
How does COM-003 apply to such organizations with respect to R3 and R4? 2) In the COM-003 FAQ
document the response to question 3 states that entities “develop their own programs that support
the requirements of COM-003.” Suggest that the SDT clarify that recorded lines are not specifically
required and that other tools such as documented direct supervisory observation could be used. 3) In
R3 and R4 the term ‘operators’ is used, in generation stations this term is widely used and relates to
different job functions. Suggest clarifying the term by stating ‘operators who receive Operating
Instructions or Reliability Directives from a Balancing Authority, Reliability Coordinator or
Transmission Operator’. 4) The COM-003 language that includes ‘reliability directives’ has the
potential to create a compliance issue with COM-002 related to “all calls” since some Transmission
Operations use ‘all calls’ or ‘one way burst messaging’ to communicate reliability directives. These
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communication methods typically do not allow for a response or repeat back or for an
acknowledgement of the response accuracy. The problems with COM-002 cannot be solved by making
edits to COM-003. Instead, changes to COM-002 should be made to clarify that "all calls" or burst
messaging systems can be used to deliver Reliability Directives.
Group
Western Electricity Coordinating Council
Steve Rueckert
WECC
No
We do not agree with the revisions to the language of R1 and R3. The changes are a lowering of the
bar for reliability. Earlier versions identified specific communication protocols for each BA, RC, and
TOP. These specific requirements would have resulted in a consistent approach to communications
between all sysem operators. The proposed revisions coupresult in varying procedures that do not
close the gap in communcations. The watered-down versions of the requirements are essentially a fillin-the-blank type of standard allowing each applcable entity to develop their own protocols.
Yes
No
Based on the changes we believe are necessary for Requirements R1 and R3, we beleive the VSLs
should be changed accordingly.
The apparent conflict beteen COM-002-3 and COM-003-1 needs to be addressed. The information
provided in the Frequently Asked Questions document was helpful but it is not clear that a drafting
team response to a frequently asked question can alter what is required in another standard. It s not
clear that developeing a communcations protocol that says three-part communcation is not necessry
for a one-way burst message is going to relieve a BA, RC, or TOP from the requirement to use threepart communcations for all Reliabliity Directives. If the position is that thre-part communcaiton is not
required for one-way burst messages, this exception should be included in COM-002-3.
Individual
D. Jones
Texas Reliability Entity
Texas RE voted "no" on this draft for reasons expressed in our comments submitted on prior drafts.
In particular, we are concerned about lack of coordination between COM-003 and COM-002.
Group
Seattle City Light
paul haase
seattle city light
Yes
Yes
Seattle City Light is supportive of the proposed "assess and implement" approach to compliance for
COM-003 R2 and R4.
No
The VSLs give a higher violation to a GO than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GO who fails to require 3-part responses when
requested is tagged with a Moderate violation, the BA with a lower. Both should be lower.
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Seattle City Light is concerned about the conflict between COM-002 and COM-003 regarding
responses to Reliability Directives. In the case of a one-way burst messaging used to issue a
Reliability Directives, COM-002 does not allow for only those responses required in COM-003 but
instead requires a full 3-way communication from all parties. This potentially sets up both the issuer
and receiver for violating COM-002 if they respond to a one-way burst messaging Reliability Directive
as the requirements indicate in COM-003. In order to be fully compliant with BOTH standards, the
receiver would have to contact the issuer, repeat what was said on the original burst message, then
the issuer would confirm that the response was accurate before acting on the message. Seattle City
Light appreciates the responsiveness of the OPCPSDT in quickly posting an FAQ once the COM002/COM-003 issue was raised. The opinion of the OPCPSDT not withstanding, Seattle is not
reassured by the secondary documentation cited in the FAQ when the plain language of the two
Standards are in conflict. Past experience, such as illustrated in the 2008 PacifiCorp case, shows that
where Standards are unclear or in conflict, auditors have been prone to take the language at face
value and disregard secondary documents. In addition, entities charged with implementing the
Standards are prone to change practices to avoid ambiguous areas and compliance risk, which in this
case could result in the phase-out of effective all-call or burst messaging systems for announcing
reliability Directives. As a result, Seattle is sufficiently concerned about the audit and reliability
implications created by the present draft of COM-003 to change from a YES position to NO at this
time. Seattle is prepared to support COM-003 once this conflict is addressed. A simple solution would
be to eliminate the words "Reliability Directive" from COM-003, which after all is designed to address
"Operating Instructions." Inclusion of Reliability Directive language in COM-003 creates an additional
complication, by making R1.8 incomplete. R1.8 require the receiver of an oral Operating Instruction
or Reliability Directive using a one-way burst messaging system to communicate a common message
to multiple parties in a short time period (e.g. an All Call system) to request clarification from the
issuer if the communication is not understood. This language does not address the next step: if an
entity receives a burst message from its RC that is unclear, and is unable to reach the RC for
clarification (perhaps because the RC is busy handling the emergency situation), what is the entity to
do? Implement to Reliability Directive to its best understanding? Wait until it can clarify the Directive?
Do nothing? Serious reliability and compliance risks attend all of these possibilities, adn the Standard
should be clear as to which is prefered. Seattle again recommends removing "Relaibility Directive"
language from COM-003 as a simple solution. If the Reliability Directive language remains in COM003, this potentiality should be addressed in the Standard as to which approach is prefered.
Group
Duke Energy
Michael Lowman
Duke Energy
Yes
R1.7, R1.8, and R3.3 – All Call should not be capitalized since it is not a defined term. It should
instead be placed in quotation (“All Call”). R1.6, R1.8, R3.2, and R3.3 – Change the word “Require” to
“Requirement for” to better align grammar with R1.
Yes
Yes
Group
Platte River Power Authority
Christopher Wood
Platte River Power Authority
Agree
Large Public Power Council
Group
San Diego Gas & Electric
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Annamay Luyun
San Diego Gas & Electric
Yes
Yes
Yes
Please see comments: NEW NERC RELIABILITY STANDARD – COM-003-1 – Version 5 Version 5
comments R1.1 and R3.1 Proposed Updated Language: Use of English language when issuing or
responding to an oral or written Operating Instruction or Reliability Directive, unless another language
is mandated by law or regulation, or as otherwise agreed to by the parties. Comment: The Western
Interconnection is interconnected with Mexico, south of the California, Arizona and New Mexico
borders and with Canadian provinces north of the Washington, Idaho and Montana borders. SDG&E,
which is located at the California-Mexico border, communicates almost daily with the Mexico utility
located in Baja California, CFE. When the standards became mandatory and enforceable, in
compliance with COM-001, R4, SDG&E maintained an agreement with CFE which documents that
English will typically be used, but in instances where communicating in Spanish is more effective in
ensuring system reliability, the personnel involved will use Spanish given that all parties involved are
fluent in Spanish. CFE does not have a mandate to be in compliance with the U.S. NERC Reliability
Standards. The native language in Mexico is Spanish, and SDG&E staffs its Electric Grid Operations
department with personnel who are fluent in Spanish, therefore its agreement with CFE is managed to
insure that all communications with its neighbor to the south are clear, concise, and understood. In
addition, there are at least two generation stations located south of the California border,
interconnected with SDG&E, and the employees at those stations are fluent in Spanish, therefore,
because those generation station personnel will also communicate with the California ISO and the
WECC RC on occasion, those entities need the flexibility provided in COM-001 R4 to be carried
through to COM-003-1, R1.1. & R3.1. All policies and procedures developed by power company
entities south of the border are written in Spanish, and at times, written communication between U.S.
and entities in Mexico are in Spanish. Since SDG&E’s neighbors to the south do not have to comply
with U.S. NERC Reliability Standards, and U.S. entities are required to comply with U.S. NERC
Reliability Standards, SDG&E proposes the revisions to COM-003-1 R1.1 and R3.1 as identified above.
This proposed revision provides for the flexibility that already exists in COM-001 R4 that has
effectively worked over the last several years. R1.2 Proposed Updated Language: Instances that
require time identification when issuing an oral or written Operating Instruction or Reliability
Directive, and the format for the time identification specified uses a 24-hour clock format and the
Entity’s time zone. Comment: SDG&E prefers the language proposed above. The proposed language
leaves NO doubt associated with how to reference a specific time for ALL entities. If one entity uses
the 24 hour clock, and another is using a.m. and p.m., it simply leaves the opportunity for some
confusion that can be eloquently avoided when stating that a 24 hour clock is to be used.
Group
North American Generator Forum Standards Review Team
Patrick Brown
Essential Power, LLC
No
See answer to 4 below.
No
See answer to 4 below.
The SRT agrees with the concepts put forth in COM-003, but have some concerns, particularly with
the proposed administrative burden associated with the Standard. The SRT offers to following
comments: 1. R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
communication protocols; this could result in a TOP having to coordinate with a hundred+ different
entities' communications protocols. This coordination would not improve reliability, but only serve to
create confusion and significant communication time delays in real-time operations. Both R1 and R4
create significant documentation and administrative burdens, without providing a comparable
improvement to the reliability of the BES. As reliability based Standard, COM-003 should focus on
those actions that would have a direct impact on reliability, while minimizing the administrative
burden. 2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They
only receive instructions from others. GOPs should have a communications procedure as part of their
operations, however, the methods used are properly business decisions made by the GOP. The
content, thoroughness and effectiveness of a communications plan are excellent items to consider
when assessing an entity’s internal compliance program. 3. R4 raises the question of sufficiency of an
entities corrective program. The RSAW requires the GO to turn over records of monitoring
communications as well as records of corrective actions and then prove the “problem” is not still in
place. This standard could easily turn into a high-profile audit target due to the varying concepts of
what does and does not constitute a sufficient corrective action program. 4. The SRT recommends
that the language to M4 be changed as follows: M4. Each Distribution Provider and Generator
Operator shall provide the results of its periodic assessment and of any corrective actions (if any
corrective actions were implemented) developed for Requirement R4. Examples of sufficient periodic
assessment programs include, but are not limited to, the following: -Documented review of voice logs
for a total of at least one hour per calendar year for each operator (does not need to be a single
session) -Documented personal monitoring of communications for a total of at least one hour per
calendar year for each operator (does not need to be a single session) -Documented annual training
Examples of sufficient corrective action programs include, but are not limited to, the following: Documented refresher training -Documented meeting -Documented “hot box” communication 5. The
VSLs give a higher violation to a GOP than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GOP who fails to require 3-part responses when
requested is tagged with a Moderate violation, while the BA would receive a Lower. 6. In the RSAW,
the following passage should be expunged; “Where practicable, verify that deficient communication
practice was indeed corrected by reviewing evidence of Operator communications (such as voice
recordings) occurring after the date of the corrective action to determine if deficient communication
practice was corrected.” Differentiating between slips of the tongue and “deficient communication
practices” involves subjective judgments. The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of making
before-and-after voice recording comparisons. This is an open-ended matter that could very quickly
become an unreasonable compliance burden. RSAWs in general should not introduce new
requirements, measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Individual
Ronnie Hoeinghaus
City of Garland
Yes
No
R2 & R4 Requirements are written assuming that corrective actions will be necessary. Should be
written to state corrective actions “if necessary”
1)COM-003 now includes “Reliability Directives” which is why COM-002-3 was developed and
approved – COM-002-3 does not need to exist if Reliability Directives are covered in COM-003 2)In
the Background Section of the "Unoffical Comment Form", it is stated that the final goal of this
standard was to implement 3 part communication. It would seem that it would be simple to state in a
requirement that the entity has to develop a procedure to use 3 part communications for Operating
Instructions using English except where prohibited by law or regulation and then a 2nd requirement
to develop an assessment process with a corrective process if necessary. It is totally unnecessary to
write a requirement with 9 sub parts that must be accounted for in a policy and procedure for an
industry wide practice that already exists. As written, it only add burdensome and unnecessary
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paperwork to operations and compliance departments that has to be maintained and audited – again
for a process that already exists industry wide. 3) Why is the Time Horizon stated as "Long Term
Planning" instead of "Real-Time"
Individual
Jim Howard
Lakeland Electric
Agree
Florida Municipal Power Agency (FMPA)
Group
Hydro One Networks Inc.
David Kiguel
Hydro One Networks Inc.
Yes
We are not convinced that a Standard is the best approach to routine communications, but we feel
that the latest draft is a reasonable compromise.
Individual
David Jendras
Ameren
No
We do not believe that we need a definition for the term “Operating Instruction” and we would like to
see this defined in the entities protocol. However if a definition is included, we ask the SDT to require
an RC, TOP, or BA to identify when an Operating Instruction is used to communication to a GOP or
DP.
No
We ask the SDT to delete requirements R3 and R4 because they are redundant and may cause double
jeopardy for entities as these requirements are addressed in requirements R1 and R2 for the BA, RC,
and TOP communication protocols with DPs/GOPs.
No
Concerning the VRF and VSLs we ask the SDT to review the severity levels because we do not believe
that any violations of this standard should be at either a High or Severe level since these are
documentation requirements.
We would ask the SDT to consider for clarity to this standard that COM-002 only address Reliability
Directives and COM-003 only address Operating Instructions.
Individual
Joe O'Brien
NIPSCO
see NIPSCO comments from Julaine Dyke, thanks
Individual
Martyn Turner
LCRA Transmission Services Corporation
Agree
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Seattle City Light
Individual
Jack Stamper
Clark Public Utilities
Yes
Yes
No
The VSLs give a higher violation to a GO than a BA for exactly the same violation, even though the
consequences with the BA are much greater. A GO who fails to require 3-part responses when
requested is tagged with a Moderate violation, the BA with a Lower. Both should be Lower.
Clark Public Utilities is concerned about the conflict between COM-002 and COM-003 regarding
responses to Reliability Directives. In the case of a one-way burst messaging used to issue a
Reliability Directive, COM-002 does not allow for only those responses required in COM-003 but
instead requires a full 3-way communication from all parties. This potentially sets up both the issuer
and receiver for violating COM-002 if they respond to a one-way burst messaging Reliability Directive
as the requirements indicate in COM-003. In order to be fully compliant with BOTH standards, the
receiver would have to contact the issuer, repeat what was said on the original burst message, then
the issuer would confirm that the response was accurate before acting on the message. Clark
appreciates the responsiveness of the OPCPSDT in quickly posting an FAQ once the COM-002/COM003 issue was raised. The opinion of the OPCPSDT not withstanding, Clark is not reassured by the
secondary documentation cited in the FAQ when the plain language of the two Standards are in
conflict. A simple solution would be to eliminate the words "Reliability Directive" from COM-003, which
after all is designed to address "Operating Instructions."
Individual
Alice Ireland
Xcel Energy
Agree
MRO NERC Standards Review Forum (NSRF)
Group
SERC OC Standards Review Group
Gerry Beckerle
Ameren
No
No
No
Regarding question #1, the SERC OC Review Group agrees with the definition of Operating
Instruction. While we also can agree to the changes made to R1, we feel R3 in its entirety is
unnecessary and duplicative. Removal of the word “develop” would eliminate double-jeopardy
concerns. R3 could be acceptable if “develop and” are omitted and “as developed in R1” is inserted
after “protocols” and before “that.” It should be noted that this suggestion only applies to the subrequirements in R1 that correspond to the proposed sub-requirements in R3. Regarding question #2,
R2 is acceptable and R4, as stated above for R3, is unnecessary and duplicative. Regarding question
#3, we agree with the VRFs and VSLs for R1 and R2. Based on our previous comments, we do not
agree with the need for R3 and R4, and therefore VRFs and VSLs for these requirements are not
needed. Additional SERC OC Standards Review Group supporting these comments are James Wood
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with Southern Company and Kelly Casteel with TVA. The comments expressed herein represent a
consensus of the views of the above named members of the SERC OC Standards Review Group only
and should not be construed as the position of SERC Reliability Corporation, its board, or its officers.
Individual
Wayne Sipperly
New York Power Authority
Agree
Large Public Power Council (LPPC)
Group
Dominion
Mike Garton
Dominion Resources Services, Inc.
Agree
EEI
Individual
Julaine Dyke
NIPSCO
Yes
No
"Each Distribution Provider and Generator Operator shall develop and implement documented
communication protocols that outline the communications expectations of its operators." This
language is unclear as to the communication expectation to its operators. Does this address the
communications between the DP and the TOP only? Or does this apply to the communication between
the DP and field personnel?
Yes
As per the effort of paragraph 81, we feel that COM-002 and COM-003 should be combined into one
standard. It is evident there is redundancy between these two standards which should be eliminated.
Individual
Michelle D'Antuono
Occidental Energy Ventures Corp
No
See comments below.
Yes
Yes
Occidental Energy Ventures Corp. (“OEVC”) is firmly on board with the strategy taken by the drafting
team to incorporate structure in the communication of Operating Instructions, while allowing each
entity some flexibility in the process. As a GOP, we take very seriously our responsibility to accurately
capture and execute all instructions from RCs, BAs, and TOPs that may affect the state of the Bulk
Electric System. This approach will allow us to differentiate between instructions issued orally, via
email/messaging, and one-to-many broadcasts – which change rapidly as new communications
technologies are introduced. In addition, we agree that a risk-based compliance method is necessary
– particularly in the case of oral communications. Even the most perfectly trained operators can
stumble on occasion, and the result should not be a compliance violation unless the errors continue to
manifest themselves. Furthermore, the amount of overhead necessary to ensure that every oral
instruction is repeated back with time stamps, equipment identifiers, and alpha-numeric clarifiers is
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extraordinary in the zero-defect model. However, we are not convinced that these excellent intentions
are captured in a manner that will assure consistent assessments by Compliance Enforcement
Authorities. It is clear from our reading of the FAQs recently posted by the drafting team that many
industry respondents are unclear how auditors will interpret COM-003-1’s requirements over a wide
range of operating scenarios – a concern that we share. This means that a common understanding
must be reached in an enforceable document that both operators and CEAs can rely on for
consistency. In our view, the RSAW is the logical vehicle for this approach. It is a fundamental audit
tool and has been traditionally used as a semi-binding reference in the evaluation of reliability
compliance. In addition, the concurrent development of the RSAW with COM-003-1 was instituted
precisely to ensure uniformity between the SDT’s intent and the standard’s enforcement. This implies
that the RSAW must contain a greater level of detail to address multiple situations – and we have
provided specific suggestions in our RSAW feedback form along these lines. Lastly, we do not have a
clear understanding how Requirement R1.9 will be implemented. As it is presently written, it would
seem that GOPs should expect some notification from their RCs, BAs, and TOPs that communication
policies are to be “coordinated.” Our experience has been that some entities simply post instructions
on their web-sites hidden among many other documents – which does not count as coordination in
our view. However, we are not sure that the issuers’ policies are consistent with all of R1’s other subrequirements. As such, OEVC recommends that R1.9 be removed.
Individual
Jonathan Appelbaum
The United Illuminating Company
Yes
Yes
Yes
UI as its functional role of DP is voting No because of the conflict between COM-003 R 1.7, R1.8 and
R3.3 with COM-002 R2. COM-003 allows for the RC/TOP/BA communication protocol when issuing
Reliability Directives to overide the clearly stated requirement of COM-002 R2 that a DP SHALL
REPEAT, RESTATE, REPHRASE, OR RECAPITULATE the Reliability Directive. There is no leeway in
COM-002 R2 to allow for solely providing an affirmation of receipt of a verbal reliability directive or
not repeating back the message when the RC/TOP requests no repeat. As a DP, UI is placed in a
position of attempting to comply with two opposing requirement in the two standards. If the RC/TOP
communication protocol clearly stated that there will be no repeat back when receiving a verbal
Reliability Directive and COM-003 requires a DP to comply with the RC/TOP communication protocol,
UI would have to choose between violating COM-002 or COM-003. Since the VRF for COM-002 R2 is
HIGH indicating a greater risk to reliability than COM-003 VRF LOW, UI would comply with COM-002
R2. This issue can be resolved either by correcting COM-002 by assigning the flexibility of opting out
of repeat back to the RC/TOP/BA function, or removing the words "Reliability Directive" from COM003.
Group
pacificorp
ryan millard
pacificorp
No
PacifiCorp supports the proposed language referenced under R1 and the definition of “Operating
Instruction” but does not support the following language proposed under R1.4: “Instances where
alpha-numeric clarifiers are necessary when issuing an oral Operating Instruction or Reliability
Directive, and the format for those clarifiers.” Under the proposed draft, instances where alphanumeric clarifiers are “necessary” are not clearly defined. In the absence of a clear definition, the
identification of such instances is open to interpretation by both the entity and the auditor. Moreover,
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requiring the use of alpha-numeric clarifiers is not warranted when the requirements listed in R1.5 R1.8 (requiring the strict use of three-way communication) alleviate any possibility of
miscommunication, which PacifiCorp understands to be the drafting team’s intent in the development
of separate Requirement R1.4. PacifiCorp believes implementing the use of alpha-numeric clarifiers
poses additional risk due to the introduction of ambiguous language.
No
PacifiCorp does not support the following language referenced under R2 (with substantially similar
language in R4) as it pertains to the Balancing Authority, Reliability Coordinator, Transmission
Operator, Generator Operator, and Distribution Provider: "…shall develop method(s) to assess System
Operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols developed for Requirement R1.” In the
absence of any proposed criteria for measuring how the aforementioned method(s) are developed,
determining whether an entity has successfully met the expectations it has established in its
communication protocols is subject to a multitude of interpretations. Moreover, Measures M2 and M4
are focused exclusively on the results of an entity’s periodic assessment and corrective actions.
PacifiCorp believes that a results-based review of an entity’s assessment fails to provide any insight
into the quality of the assessment itself.
No
PacifiCorp does not support the VRFs and VSLs for Requirements R2 and R4. In keeping with
PacifiCorp’s comment in Question 2, a method of assessment that is not explicitly defined and cannot
be measured against a clear set of criteria makes it difficult for an entity or auditor to determine
whether any of the corrective actions taken by an entity have fulfilled the expectations documented in
their communication protocols. Assigning a severity level based on a percentage of completion is
redundant when an entity cannot determine what a “complete” assessment is or the criteria by which
it is measured.
Individual
William O. Thompson
NIPSCO
No
See comments submitted on NIPSCO's behalf by Julaine Dyke
Yes
See comments submitted on NIPSCO's behalf by Julaine Dyke
Group
MRO NSRF
Russ Mountjoy
MRO
Yes
Yes
Yes
The NSRF recommends the following issues be addressed in order to provide a less ambiguous
Requirement. Regarding R1 and the term; ‘implement’. The “Blue Box” explanation is not carried
forward when the standard is filed with the Commission. The “Blue Box” explanation greatly expands
the meaning “and implement”. Our understanding of ‘implement’ is that you will use the documented
communication protocols in the manner outlined in your System Operator communications protocols.
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Training is not a demonstration of implementing. Only actual System Operator communications
demonstrating the use of the communication protocols is demonstrating implementation. Recommend
that “training” be removed from the blue text box since training is inherent to assuring that protocols
are followed. The Training issue will also need to be removed from the RSAW. Suggest R1.8 be
removed. This requirement cannot be measured. How do you prove compliance? An entity will be
asked to prove the negative and demonstrate that my System Operators were not confused? I can
see where I might have to provide an attestation that states: “My System Operators were not
confused on any one-way burst messages.” This proposed requirement is a common sense issue.
R1.9, R3.3: the word “coordination with affected” is vague and open to many interpretations. Suggest
this requirement be deleted. Should the requirement be kept, suggest clarifying what is intended in
the requirement. Such as “RC, TOP’s BA’s… shall share their communication protocols with applicable
RC, BA, TOP, … “ The NSRF does not understand if the intent is to share or coordinate protocols? Both
have different outcomes, please clarify. The NSRF believes that the infrequent communications to a
Distribution Provider, that are not already in scope of COM-002-3, do not carry any considerable risk
to the BES. The administrative burden on the Distribution Provider should be greatly reduced, as
there would not be a measurable gain in reliability by requiring them to formally document
communication protocols and establish a monitoring program. To address these concerns, we
recommend that Distribution Provider be removed from the applicability in R3 and R4. Secondly, we
suggest that an R5 be created similarly to COM-002-3, R2. Recommend the following for how the new
R5 might read: R5. Each Distribution Provider that is the recipient of an oral Operating Instruction,
other than Reliability Directives, shall: 5.1 Use the English language, unless another language is
mandated by law or regulation. 5.2 Repeat, restate, rephrase, or recapitulate the oral Operating
Instruction, excluding oral Operating Instructions issued as a one-way burst message.
Individual
Michael Falvo
Independent Electricity System Operator
No
We agree with most of the changes made. We offer a preferred wording for Part 1.4, and have a
concern over the ambiguity of Part 1.6 and Part 1.8. Part 1.4 states that: 1.4 Instances that alphanumeric clarifiers are necessary when issuing an oral Operating Instruction or Reliability Directive,
and the format for those clarifiers. A preferable description would say that the protocol should address
the risk of miscommunication arising from alpha-numeric identifiers. This could be addressed through
the use of the phonetic alphabet or through different means if local conditions dictate a different
approach. As noted above, we are concerned over the ambiguity of Part 1.6, which states that: 1.6
Require the recipient of an oral two party, person-to-person Operating Instruction to repeat, restate,
rephrase, or recapitulate the Operating Instruction, if requested by the issuer. When read together
with the last sentence in R1, “The documented communication protocols will address, where
applicable, the following:”, this part is unclear as to whether it is to identify the instances that the
repeat is required,or that the documentation needs to include explicit statements that the issuer
needs to request a repeat when issuing an operating instruction or reliability directive which the
issuer feels a repeat is necessary. This sub-requirement part, as written, is ambiguous and appears to
be more applicable to the instruction recipient than the issuer. When read together with Part 3.2, Part
1.6 appears to be requiring the issuer to identify the instances that a repeat is required. We therefore
suggest the SDT to revise Part 3.2 as follows: 1.6 Instances where it requires the recipient of an oral
two party, person-to-person Operating Instruction to repeat, restate, rephrase, or recapitulate the
Operating Instruction, if requested by the issuer. Similar concerns with Part 1.8 except the mirror part
3.3 does not contain the wording “if requested by the issuer”. Hence, we assume that the recipient is
required to request clarification from the issuer if the communication is not understood without having
to be asked. Therefore, we propose Part 1.8 be revised as follow: 1.8 A stipulation that the receiver of
an oral Operating Instruction or Reliability Directive using a one-way burst messaging system to
communicate a common message to multiple parties in a short time period (e.g. an All Call system)
to request clarification from the issuer if the communication is not understood.
Yes
Yes
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Individual
Nazra Gladu
Manitoba Hydro
Yes
(1) Definition “Operating Instruction” - reference is made to both ‘Bulk Electric System’ and ‘BES’. For
consistency, either the words or acronym should be used.
No
(1) Compliance Data Retention, 1.2 – COM-001 and COM-002 standards both read 3 months or 90
days for the retention of evidence. It is unclear as to why the retention has been doubled in this
standard to 180 days for R2, M2 and R4, M4. For consistency and simplicity, 90 days should be used.
Yes
Although Manitoba Hydro is in general agreement with the standard, we have the following clarifying
comments: (1) VSLs, R1 – the Severe category is missing the concept of ‘The Responsible Entity did
not implement four or more documented communication protocols as required in Requirement R1’. As
written, it skips from ‘three or more’ to not implementing any of them. There is a gap if there is a
Responsible Entity that failed to implement for example, 5 of the protocols. (2) VSLs, R3 – for
readability, the first paragraph should be written ‘The Responsible Entity did not address any parts of
Requirement R3 in their documented communication protocols as required by Requirement R3.”.
(1) ‘Reliability Directive’ is referred to in R1, 1.1 of the COM-003-1 standard but is not currently a
FERC approved definition, defined in the Glossary of Terms. (2) R1, 1.3 and Rationale and Technical
Justification documents - reference is made to ‘interface’, which is not a defined term. Accordingly, its
meaning is questionable. Consider removing or clarifying. (3) R1, 1.6 and 1.8 – requirement language
is not consistent. For example, ‘recipient’ and ‘receiver’ are used but have the same meaning.
Suggest beginning the requirements with the following text “Instances where….”. (4) R2, R4 - the
word ‘periodically’ should be inserted before ‘assess’ in each of these requirements for consistency
with the Measures and VSLs, which refer to ‘periodic assessments’. (5) R2, R4 - the phrase ‘necessary
to meet the expectations in its documented communication protocols’ is ambiguous and will be
difficult to interpret when assessing compliance. Is this statement to be the interpretation of the
drafter of the protocols as to what is, in their opinion ‘reasonably necessary’? (6) R3, 3.2 and 3.3 –
requirement language is not consistent. For example, ‘recipient’ and ‘receiver’ are used but have the
same meaning. Suggest beginning the requirements with the following text “Instances where….”. (7)
General Measures – there is lack of guidance with respect to both who the documentation is to be
provided, and when. For example, periodically, upon request, etc. (8) M1 and M3 – ‘ / ‘ should be
placed between the words ‘and’ and ‘or’. (9) Section D, Compliance, 1.1 – the paraphrased definition
of ‘Compliance Enforcement Authority’ from the Rules of Procedure is not the standard language for
this section. Is there a reason that the standard CEA language is not being used?
Individual
Michiko Sell
Grant County PUD
Agree
Seattle City Light
Individual
David Thorne
Pepco Holdings Inc
Agree
Pepco Holdings Inc supports the comments submitted by EEI
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
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Yes
Yes
Yes
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
ERCOT recognizes and commends the drafting team’s efforts to respond to industry comments and is
supportive of draft 5 of COM-003-1. It should be clear in the definition and the standard that
electronic systematic interchanges are not Operating Instructions. Please consider modifying the last
sentence of the definition for Operating Instructions as below: “Discussions of general information and
of potential options or alternatives to resolve BES operating concerns as well as electronic, system to
system, interchanges are not commands and are not considered Operating Instructions.” ERCOT ISO
also maintains that the sub-requirements for R1 and R3 are not the “communication protocols” that
FERC Order 693 and Blackout Recommendation #26 intended to be addressed as they are solely
focused on “miscommunication”. However, ERCOT ISO believes that the structure of COM-003-1, in
allowing an entity to address subrequirements through development of its own documented
communication protocols and identification of the instances of needing to use such protocols, allows
for future revisions to focus on the subrequirements, as needed, leaving the construct in place to
easily add, modify, or delete such parts as necessary through such subsequent revisions. An example
of such a revision is where IRO-014-1 R1 has a similar construct and was modified to include an
additional subrequirement (R1.7) in version 2. ERCOT believes that oral and written operator
communication requirements should be in a single reliability standard and supports further refinement
of the requirements and combining COM-002 and COM-003 into a single reliability standard.
Group
SMUD/Balancing Authority of Northern California
Joe Tarantino
Sacramento Municipal Utility District
SMUD would like to thank the Drafting Team for their efforts. While we agree with the intent of COM003 SMUD believes the requirements R1.5 & R1.5 are too vague. Requiring the receiving party to
repeat back the Operating Instruction only (emphasis added) if requested does not provide insurance
that the receiving party would have a clear understanding of the necessary actions intended by the
issuing party.
SMUD would like to thank the Drafting Team for their efforts. While we agree with the intent of COM003 we would like the Drafting Team to provide input on a possible conflict between the Board
approved COM-002-3 Requirement and Draft #5 of COM-003-1 Requirements R1, Part 1.7 & R3, Part
3.3. It appears that a “One-way” burst messaging that includes either oral or electronic Operating
Instructions or Reliability Directives as depicted in the current COM-003 does not require practice of
3-way communication prior to taking action. Since COM-002 Requirement R2 specifies that the
recipient “shall repeat, restate, rephrase, or recapitulate the Reliability Directive” it is unclear whether
or not the receiving parties of a blast message adhering to the COM-003 Standards would be in
compliance with COM-002 requirement R2.
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Individual
Richard Vine
California ISO
Agree
The California ISO is supportive of those comments submitted by the SRC (ISO/RTO Council).
Group
Western Small Entity Comment Group
Steve Alexanderson
Central Lincoln
No
In the comment area of the last section as asked.
No
In the comment area of the last section as asked.
1) R3 (formerly R2) apparently now applies to all of a DP’s or GO’s operating communication
expectations, and not just to Operating Instructions or Reliability Directives. We fail to see what
Reliability objective is accomplished by entities presenting all their communication protocols for audit,
when the only real reliability concern is if the entity responds appropriately to an Operating
Instruction or Reliability Directive. Although 3.1, 3.2, and 3.3 deal only with Operating Instructions
and Reliability Directives, R3 itself does not share this limitation. 2) We also note that by removing
the “in a manner that identifies, assesses and corrects deficiencies” language, R3 becomes a zero
defect requirement and an entity becomes subject to sanction for a single failure to implement the
developed protocol. We don’t believe this was the SDT’s intent, but this was the effect of moving the
language to R4. R4 is simply an additional separate requirement an entity must comply with. Taken
together, we believe most auditors would look first to find failures to implement procedure under R3.
If any failure was found, they would assign a violation and move on to R4 to look for evidence of
corrective action following the occurrence. If none were found, a second violation would be assigned.
3) We suggest: “R3. Each Distribution Provider and Generator Operator shall develop and implement,
in a manner that identifies, assesses and corrects deficiencies, documented communication protocols
that outline the communications expectations for receipt of Operating Instructions and Reliability
Directives by its operators,” and that R4 be removed.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
No
No
This standard is becoming overly complicated. The reason this COM standard is being developed is to
reduce the possibility of miscommunication of information when the BES is being altered. This
proposed standard is an administrative burden. Operators will be fearful that they will cause a NERC
Compliance Violation every time they communicate. Their focus will be on communicating compliantly
and not on operating the BES. Consideration should be given to simplifying this standard. Below is an
unrefined proposal for consideration: R1: Applicable REs shall have a procedure that requires its
personnel (whether as a receiver or as an initiator) to use three-part communication when altering
the state of the BES. Three-part communication is defined as when an initiator issues a command, the
receiver repeats the command back, and the initiator confirms. Any misunderstandings are resolved
during the repeat back. (3-part communication is the only proven way to mitigate miscommunication.
If personnel use three way communication then all issues related to alpha-numeric clarifiers, time, etc
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should be resolved naturally during the repeat back/confirmation. Additionally, this requires operators
and field personnel to remember one thing: when changing the state of the BES they must use 3-part
communication.) R2: Each calendar month REs required to comply with R1 shall assess a random
sample of communications that occurred over the month to ensure that three-way communication
was properly being utilized, when the BES was being altered. In instances where deficiencies are
found, REs shall require remedial training to be completed by the individuals involved in the deficient
communication. (Remedial training will act as a deterrent for those who get lazy about using threepart communication. Additionally, peers will be aware of who had to undergo remedial training, which
will further act as deterrent. Requiring remedial training would be an incentive to using three-part
communication properly)
Individual
Brenda Frazer
Edison Mission Marketing & Trading
Yes
No
No
EMMT agrees with the concepts put forth in COM-003, but have some concerns, particularly with the
proposed administrative burden associated with the Standard. EMMT offers the following comments:
1. R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP
communication protocols; this could result in a TOP having to coordinate with a hundred+ different
entities communications protocols. This coordination would not improve reliability, but only serve to
create confusion and significant communication time delays in real-time operations. Both R1 and R4
create significant documentation and administrative burdens, without providing a comparable
improvement to the reliability of the BES. As reliability based Standard, COM-003 should focus on
those actions that would have a direct impact on reliability, while minimizing the administrative
burden. 2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They
only receive instructions from others. GOPs should have a communications procedure as part of their
operations, however, the methods used are properly business decisions made by the GOP. The
content, thoroughness and effectiveness of a communications plan are excellent items to consider
when assessing an entity’s internal compliance program. 3. R4 raises the question of sufficiency of an
entities corrective program. The RSAW requires the GO to turn over records of monitoring
communications as well as records of corrective actions and then prove the “problem” is not still in
place. This standard could easily turn into a high-profile audit target due to the varying concepts of
what does and does not constitute a sufficient corrective action program. 4. EMMT recommends that
the language to M4 be changed as follows: M4. Each Distribution Provider and Generator Operator
shall provide the results of its periodic assessment and of any corrective actions (if any corrective
actions were implemented) developed for Requirement R4. Examples of sufficient periodic assessment
programs include, but are not limited to, the following: Documented review of voice logs for a total of
at least one hour per calendar year for each operator (does not need to be a single session)
Documented personal monitoring of communications for a total of at least one hour per calendar year
for each operator (does not need to be a single session) Documented annual training Examples of
sufficient corrective action programs include, but are not limited to, the following: Documented
refresher training Documented meeting Documented “hot box” communication 5. The VSLs give a
higher violation to a GOP than a BA for exactly the same error, even though the consequences with
the BA are much greater. A GOP who fails to require 3-part responses when requested is tagged with
a Moderate violation, while the BA would receive a Lower. 6. In the RSAW, the following passage
should be expunged; “Where practicable, verify that deficient communication practice was indeed
corrected by reviewing evidence of Operator communications (such as voice recordings) occurring
after the date of the corrective action to determine if deficient communication practice was
corrected.” Differentiating between slips of the tongue and “deficient communication practices”
involves subjective judgments. The same is true for attempting to identify changes in an operator’s
degree of understanding, especially when doing so through the numbing process of making before-
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and-after voice recording comparisons. This is an open-ended matter that could very quickly become
an unreasonable compliance burden. RSAWs in general should not introduce new requirements,
measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Group
ISO/RTO Standards Review Committee
Albert DiCaprio
PJM
No
No
The SRC recognizes and commends the Drafting Team’s efforts to respond to Industry comments and
to offer a revised pragmatic solution for this Project. The proposed changes do not create a common
results-based standard that addresses let alone resolves any identified reliability problem. The SRC is
concerned that the posting as proposed the standard creates a fill-in-the-blanks solution that could
discourage a functional entity from employing anything more than a least common denominator
solution. Technically the definition and proposal are improvements and the SRC would agree with the
proposed changes, if the definition and proposal were needed. The issue is with the need for this
definition, and the continuing debate this definition is generating. The SRC is opposed to having this
term defined and added to the NERC Glossary. The term operating instruction does not need to be
defined. For years, system operators deal with operating instructions on a daily if not minute-tominute basis. Having a defined term, and calling such communication as “Command” is unnecessary,
and potentially could confuse operators from what they understand to be the meaning of operating
instructions. While the SDT has found that their previous definitions were not appropriate for a NERC
standard, and the subsequent incremental changes are useful, the debate itself does not seem to be a
productive use of the SDT’s or the Industry’s time. The SRC would prefer that the objectives of the
SAR (communications protocols) be handled through means other than a Standard (e.g. the
Operating Committee’s Reliability Guidelines on Communications). The reason being, a standard
requires zero-defect compliance, data retention, self-reporting, and requires these debates over the
proposed terms such as “Operating instruction” which diverts the Industry, NERC and the Regional
Entities from focusing on more productive reliability issues. The proposed RSAW wording must be
more objective as the current test contains too many subjective requirements: Page 3 • “…
Identification of instances …” – will this be viewed as identification of every instance or will one
instance be sufficient? • “…when….necessary…” – who decides when there is a necessity? The auditor
or the functional entity? Page 4 • “…may include…” – this phraseology may be seen as meaning the
listed following items are among the items that are required but are themselves insufficient to meet
the requirement. Page 5 • “…reviews of System Operator voice recordings…: - it should be made clear
that the “review” is of the sampled recordings used by the entity in its own self-assessments, and not
a “review” of any voice recording. • “Where practicable” is subjective and inappropriate for a
standard. To avoid confusion and misapplication of the standard, the RSAW should include a
statement that messaging systems are not oral communication and not evaluated under the standard.
Group
ACES Standards Collaborators
Ben Engelby
ACES
Yes
(1) We appreciate the efforts of the drafting team in developing this standard and the steps the team
took to resolve industry’s concerns. (2) We continue to have concerns that the glossary term
“Operating Instruction” overlaps with “Reliability Directive.” The standard as written allows flexibility
on how to deal with these two terms/situations and gives the registered entity the responsibility to
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handle these types of communications in its protocol. Because of the flexibility and in the spirit of
moving forward, we can support the approach by the drafting team that would allow NERC to address
FERC concerns. This represents a good balance.
Yes
(1) We appreciate the drafting team allowing the registered entity to have the flexibility in
determining the assessment methods and corrective actions to implement. Further, we appreciate
that the measures for these requirements state that the assessment should be “periodic” but do not
impose any strict timeline. We recommend that the RSAW state the same or similar language, as the
entity should be able to dictate how often the assessments occur in their protocols, policies, and
procedures.
No
(1) There are a few changes that need to be made in the severe VSLs for R1 and R3. The severe VSL
states, “The Responsible Entity did not implement any documented communication protocols as
required in Requirement R1.” This statement is in direct conflict with the lower, medium and high
VSLs because if an entity violated at least one documented communication protocol (low VSL), or two
protocols (medium VSL), or three protocols (high VSL), then the entity violated “any.” We
recommend striking the statement in the severe VSL to avoid this conflict.
(1) The sub-parts of the protocols have grammatical errors, where the sub-parts do not correlate to
the lead-in sentence. We recommend replacing the phrase “Require the recipient/receiver…” that is
stated in sub-parts 1.6, 1.8, 3.2 and 3.3 with “Instances in which the recipient/receiver is required
to…” in order to maintain consistency throughout the standard. Leaving these sections as mandates
(verb phrases) could confuse auditors into thinking that these are zero defect requirements.
Individual
Scott Berry
Indiana Municipal Power Agency
No
The COM-003-1 standard needs to an independent document used to audit entities and the RSAW
should not be used to address items not covered in the standard as to what is acceptable and what is
not acceptable when it comes to instances when three-part communication is not properly followed by
an entity during an audit. IMPA is concerned that an entity has one instance of a missed repeat back
and per the entity’s plan they address it and re-train for it; NERC could still call it a violation. The
standard language needs to be clear about the latitude that an entity is given to work things out
within their internal controls. The main item that the standard should do is to make sure that entities
have communication plans and their internal controls within the communication plans contain a
process to monitor and self-deal with corrective action of instances where its communication plan was
not properly followed. This language needs to be clearly stated in the standard and not somewhat
stated in the RSAW. IMPA believes the prior version of this draft standard was close when it used
language on internal controls that stated “implement, in a manner that identifies, assesses, and
corrects deficiencies…”.
IMPA believes there is a conflict between COM-003-1 and COM-002-3 when it comes to how an entity
replies back to an “All Call”. COM-003-1 does not require three part communication and it seems that
COM-002-3 does require it. This creates confusion and needs to be corrected. IMPA supports the use
of one communication standard to address proper communication protocols for Directives and
Operating Instructions. This could be accomplished by retiring COM-002-3 upon the implementation
of COM-003-1.
Individual
Anthony Jablonski
ReliabiltyFirst
No
ReliabilityFirst abstains and offers the following comments for consideration: 1. Requirement R1 and
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Requirement R3 - ReliabilityFirst questions the reasoning behind the term “where applicable” in the
last sentence of Requirement R1 and Requirement R3. Can the SDT provide examples when there
would be instances where an Entity would not need to address a sub-part within their documented
communication protocols? ReliabilityFirst believes all sub-parts under Requirement R1 and
Requirement R3 should be addressed within the respected protocols. 2.Requirement R1, Part 1.9 ReliabilityFirst does not believe it is appropriate for Requirement R1, Part 1.9 to be addressed within
the documented communication protocols. It is unclear how an entity would address “coordination” of
its protocol within the protocol itself. ReliabilityFirst does agree with the concept of having the
responsible entities be aware of each other’s communication protocols and thus recommend elevating
this to a stand-alone requirement. ReliabilityFirst recommends the following for consideration as a
new R3, “Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall make
available its documented communication protocols that outline the communications expectations of its
System Operators.”
No
ReliabilityFirst abstains and offers the following comments for consideration: 1. Requirement R2 ReliabilityFirst believes the concept of implementation of the method(s) to assess System Operators’
communication should be added to the requirement. If the Entity is not required to implement the
method(s), an Entity may never find any deficiencies and get to the point of implementing the
corrective actions necessary to meet the expectations in its documented communication protocols.
ReliabilityFirst recommends the following for consideration, “Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall develop and implement method(s) to assess System
Operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols developed for Requirement R1.” 2.
Requirement R4 - Similar to the comment on Requirement R2, ReliabilityFirst believes the concept of
implementation of the method(s) to assess System Operators’ communication should be added to the
requirement. ReliabilityFirst recommends the following for consideration, “Each Distribution Provider
and Generator Operator shall develop and implement method(s) to assess operators’ communication
practices and implement corrective actions necessary to meet the expectations in its documented
communication protocols developed for Requirement R3.”
No
1. VSL for Requirement R1 - In order to capture instances where more than three parts were not
addressed, the second VSL under the “High” category needs to be modified to state, “…did not
implement three (3) or more of the nine (9) parts of…” 2. VSL for Requirement R2 - ReliabilityFirst
recommends including a lower bounds around the “Medium VSL”. As written, an entity would fall into
the Medium VSL range if they only implemented 1% or implemented 49% of the corrective actions.
ReliabilityFirst recommends gradating the VSLs using 25% increments across all four VSLs. 3. VSL for
Requirement R4 - ReliabilityFirst recommends including a lower bounds around the “Medium VSL”. As
written, an entity would fall into the Medium VSL range if they only implemented 1% or implemented
49% of the corrective actions. ReliabilityFirst recommends gradating the VSLs using 25% increments
across all four VSLs.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
LG&E and KU Services
These comments are submitted on behalf of the following PPL Companies: Louisville Gas and Electric
Company and Kentucky Utilities Company; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; and
PPL Generation, LLC, on behalf of its NERC registered subsidiaries. The PPL Companies are registered
in six regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC
functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP The PPL Companies believe
that the revised COM-003 standard represents an improvement over previous drafts. Nevertheless,
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we have one concern with the proposed standard and urge the Standard Drafting Team to add the
following note to Requirements 1.7, 1.8, and 3.3 in the standard before it is submitted to NERC and
FERC for their approval: Notwithstanding anything in COM-002, the requirements set forth in COM003 Requirements R1.7, R1.8 and R3.3 shall govern the manner for responding to Reliability
Directives that are issued through one-way burst messages (e.g., an All Call system).
Individual
Kathleen Goodman
ISO New England Inc.
No
No
We do not believe a Standard is needed, given other developments: A. The SDT materials have not
demonstrated the reliability gap/need for this Standard. Without having a better sense of what the
scope of the actual reliability risks are (frequency, impact, etc…), it’s difficult to know if the proposed
solution – as embodied in COM-003 Draft Version 5 – is “necessary to provide for reliable operation of
the bulk-power system”. B. Moreover, the Requirements that the recipient repeat, restate, etc., if
required/requested by the issuer (1.6 & 3.2) suggest that a RC, BA or TOP needs to ensure a repeat
back or be non-compliant even though taking this extra time may, in fact, impact reliability. C. Lastly,
the fact that the Ballot Body and Standard Drafting Team continue to have so many questions about
how to interpret these requirements (see the recently issued FAQs) suggests: (a) that the Operating
Committee would serve as a more effective forum for discussing what additional communication
practices, if any, are needed, and (b) the requirements themselves may be unduly ambiguous. Proposed Solution: We support strengthening communications protocols such as contained in the
pending COM-002 revisions and in the OC White Paper. NERC Event Analysis Staff should work with
the NERC OC to document the reported risks to the system, continue to monitor system operator
performance, and periodically report on findings. If, however, it is determined that the Standard will
move forward, then we would offer the following suggestions: A. We consider use of one-way burst
messaging systems to be electronic and, as such, do not believe they should be included in the
Standard. Further, in accordance with 1.5, a one-way burst messaging system is not a “oral two
party, person-to-person Operating Instruction,” which would further justify its exclusion. B. Draft
Version 5’s Requirements establish that each covered registered Entity shall develop its own
communication protocol outlining the communications expectations of its operators. This has the
potential for confusion as multiple Registered Entities within a single RC, BA or TOPs’ footprint may
establish different communication expectations. - Proposed Solution: The Requirements should
establish that if the RC, BA or TOP establish a communication protocol for their System Operators, the
RC, BA or TOP should share that protocol with Registered Entities operating within their footprint,
those Registered Entities must follow the RC, BA or TOP’s protocol, or adopt a consistent one for their
company C. We agree with the SDT that the COM Standard need not employ a “zero tolerance/zero
defect” approach, because NERC Enforcement need not monitor and assess every Operator-toOperator communication. In Draft Version 5 (Measurements & RSAW), NERC, however, appears to
adopt an approach of establishing “zero tolerance” around a Company’s Internal Controls program.
The RSAW states that registered entities must provide “evidence that corrective actions necessary to
meet the expectations in its documented communication protocols… are taken” and “deficient
communication practice was indeed corrected.” - This type of approach to Standard drafting raises
untested questions of how the Standard will be enforced, whether it is a “fill-in-the-blank”-type
Standard, and whether a new “zero tolerance” enforcement approach to monitoring will, in fact, be
maintained. - Proposed solution: Draft a Standard that sets performance based expectations and
allow the ERO to use its enforcement discretion (e.g., through FFT and through review of internal
control programs) to determine how stringently to audit and sanction.
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency
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No
FMPA prefers the prior version which had language on internal controls, e.g., “implement, in a manner
that identifies, assesses and corrects deficiencies …”. As stated, and by using the word “implement”
which means: “carry out, accomplish; especially : to give practical effect to and ensure of actual
fulfillment by concrete measures”, means that each entity must have evidence (“concrete measures”)
of implementing its communications protocol at all times for every instance. Three part
communication is watered-down by giving the entity the choice as to whether to follow three-part
communication for: 1) all Operating Instructions; 2) for Reliability Directives only; or 3) something in
between. Many entities, to manage compliance risk, will only require three-part communications for
Reliability Directives in their communication protocols as a result. For reliability reasons, FMPA
believes that three-part communication ought to be required for all Operating Instructions, but, at the
same time, there should be some tolerance for mistakes through use of the CIP v5 internal controls
language “implement, in a manner that identifies, assesses and corrects deficiencies …”.
No
Use of the term “System Operators’” is ambiguous; does the requirement cause internal evaluation,
or evaluation of neighboring System Operators? We assume the former and suggest adding “its” in
front of “System Operators”.
As commented on several times previously, FMPA will not vote Affirmative (or recommend an
Affirmative vote) until the inconsistencies of COM-003-1 and COM-002-3 concerning Reliability
Directives are resolved. For a Reliability Directive delivered by an “All Call”, COM-003-1 does not
require three part communication whereas COM-002-3 does. This inconsistency will only be a source
of confusion during the very time when rapid response to communication is needed, which causes us
to be concerned for reliability. FMPA continues to recommend retiring COM-002-3 as part of the
implementation plan of COM-003-1 and fails to see a good reason not to do so. All that would need to
be done is to retain the definition of Reliability Directive and include R1 of COM-002-3 into COM-0031, and a slight modification to 1.5 of COM-003-1 to require confirmation of a Reliability Directive.
Individual
Marie Knox
MISO
Yes
While MISO is not opposed to the current version of COM-003-1, it remains concerned regarding the
overlap between COM-002-3 and COM-003-1. As written, the definition of “operating instruction”
encompasses “reliability directives”. This overlap and the application of multiple separate standards to
operator communications in general is likely to result in ambiguity and confusion. Further, that only
certain sub-requirements of COM-003-1 also mention reliability directives further confuses the
applicability of these standards. While the identified overlap and application is manageable, it is
recommended that this overlap be addressed at the earliest opportunity. One clear, succinct standard
that addresses both operator communications, whether reliability directives or operating instructions,
is respectfully recommended.
Yes
We believe the drafting team found a very reasonable solution to meet a FERC directive for a situation
that deals with managing the quality of the millions of operator communications that occur annually.
Yes
To avoid confusion and misapplication of the standard, the RSAW should include a statement that
electronic messaging systems are not subject to compliance with this standard.
Individual
James R. Keller
Wisconsin Electric Power Company
Agree
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Edison Electric Institute
Group
Southern Company - Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Pamela R. Hunter
Southern Company Operations Compliance
No
Southern Company agrees with the new definition. Southern Company believes that Requirements R3
and R4 should be deleted. A. Southern Company believes that Requirements R3 and R4 (applicable to
Distribution Providers (“DPs”) and Generator Operators (“GOPs”)) should be deleted from the
proposed COM-003 standard because the burdens placed on Balancing Authorities (“BAs”), Reliability
Coordinators (“RCs”) and Transmission Operators (“TOPs”) by Requirements R1 and R2: (a)
sufficiently tighten communications protocols with DPs and GOPs, (b) render Requirements R3 and R4
administrative, unnecessary, and redundant, counter to FERC’s objectives as implemented by the
NERC Paragraph 81 Task Force, and (c) potentially expose some Registered Entities to double
jeopardy violations of COM-003-1. Specifically, Requirement R1 provides that BAs, RCs, and TOPs
must develop and implement documented communication protocols that (a) address instances where
the issuer of an oral two-party communication Operating Instruction is required to confirm that the DP
or GOP recipient’s response was accurate or to reissue the Operating Instruction to resolve the
misunderstanding (R1.5); and (b) to address coordination with affected DPs’ and GOPs’
communication protocols (R1.9). Requirement R2 further requires BAs, RCs, and TOPs to develop
methods that assess communication practices and implement corrective actions necessary to meet
the expectations outlined in these same protocols. Note that this assessment method would
necessarily include assessment of the expectations included in the protocols regarding DPs and GOPs
as required by R1.5 and R1.9. Meanwhile, proposed Requirement R3 would require the recipient DPs
and GOPs to develop their own documented communications protocols that outline the communication
expectations already addressed in the R1 protocols. [Note that the Rationale and Technical
Justification for COM-003-1 specifies that Requirements R1 and R2 are addressed to entities that both
issue and receive Operating instructions (BAs, RCs, and TOPs) whereas Requirements R3 and R4 are
addressed to entities that only receive Operating Instructions.] Requiring DPs and GOPs in R3 to
develop protocols outlining the communications expectations of its operators -- and requiring DPs and
GOPs in R4 to assess those same operators’ communications practices and implement corrective
actions -- is redundant and unnecessary when those same expectations are already being
documented by BAs, RCs, and TOPs in the R1 protocols, are already being coordinated with DPs and
GOPs under R1.9, and are already being assessed and corrected by the BAs, RCs, and TOPs as
required by R2. Therefore, requiring DPs and GOPs to go through the same motions simply creates
another layer of documentation that strains limited resources and does little to enhance the reliability
of the Bulk Electric System. B. These duplicative exercises created by Requirements R3 and R4 run
counter to the objectives directed by FERC in Paragraph 81 of FERC’s March 15, 2012 Order on
NERC’s proposed “Find, Fix, and Track” (“FFT”) initiatives (“FFT Order”) as implemented by the P 81
Task Force. In Paragraph 81 of the FFT Order, FERC noted that “some current requirements likely
provide little protection for Bulk-Power System reliability or may be redundant.” In complying with
FERC’s directives, the Paragraph 81 Task Force set out to identify standards that (a) do “little if
anything, to benefit or protect the reliable operation of the BES” and (b) among other possible
criteria, are either: “(a) Administrative in nature, do not support reliability, and are needlessly
burdensome; or (b) Require responsible entities to develop documents that are not necessary to
protect BES reliability; or (c) Impose documentation updating requirements that are out of sync with
the actual BES operations, unnecessary, or duplicative; or (d) Redundant with another FERCapproved Reliability Standard requirement(s), the ERO compliance and monitoring program, or a
governmental regulation.” (See Paragraph 81 Task Force Technical White Paper.) With respect to this
last criterion of redundancy, the Task Force specifically stated that it is “designed to identify
requirements that are redundant with other requirements and are therefore unnecessary. Unlike the
other criteria listed … in the case of redundancy, the task or activity itself may contribute to a reliable
BES, but it is not necessary to have two duplicative requirements on the same or similar task or
activity.” (emphasis added). By creating duplicative requirements on both ends of a coordinated
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communication scheme between issuing BAs/RCs/TOPs and recipient DPs/GOPs, the Standards
Drafting Team is creating an unnecessary administrative burden that does “little, if anything, to
benefit or protect the reliable operation of the BES.” Even if it may be argued that requiring double
coordination from both issuer and recipient somehow contributes to a reliable BES, “it is not
necessary to have the two duplicative requirements on the same or similar task or activity.” Proposed
Requirements R3 and R4 would fit all of the criteria listed above that the Paragraph 81 Task Force is
using to identify candidates for retirement and/or revision. C. Finally, the risk created by proposed
Requirements R3 and R4 in conjunction with R1 and R2 is more than simple administrative
duplication. For vertically integrated entities that are registered both as issuing BAs/RC/TOPs and
recipient DPs/GOPs, the redundancy created by Requirement R3 and R4 could potentially expose
them to double penalties for a single violation. Because of the duplicative documentation and
coordination requirements in R1/R2 and R3/R4, an auditor could interpret a single instance where the
communications protocol of an issuing BA/RC/TOP did not match up with the recipient DP/GOP as
multiple violations. In such an instance, both the issuers and the recipients could conceivably be
penalized because the issuer’s communications protocols were not coordinated with the recipient’s
communications protocols and this lack of coordination was not assessed and remedied. If the
Standards Drafting Team chooses not to delete Requirements R3 and R4, then Southern suggests
that the following rewording of R3 and R4 would be beneficial. If the Standards Draft Team does not
delete Requirement R3 and R4 in their entirety, then Southern suggests that R3 and R4 be reworded
such that the entities work together to implement and coordinate one set of issuers’ communications
protocols (i.e., that of the BAs/RCs/TOPs) instead of two sets of both issuers’ and recipients’
protocols. This should help to “tighten” the communications protocols as directed in Order 693 and to
mitigate some of the confusion and duplicative documentation that could arise from Requirements R3
and R4 as written: “R3. Each Distribution Provider and Generator Operator shall implement the
documented communication protocols of its associated BA, RC, and TOP that define the
communications expectations of R1. The documented communication protocols will address, where
applicable, the following: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning ] ….” and
“R4. Each Distribution Provider and Generator Operator shall develop method(s) to assess its
communications practices and implement corrective actions necessary to meet the expectations in the
documented communications protocols developed for Requirement R1.” Conforming revisions would
also need to be made to the language in the Measures, VRFs, and VSLs as applicable.
No
See Southern’s comments above regarding deletion and/or modification of R4. If R4 was not part of
this question then Southern’s answer would change to yes for this question. Additionally, GOPs do not
issue Operating Instructions. They only receive instructions from others. GOPs should have a
communications procedure as part of their operations. However, the methods used are proper
business decisions made by the GOP. The content, thoroughness and effectiveness of a
communications plan are excellent items to consider when assessing an internal compliance program.
No
We agree with the VRFs and VSLs for R1 and R2. As discussed above, R3 and R4 should not be part of
the standard. To the extent R3 and R4 should be deleted or modified, the VRFs and VSLs should be
modified accordingly.
See Southern’s comments for R3 and R4 in the RSAW comments regarding use of the terms
“Operator” and “operator”. If Requirements R3 and R4 are neither deleted nor reworded as suggested
above, then changes should be made in either the standard or the RSAW to make the two terms
consistent and to clearly define the term “operator” if necessary.
Individual
Brett Holland
Kansas City Power & Light
Agree
Southwest Power Pool
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
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No
We suggest adding 'as determined by the Functional Entity' to R1 to clarify that the protocols are
those specifically determined by the applicable responsible entity: 'The documented communication
protocols will address, where applicable as determined by the Functional Entity, the following:' Is the
intent of R1.3 for applicable entities to maintain a list of common name identifiers which must be
utilized in communications with all affected entities? If so, a similar requirement (R18) in TOP-002-2
is currently proposed to be eliminated in TOP-002-3. Therefore it shouldn’t be added back by this
requirement. Can the drafting team be more specific as to exactly what is required in R1.3 without
going overboard as in the existing wording? We understand the need to be sure that affected entities
do not have any misunderstandings regarding the specific facility that is at issue. However, our
experience does not indicate that this is a problem. If we can’t relax R1.3, we suggest eliminating it
altogether. The use of the term ‘coordination’ in R1.9 causes concern in determining exactly what is
required to coordinate. This could become a compliance nightmare for applicable entities. We suggest
replacing R1.9 with “Provide each affected Reliability Coordinator, Balancing Authority, Transmission
Operator, Distribution Provider, and Generator Operator with its communication protocols.“
No
We have concerns with the continued inclusion of Distribution Provider in the list of Applicable
Entities. Although this is in response to a FERC directive, the risk that Distribution Providers present
to the BES is minimal at best. Actions taken by Distribution Providers which impact the reliability of
the BES, load shedding for example, are adequately covered under COM-002-3 which applies to
emergency situations. There are also jurisdictional questions associated with FERC directing the
inclusion of Distribution Providers. If the Distribution Provider must remain as an Applicable Entity,
then we would propose deleting Distribution Provider from R3 and R4 and then follow with the
addition of a new R5 and R6. R5. Each Distribution Provider that is the recipient of an oral Operating
Instruction, other than Reliability Directives, shall: 5.1 Use the English language, unless another
language is mandated by law or regulation. 5.2 Repeat, restate, rephrase, or recapitulate the oral
Operating Instruction. 5.3 For oral Operating Instructions issued as a one-way burst message to
multiple parties in a short time period (e.g. an All Call system), request clarification from the issuer if
the communication is not understood. R6. Each Distribution Provider shall develop method(s) to
assess operators’ communication practices and implement corrective actions necessary to meet the
expectations in Requirement R5.
No
While we understand the process that gets us to the point where the VRFs for R1 and R3 are Low and
those for R2 and R4 are Medium, in this situation we question the logic of the process. If developing a
document only deserves a low VRF then how can we logically say that not implementing the items
contained in the document is a medium? What happens if the document is flawed? This appears to be
an inverted pyramid. We suggest using Low for all requirements.
Our comments are listed with the specific question they address.
Individual
Larry Watt
Lakeland Electric
Agree
LAK supports FMPA comments
Individual
Andrew Z. Pusztai
American Tranmission Company
Yes
Yes
Yes
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Requirement 1.9 requires “Coordination with affected Reliability Coordinators’, Balancing Authorities’,
Transmission Operators’, Distribution Providers’, and Generator Operators’ communication protocols.”
This requirement seems unnecessary since the requirements of COM-3-1 apply to all these entities. If
everyone is adhering to the requirements of COM-3-1 then the need for coordination is redundant as
it becomes automatic. If individual entities adopt slight nuances to this requirement, or are more
restrictive then the requirement then coordination between every entity becomes extremely difficult.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Agree
Florida Municipal Power Agency
Group
Santee Cooper
Terry L. Blackwell
SC Public Service Authority
The latest version of COM-003 introduces a potential conflict with COM-002 related to use of one-way
burst messaging systems to issue a Reliability Directive. COM-002 does not allow for only those
responses required in COM-003 but instead requires a full 3 way communication from all parties. This
potentially sets up both the issuer and receiver for violating COM-002 if they respond to a one-way
burst messaging RD as the requirements indicate in COM-003. In COM-003, the follow Requirements
are included: R1.7 Instances where the issuer of an oral Operating Instruction or Reliability Directive
using a one-way burst messaging system to communicate a common message to multiple parties in a
short time period (e.g. an All Call system) is required to verbally or electronically confirm receipt from
at least one receiving party. R1.8 Require the receiver of an oral Operating Instruction or Reliability
Directive using a one-way burst messaging system to communicate a common message to multiple
parties in a short time period (e.g. an All Call system) to request clarification from the issuer if the
communication is not understood. R3.3 Require the receiver of an oral Operating Instruction or
Reliability Directive using a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request clarification from the issuer
if the communication is not understood. In other words, COM-003 allows one-way burst messaging to
be used for Reliability Directives and prescribes: • issuer to confirm receipt from at least one receiving
party • receiver to request clarification from the issuer if the communication is not understood
Individual
Mike Hirst
Cogentrix Energy Power Management
No
No
No
Regarding question #1, the SERC OC Review Group agrees with the definition of Operating
Instruction. While we also can agree to the changes made to R1, we feel R3 in its entirety is
unnecessary and duplicative. Removal of the word “develop” would eliminate double-jeopardy
concerns. R3 could be acceptable if “develop and” are omitted and “as developed in R1” is inserted
after “protocols” and before “that.” It should be noted that this suggestion only applies to the subrequirements in R1 that correspond to the proposed sub-requirements in R3. Regarding question #2,
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R2 is acceptable and R4, as stated above for R3, is unnecessary and duplicative. Regarding question
#3, we agree with the VRFs and VSLs for R1 and R2. Based on our previous comments, we do not
agree with the need for R3 and R4, and therefore VRFs and VSLs for these requirements are not
needed. 1. R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP
communication protocols; this could result in a TOP having to coordinate with a hundred+ different
entities communications protocols. This coordination would not improve reliability, but only serve to
create confusion and significant communication time delays in real-time operations. Both R1 and R4
create significant documentation and administrative burdens, without providing a comparable
improvement to the reliability of the BES. As reliability based Standard, COM-003 should focus on
those actions that would have a direct impact on reliability, while minimizing the administrative
burden. 2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They
only receive instructions from others. GOPs should have a communications procedure as part of their
operations, however, the methods used are properly business decisions made by the GOP. The
content, thoroughness and effectiveness of a communications plan are excellent items to consider
when assessing an entity’s internal compliance program. 3. R4 raises the question of sufficiency of an
entities corrective program. The RSAW requires the GO to turn over records of monitoring
communications as well as records of corrective actions and then prove the “problem” is not still in
place. This standard could easily turn into a high-profile audit target due to the varying concepts of
what does and does not constitute a sufficient corrective action program. 4. The SRT recommends
that the language to M4 be changed as follows: M4. Each Distribution Provider and Generator
Operator shall provide the results of its periodic assessment and of any corrective actions (if any
corrective actions were implemented) developed for Requirement R4. Examples of sufficient periodic
assessment programs include, but are not limited to, the following: Documented review of voice logs
for a total of at least one hour per calendar year for each operator (does not need to be a single
session) Documented personal monitoring of communications for a total of at least one hour per
calendar year for each operator (does not need to be a single session) Documented annual training
Examples of sufficient corrective action programs include, but are not limited to, the following:
Documented refresher training Documented meeting Documented “hot box” communication 5. The
VSLs give a higher violation to a GOP than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GOP who fails to require 3-part responses when
requested is tagged with a Moderate violation, while the BA would receive a Lower. 6. In the RSAW,
the following passage should be expunged; “Where practicable, verify that deficient communication
practice was indeed corrected by reviewing evidence of Operator communications (such as voice
recordings) occurring after the date of the corrective action to determine if deficient communication
practice was corrected.” Differentiating between slips of the tongue and “deficient communication
practices” involves subjective judgments. The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of making
before-and-after voice recording comparisons. This is an open-ended matter that could very quickly
become an unreasonable compliance burden. RSAWs in general should not introduce new
requirements, measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Group
Pacific Gas and Electric Company
Glenn Rounds
Pacific Gas and Electric Company
Yes
Yes
Yes
Draft 5 fails to address all of the communication gaps identified in the Standards Authorization
Request (SAR), FERC Order 693 and the recommendations of the August 2003 Blackout Report. The
draft as written does not require a consistent application of effective communications protocols but in
turn requires each functional entity to develop their own protocols with insufficient guidance on how
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to achieve better consistency.
Individual
Keith Morisette
Tacoma Power
No
Tacoma Power supports and strongly suggests reverting back to the Draft 2 definition, “Operating
Communication — Communication of instruction to change or maintain the state, status, output, or
input of an Element or Facility of the Bulk Electric System.”
No
Tacoma Power supports Draft 2 - The requirement to establish communication protocols should be
identical for BA, TO, RC, GO, and DP. To make different requirements for different functions is very
confusing for those who perform multiple functions. Go back to basic “3-part communication” (and
include an option for push-to talk). Remove fuzzy language such as “if requested”. The Standard
should leave it up to the Entity to establish their communication protocols and procedures based upon
the type of communication systems they are using. This draft seems to trying to write the procedures
for every type of possible communication equipment rather than set a standard for how to
communicate.
No
Tacoma Power believes the Standard Drafting Team made Draft 5 overly complex and confusing for
the System Operators and Operators to use. The Drafting Team needs to go back to the basics. The
standard should apply to all, BA, TO, RC, GO and DPs alike. 1. Require all parties to develop
Communication Protocols, train their operating personnel to use them, review their protocols annually
and make improvements if necessary. 2. Require all parties to use “3-part communication” and forget
the “oral two-party, person-to-person Operating Instruction” that has different requirements for GO
and DP. All responsible entities should have the same requirements. The proposed Standard as
written allows for the Instruction to be repeated back “if requested” by the issuer. This exception
creates a “compliance” trap for the people communicating – remove it. BASIC 3-PART
COMMUNICATION should include: * A System Operator or Operator shall issue an Operating
Instruction * The person receiving the Operating Instruction shall repeat it back to the issuer, and/or
request clarification if needed * The System Operator or Operator will acknowledge as correct and/or
discuss clarifications as needed and agree on the final instruction. 3. We are not sure why “address
nomenclature for Transmission interface Elements and Transmission interface Facilities” has replaced
the term “common line identifiers.” Entities should coordinate their communication protocols with the
other Entities that they commonly communicate with and agree on: * Nomenclature for Lines and
equipment * A common system for Alpha Numeric clarifiers * Use 24-hour clock and identify the time,
time-zone and if day-light savings or standard time is in effect. System Operators and Operators are
too busy to be put in the position of trying to maintain compliance with a standard that is so
convoluted and confusing as to become a potential violation. Tacoma Power supports the original
premise of the proposed COM-003 and the concept to separate the technical communication
equipment requirements from communication protocol requirements but the drafting team has gone
too far away from the intent of the standard by trying to make exceptions for too many different
issues when they do not need to. Get back to the basics, i.e. Draft 2.
Individual
Gregory Campoli
NYISO
The text presented in the blue box for Requirement 1 should be incorporated into Requirement #1. If
the requirement needs to be explained at this point, we recommend clarifying it in the text. In
addition, by using this definition we have now introduced a list of controls that we will be audited
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against. The requirement should simply be to have a procedure. The controls assessment can be
addressed during the future RAI process. The current draft provides for a fill in the blank framework
that allows for an entity to define what is applicable for its communication protocol. A better approach
would be to state that an entity may include items from the list provided that the entity identifies
them as critical. Then the entity would only be required to show what is critical to its operations,
rather than having to prove what is not critical. The language in requirement 1.5 needs to be clarified.
It is not clear on how an entity is required to ‘confirm’ the response was accurate. This could simply
be a ‘2 part communication’, where once the receiving entity repeats the instruction, the initiator may
move on if he deems it correct. Or does the confirmation need to be ‘confirmed’ with the receiving
party as in ‘3 part communications’? If the requirement is meant to initiate 2 part communication, the
requirement should say that. If the requirement is meant for ‘3 part communication,’ then we
recommend utilizing the language from COM-002 R2 in place of Requirements 1.5 and 1.6.
Individual
Jason Snodgrass
Georgia Transmission Corporation
No
Georgia Transmission Corporation agrees with the new definition. Georgia Transmission Corporation
believes that Requirements R3 and R4 should be deleted. A. Georgia Transmission Corporation does
not agree with the use of the term “operators” with respect to the functional entity Distribution
Providers for R3 and R4. This poses an incomprehensible requirement for non-vertically integrated
entities that are registered as Transmission Owner’s also serving as the DPs. NERC does not define or
associate anywhere in the Functional Model or NERC registry the term Distribution Provider operator.
Specifically, GTC would not understand how to comply with R3 or R4 because GTC does not have any
operators yet we are registered as a DP for the functions we perform of our facilities which are
directly connected to the BES. GTC believes that Requirements R3 and R4 (applicable to Distribution
Providers (“DPs”)) should be deleted from the proposed COM-003 standard, or else disassociate the
term “operators” from the DP. B. Additionally, Georgia Transmission Corporation believes that
Requirements R3 and R4 (applicable to Distribution Providers (“DPs”) and Generator Operators
(“GOPs”)) should be deleted from the proposed COM-003 standard because the burdens placed on
Balancing Authorities (“BAs”), Reliability Coordinators (“RCs”) and Transmission Operators (“TOPs”)
by Requirements R1 and R2: (a) sufficiently tighten communications protocols with DPs and GOPs, (b)
render Requirements R3 and R4 administrative, unnecessary, and redundant, counter to FERC’s
objectives as implemented by the NERC Paragraph 81 Task Force, and (c) potentially expose some
Registered Entities to double jeopardy violations of COM-003-1. Specifically, Requirement R1 provides
that BAs, RCs, and TOPs must develop and implement documented communication protocols that (a)
address instances where the issuer of an oral two-party communication Operating Instruction is
required to confirm that the response of any recipient entity such as a DP or GOP was accurate or to
reissue the Operating Instruction to resolve the misunderstanding (R1.5); and (b) to address
coordination with affected recipient entities’ communication protocols (R1.9). Requirement R2 further
requires BAs, RCs, and TOPs to develop methods that assess communication practices and implement
corrective actions necessary to meet the expectations outlined in these same protocols. Note that this
assessment method would necessarily include assessment of the expectations included in the
protocols regarding any recipient entity as required by R1.5 and R1.9. Meanwhile, proposed
Requirement R3 would require the recipient DPs and GOPs to develop their own documented
communications protocols that outline the communication expectations already addressed in the R1
protocols. [Note that the Rationale and Technical Justification for COM-003-1 specifies that
Requirements R1 and R2 are addressed to entities that both issue and receive Operating instructions
(BAs, RCs, and TOPs) whereas Requirements R3 and R4 are addressed to entities that only receive
Operating Instructions.] Requiring DPs and GOPs in R3 to develop protocols outlining the
communications expectations of its operators -- and requiring DPs and GOPs in R4 to assess those
same operators’ communications practices and implement corrective actions -- is redundant and
unnecessary when those same expectations are already being documented by BAs, RCs, and TOPs in
the R1 protocols, are already being coordinated with recipient entities, such as DPs and GOPs under
R1.9, and are already being assessed and corrected by the BAs, RCs, and TOPs as required by R2.
Therefore, requiring DPs and GOPs to go through the same motions simply creates another layer of
documentation that strains limited resources and does little to enhance the reliability of the Bulk
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Electric System. C. These duplicative exercises created by Requirements R3 and R4 run counter to the
objectives directed by FERC in Paragraph 81 of FERC’s March 15, 2012 Order on NERC’s proposed
“Find, Fix, and Track” (“FFT”) initiatives (“FFT Order”) as implemented by the P 81 Task Force. In
Paragraph 81 of the FFT Order, FERC noted that “some current requirements likely provide little
protection for Bulk-Power System reliability or may be redundant.” In complying with FERC’s
directives, the Paragraph 81 Task Force set out to identify standards that (a) do “little if anything, to
benefit or protect the reliable operation of the BES” and (b) among other possible criteria, are either:
“(a) Administrative in nature, do not support reliability, and are needlessly burdensome; or (b)
Require responsible entities to develop documents that are not necessary to protect BES reliability; or
(c) Impose documentation updating requirements that are out of sync with the actual BES operations,
unnecessary, or duplicative; or (d) Redundant with another FERC-approved Reliability Standard
requirement(s), the ERO compliance and monitoring program, or a governmental regulation.” (See
Paragraph 81 Task Force Technical White Paper.) With respect to this last criterion of redundancy, the
Task Force specifically stated that it is “designed to identify requirements that are redundant with
other requirements and are therefore unnecessary. Unlike the other criteria listed … in the case of
redundancy, the task or activity itself may contribute to a reliable BES, but it is not necessary to have
two duplicative requirements on the same or similar task or activity.” (emphasis added). By creating
duplicative requirements on both ends of a coordinated communication scheme between issuing
BAs/RCs/TOPs and recipient DPs/GOPs, the Standards Drafting Team is creating an unnecessary
administrative burden that does “little, if anything, to benefit or protect the reliable operation of the
BES.” Even if it may be argued that requiring double coordination from both issuer and recipient
somehow contributes to a reliable BES, “it is not necessary to have the two duplicative requirements
on the same or similar task or activity.” Proposed Requirements R3 and R4 would fit all of the criteria
listed above that the Paragraph 81 Task Force is using to identify candidates for retirement and/or
revision. D. Finally, the risk created by proposed Requirements R3 and R4 in conjunction with R1 and
R2 is more than simple administrative duplication. For vertically integrated entities that are registered
both as issuing BAs/RC/TOPs and recipient DPs/GOPs, the redundancy created by Requirement R3
and R4 could potentially expose them to double penalties for a single violation. Because of the
duplicative documentation and coordination requirements in R1/R2 and R3/R4, an auditor could
interpret a single instance where the communications protocol of an issuing BA/RC/TOP did not match
up with the recipient DP/GOP as multiple violations. In such an instance, both the issuers and the
recipients could conceivably be penalized because the issuer’s communications protocols were not
coordinated with the recipient’s communications protocols and this lack of coordination was not
assessed and remedied. If the Standards Draft Team does not delete Requirement R3 and R4 in their
entirety, then Georgia Transmission Corporation suggests that R3 be reworded such that the entities
work together to implement and coordinate one set of issuers’ communications protocols (i.e., that of
the BAs/RCs/TOPs) instead of two sets of both issuers’ and recipients’ protocols. This should help to
“tighten” the communications protocols as directed in Order 693 and to mitigate some of the
confusion and duplicative documentation that could arise from Requirements R3 as written: “R3. Each
Distribution Provider and Generator Operator shall implement the documented communication
protocols of its associated BA, RC, and TOP that define the communications expectations of R1. The
documented communication protocols will address, where applicable, the following: [Violation Risk
Factor: Low] [Time Horizon: Long-term Planning ] ….” and “R4. In addition to the recommendation to
eliminate for the reasons above, GTC still believes R4 prescribes elements of internal control language
to which is not necessary due to the tightening of communications protocols for issuing entities within
R1 and should still be eliminated under this alternate scenario.
No
See GTC’s comments above regarding deletion of R4. GTC also believes the same logic can apply to
R2 and recommends to be deleted. Additionally, see GTC’s comments regarding the conflict with the
drafting team’s proposal to inadvertently define a new function for the DP “operators”. Lastly, DPs do
not issue Operating Instructions; DP field personnel only receive instructions from others.
No
We agree with the VRFs and VSLs for R1. As discussed above, R3 and R4 should not be part of the
standard. To the extent R3 and R4 should be deleted or modified, the VRFs and VSLs should be
modified accordingly.
If Requirements R3 and R4 are neither deleted nor reworded as suggested above, then changes
should be made in the standard to clearly define the term “operator” or disassociate the term from
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the DP function.
Group
Oklahoma Gas & Electric
Terri Pyle
Oklahoma Gas & Electric
Oklahoma Gas & Electric supports that comments submitted by the Southwest Power Pool and
submits its own comments as well.
No
Comment for R1.3: Is the intent of R1.3 for applicable entities to maintain a list of common name
identifiers which must be utilized in communications with all affected entities? If so, a similar
requirement (R18) in TOP-002-2 is currently proposed to be eliminated in TOP-002-3. Therefore, it
shouldn’t be added back by this requirement. Can the drafting team be more specific as to exactly
what is required in R1.3 without going overboard as in the existing wording? We understand the need
to be sure that affected entities do not have any misunderstandings regarding the specific facility that
is at issue. However, our experience does not indicate that this is a problem. If we can’t relax R1.3,
we suggest eliminating it altogether since we believe this not does significantly impact the reliability
of the BES. Comment for R1.9: The use of the term ‘coordination’ in R1.9 causes concern in
determining exactly what is required to coordinate. This could become a compliance nightmare for
applicable entities. We suggest replacing R1.9 with “Provide each affected Reliability Coordinator,
Balancing Authority, Transmission Operator, Distribution Provider, and Generator Operator with its
communication protocols.“
No
We believe that R2 and R4 should already be covered in PER-005
No
While we understand the process that gets us to the point where the VRFs for R1 and R3 are Low and
those for R2 and R4 are Medium; however, in this situation we question the logic of the process. If
developing a document only deserves a Low VRF then how can we logically say that not implementing
the items contained in the document is a Medium? What happens if the document is flawed? We
suggest using Low for all requirements.
• We believe that this proposed Standard (COM-003-1) meets the intent of Paragraph 81 of the FERC
Order which notes that reliability standards that provide little protection to the reliable operations of
the BES are redundant or unnecessary. Although blackout occurrences in the past points to
communication issues, we believe it is not related to miscommunication. Instead, we believe it is due
to lack of communication and communicating information that was incorrect to begin with. • In the
Consideration of Comments from the Feb 14-15 conference, the SDT said “The OPCPSDT maintains its
position that three-part communication be addressed in documented communication protocols, where
applicable.” OG&E believes that while the opinions of the members of SDT are important, the SDT
itself should not maintain a “position” as such. Rather, the SDT should attempt to merge direction
from FERC with the comments from industry instead of rejecting industry comments out of hand. Per
the Standards Process Manual (pg.9), the roles of drafting teams are: o Drafts proposed language for
the Reliability Standards, definitions, Variances, and/or Interpretations and associated implementation
plans. o Solicits, considers, and responds to comments related to the specific Reliability Standards
development project. o Participates in industry forums to help build consensus on the draft Reliability
Standards, definitions, Variances, and/or Interpretations and associated implementation plans. o
Assists in developing the documentation used to obtain governmental approval of the Reliability
Standards, definitions, Variances, and/or Interpretations and associated implementation plans.
Group
Luminant
Brenda Hampton
Luminant Energy Company LLC
Edison Electric Institute (EEI)
No
All comments are shown in response to Question 4.
Yes
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No
All comments are shown in response to Question 4.
Luminant is generally supportive of the direction of this standard and agrees that requiring a
documented communication protocol and monitoring processes is the correct approach for this
standard. While we understand the need for the some Registered Entities (RE) to use a one-way burst
messaging system to make mass communication quicker and easier the inclusion of Reliability
Directive in R1.7, R1.8 and R3.3 creates a conflict COM-002-3 R2 and R3. By including Reliability
Directives in R1.7, R1.8 and R3.3 which allows and electronic response or only one receipt to restate,
the receiving REs will not be able to comply with COM-002-3 R2 that requires EACH recipient of a
Reliability Directive to repeat, restate, rephrase or recapitulate the Reliability Directive. Removing
Reliability Directive from those section would eliminate any confusion and conflict between COM-0023 and COM-001-3 and allow COM-001-3 to be passed and implemented. Alternatively, COM-002-3
could be revised to CLEARLY STATE that it only applies to one-on-one verbal (or written?)
communication.
Individual
Bradley Collard
Oncor Electric Delivery Company LLC
No
Oncor believes the specificity in the subparts of R1 is unnecessary. Three-part communication is the
preferred method for ensuring that both parties understand an Operating Instruction and it provides a
sufficient mechanism for clear, concise and accurate communication. In creating a protocol that
requires System Operators to essentially relearn the way to speak (specifically using alpha-numeric
identifiers) will only create confusion and inefficiency as operators try to follow protocol and
catch/correct themselves.
No
Oncor supports the shift in compliance to the internal controls approach and we look forward to NERC
providing a programmatic/principles framework in a collaborative approach with the industry. In the
absence of this framework, it is unknown how the concept of "assess and correct" will evolve. As the
framework is developed including the "assess and correct" concept, Oncor requests that continuous
focus be placed on implementing principles including this concept and not requiring or specifying
internal controls which would place additional compliance burden on entities. The internal controls
principles/framework should enable entities to establish internal controls model utilizing deficiency
correction approach but should not mandate the approach at the Standard/Requirement level.
Internal Controls Program needs to be defined by an Entity, it is not a “One Size Fits All”. The
standards/RSAWs should reflect this understanding. Oncor does not see how the Drafting Team
adequately addressed this concern. NERC and the rest of the industry should work together and
define the framework around Internal Controls.
Yes
R1.9 states that entities will address “Coordination with affected Reliability Coordinators’, Balancing
Authorities’, Transmission Operators’, Distribution Providers’, and Generator Operators’
communication protocols.” Coordination with these entities in the ERCOT market will become
cumbersome. Is it the SDT’s intent to ensure all communication protocols are coordinated with
multiple entities that a Transmission Operator communicates with, including the RC, BA, other TOs,
GOPs, and DPs? Oncor is unclear how an entity with multiple registrations would communicate with
itself in different functions. Would this require an entity with multiple registration functions to
designate personnel by functional entity and in turn, personnel would have to identify which
functional entity each person they interface with? It is impractical and inefficient to require Entities to
re-organize all personnel which would foster an inefficient structure and could potentially lead teams
to not communicate effectively. In addition, this could have a negative impact on communications
between companies. For example, in the ERCOT region, there are approximately 15 local control
centers and ERCOT who are all registered as TOPs. One might interpret communications between
neighboring TOPs or ERCOT and one of the local control centers are not subject to the requirements
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of COM-003-1 since these are TOP to TOP communications. We strongly recommend the SDT review
this to greatly simplify COM-003-1. Potential alternative to the current language would be “require
entities to implement, in a manner …, protocols that include three-part communication for Operating
Instructions” and eliminate the reference to Functional Entity.
Group
Tennessee Valley Authority
Dennis Chastain
Tennessee Valley Authority
SERC OC Standards Review Group
No
We agree with the definition of Operating Instruction. While we also can agree to the changes made
to R1, we feel R3 in its entirety is unnecessary and duplicative. Removal of the word “develop” would
eliminate double-jeopardy concerns. R3 could be acceptable if “develop and” is omitted and “as
developed in R1” is inserted after “protocols” and before “that.” It should be noted that this
suggestion only applies to the sub-requirements in R1 that correspond to the proposed subrequirements in R3.
No
R2 is acceptable and R4, as stated above for R3, is unnecessary and duplicative.
No
We agree with the VRFs and VSLs for R1 and R2. Based on our previous comments, we do not agree
with the need for R3 and R4, and therefore VRFs and VSLs for these requirements are not needed.
TVA Nuclear Power’s Human Performance program is driven by INPO and includes 1) requirements for
operations to use 3-way communication and the phonetic alphabet; and 2) a documented assessment
process via an established observation program with corrective actions. Any additional oversight
process will contribute to distraction in the control room and promote overreliance on process and
procedure with a “checklist mentality” rather than focus on potential impacts of the task being
performed. If the RC, TOP, or BA specifically requests confirmation of a verbal communication (R1.6),
our nuclear plant operators will respond accordingly as they are already expected to do. The use of
“periodic assessment” in the measurements does not provide adequate guidance in the development
of consistent, effective measures of compliance.
Individual
Jose H Escamilla
CPS Energy
Yes
No
Distribution Providers (DP) may be co-located in the same room with Transmission Operators (TOP)
and would have oral communications and not use a telephone or other messaging system. Generator
Operators (GOP) should have a separate standard.
No
I do not agree with the requirements, therefore I do not agree with the VRF's and VSL.
Separate the Distribution Provider (DP) and Generator Operator (GOP) COM requirements into a
separate standard.
Group
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
Individual
Daniel Duff
Liberty Electric Power
Agree
Generator Forum Standards Review Team
Individual
Banagalore
Vijayraghavan
The primary reason for a no vote is that Draft 5 fails to address the communication gaps identified in
the Standards Authorization Request (SAR), FERC Order 693 and the recommendations of the August
2003 Blackout Report. The draft as written does not require a consistent application of effective
communications protocols but in turn requires each functional entity to develop their own protocols
with insufficient guidance on how to achieve better consistency.
No
No
No
Individual
Tony Kroskey
Brazos Electric Power Cooperative, Inc.
Agree
ACES Power Marketing.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
Agree
Western Small Entity Comment Group submitted by Central Lincoln
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Consideration of Comments
Project 2007-02 Operating Personnel Communications
Protocols COM-003-1
The Operating Personnel Communications Protocols Drafting Team thanks all commenters who
submitted comments on the proposed draft COM-003-1 standard. The standard was posted for a 30day public comment period from March 7, 2013 through April 8, 2013. Stakeholders were asked to
provide feedback on the standard and associated documents through a special electronic comment
form. There were 78 sets of comments, including comments from approximately 215 different people
from approximately 130 companies representing all 10 of the Industry Segments as shown in the table
on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process. If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1
Summary Consideration:
Requirements (Question 1, Comments on R1 and R3):
“Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop and
implement documented communication protocols that outline the communications expectations of
its System Operators. The documented communication protocols will address, where applicable, the
following: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning]”
A Major concern from draft 5, Question one regarding COM-003-1, R1 and R3 was the term “Reliability
Directive” appearing in many parts of requirements R1 and R3 causing confusion as to which standard
would apply to a situation and if potential conflict could exist between COM-003-1 and COM-002-3.
The OPCPSDT agrees and has removed the term “Reliability Directive” from the Parts of Requirement
R1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
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Another concern of commenters of draft 5 was the use of the term “all call” in COM-003-1, R1 and R3.
Commenters are concerned these requirements create a conflict with COM-002-3 which is silent on the
use of multi-party one way messages. Commenters cited confusion and double jeopardy as concerns.
The OPCPSDT agrees and has removed the term “all call” from the Parts of R1
An additional concern in COM-003-1, R1 was Part 1.9 requiring entities to coordinate communication
protocols. Commenters believed this was ambiguous and difficult to accomplish.
The OPCPSDT agrees and has removed COM-003-1, R1 Part 1.9 from R1 and now requires applicable
entities to jointly develop the communication protocols.
In response to Question 1 regarding use of the English language, 24 hour clock and time zone
reference, common interface identifiers, and alpha-numeric clarifiers, a large majority of the
commenters still believe that all of Parts are too prescriptive.
The OPCPSDT believes the protocols must have common elements to ensure uniformity and
consistent application for clear and concise communication.
Another continuing theme that was repeated in draft 5 comments and previously from draft 2, 3 and 4
was the concern that the OPCPSDT was not addressing the tasking from the SAR, as well as related
directives and orders.
The OPCPSDT disagrees and cites the language from the SAR. The purpose of the SAR for this project
is “Require that real time System Operators use standardized communication protocols during
normal and emergency operations to improve situational awareness and shorten response time.”
Additionally, the SAR is very specific in that it also includes the term normal operating conditions
under Applicability: “Clear and mutually established communications protocols used during real time
operations under normal and emergency conditions ensure universal understanding of terms and
reduce errors.”
There were many recommendations for multiple requirement language changes to improve clarity.
The OPCPSDT agrees and has incorporated many of those recommendations into COM-003-1, draft 6.
Others expressed a desire to combine COM-002-3 and COM-003-1 into a single standard.
Based on other feedback, the OPCPSDT has chosen not to combine the two standards. The OPCPSDT
also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
Requirements (Question 2 Comments on R2 and R4):
“Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop
method(s) to assess System Operators’ communication practices and implement corrective actions
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
2
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necessary to meet the expectations in its documented communication protocols developed for
Requirement R1. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Operations
Assessment] (Same language for R4 for DP and GOP)”
A majority of the commenters expressed concerns over how an entity’s internal controls to improve
System Operators’ communication performance would be audited. The commenters state that auditing
internal controls is contrary to ongoing initiatives that are seeking to improve the effectiveness of the
audit process. Some commenters also claim the potential for double jeopardy exists. The lack of
certainty over how compliance would be administered caused commenters to be concerned.
The OPCPSDT understands the commenters’ concerns. The OPCPSDT decided to eliminate the COM003-1, draft 5, R2 and R4 requirements in draft 6. Draft 6 features a results based approach that
clearly specifies compliance and is linked to reliability results. The draft 6 requirements will also
reduce the exposure of entities to voluminous compliance documentation.
The OPCPSDT points out that many other commenters responded positively to the use of internal
controls and preferred the assess and correct requirement.
After consideration of all of the comments, the OPCPSDT voted for the approach featured in COM003-1, draft 6.
VRFs and VSLs (Question 3):
The OPCPSDT acknowledges there were many good comments on draft 5 regarding VSLs and VRFs and
appreciates the contributions.
The OPCPSDT has changed draft 6, and all of the VRFs and VSLs have been adjusted to reflect those
changes. The elimination of the “assess and correct” language and the revisions to R1, R2 and R3
have resulted in extensive changes to VRFs and VSLs for draft 6.
Additional Issues Addressed by the OPCPSDT:
Other commenters raised issues around:
The requirement for DPs and GOPs to have documented protocols
Draft 6 resolves this issue by eliminating this requirement for GOPs and DPs.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Index to Questions, Comments, and Responses
1. The SDT has proposed new language in COM-003-1, R1 and R3: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall develop and implement documented
communication protocols that outline the communications expectations of its System Operators.
The documented communication protocols will address, where applicable, the following:” (the
same language exists for R3, except DPs and GOPs listed as applicable entities and the use of
“operators” instead of “System Operators”). Do you agree with the changes made to the proposed
definition “Operating Instruction” (now proposed as a “A command by a System Operator of a
Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act, to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Discussions of
general information and of potential options or alternatives to resolve BES operating concerns are
not commands and are not considered Operating Instructions. ”) to be added as a term for the
NERC Glossary? Do you agree with these proposed requirement changes? If not, please explain in
the comment area of the last question. ..............................................................................17
2. The SDT has proposed new language in COM-003-1, R2 and R4: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall develop method(s) to assess System
Operators’ communication practices and implement corrective actions necessary to meet the
expectations in its documented communication protocols. (the same language exists for R3, except
DPs and GOPs listed as applicable entities and the use of “operators” instead of “System
Operators”). ” Do you agree with these proposed requirement changes? If not, please explain in the
comment area of the last question: ...................................................................................42
3. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4? ...............................55
4. Do you have any other comments or suggestions to improve the draft standard? .......................63
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
4
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Additional Member
Guy Zito
Northeast Power Coordinating Council
Additional Organization
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
Carmen Agavriloai
Independent Electricity System Operator
NPCC 2
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
7.
Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Michael Jones
National Grid
NPCC 1
NPCC 10
2
3
4
5
6
7
8
9
10
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
10. David Kiguel
Hydro One Networks Inc.
NPCC 1
11. Christina Koncz
PSEG Power LLC
NPCC 5
12. Randy MacDonald
New Brunswick Power Transmission
NPCC 9
13. Bruce Metruck
New York Power Authority
NPCC 6
14. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
15. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
16. Robert Pellegrini
The United Illuminating Company
NPCC 1
17. Si-Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
18. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
19. Brian Robinson
Utility Services
NPCC 8
20. Brian Shanahan
National Grid
NPCC 1
21. Wayne Sipperly
New York Power Authority
NPCC 5
22. Donald Weaver
New Brunswick System Operator
NPCC 2
23. Ben Wu
Orange and Rockland Utilities
NPCC 1
2.
paul haase
Group
Seattle City Light
2
3
X
X
X
X
4
X
5
6
X
X
X
X
7
Additional Member Additional Organization Region Segment Selection
1. pawel krupa
seattle city light
WECC 1
2. dana wheelock
seattle city light
WECC 3
3. hao li
seattle city light
WECC 4
4. mike haynes
seattle city light
5
5. dennis sismaet
seattle city light
6
3.
Group
Michael Lowman
Duke Energy
Additional Member Additional Organization Region Segment Selection
1. Doug Hills
1
2. Lee Schuster
3
3. Dale Goodwine
5
4. Greg Cecil
4.
Group
Patrick Brown
Additional Member
1. Allen Schriver
Additional Organization
NextEra
North American Generator Forum
Standards Review Team
X
Region Segment Selection
5
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Pamela Dautel
IPR-GDF Suez Generation NA
5
3. Dan Duff
Liberty Electric Power
5
4. Mike Hirst
Cogentrix Energy, LLC
5
5. Don Lock
PPL Generation, LLC
5
6. Dana Showalter
e.on
5
7. William Shultz
Southern Company
5
5.
Group
David Kiguel
Hydro One Networks Inc.
Additional Member Additional Organization
Region
Ajay Garg
Hydro One Networks Inc. NPCC
1, 3
2.
Sasa Maljukan
Hydro One Networks inc. NPCC
1, 3
Group
Gerry Beckerle
Additional Member
SERC OC Standards Review Group
Additional Organization
3
X
X
X
X
4
5
6
7
Segment
Selection
1.
6.
2
Region Segment Selection
1.
Jeff Harrison
AECI
SERC
1, 3, 5, 6
2.
Randy Castello
Alabama Power Company
SERC
3
3.
Eric Scott
Ameren
SERC
1, 3
4.
Jeff Hackman
Ameren
SERC
1, 3
5.
Mark Fowler
Ameren
SERC
1, 3
6.
Mike Hirst
Cogentrix
SERC
5
7.
Dan Roethemeyer
Dynegy
SERC
5
8.
Phil Whitmer
Georgia Power Company
SERC
3
9.
Bob Thomas
Illinois Municipal Electric Agency SERC
4
10. Wayne Van Liere
LGE-KU
SERC
1, 3, 5, 6
11. Timmy LeJeune
Louisiana Generating, LLC
SERC
4, 5, 6
12. Martin Summe
NC Municipal Power Agency # 1
SERC
3
13. Doug White
NCEMC
SERC
1, 3, 4, 5
14. Scott Brame
NCEMC
SERC
1, 3, 4, 5
15. Dwayne Roberts
Owensboro, KY Municipal Utilities SERC
3
16. William Berry
Owensboro, KY Municipal Utilities SERC
3
17. Bill Thigpen
PowerSouth Energy Cooperative SERC
1, 5
18. Tim Hattaway
PowerSouth Energy Cooperative SERC
1, 5
19. Alisha Anker
Prairie Power
3
SERC
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
20. Rene Free
SCPSA
SERC
1, 3, 5, 6
21. Marc Butts
Southern
SERC
1, 5
22. Mike Hardy
Southern
SERC
1, 5
23. Randy Hubbert
Southern
SERC
1, 5
24. Joel Wise
TVA
SERC
1, 3, 5, 6
25. Stuart Goza
TVA
SERC
1, 3, 5, 6
7.
Mike Garton
Group
Dominion
Additional Member Additional Organization
X
Region
Louis Slade
Dominion Resources Services, Inc.
RFC
5, 6
2.
Randi Heise
Dominion Resources Services, Inc.
MRO
5, 6
3.
Connie Lowe
Dominion Resources Services, Inc.
NPCC
5, 6
4.
Michael Crowley
Virginia Electric and Power Company SERC
Group
Russ Mountjoy
Additional Member Additional Organization
MRO NSRF
Region
3
4
X
5
6
X
X
X
X
7
9
10
1, 3, 5, 6
X
X
X
X
X
Segment
Selection
1.
Alice Ireland
Xcel Energy MRO
1, 3, 5, 6
2.
Chuck Lawrence
ATC
MRO
1
3.
Dan Inman
MPC
MRO
1, 3, 5, 6
4.
Dave Rudolph
BEPC
MRO
1, 3, 5, 6
5.
Kayleigh Wilkerson
LES
MRO
1, 3, 5, 6
6.
Jodi Jensen
WAPA
MRO
1, 6
7.
Joseph DePoorter
MGE
MRO
3, 4, 5, 6
8.
Ken Goldsmith
ALTW
MRO
4
9.
Lee Kittleson
OTP
MRO
1, 3, 5
10.
Mahmood Safi
OPPD
MRO
1, 3, 5, 6
11.
Marie Knox
MISO
MRO
2
12.
Mike Brytowski
GRE
MRO
1, 3, 5, 6
13.
Scott Bos
MPW
MRO
1, 3, 5, 6
14.
Scott Nickles
RPU
MRO
4
15.
Terry Harbour
MEC
MRO
1, 3, 5, 6
16.
Tom Breene
WPS
MRO
3, 4, 5, 6
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
8
Segment
Selection
1.
8.
2
8
X
X
X
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17.
9.
Tony Eddleman
Group
NPPD
MRO
3
4
5
6
7
8
9
1, 3, 5
SMUD/Balancing Authority of Northern
California
Joe Tarantino
2
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Kevin Smith
10.
BANC
Group
WECC 1
Steve Alexanderson
Additional Member
Western Small Entity Comment Group
Additional Organization
1. Eric Scott
City of Palo Alto
WECC 3
2. Kathy Zancanella
South Feather Water & Power Agency
WECC 5
3. Steven J. Grega
Public Utility District #1 of Lewis County WECC 5
4. Russ Noble
Cowlitz County PUD No. 1
WECC 3, 4, 5
5. Russ Schneider
Flathead Electric Cooperative, Inc.
WECC 3, 4
11.
Group
Albert DiCaprio
ISO/RTO Standards Review Committee
Additional Member Additional Organization Region
Greg Campoli
NYISO NPCC
2.
Ali Miremadi
CAISO WECC
3.
Kathleen Goodman
ISONE NPCC
4.
Charles Yeung
SPP
SPP
5.
Stephanie Monzon
PJM
RFC
6.
Ben Li
IESO
NPCC
Group
Ben Engelby
Additional
Member
X
Segment
Selection
1.
12.
X
Region Segment Selection
2
ACES Standards Collaborators
Additional Organization
X
Region
Segment
Selection
1. Bill Watson
Old Dominion Electric Cooperative
RFC
3, 4
2. Scott Brame
North Carolina Electric Membership Corporation
SERC
1, 3, 5, 6
3. John Shaver
Arizona Electric Power Cooperative, Inc and Southwest Transmission
Cooperative, Inc.
WECC 1, 4, 5
4. Shari Heino
Brazos Electric Power Cooperative, Inc.
ERCOT 1, 5
5. Bob Solomon
Hoosier Energy Rural Electric Cooperative, Inc.
RFC
1
6. Megan Wagner
Sunflower Electric Power Corporation
SPP
1
7. Laurel Heacock
Oglethorpe Power Corporation
SERC
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
13.
Group
Brent Ingebrigtson
Additional
Member
PPL NERC Registered Affiliates
Additional
Organization
1.
2
3
X
Region
X
PPL Electric Utilities Corporaton
RFC
1
Annette Bannon
PPL Generation, LLC on behalf of Supply NERC
Registered Affiliates
RFC
5
WECC
5
Elizabeth Davis
PPL EnergyPlus, LLC
MRO
6
5.
NPCC
6
6.
SERC
6
7.
SPP
6
8.
RFC
6
9.
WECC
6
3.
4.
14.
Group
Frank Gaffney
5
6
X
X
X
X
7
Segment
Selection
Brenda Truhe
2.
4
Florida Municipal Power Agency
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
3
15.
Group
Robert Rhodes
FRCC
SPP Standards Review Group
X
.
Additional Member
Additional Organization
Region Segment Selection
1.
John Allen
City Utilities of Springfield
SPP
1, 4
2.
Bo Jones
Westar Energy
SPP
1, 3, 5, 6
3.
Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
4.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
5.
Danny McDaniel
Cleco Power
SPP
1, 3, 5
6.
Mike Murrary
City of Independence, Power & Light Department SPP
3
7.
James Nail
City of Independence, Power & Light Department SPP
3
8.
Kevin Nincehelser
Westar Energy
1, 3, 5, 6
SPP
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
10
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
9.
Ashley Stringer
Oklahoma Municipal Power Authority
SPP
4
10. Jessica Tucker
Kansas City Power & Light
SPP
1, 3, 5, 6
11. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
12. Jim Useldinger
Kansas City Power & Light
SPP
1, 3, 5, 6
16.
Terry L. Blackwell
Group
Santee Cooper
2
3
4
5
X
X
X
X
X
X
6
7
X
Additional Member Additional Organization Region Segment Selection
1. S. Tom Abrams
Santee Cooper
SERC
1
2. Vicky Budreau
Santee Cooper
SERC
1
3. Chris Wagner
Santee Cooper
SERC
1
4. Rene' Free
Santee Cooper
SERC
1
17.
Group
Terri Pyle
Oklahoma Gas & Electric
Additional Member Additional Organization Region Segment Selection
1. Greg McAuley
Oklahoma Gas and Electric SPP
1, 3, 5
2. Sing Tay
Oklahoma Gas and Electric SPP
1, 3, 5
3. Don Hargrove
Oklahoma Gas and Electric SPP
1, 3, 5
18.
Group
Brenda Hampton
Additional Member
1. Rick Terrill
19.
X
Luminant
Additional Organization
Region Segment Selection
Luminant Generation Company LLC ERCOT 5
Group
Dennis Chastain
Tennessee Valley Authority
X
X
X
X
X
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Ian Grant
TVA
SERC
3
2. Marjorie Parsons
TVA
SERC
6
3. DeWayne Scott
TVA
SERC
1
4. David Thompson
TVA
SERC
5
20.
Group
Jamison Dye
Bonneville Power Administration
Additional Member Additional Organization Region Segment Selection
1. Tim Loepker
Process Analyst
WECC 1
2. Erika Doot
Generation
WECC 3, 5, 6
3. Fran Halpin
Physical Scientist
WECC 3
21.
Individual
Bob Steiger
Salt River Project
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
11
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
22.
Individual
2
3
4
5
6
Western Electricity Coordinating Council
Individual
24. Individual
Christopher Wood
Annamay Luyun
Platte River Power Authority
San Diego Gas & Electric
X
X
X
X
X
X
25.
ryan millard
Janet Smith, Regulatory
Affairs Supervisor
pacificorp
X
X
X
X
X
X
X
X
X
X
X
X
26.
Individual
Individual
Pamela R. Hunter
28.
Individual
Glenn Rounds
Pacific Gas and Electric Company
X
X
X
29.
Individual
Scott Bos
Muscatine Power and Water
X
X
X
30.
Individual
Herb Schrayshuen
Self
31.
Individual
Scott McGough
Georgia System Operations Corporation
32.
Individual
Greg Travis
Idaho Power Company
33.
Individual
Robert W. Kenyon
NERC
34.
Individual
Thad Ness
American Electric Power
X
X
X
X
35.
Individual
John Seelke
Public Service Enterprise Group
X
X
X
X
36.
Individual
Andrew Gallo
City of Austin dba Austin Energy
X
X
X
37.
Individual
CenterPoint Energy Houston Electric L.L.C.
X
X
Individual
John Brockhan
John Bee on behalf of
Exelon and its' affiliates
X
X
Exelon
39.
Individual
D. Jones
Texas Reliability Entity
40.
Individual
Ronnie Hoeinghaus
City of Garland
X
X
41.
Individual
Jim Howard
Lakeland Electric
X
X
X
X
42.
Individual
David Jendras
Ameren
X
X
X
X
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
10
X
Individual
38.
9
X
Arizona Public Service Company
Southern Company - Southern Company
Services, Inc.; Alabama Power Company;
Georgia Power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation; Southern
Company Generation and Energy Marketing
27.
8
X
Steve Rueckert
23.
7
X
X
X
X
X
X
X
12
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2
3
4
NIPSCO
X
Individual
45. Individual
Martyn Turner
Jack Stamper
LCRA Transmission Services Corporation
Clark Public Utilities
X
46.
Individual
Alice Ireland
Xcel Energy
47.
Individual
Wayne Sipperly
New York Power Authority
X
X
X
X
X
X
X
X
48.
Individual
Julaine Dyke
NIPSCO
X
X
X
X
49.
Individual
Michelle D'Antuono
Occidental Energy Ventures Corp
X
X
50.
Individual
Jonathan Appelbaum
The United Illuminating Company
X
51.
Individual
William O. Thompson
NIPSCO
X
X
X
X
52.
Individual
Michael Falvo
Independent Electricity System Operator
53.
Individual
Nazra Gladu
Manitoba Hydro
X
X
X
X
54.
Individual
Michiko Sell
Grant County PUD
X
X
X
X
55.
Individual
David Thorne
Pepco Holdings Inc
X
X
56.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
X
57.
Individual
Richard Vine
California ISO
X
58.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
X
X
59.
Individual
Brenda Frazer
Edison Mission Marketing & Trading
60.
Individual
Scott Berry
Indiana Municipal Power Agency
Individual
62. Individual
Anthony Jablonski
Kathleen Goodman
ReliabiltyFirst
ISO New England Inc.
X
63.
Individual
Marie Knox
MISO
X
64.
Individual
James R. Keller
Wisconsin Electric Power Company
65.
Individual
Brett Holland
Kansas City Power & Light
X
66.
Individual
Larry Watt
Lakeland Electric
X
67.
Individual
Andrew Z. Pusztai
American Tranmission Company
X
68.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Individual
44.
61.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
X
6
Joe O'Brien
43.
X
5
X
7
8
9
10
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
13
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
69.
Individual
Cogentrix Energy Power Management
Individual
71. Individual
Keith Morisette
Gregory Campoli
Tacoma Power
NYISO
X
72.
Individual
Jason Snodgrass
Georgia Transmission Corporation
73.
Individual
Bradley Collard
Oncor Electric Delivery Company LLC
X
X
74.
Individual
Jose H Escamilla
CPS Energy
75.
Individual
Daniel Duff
Liberty Electric Power
76.
Individual
Banagalore
Vijayraghavan
X
77.
Individual
Tony Kroskey
Brazos Electric Power Cooperative, Inc.
X
78.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
3
4
5
6
7
X
Mike Hirst
70.
2
X
X
X
X
X
X
X
X
X
14
8
9
10
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Summary Consideration:
Organization
Supporting Comments of “Entity Name”
Brazos Electric Power Cooperative, Inc.
ACES Power Marketing.
Wisconsin Electric Power Company
Edison Electric Institute
Luminant
Edison Electric Institute (EEI)
Dominion
EEI
Illinois Municipal Electric Agency
Florida Municipal Power Agency
Lakeland Electric
Florida Municipal Power Agency (FMPA)
Liberty Electric Power
Generator Forum Standards Review Team
Lakeland Electric
LAK supports FMPA comments
Platte River Power Authority
Large Public Power Council
New York Power Authority
Large Public Power Council (LPPC)
Xcel Energy
MRO NERC Standards Review Forum (NSRF)
Oklahoma Gas & Electric
Oklahoma Gas & Electric supports that comments submitted by the Southwest
Power Pool and submits its own comments as well.
Pepco Holdings Inc
Pepco Holdings Inc supports the comments submitted by EEI
Grant County PUD
Seattle City Light
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
15
Organization
Supporting Comments of “Entity Name”
LCRA Transmission Services Corporation
Seattle City Light
Tennessee Valley Authority
SERC OC Standards Review Group
Kansas City Power & Light
Southwest Power Pool
California ISO
The California ISO is supportive of those comments submitted by the SRC (ISO/RTO
Council).
Vijayraghavan
The primary reason for a no vote is that Draft 5 fails to address the communication
gaps identified in the Standards Authorization Request (SAR), FERC Order 693 and
the recommendations of the August 2003 Blackout Report. The draft as written
does not require a consistent application of effective communications protocols but
in turn requires each functional entity to develop their own protocols with
insufficient guidance on how to achieve better consistency.
Flathead Electric Cooperative, Inc.
Western Small Entity Comment Group submitted by Central Lincoln
Consideration of Draft 5 Comments: Project 2007-02 COM-003
Posted June 16, 2013
16
1. The SDT has proposed new language in COM-003-1, R1 and R3: “Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop and implement documented communication protocols that outline the communications
expectations of its System Operators. The documented communication protocols will address, where applicable, the following:”
(the same language exists for R3, except DPs and GOPs listed as applicable entities and the use of “operators” instead of “System
Operators”). Do you agree with the changes made to the proposed definition “Operating Instruction” (now proposed as a “A
command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where
the recipient of the command is expected to act, to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. Discussions of general information and of potential options or
alternatives to resolve BES operating concerns are not commands and are not considered Operating Instructions. ”) to be added
as a term for the NERC Glossary? Do you agree with these proposed requirement changes? If not, please explain in the comment
area of the last question.
Summary Consideration:
Requirements (Question 1 Comments on R1 and R3):
A Major theme from draft 5, Question one regarding COM-003-1, R1 and R3 was the term “Reliability Directive” in many
Parts of requirements R1 and R3 causing confusion as to which standard would apply and if there was potential conflict
between COM-003-1 and COM-002-3.
The OPCPSDT agrees and has removed the term “Reliability Directive” from the Parts of R1
A similar theme in draft 5 was the use of the term “all call” in COM-003-1, R1 and R3. Commenters are concerned these
requirements create a conflict with COM-002-3 where the use of multi-party one way messages is silent. Commenters
cited confusion and double jeopardy as concerns.
The OPCPSDT agrees and has removed the term “all call” from the Parts of R1
An additional major concern in COM-003-1, R1 was Part 1.9 requiring entities to coordinate communication protocols.
Commenters believed this was ambiguous and difficult to accomplish.
The OPCPSDT agrees and has removed COM-003-1, R1 Part 1.9 from R1 and now requires applicable entities to jointly
develop the communication protocols subject to RC approval.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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17
In response to Question 1, regarding use of the English language, 24 hour clock and time zone reference, common
interface identifiers, and alpha-numeric clarifiers, many commenters still believe that all of subparts are too prescriptive
and unnecessary.
The OPCPSDT believes the protocols must have common elements to ensure uniformity and consistent application for
understanding communication.
Another continuing theme that was repeated in draft 5 comments and previously from draft 2, 3 and 4 was the concern
that the work of the OPCPSDT was not addressing the intentions of the SAR, related directives and orders.
The OPCPSDT disagrees and cites the language from the SAR. The purpose of the SAR for this project is “Require that
real time System Operators use standardized communication protocols during normal and emergency operations to
improve situational awareness and shorten response time.” Additionally, the SAR is very specific in that it also
includes the term normal operating conditions under Applicability: “Clear and mutually established communications
protocols used during real time operations under normal and emergency conditions ensure universal understanding of
terms and reduce errors.”
There were many recommendations for multiple requirement language changes to improve clarity.
The OPCPSDT agrees and has incorporated many of those recommendations into COM-003-1, draft 6.
Others expressed a desire to combine COM-002-3 and COM-003-1 into a single standard.
Based on other feedback, the OPCPSDT has chosen not to combine the two standards. The OPCPSDT also believes draft
6 requirements create a logical delineation between COM-002-3 and COM-003-1.
Organization
Yes or No
Luminant
No
Question 1 Comment
All comments are shown in response to Question 4.
Response: The OPCPSDT thanks you for your comments. Please see our response to Question 4.
Oklahoma Gas & Electric
No
Comment for R1.3:
Is the intent of R1.3 for applicable entities to maintain a list of common name
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Organization
Yes or No
Question 1 Comment
identifiers which must be utilized in communications with all affected entities? If so, a
similar requirement (R18) in TOP-002-2 is currently proposed to be eliminated in TOP002-3. Therefore, it shouldn’t be added back by this requirement. Can the drafting
team be more specific as to exactly what is required in R1.3 without going overboard
as in the existing wording?
Response: R1.3 is designed to increase familiarity with interface Transmission
Elements and Facilities to prevent confusion and increase situational awareness. The
requirement calls for entities to ensure operators are aware of the names or
designators of interface equipment between those entities. It is up to the affected
entities to determine how they would accomplish this through their communication
protocols.
One example may be to designate in the documented Communication Protocols to
use the name of the Transmission interface Element/Facility assigned by the owner
of such Element/Facility.
We understand the need to be sure that affected entities do not have any
misunderstandings regarding the specific facility that is at issue. However, our
experience does not indicate that this is a problem. If we can’t relax R1.3, we suggest
eliminating it altogether since we believe this not does significantly impact the
reliability of the BES.
Response: The requirement focuses on Transmission interface Elements and Facilities
only. The OPCPSDT believes that the draft standard requirements provide flexibility
so that an entity may develop the protocols in a manner that supports their unique
circumstances.
Comment for R1.9:
The use of the term ‘coordination’ in R1.9 causes concern in determining exactly what
is required to coordinate. This could become a compliance nightmare for applicable
entities. We suggest replacing R1.9 with “Provide each affected Reliability Coordinator,
Balancing Authority, Transmission Operator, Distribution Provider, and Generator
Operator with its communication protocols.”
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT agrees and has changed the wording of R1, to eliminate Part
1.9.
Response: The OPCPSDT thanks you for your comments.
American Electric Power
No
Due to the manner in which the sub-requirements for R1 are written, there could be
misinterpretation at which entities plan would require those sub-requirements. We
assume that requirements R1.6 and R1.8 apply to an entity that in that instance is
*receiving* an Operating Instruction where Requirement R1.2, R1.3, R1.4, R1.5, R1.7
are reserved for only those cases where an entity is *issuing* the Operating
Instruction. As currently drafted, R1.6 and R1.8 could be interpreted as somehow
requiring an entity that would normally be issuing an instruction (such as an RC) to
implement documented communication protocols for an outside receiving entity (such
as a Balancing Authority). A potential solution would be to restructure R1 and R3 in
such a way that it is based on entities that would be issuing instructions in one
requirement and entities that would be receiving instructions in a separate
requirement.
Response: The OPCPSDT agrees with your comments and have made changes similar
to those suggested.
AEP strongly disagrees with R 1.9, requiring coordination with affected Reliability
Coordinators’, Balancing Authorities’, Transmission Operators’, Distribution Providers’,
and Generator Operators’ communication protocols. For AEP, this requirement would
require coordination among numerous entities, and keeping all those protocols in sync
would be a significant logistical challenge that does not appear to proportionately
improve reliability. In addition, exactly what kind of coordination is needed? R1.1
through are robust enough that adding R1.9 is totally redundant and unnecessary.
Response: T The OPCPSDT agrees and has changed the wording of R1, to eliminate
Part 1.9.
If beyond R1.1 through 1.8 there are additional, specific needs that still need to be
addressed, those should be identified so that specific requirements could be developed
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
if necessary. For this requirement alone, AEP must vote negative on this proposed
draft.
Response: If the intended meaning of your comment is that an entity may chose to
develop protocols beyond R1.1 through 1.8, there is no restricting language to
prevent them from doing so. The standard lists the basic requirements.
Response: The OPCPSDT thanks you for your comments.
Florida Municipal Power
Agency
No
FMPA prefers the prior version which had language on internal controls, e.g.,
“implement, in a manner that identifies, assesses and corrects deficiencies ...”. As
stated, and by using the word “implement” which means: “carry out, accomplish;
especially : to give practical effect to and ensure of actual fulfillment by concrete
measures”, means that each entity must have evidence (“concrete measures”) of
implementing its communications protocol at all times for every instance. Three part
communication is watered-down by giving the entity the choice as to whether to
follow three-part communication for: 1) all Operating Instructions; 2) for Reliability
Directives only; or 3) something in between. Many entities, to manage compliance risk,
will only require three-part communications for Reliability Directives in their
communication protocols as a result. For reliability reasons, FMPA believes that threepart communication ought to be required for all Operating Instructions, but, at the
same time, there should be some tolerance for mistakes through use of the CIP v5
internal controls language “implement, in a manner that identifies, assesses and
corrects deficiencies ...”.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes draft 5 continues to permit entities to have
protocols to address the standard as they believe the protocols will sustain reliability on the BES. The OPCPSDT agrees with FMPA
that all Operating Instructions and Reliability Directives should employ three-part communications and believes FMPA is
permitted to develop protocols that require it.
Georgia Transmission
Corporation
No
Georgia Transmission Corporation agrees with the new definition. Georgia
Transmission Corporation believes that Requirements R3 and R4 should be deleted.
A. Georgia Transmission Corporation does not agree with the use of the term
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
“operators” with respect to the functional entity Distribution Providers for R3 and R4.
This poses an incomprehensible requirement for non-vertically integrated entities that
are registered as Transmission Owner’s also serving as the DPs. NERC does not define
or associate anywhere in the Functional Model or NERC registry the term Distribution
Provider operator. Specifically, GTC would not understand how to comply with R3 or
R4 because GTC does not have any operators yet we are registered as a DP for the
functions we perform of our facilities which are directly connected to the BES. GTC
believes that Requirements R3 and R4 (applicable to Distribution Providers (“DPs”))
should be deleted from the proposed COM-003 standard, or else disassociate the term
“operators” from the DP.
Response: The OPCPSDT has eliminated R2 and R4 and has narrowed the role of
GOPs and DP to those who would receive Operating Instructions
B. Additionally, Georgia Transmission Corporation believes that Requirements R3 and
R4 (applicable to Distribution Providers (“DPs”) and Generator Operators (“GOPs”))
should be deleted from the proposed COM-003 standard because the burdens placed
on Balancing Authorities (“BAs”), Reliability Coordinators (“RCs”) and Transmission
Operators (“TOPs”) by Requirements R1 and R2:
(a) sufficiently tighten communications protocols with DPs and GOPs,
(b) render Requirements R3 and R4 administrative, unnecessary, and redundant,
counter to FERC’s objectives as implemented by the NERC Paragraph 81 Task Force,
and
(c) Potentially expose some Registered Entities to double jeopardy violations of COM003-1.
Response: The SDT has eliminated draft 5 R3 and R4 from draft 6.
Specifically, Requirement R1 provides that BAs, RCs, and TOPs must develop and
implement documented communication protocols that
(a) address instances where the issuer of an oral two-party communication Operating
Instruction is required to confirm that the response of any recipient entity such as a DP
or GOP was accurate or to reissue the Operating Instruction to resolve the
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
misunderstanding (R1.5); and
(b) to address coordination with affected recipient entities’ communication protocols
(R1.9).
Requirement R2 further requires BAs, RCs, and TOPs to develop methods that assess
communication practices and implement corrective actions necessary to meet the
expectations outlined in these same protocols. Note that this assessment method
would necessarily include assessment of the expectations included in the protocols
regarding any recipient entity as required by R1.5 and R1.9.
Meanwhile, proposed Requirement R3 would require the recipient DPs and GOPs to
develop their own documented communications protocols that outline the
communication expectations already addressed in the R1 protocols. [Note that the
Rationale and Technical Justification for COM-003-1 specifies that Requirements R1
and R2 are addressed to entities that both issue and receive Operating instructions
(BAs, RCs, and TOPs) whereas Requirements R3 and R4 are addressed to entities that
only receive Operating Instructions.] Requiring DPs and GOPs in R3 to develop
protocols outlining the communications expectations of its operators -- and requiring
DPs and GOPs in R4 to assess those same operators’ communications practices and
implement corrective actions -- is redundant and unnecessary when those same
expectations are already being documented by BAs, RCs, and TOPs in the R1 protocols,
are already being coordinated with recipient entities, such as DPs and GOPs under
R1.9, and are already being assessed and corrected by the BAs, RCs, and TOPs as
required by R2. Therefore, requiring DPs and GOPs to go through the same motions
simply creates another layer of documentation that strains limited resources and does
little to enhance the reliability of the Bulk Electric System.
Response: The OPCPSDT has also modified the standard requirements to make the
DP and GOP subject to the protocols developed by its directing RC, TOP and BA
rather than develop their own. This will hopefully help alleviate any confusion noted
in the comments. The OPCPSDT believes assigning the appropriate responsibilities
to those functions that will be “receiving” Operating Instructions so that clear and
effective communications can occur does enhance reliability. The OPCPSDT supports
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Organization
Yes or No
Question 1 Comment
and encourages the effort of affected entities to develop and implement a common
set of communication protocols. This adds additional clarity through enhanced
uniformity.
C. These duplicative exercises created by Requirements R3 and R4 run counter to the
objectives directed by FERC in Paragraph 81 of FERC’s March 15, 2012 Order on NERC’s
proposed “Find, Fix, and Track” (“FFT”) initiatives (“FFT Order”) as implemented by the
P 81 Task Force. In Paragraph 81 of the FFT Order, FERC noted that “some current
requirements likely provide little protection for Bulk-Power System reliability or may be
redundant.” In complying with FERC’s directives, the Paragraph 81 Task Force set out
to identify standards that
(a) do “little if anything, to benefit or protect the reliable operation of the BES” and
(b) among other possible criteria, are either:
“(a) Administrative in nature, do not support reliability, and are needlessly
burdensome; or
(b) Require responsible entities to develop documents that are not necessary to
protect BES reliability; or
(c) Impose documentation updating requirements that are out of sync with the actual
BES operations, unnecessary, or duplicative; or
(d) Redundant with another FERC-approved Reliability Standard requirement(s), the
ERO compliance and monitoring program, or a governmental regulation.” (See
Paragraph 81 Task Force Technical White Paper.) With respect to this last criterion of
redundancy, the Task Force specifically stated that it is “designed to identify
requirements that are redundant with other requirements and are therefore
unnecessary. Unlike the other criteria listed ... in the case of redundancy, the task or
activity itself may contribute to a reliable BES, but it is not necessary to have two
duplicative requirements on the same or similar task or activity.” (emphasis added). By
creating duplicative requirements on both ends of a coordinated communication
scheme between issuing BAs/RCs/TOPs and recipient DPs/GOPs, the Standards
Drafting Team is creating an unnecessary administrative burden that does “little, if
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
anything, to benefit or protect the reliable operation of the BES.” Even if it may be
argued that requiring double coordination from both issuer and recipient somehow
contributes to a reliable BES, “it is not necessary to have the two duplicative
requirements on the same or similar task or activity.” Proposed Requirements R3 and
R4 would fit all of the criteria listed above that the Paragraph 81 Task Force is using to
identify candidates for retirement and/or revision. D. Finally, the risk created by
proposed Requirements R3 and R4 in conjunction with R1 and R2 is more than simple
administrative duplication. For vertically integrated entities that are registered both as
issuing BAs/RC/TOPs and recipient DPs/GOPs, the redundancy created by Requirement
R3 and R4 could potentially expose them to double penalties for a single violation.
Because of the duplicative documentation and coordination requirements in R1/R2 and
R3/R4, an auditor could interpret a single instance where the communications protocol
of an issuing BA/RC/TOP did not match up with the recipient DP/GOP as multiple
violations. In such an instance, both the issuers and the recipients could conceivably
be penalized because the issuer’s communications protocols were not coordinated
with the recipient’s communications protocols and this lack of coordination was not
assessed and remedied.
Response: The OPCPSDT has substantially modified the standard, making it “results”
oriented and directly tying it to reliability. The draft 6 approach addresses some of
the commenters concern, but sustains the applicability of the DP and GOP because
they can and do have the potential for impacting reliability on the BES.
If the Standards Draft Team does not delete Requirement R3 and R4 in their entirety,
then Georgia Transmission Corporation suggests that R3 be reworded such that the
entities work together to implement and coordinate one set of issuers’
communications protocols (i.e., that of the BAs/RCs/TOPs) instead of two sets of both
issuers’ and recipients’ protocols. This should help to “tighten” the communications
protocols as directed in Order 693 and to mitigate some of the confusion and
duplicative documentation that could arise from Requirements R3 as written:
”R3. Each Distribution Provider and Generator Operator shall implement the
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
documented communication protocols of its associated BA, RC, and TOP that define
the communications expectations of R1. The documented communication protocols
will address, where applicable, the following: [Violation Risk Factor: Low] [Time
Horizon: Long-term Planning ] ....
”and
”R4. In addition to the recommendation to eliminate for the reasons above, GTC still
believes R4 prescribes elements of internal control language to which is not necessary
due to the tightening of communications protocols for issuing entities within R1 and
should still be eliminated under this alternate scenario.
Response: The OPCPSDT changed draft 6 and believes it addresses your concerns.
Response: The OPCPSDT thanks you for your comments.
Western Small Entity
Comment Group
No
In the comment area of the last section as asked.
Response: The OPCPSDT thanks you for your comments.
Oncor Electric Delivery
Company LLC
No
Oncor believes the specificity in the subparts of R1 is unnecessary. Three-part
communication is the preferred method for ensuring that both parties understand an
Operating Instruction and it provides a sufficient mechanism for clear, concise and
accurate communication. In creating a protocol that requires System Operators to
essentially relearn the way to speak (specifically using alpha-numeric identifiers) will
only create confusion and inefficiency as operators try to follow protocol and
catch/correct themselves.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the level of specificity is necessary to attain a level
of communication uniformity among affected entities. If protocols differ dramatically among entities they could be ineffective.
pacificorp
No
PacifiCorp supports the proposed language referenced under R1 and the definition of
“Operating Instruction” but does not support the following language proposed under
R1.4:”Instances where alpha-numeric clarifiers are necessary when issuing an oral
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Organization
Yes or No
Question 1 Comment
Operating Instruction or Reliability Directive, and the format for those clarifiers.”Under
the proposed draft, instances where alpha-numeric clarifiers are “necessary” are not
clearly defined. In the absence of a clear definition, the identification of such instances
is open to interpretation by both the entity and the auditor. Moreover, requiring the
use of alpha-numeric clarifiers is not warranted when the requirements listed in R1.5 R1.8 (requiring the strict use of three-way communication) alleviate any possibility of
miscommunication, which PacifiCorp understands to be the drafting team’s intent in
the development of separate Requirement R1.4. PacifiCorp believes implementing the
use of alpha-numeric clarifiers poses additional risk due to the introduction of
ambiguous language.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the current draft allows the flexibility for an entity
to determine the instances where R1.4 would be necessary. The OPCPSDT reminds commenters they have significant flexibility on
the “how” to develop their communication. The entity is to define the instances where they determine alphanumeric clarifiers
shall apply.
Reliability First
No
Reliability First abstains and offers the following comments for consideration:
1. Requirement R1 and Requirement R3 - Reliability First questions the reasoning
behind the term “where applicable” in the last sentence of Requirement R1 and
Requirement R3. Can the SDT provide examples when there would be instances where
an Entity would not need to address a sub-part within their documented
communication protocols? Reliability First believes all sub-parts under Requirement
R1 and Requirement R3 should be addressed within the respected protocols.
Response: The OPCPSDT agrees that entities should address all protocols that apply
to them. Some entities have pointed out their asset density; locations and their
organizational structure negate the requirement for some protocols. An example is a
BA that would never issue Operating Instructions for Transmission interface
Elements/Facilities. The language referenced is how the OPCPSDT addressed these
exceptions with those entities.
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Organization
Yes or No
Question 1 Comment
2.Requirement R1, Part 1.9 - ReliabilityFirst does not believe it is appropriate for
Requirement R1, Part 1.9 to be addressed within the documented communication
protocols. It is unclear how an entity would address “coordination” of its protocol
within the protocol itself. ReliabilityFirst does agree with the concept of having the
responsible entities be aware of each other’s communication protocols and thus
recommend elevating this to a stand-alone requirement. ReliabilityFirst recommends
the following for consideration as a new R3, “Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall make available its documented
communication protocols that outline the communications expectations of its System
Operators.”
Response: The OPCPSDT agrees and has changed the wording of R1, to eliminate Part
1.9.
Response: The OPCPSDT thanks you for your comments.
CenterPoint Energy Houston
Electric L.L.C.
No
See comments below
Response: The OPCPSDT thanks you for your comments.
Occidental Energy Ventures
Corp
No
See comments below.
Response: The OPCPSDT thanks you for your comments.
Southern Company - Southern
Company Services, Inc.;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
No
Southern Company agrees with the new definition.Southern Company believes that
Requirements R3 and R4 should be deleted.
A. Southern Company believes that Requirements R3 and R4 (applicable to Distribution
Providers (“DPs”) and Generator Operators (“GOPs”)) should be deleted from the
proposed COM-003 standard because the burdens placed on Balancing Authorities
(“BAs”), Reliability Coordinators (“RCs”) and Transmission Operators (“TOPs”) by
Requirements R1 and R2:
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Organization
Yes or No
Southern Company
Generation and Energy
Marketing
Question 1 Comment
(a) sufficiently tighten communications protocols with DPs and GOPs,
(b) render Requirements R3 and R4 administrative, unnecessary, and redundant,
counter to FERC’s objectives as implemented by the NERC Paragraph 81 Task Force,
and
(c) potentially expose some Registered Entities to double jeopardy violations of COM003-1. Specifically, Requirement R1 provides that BAs, RCs, and TOPs must develop
and implement documented communication protocols that
(a) address instances where the issuer of an oral two-party communication Operating
Instruction is required to confirm that the DP or GOP recipient’s response was accurate
or to reissue the Operating Instruction to resolve the misunderstanding (R1.5); and
(b) to address coordination with affected DPs’ and GOPs’ communication protocols
(R1.9). Requirement R2 further requires BAs, RCs, and TOPs to develop methods that
assess communication practices and implement corrective actions necessary to meet
the expectations outlined in these same protocols. Note that this assessment method
would necessarily include assessment of the expectations included in the protocols
regarding DPs and GOPs as required by R1.5 and R1.9.
Meanwhile, proposed Requirement R3 would require the recipient DPs and GOPs to
develop their own documented communications protocols that outline the
communication expectations already addressed in the R1 protocols. [Note that the
Rationale and Technical Justification for COM-003-1 specifies that Requirements R1
and R2 are addressed to entities that both issue and receive Operating instructions
(BAs, RCs, and TOPs) whereas Requirements R3 and R4 are addressed to entities that
only receive Operating Instructions.] Requiring DPs and GOPs in R3 to develop
protocols outlining the communications expectations of its operators -- and requiring
DPs and GOPs in R4 to assess those same operators’ communications practices and
implement corrective actions -- is redundant and unnecessary when those same
expectations are already being documented by BAs, RCs, and TOPs in the R1 protocols,
are already being coordinated with DPs and GOPs under R1.9, and are already being
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Organization
Yes or No
Question 1 Comment
assessed and corrected by the BAs, RCs, and TOPs as required by R2. Therefore,
requiring DPs and GOPs to go through the same motions simply creates another layer
of documentation that strains limited resources and does little to enhance the
reliability of the Bulk Electric System.
B. These duplicative exercises created by Requirements R3 and R4 run counter to the
objectives directed by FERC in Paragraph 81 of FERC’s March 15, 2012 Order on NERC’s
proposed “Find, Fix, and Track” (“FFT”) initiatives (“FFT Order”) as implemented by the
P 81 Task Force. In Paragraph 81 of the FFT Order, FERC noted that “some current
requirements likely provide little protection for Bulk-Power System reliability or may be
redundant.” In complying with FERC’s directives, the Paragraph 81 Task Force set out
to identify standards that
(a) do “little if anything, to benefit or protect the reliable operation of the BES” and
(b) among other possible criteria, are either:
“(a) Administrative in nature, do not support reliability, and are needlessly
burdensome; or
(b) Require responsible entities to develop documents that are not necessary to
protect BES reliability; or
(c) Impose documentation updating requirements that are out of sync with the actual
BES operations, unnecessary, or duplicative; or
(d) Redundant with another FERC-approved Reliability Standard requirement(s), the
ERO compliance and monitoring program, or a governmental regulation.” (See
Paragraph 81 Task Force Technical White Paper.) With respect to this last criterion of
redundancy, the Task Force specifically stated that it is “designed to identify
requirements that are redundant with other requirements and are therefore
unnecessary. Unlike the other criteria listed ... in the case of redundancy, the task or
activity itself may contribute to a reliable BES, but it is not necessary to have two
duplicative requirements on the same or similar task or activity.” (emphasis added). By
creating duplicative requirements on both ends of a coordinated communication
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Question 1 Comment
scheme between issuing BAs/RCs/TOPs and recipient DPs/GOPs, the Standards
Drafting Team is creating an unnecessary administrative burden that does “little, if
anything, to benefit or protect the reliable operation of the BES.” Even if it may be
argued that requiring double coordination from both issuer and recipient somehow
contributes to a reliable BES, “it is not necessary to have the two duplicative
requirements on the same or similar task or activity.” Proposed Requirements R3 and
R4 would fit all of the criteria listed above that the Paragraph 81 Task Force is using to
identify candidates for retirement and/or revision. C. Finally, the risk created by
proposed Requirements R3 and R4 in conjunction with R1 and R2 is more than simple
administrative duplication. For vertically integrated entities that are registered both as
issuing BAs/RC/TOPs and recipient DPs/GOPs, the redundancy created by Requirement
R3 and R4 could potentially expose them to double penalties for a single violation.
Because of the duplicative documentation and coordination requirements in R1/R2 and
R3/R4, an auditor could interpret a single instance where the communications protocol
of an issuing BA/RC/TOP did not match up with the recipient DP/GOP as multiple
violations. In such an instance, both the issuers and the recipients could conceivably
be penalized because the issuer’s communications protocols were not coordinated
with the recipient’s communications protocols and this lack of coordination was not
assessed and remedied.
If the Standards Drafting Team chooses not to delete Requirements R3 and R4, then
Southern suggests that the following rewording of R3 and R4 would be beneficial. If the
Standards Draft Team does not delete Requirement R3 and R4 in their entirety, then
Southern suggests that R3 and R4 be reworded such that the entities work together to
implement and coordinate one set of issuers’ communications protocols (i.e., that of
the BAs/RCs/TOPs) instead of two sets of both issuers’ and recipients’ protocols. This
should help to “tighten” the communications protocols as directed in Order 693 and to
mitigate some of the confusion and duplicative documentation that could arise from
Requirements R3 and R4 as written:
”R3. Each Distribution Provider and Generator Operator shall implement the
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Question 1 Comment
documented communication protocols of its associated BA, RC, and TOP that define the
communications expectations of R1. The documented communication protocols will
address, where applicable, the following: [Violation Risk Factor: Low] [Time Horizon:
Long-term Planning ] ....”and”
R4. Each Distribution Provider and Generator Operator shall develop method(s) to
assess its communications practices and implement corrective actions necessary to
meet the expectations in the documented communications protocols developed for
Requirement R1.”Conforming revisions would also need to be made to the language in
the Measures, VRFs, and VSLs as applicable.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT changed draft 6 and believes it addresses your concerns.
Tacoma Power
No
Tacoma Power supports and strongly suggests reverting back to the Draft 2 definition,
“Operating Communication - Communication of instruction to change or maintain the
state, status, output, or input of an Element or Facility of the Bulk Electric System.”
Response: The OPCPSDT thanks you for your comments. The definition has been changed in response to past industry comments
over several drafts.
City of Austin dba Austin
Energy
No
The latest version of COM-003 introduces a potential conflict with COM-002 related to
the use of one-way burst messaging systems to issue a Reliability Directive. In COM003, the follow Requirements apply:
R1.7 Instances where the issuer of an oral Operating Instruction or Reliability Directive
using a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) is required to verbally or
electronically confirm receipt from at least one receiving party.R1.8 Require the
receiver of an oral Operating Instruction or Reliability Directive using a one-way burst
messaging system to communicate a common message to multiple parties in a short
time period (e.g. an All Call system) to request clarification from the issuer if the
communication is not understood.R3.3 Require the receiver of an oral Operating
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Organization
Yes or No
Question 1 Comment
Instruction or Reliability Directive using a one-way burst messaging system to
communicate a common message to multiple parties in a short time period (e.g. an All
Call system) to request clarification from the issuer if the communication is not
understood.In other words, COM-003 allows one-way burst messaging for Reliability
Directives and prescribes: o the issuer confirm receipt from at least one receiving party
o the receiver request clarification from the issuer if the communication is not
understoodHowever, COM-002 has the following requirements:R2. Each Balancing
Authority, Transmission Operator, Generator Operator, and Distribution Provider that
is the recipient of a Reliability Directive shall repeat, restate, rephrase, or recapitulate
the Reliability Directive.R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either: o Confirm that the
response from the recipient of the Reliability Directive (in accordance with
Requirement R2) was accurate, or o Reissue the Reliability Directive to resolve a
misunderstanding.In other words, in the case of a one-way burst message used for
Reliability Directives, COM-002 does not allow for only those responses required in
COM-003 but instead requires a full 3 way communication from all parties. This
potentially sets up both the issuer and receiver for violating COM-002 if they respond
to a one-way burst message Reliability Directive as the requirements indicate in COM003.In order to fully comply with BOTH standards, the receiver would have to contact
the issuer and repeat what was said on the original burst message; then, the issuer
would confirm the response was accurate before acting on the message.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has eliminated R1, Parts 1.7, 1.8, and 3.3, which reference
requirements for all calls.
NERC
No
This will require each entity to develop its own unique protocol. This will not "tighten
up" communications. Having each entity follow its own protocol will complicate and
confuse communications. One entity will be attempting to communicate with another
entity which is not familiar with the protocol being used by the first entity because the
second entiy uses a diferent protocol. Protocols if required should be standardized.
Moreover, the proposed language requires a protocol that "meets the expectations of
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
its System Operators". The plain meaning of that sentence as writtem is that the
protocol meet the expectations of the individual workers, not the entity itself. If this
change is going to be approoved, should not it read "Each (entity) shall develop
protocols that PROVIDE ITS expections of its System Operators"?
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has substantially altered the standard by changing the R1
language to require the TOP, BA and RC to develop the protocols subject to approval of the RC.
Independent Electricity
System Operator
No
We agree with most of the changes made. We offer a preferred wording for Part 1.4,
and have a concern over the ambiguity of Part 1.6 and Part 1.8.
Part 1.4 states that:1.4 Instances that alpha-numeric clarifiers are necessary when
issuing an oral Operating Instruction or Reliability Directive, and the format for those
clarifiers. A preferable description would say that the protocol should address the risk
of miscommunication arising from alpha-numeric identifiers. This could be addressed
through the use of the phonetic alphabet or through different means if local conditions
dictate a different approach.
Response: The requirement permits the entity to determine the circumstances where
they would employ alphanumeric clarifiers. The examples you cited: “The phonetic
alphabet or through different means if local conditions dictate a different approach”
would be acceptable.
As noted above, we are concerned over the ambiguity of Part 1.6, which states that:
1.6 Require the recipient of an oral two party, person-to-person Operating Instruction
to repeat, restate, rephrase, or recapitulate the Operating Instruction, if requested by
the issuer.
When read together with the last sentence in R1, “The documented communication
protocols will address, where applicable, the following:”, this part is unclear as to
whether it is to identify the instances that the repeat is required, or that the
documentation needs to include explicit statements that the issuer needs to request a
repeat when issuing an operating instruction or reliability directive which the issuer
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
feels a repeat is necessary. This sub-requirement part, as written, is ambiguous and
appears to be more applicable to the instruction recipient than the issuer. When read
together with Part 3.2, Part 1.6 appears to be requiring the issuer to identify the
instances that a repeat is required. We therefore suggest the SDT to revise Part 3.2 as
follows:
1.6 Instances where it requires the recipient of an oral two party, person-to-person
Operating Instruction to repeat, restate, rephrase, or recapitulate the Operating
Instruction, if requested by the issuer.
Response: The OPCPSDT agrees and has reworded R1, Part 1.6 (Now Part 1.5) to
reflect its intent that a repeat back is required. The OPCPSDT has elected to eliminate
R3 in its entirety.
Similar concerns with Part 1.8 except the mirror part 3.3 does not contain the wording
“if requested by the issuer”. Hence, we assume that the recipient is required to request
clarification from the issuer if the communication is not understood without having to
be asked. Therefore, we propose Part 1.8 be revised as follow:1.8 A stipulation that the
receiver of an oral Operating Instruction or Reliability Directive using a one-way burst
messaging system to communicate a common message to multiple parties in a short
time period (e.g. an All Call system) to request clarification from the issuer if the
communication is not understood.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has eliminated
R1, Parts 1.7, 1.8, and 3.3, which reference requirements for all calls.
Response: The OPCPSDT thanks you for your comments.
Tennessee Valley Authority
No
We agree with the definition of Operating Instruction. While we also can agree to the
changes made to R1, we feel R3 in its entirety is unnecessary and duplicative. Removal
of the word “develop” would eliminate double-jeopardy concerns. R3 could be
acceptable if “develop and” is omitted and “as developed in R1” is inserted after
“protocols” and before “that.” It should be noted that this suggestion only applies to
the sub-requirements in R1 that correspond to the proposed sub-requirements in R3.
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has eliminated R3 in draft 6.
Western Electricity
Coordinating Council
No
We do not agree with the revisions to the language of R1 and R3. The changes are a
lowering of the bar for reliability. Earlier versions identified specific communication
protocols for each BA, RC, and TOP. These specific requirements would have resulted
in a consistent approach to communications between all sysem operators. The
proposed revisions coupresult in varying procedures that do not close the gap in
communcations. The watered-down versions of the requirements are essentially a fillin-the-blank type of standard allowing each applcable entity to develop their own
protocols.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes WECC is permitted to create communication
protocols that are robust and as comprehensive as it desires. The OPCPSDT would recommend that all entities create strong
protocols.
Ameren
No
We do not believe that we need a definition for the term “Operating Instruction” and
we would like to see this defined in the entities protocol. However if a definition is
included, we ask the SDT to require an RC, TOP, or BA to identify when an Operating
Instruction is used to communication to a GOP or DP.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has considered this request often and believes it has merit,
but it may create undue burdens on some operators. If an entity wishes to announce an “Operating Instruction”, it may
incorporate that in its communication protocols.
Public Service Enterprise
Group
No
We found what we believe to be a typo in the definition of "Operating Instruction."
The defined term “Operating Instruction” has this phrase: “...where the recipient of
the command is expected to act, to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.”
The comma after “act” should be removed because it is not grammatically correct. If
removed, the phrase would become: “...where the recipient of the command is
expected to act to change or preserve the state, status, output, or input of an Element
of the Bulk Electric System or Facility of the Bulk Electric System.
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Organization
Yes or No
Question 1 Comment
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has corrected the error.
SPP Standards Review Group
No
We suggest adding 'as determined by the Functional Entity' to R1 to clarify that the
protocols are those specifically determined by the applicable responsible entity:
'The documented communication protocols will address, where applicable as
determined by the Functional Entity, the following:'
Response: The OPCPSDT believes that is redundant based on the previous addition of
“where applicable”.
Is the intent of R1.3 for applicable entities to maintain a list of common name
identifiers which must be utilized in communications with all affected entities? If so, a
similar requirement (R18) in TOP-002-2 is currently proposed to be eliminated in TOP002-3. Therefore it shouldn’t be added back by this requirement. Can the drafting team
be more specific as to exactly what is required in R1.3 without going overboard as in
the existing wording? We understand the need to be sure that affected entities do not
have any misunderstandings regarding the specific facility that is at issue. However, our
experience does not indicate that this is a problem. If we can’t relax R1.3, we suggest
eliminating it altogether.
Response: R1.3 is designed to increase familiarity with Transmission interface
Elements and Facilities to prevent confusion and increase situational awareness. The
requirement calls for entities to ensure that operators are aware of the names or
designators of interface equipment between those entities. It is up to the affected
entities to determine how they would accomplish this through their communication
protocols. One example may be designate in the documented Communication
Protocols to use the name of the Transmission interface Element/Facility assigned by
the owner of such Element/Facility.
We understand the need to be sure that affected entities do not have any
misunderstandings regarding the specific facility that is at issue. However, our
experience does not indicate that this is a problem. If we can’t relax R1.3, we suggest
eliminating it altogether since we believe this not does significantly impact the
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
reliability of the BES.
Response: The requirement focuses on interface Elements and Facilities only. An
entity may develop the protocols in a manner that supports their unique operating
footprint.
The use of the term ‘coordination’ in R1.9 causes concern in determining exactly what
is required to coordinate. This could become a compliance nightmare for applicable
entities. We suggest replacing R1.9 with “Provide each affected Reliability Coordinator,
Balancing Authority, Transmission Operator, Distribution Provider, and Generator
Operator with its communication protocols.”
Response: The OPCPSDT agrees and has changed the wording of R1, to eliminate Part
1.9.
Response: The OPCPSDT thanks you for your comments.
Idaho Power Company
No
Yes for R1 and R3. No for the definition of "Operating Instructions". It is not written
very well and is difficult to understand. The language below is offered as a suggestion
to simplify the definition.
Operating Instruction -A command by a System Operator of a Reliability Coordinator,
Transmission Operator, or Balancing Authority where the recipient is instructed to
change or preserve the state, status, output, or input of any portion of the Bulk Electric
System. Discussions of general information and of potential options or alternatives to
resolve BES operating concerns are not commands and are not considered Operating
Instructions.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has considered your comments and elects to maintain the
existing definition of an Operating Instruction because it reflects the response to many other comments from previous drafts.
SERC OC Standards Review
Group
No
ISO/RTO Standards Review
No
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 1 Comment
Committee
South Carolina Electric and
Gas
No
ISO New England Inc.
No
Cogentrix Energy Power
Management
No
Vijayraghavan
No
Manitoba Hydro
Yes
(1) Definition “Operating Instruction” - reference is made to both ‘Bulk Electric System’
and ‘BES’. For consistency, either the words or acronym should be used.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has made the correction.
ACES Standards Collaborators
Yes
(1) We appreciate the efforts of the drafting team in developing this standard and the
steps the team took to resolve industry’s concerns.
(2) We continue to have concerns that the glossary term “Operating Instruction”
overlaps with “Reliability Directive.” The standard as written allows flexibility on how
to deal with these two terms/situations and gives the registered entity the
responsibility to handle these types of communications in its protocol. Because of the
flexibility and in the spirit of moving forward, we can support the approach by the
drafting team that would allow NERC to address FERC concerns. This represents a
good balance.
Response: The OPCPSDT thanks you for your comments. The intention of the OPCPSDT is to balance uniformity with enough
flexibility. Draft 6 includes more language to further separate Operating Instructions and Reliability Directives
Duke Energy
Yes
R1.7, R1.8, and R3.3 - All Call should not be capitalized since it is not a defined term. It
should instead be placed in quotation (“All Call”).R1.6, R1.8, R3.2, and R3.3 - Change
the word “Require” to “Requirement for” to better align grammar with R1.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has eliminated R1, Parts 1.7, 1.8, and R3, Part 3.3, which
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Organization
Yes or No
Question 1 Comment
reference requirements for all calls. Also, The OPCPSDT has eliminated R1, Parts 1.6 and R3, Part 3.2.
MISO
Yes
While MISO is not opposed to the current version of COM-003-1, it remains concerned
regarding the overlap between COM-002-3 and COM-003-1. As written, the definition
of “operating instruction” encompasses “reliability directives”. This overlap and the
application of multiple separate standards to operator communications in general is
likely to result in ambiguity and confusion. Further, that only certain sub-requirements
of COM-003-1 also mention reliability directives further confuses the applicability of
these standards. While the identified overlap and application is manageable, it is
recommended that this overlap be addressed at the earliest opportunity. One clear,
succinct standard that addresses both operator communications, whether reliability
directives or operating instructions, is respectfully recommended.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has removed references to Reliability Directive.
Northeast Power Coordinating
Council
Yes
Seattle City Light
Yes
Hydro One Networks Inc.
Yes
MRO NSRF
Yes
Bonneville Power
Administration
Yes
Salt River Project
Yes
San Diego Gas & Electric
Yes
Arizona Public Service
Company
Yes
Pacific Gas and Electric
Company
Yes
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Muscatine Power and Water
Yes
Self
Yes
Georgia System Operations
Corporation
Yes
Exelon
Yes
City of Garland
Yes
Clark Public Utilities
Yes
NIPSCO
Yes
The United Illuminating
Company
Yes
Edison Mission Marketing &
Trading
Yes
American Tranmission
Company
Yes
CPS Energy
Yes
SMUD/Balancing Authority of Northern
California
Question 1 Comment
SMUD would like to thank the Drafting Team for their efforts. While we agree with the
intent of COM-003 SMUD believes the requirements R1.5 & R1.5 are too vague.
Requiring the receiving party to repeat back the Operating Instruction only (emphasis
added) if requested does not provide insurance that the receiving party would have a
clear understanding of the necessary actions intended by the issuing party.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the requirement for a repeat back of an Operating
Instruction is important because it allows the issuer to determine whether a recipient understands a command. The issuer can
then reissue the command until they are convinced the recipient understands it.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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2. The SDT has proposed new language in COM-003-1, R2 and R4: “Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop method(s) to assess System Operators’ communication practices and implement corrective
actions necessary to meet the expectations in its documented communication protocols. (the same language exists for R3, except
DPs and GOPs listed as applicable entities and the use of “operators” instead of “System Operators”). ” Do you agree with these
proposed requirement changes? If not, please explain in the comment area of the last question:
Summary Consideration:
Requirements (Question 2 Comments on R2 and R4):
A majority of the commenters expressed concerns over how an entity’s internal controls to improve System Operators’
communication performance would be audited. The commenters state that auditing internal controls is contrary to both,
existing ERO doctrine and ongoing initiatives that are seeking to improve the effectiveness of the audit process. Some
commenters also claim the potential for double jeopardy exists. The lack of certainty over how compliance would be
administered caused commenters significant concern.
The OPCPSDT understands the commenters’ concerns. The OPCPSDT decided to eliminate the COM-003-1, draft 5, R2
and R4 requirements in draft 6. Draft 6 features a results based approach that clearly specifies compliance and is linked
to reliability results. The draft 6 requirements will also reduce the exposure of entities to voluminous compliance
documentation.
The OPCPSDT points out that many other commenters responded positively to the use of internal controls and preferred
the assess and correct requirement.
After consideration of all of the comments, the OPCPSDT voted for the approach featured in COM-003-1, draft 6.
Organization
Yes or No
NIPSCO
No
Question 2 Comment
"Each Distribution Provider and Generator Operator shall develop and implement
documented communication protocols that outline the communications expectations
of its operators." This language is unclear as to the communication expectation to its
operators. Does this address the communications between the DP and the TOP only?
Or does this apply to the communication between the DP and field personnel?
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified COM-003-1, draft 6 to address your concern.
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Manitoba Hydro
No
Question 2 Comment
(1) Compliance Data Retention, 1.2 - COM-001 and COM-002 standards both read 3
months or 90 days for the retention of evidence. It is unclear as to why the retention
has been doubled in this standard to 180 days for R2, M2 and R4, M4. For consistency
and simplicity, 90 days should be used.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified COM-003-1, draft 6 to address your concern.
CPS Energy
No
Distribution Providers (DP) may be co-located in the same room with Transmission
Operators (TOP) and would have oral communications and not use a telephone or
other messaging system. Generator Operators (GOP) should have a separate standard.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the risk of misunderstanding and
miscommunication exists in face-to-face communication as you describe. The use of communication protocols reduce that risk and
subsequent harm it could cause during BES operations. The current draft of the standard would allow an entity to develop its own
communication protocols to identify the instances of when to use the protocols. There is no requirement to use a telephone or
messaging system. The OPCPSDT has modified COM-003-1 to address your concern.
American Electric Power
No
If an entity has a control in place, but that control is somehow not viewed favorably
during an audit, is that entity potentially in violation of an additional requirement? R2
and R4 appear to have potential double jeopardy implications.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a “Reliability Directive.”
Western Small Entity
Comment Group
No
In the comment area of the last section as asked.
Response: The OPCPSDT thanks you for your comments. We will respond to those comments.
Georgia System Operations
Corporation
No
Internal controls-like language was first introduced into draft 3, R3 and R4. We note
that after the technical conference held in Atlanta - Feb 2013, draft 5, R2 and R4
appear to still have remnants of this control language. As discussed in length, it is not
appropriate to have such control language in reliability requirements. As GSOC recalls,
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Organization
Yes or No
Question 2 Comment
insertion of R2 and R4 was not discussed or agreed upon at the conference.
Response: The Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a
Reliability Directive.
GSOC recalls that statements were made by participants that it was pre-mature to
include controls language in the standard/requirement at this time. So it appears that
revisions to the contrary when were made when in fact NERC statements were made
that the full RAI process would not be in place until 2016.GSOC still supports the RAI as
it “proposes to transition away from a process-driven enforcement strategy to a
proactive, risk-based strategy that clearly defines, communicates, and promotes
desired entity behavior in an effort to improve the reliability of the BPS.” However,
this transition has not been implemented yet. Until NERC transitions the Compliance
Monitoring and Evaluation Program (CEMP) to the risk-based strategy, we are still
under the past/current process-driven enforcement strategy. A primary concern of
GSOC is that until the RAI is developed and provides audit guidance regarding
treatment of entity control measures, then auditor subjectivity may creep into the
audit process. GSOC believes that once a transition to a risk-based strategy is
complete, only then will there be an established “set of parameters” to “guide the
exercise of enforcement discretion.” “The parameters that would guide the exercise of
discretion as well as the protections” “would be in place to ensure due process and to
ensure that enforcement decisions are sound and reflect a consistent application of the
ERO enterprise enforcement strategy.”More specifically, The “decline to pursue
option” will have replaced Find, Fix, and Track “after necessary training of [NERC and
Regional] personnel, industry and stakeholder outreach, and development of process
improvements.” At that time, “for those violations that pose a serious or substantial
risk, or are not proper candidates for the exercise of enforcement discretion, the ability
to impose penalties up to the statutory maximum or adopt increased monitoring and
broader audit scope must be retained.” At that time, internal controls will be the way
to do business (operations/planning) and the process-driven zero-tolerance
enforcement process will only apply to those serious or substantial risks. Regarding
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Organization
Yes or No
Question 2 Comment
zero tolerance, some in industry have the false perception that putting internal
controls-like language in a reliability requirement NOW will subsequently allow
auditors to apply non-zero tolerance. To the contrary, GSOC believes the current
process-driven CMEP inclusive of requirements with controls-like language actually
requires zero-tolerance treatment. If this standard is passed in its present form an
auditor will not have the discretion to “decline to pursue” and must treat every
possible violation the same. Of course, NERC/Regional compliance enforcement can
now treat some possible violations as applicable to Find, Fix, Track. But that does not
require controls language in a requirement. Accordingly, mitigating COMPLIANCE risk
has been and still is a driver for the industry’s compliance programs. Once the CMEP is
transitioned to the risk-based strategy, then such language will be in place with the
CMEP and the industry can focus more on RELIABILITY risk and less on COMPLIANCE
risk.
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a
Reliability Directive.
In addition, GSOC notes that controls-like language is a requirement which is
administrative and therefore meets the criteria under P81 for exclusion from reliability
requirements. It is not a risk-based reliability requirement. A reliability requirement is
one that is (as the statutory definition says) a requirement to provide for reliable
operation of the bulk-power system. A reliability requirement includes requirements
for the operation of existing bulk-power system facilities, including cyber-security
protection, and the design of planned additions or modifications to such facilities to
the extent necessary to provide for reliable operation of the bulk-power system. This
administrative requirement does not meet the criteria for being a reliability
requirement.
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a
Reliability Directive.
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Organization
Yes or No
Question 2 Comment
Response: The OPCPSDT thanks you for your comments.
Oncor Electric Delivery
Company LLC
No
Oncor supports the shift in compliance to the internal controls approach and we look
forward to NERC providing a programmatic/principles framework in a collaborative
approach with the industry. In the absence of this framework, it is unknown how the
concept of "assess and correct" will evolve. As the framework is developed including
the "assess and correct" concept, Oncor requests that continuous focus be placed on
implementing principles including this concept and not requiring or specifying internal
controls which would place additional compliance burden on entities. The internal
controls principles/framework should enable entities to establish internal controls
model utilizing deficiency correction approach but should not mandate the approach at
the Standard/Requirement level. Internal Controls Program needs to be defined by an
Entity, it is not a “One Size Fits All”. The standards/RSAWs should reflect this
understanding. Oncor does not see how the Drafting Team adequately addressed this
concern. NERC and the rest of the industry should work together and define the
framework around Internal Controls.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive. Draft 6 does not address or
reference internal controls in its requirements.
pacificorp
No
PacifiCorp does not support the following language referenced under R2 (with
substantially similar language in R4) as it pertains to the Balancing Authority, Reliability
Coordinator, Transmission Operator, Generator Operator, and Distribution
Provider:"...shall develop method(s) to assess System Operators’ communication
practices and implement corrective actions necessary to meet the expectations in its
documented communication protocols developed for Requirement R1.”In the absence
of any proposed criteria for measuring how the aforementioned method(s) are
developed, determining whether an entity has successfully met the expectations it has
established in its communication protocols is subject to a multitude of interpretations.
Moreover, Measures M2 and M4 are focused exclusively on the results of an entity’s
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 2 Comment
periodic assessment and corrective actions. PacifiCorp believes that a results-based
review of an entity’s assessment fails to provide any insight into the quality of the
assessment itself.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive. Draft 6 does not address or
reference internal controls in its requirements.
City of Garland
No
R2 & R4 Requirements are written assuming that corrective actions will be necessary.
Should be written to state corrective actions “if necessary”
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive. Draft 6 does not address or
reference internal controls in its requirements.
Tennessee Valley Authority
No
R2 is acceptable and R4, as stated above for R3, is unnecessary and duplicative.
Response: The OPCPSDT thanks you for your comments. Please refer to the response to your prior comment.
ReliabiltyFirst
No
ReliabilityFirst abstains and offers the following comments for consideration:
1. Requirement R2 - ReliabilityFirst believes the concept of implementation of the
method(s) to assess System Operators’ communication should be added to the
requirement. If the Entity is not required to implement the method(s), an Entity may
never find any deficiencies and get to the point of implementing the corrective actions
necessary to meet the expectations in its documented communication protocols.
ReliabilityFirst recommends the following for consideration,
“Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop and implement method(s) to assess System Operators’ communication
practices and implement corrective actions necessary to meet the expectations in its
documented communication protocols developed for Requirement R1.”
2. Requirement R4 - Similar to the comment on Requirement R2, ReliabilityFirst
believes the concept of implementation of the method(s) to assess System Operators’
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Organization
Yes or No
Question 2 Comment
communication should be added to the requirement. ReliabilityFirst recommends the
following for consideration,
“Each Distribution Provider and Generator Operator shall develop and implement
method(s) to assess operators’ communication practices and implement corrective
actions necessary to meet the expectations in its documented communication protocols
developed for Requirement R3.”
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive.
North American Generator
Forum Standards Review
Team
No
See answer to 4 below.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT will address your comments at that location
Exelon
No
See comment #3 in the comment area of the last question
Response: The OPCPSDT thanks you for your comments. The OPCPSDT will address your comments at that location
NIPSCO
No
See comments submitted on NIPSCO's behalf by Julaine Dyke
Response: The OPCPSDT thanks you for your comments. The OPCPSDT will address your comments at that location
Georgia Transmission
Corporation
No
See GTC’s comments above regarding deletion of R4. GTC also believes the same logic
can apply to R2 and recommends to be deleted. Additionally, see GTC’s comments
regarding the conflict with the drafting team’s proposal to inadvertently define a new
function for the DP “operators”. Lastly, DPs do not issue Operating Instructions; DP
field personnel only receive instructions from others.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive. Draft 6 does not address or
reference internal controls in its requirements.
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Organization
Yes or No
Southern Company - Southern
Company Services, Inc.;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing
No
Question 2 Comment
See Southern’s comments above regarding deletion and/or modification of R4. If R4
was not part of this question then Southern’s answer would change to yes for this
question. Additionally, GOPs do not issue Operating Instructions. They only receive
instructions from others. GOPs should have a communications procedure as part of
their operations. However, the methods used are proper business decisions made by
the GOP. The content, thoroughness and effectiveness of a communications plan are
excellent items to consider when assessing an internal compliance program.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance in avoiding communication related events that would generate a Reliability Directive. Draft 6 does not address or
reference internal controls in its requirements.
Tacoma Power
No
Tacoma Power supports Draft 2 - The requirement to establish communication
protocols should be identical for BA, TO, RC, GO, and DP. To make different
requirements for different functions is very confusing for those who perform multiple
functions.Go back to basic “3-part communication” (and include an option for push-to
talk). Remove fuzzy language such as “if requested”. The Standard should leave it up
to the Entity to establish their communication protocols and procedures based upon
the type of communication systems they are using. This draft seems to trying to write
the procedures for every type of possible communication equipment rather than set a
standard for how to communicate.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has substantially altered the standard by changing the R1
language to require the TOP, BA and RC to develop the protocols subject to the approval of the RC. This and other changes address
many of your comments.
Indiana Municipal Power
Agency
No
The COM-003-1 standard needs to an independent document used to audit entities
and the RSAW should not be used to address items not covered in the standard as to
what is acceptable and what is not acceptable when it comes to instances when three-
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Organization
Yes or No
Question 2 Comment
part communication is not properly followed by an entity during an audit. IMPA is
concerned that an entity has one instance of a missed repeat back and per the entity’s
plan they address it and re-train for it; NERC could still call it a violation. The standard
language needs to be clear about the latitude that an entity is given to work things out
within their internal controls. The main item that the standard should do is to make
sure that entities have communication plans and their internal controls within the
communication plans contain a process to monitor and self-deal with corrective action
of instances where its communication plan was not properly followed. This language
needs to be clearly stated in the standard and not somewhat stated in the RSAW.
IMPA believes the prior version of this draft standard was close when it used language
on internal controls that stated “implement, in a manner that identifies, assesses, and
corrects deficiencies...”.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance to avoiding communication related events that would generate a Reliability Directive.
Florida Municipal Power
Agency
No
Use of the term “System Operators’” is ambiguous; does the requirement cause
internal evaluation, or evaluation of neighboring System Operators? We assume the
former and suggest adding “its” in front of “System Operators”.
Response: The OPCPSDT thanks you for your comments. The term “System Operator” has been eliminated from the requirements of
draft 6 of COM-003-1.
Ameren
No
We ask the SDT to delete requirements R3 and R4 because they are redundant and
may cause double jeopardy for entities as these requirements are addressed in
requirements R1 and R2 for the BA, RC, and TOP communication protocols with
DPs/GOPs.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance to avoiding communication related events that would generate a Reliability Directive.
Oklahoma Gas & Electric
No
We believe that R2 and R4 should already be covered in PER-005
Response: The OPCPSDT thanks you for your comments. The OPCPSDT disagrees—training is only one of several means of
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Organization
Yes or No
Question 2 Comment
accomplishing the goals of COM-003-1.
SPP Standards Review Group
No
We have concerns with the continued inclusion of Distribution Provider in the list of
Applicable Entities. Although this is in response to a FERC directive, the risk that
Distribution Providers present to the BES is minimal at best. Actions taken by
Distribution Providers which impact the reliability of the BES, load shedding for
example, are adequately covered under COM-002-3 which applies to emergency
situations.
There are also jurisdictional questions associated with FERC directing the inclusion of
Distribution Providers. If the Distribution Provider must remain as an Applicable Entity,
then we would propose deleting Distribution Provider from R3 and R4 and then follow
with the addition of a new R5 and R6.R5.
Each Distribution Provider that is the recipient of an oral Operating Instruction, other
than Reliability Directives, shall:
5.1 Use the English language, unless another language is mandated by law or
regulation.
5.2 Repeat, restate, rephrase, or recapitulate the oral Operating Instruction.
5.3 For oral Operating Instructions issued as a one-way burst message to multiple
parties in a short time period (e.g. an All Call system), request clarification from the
issuer if the communication is not understood.
R6. Each Distribution Provider shall develop method(s) to assess operators’
communication practices and implement corrective actions necessary to meet the
expectations in Requirement R5.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified COM-003-1 to address your concern.
Northeast Power Coordinating
Council
No
SERC OC Standards Review
Group
No
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Organization
Yes or No
ISO/RTO Standards Review
Committee
No
South Carolina Electric and
Gas
No
Edison Mission Marketing &
Trading
No
ISO New England Inc.
No
Cogentrix Energy Power
Management
No
Vijayraghavan
No
Question 2 Comment
Response:
ACES Standards Collaborators
Yes
(1) We appreciate the drafting team allowing the registered entity to have the
flexibility in determining the assessment methods and corrective actions to implement.
Further, we appreciate that the measures for these requirements state that the
assessment should be “periodic” but do not impose any strict timeline. We
recommend that the RSAW state the same or similar language, as the entity should be
able to dictate how often the assessments occur in their protocols, policies, and
procedures.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance to avoiding communication related events that would generate a Reliability Directive.
Seattle City Light
Yes
Seattle City Light is supportive of the proposed "assess and implement" approach to
compliance for COM-003 R2 and R4.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance to avoiding communication related events that would generate a Reliability Directive.
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Organization
Yes or No
MISO
Yes
Question 2 Comment
We believe the drafting team found a very reasonable solution to meet a FERC
directive for a situation that deals with managing the quality of the millions of operator
communications that occur annually.
Response: The OPCPSDT thanks you for your comments.
Duke Energy
Yes
MRO NSRF
Yes
Luminant
Yes
Bonneville Power
Administration
Yes
Salt River Project
Yes
Western Electricity
Coordinating Council
Yes
San Diego Gas & Electric
Yes
Arizona Public Service
Company
Yes
Pacific Gas and Electric
Company
Yes
Muscatine Power and Water
Yes
Self
Yes
Idaho Power Company
Yes
NERC
Yes
Public Service Enterprise
Group
Yes
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Organization
Yes or No
City of Austin dba Austin
Energy
Yes
Clark Public Utilities
Yes
Occidental Energy Ventures
Corp
Yes
The United Illuminating
Company
Yes
Independent Electricity
System Operator
Yes
American Tranmission
Company
Yes
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Question 2 Comment
54
3. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3 and R4?
Summary Consideration:
VRFs and VSLs (Question 3):
The OPCPSDT acknowledges there were many comments on draft 5 regarding VSLs and VRFs and we appreciate the
contributions.
The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have been modified to reflect those changes. The
elimination of the “assess and correct” language and the revisions to R1, R2 and R3 have resulted in extensive changes
to VRFs and VSLs for draft 6.
Organization
Yes or No
ACES Standards Collaborators
No
Question 3 Comment
(1) There are a few changes that need to be made in the severe VSLs for R1 and R3.
The severe VSL states, “The Responsible Entity did not implement any documented
communication protocols as required in Requirement R1.” This statement is in direct
conflict with the lower, medium and high VSLs because if an entity violated at least one
documented communication protocol (low VSL), or two protocols (medium VSL), or
three protocols (high VSL), then the entity violated “any.” We recommend striking the
statement in the severe VSL to avoid this conflict.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes. The draft 6 approach has required substantial changes to the VSLs and VRFs.
ReliabiltyFirst
No
1. VSL for Requirement R1 - In order to capture instances where more than three parts
were not addressed, the second VSL under the “High” category needs to be modified
to state, “...did not implement three (3) or more of the nine (9) parts of...”
2. VSL for Requirement R2 - ReliabilityFirst recommends including a lower bounds
Organization
Yes or No
Question 3 Comment
around the “Medium VSL”. As written, an entity would fall into the Medium VSL range
if they only implemented 1% or implemented 49% of the corrective actions.
ReliabilityFirst recommends gradating the VSLs using 25% increments across all four
VSLs.3. VSL for Requirement R4 - ReliabilityFirst recommends including a lower bounds
around the “Medium VSL”. As written, an entity would fall into the Medium VSL range
if they only implemented 1% or implemented 49% of the corrective actions.
ReliabilityFirst recommends gradating the VSLs using 25% increments across all four
VSLs.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Luminant
No
All comments are shown in response to Question 4.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT will address your comments at that location.
Western Electricity
Coordinating Council
No
Based on the changes we believe are necessary for Requirements R1 and R3, we
beleive the VSLs should be changed accordingly.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have been
modified to reflect those changes.
Ameren
No
Concerning the VRF and VSLs we ask the SDT to review the severity levels because we
do not believe that any violations of this standard should be at either a High or Severe
level since these are documentation requirements.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the VSL levels, in addition to adhering to NERC and
FERC guidelines, properly reflect the threshold of severity for violations.
CPS Energy
No
I do not agree with the requirements, therefore I do not agree with the VRF's and VSL.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
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Organization
Yes or No
pacificorp
No
Question 3 Comment
PacifiCorp does not support the VRFs and VSLs for Requirements R2 and R4. In keeping
with PacifiCorp’s comment in Question 2, a method of assessment that is not explicitly
defined and cannot be measured against a clear set of criteria makes it difficult for an
entity or auditor to determine whether any of the corrective actions taken by an entity
have fulfilled the expectations documented in their communication protocols.
Assigning a severity level based on a percentage of completion is redundant when an
entity cannot determine what a “complete” assessment is or the criteria by which it is
measured.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have been
modified to reflect those changes.
Georgia System Operations
Corporation
No
R2 & R4 - we believe without any definitive guidance from NERC's still-undeveloped
RAI, auditors will apply subjective judgment as to the adequacy of controls used to
perform periodic assessments and therefore VRF and VSL are not appropriate.
Response: The OPCPSDT thanks you for your comments. Draft 6 eliminates R2 and R4 “assess and correct” language and ties
performance to avoiding communication related events that would generate a Reliability Directive. The OPCPSDT has modified
draft 6, and all of the VRFs and VSLs have been modified to reflect those changes.
North American Generator
Forum Standards Review
Team
No
See answer to 4 below.
Response: The OPCPSDT thanks you for your comments. Please see our response at that location.
CenterPoint Energy Houston
Electric L.L.C.
No
See comments below
Response: The OPCPSDT thanks you for your comments. Please see our response at that location.
Salt River Project
No
The VSLs give a higher violation to a GO than a BA for exactly the same error, even
though the consequences with the BA are much greater. A GO who fails to require 3part responses when requested is tagged with a Moderate violation, the BA with a
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Organization
Yes or No
Question 3 Comment
lower. We believe the VRF should be Low rather than Medium for R4.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Seattle City Light
No
The VSLs give a higher violation to a GO than a BA for exactly the same error, even
though the consequences with the BA are much greater. A GO who fails to require 3part responses when requested is tagged with a Moderate violation, the BA with a
lower. Both should be lower.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Clark Public Utilities
No
The VSLs give a higher violation to a GO than a BA for exactly the same violation, even
though the consequences with the BA are much greater. A GO who fails to require 3part responses when requested is tagged with a Moderate violation, the BA with a
Lower. Both should be Lower.
Response: The OPCP SDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Southern Company - Southern
Company Services, Inc.;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing
No
We agree with the VRFs and VSLs for R1 and R2. As discussed above, R3 and R4 should
not be part of the standard. To the extent R3 and R4 should be deleted or modified,
the VRFs and VSLs should be modified accordingly.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
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Organization
Yes or No
Question 3 Comment
been modified to reflect those changes.
Tennessee Valley Authority
No
We agree with the VRFs and VSLs for R1 and R2. Based on our previous comments, we
do not agree with the need for R3 and R4, and therefore VRFs and VSLs for these
requirements are not needed.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Georgia Transmission
Corporation
No
We agree with the VRFs and VSLs for R1. As discussed above, R3 and R4 should not be
part of the standard. To the extent R3 and R4 should be deleted or modified, the VRFs
and VSLs should be modified accordingly.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
SPP Standards Review Group
No
While we understand the process that gets us to the point where the VRFs for R1 and
R3 are Low and those for R2 and R4 are Medium, in this situation we question the logic
of the process. If developing a document only deserves a low VRF then how can we
logically say that not implementing the items contained in the document is a medium?
What happens if the document is flawed? This appears to be an inverted pyramid. We
suggest using Low for all requirements.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Oklahoma Gas & Electric
No
While we understand the process that gets us to the point where the VRFs for R1 and
R3 are Low and those for R2 and R4 are Medium; however, in this situation we
question the logic of the process. If developing a document only deserves a Low VRF
then how can we logically say that not implementing the items contained in the
document is a Medium? What happens if the document is flawed? We suggest using
Low for all requirements.
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Organization
Yes or No
Question 3 Comment
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
SERC OC Standards Review
Group
No
South Carolina Electric and
Gas
No
Edison Mission Marketing &
Trading
No
Cogentrix Energy Power
Management
No
Tacoma Power
No
Vijayraghavan
No
Manitoba Hydro
Yes
Although Manitoba Hydro is in general agreement with the standard, we have the
following clarifying comments:
(1) VSLs, R1 - the Severe category is missing the concept of ‘The Responsible Entity did
not implement four or more documented communication protocols as required in
Requirement R1’. As written, it skips from ‘three or more’ to not implementing any of
them. There is a gap if there is a Responsible Entity that failed to implement for
example, 5 of the protocols.
(2) VSLs, R3 - for readability, the first paragraph should be written ‘The Responsible
Entity did not address any parts of Requirement R3 in their documented
communication protocols as required by Requirement R3.”.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified draft 6, and all of the VRFs and VSLs have
been modified to reflect those changes.
Duke Energy
Yes
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Organization
Yes or No
MRO NSRF
Yes
Bonneville Power
Administration
Yes
San Diego Gas & Electric
Yes
Arizona Public Service
Company
Yes
Pacific Gas and Electric
Company
Yes
Muscatine Power and Water
Yes
Self
Yes
Idaho Power Company
Yes
NERC
Yes
City of Austin dba Austin
Energy
Yes
NIPSCO
Yes
Occidental Energy Ventures
Corp
Yes
The United Illuminating
Company
Yes
NIPSCO
Yes
Independent Electricity
System Operator
Yes
MISO
Yes
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Question 3 Comment
61
Organization
Yes or No
American Tranmission
Company
Yes
Oncor Electric Delivery
Company LLC
Yes
Consideration of Draft 5 Comments: Project 2007-02 COM-003
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Question 3 Comment
62
4. Do you have any other comments or suggestions to improve the draft standard?
Summary Consideration:
The content of Question four comments has been addressed in the previous three summaries and the consolidated summary.
Organization
Question 4 Comment
Manitoba Hydro
(1) ‘Reliability Directive’ is referred to in R1, 1.1 of the COM-003-1 standard but is not currently a FERC
approved definition, defined in the Glossary of Terms.
Response: The term “Reliability Directive” has been approved by the NERC Board of Trustees. It is
appropriate to use the term.
(2) R1, 1.3 and Rationale and Technical Justification documents - reference is made to ‘interface’, which is
not a defined term. Accordingly, its meaning is questionable. Consider removing or clarifying.
Response: Interface refers to Elements and Facilities that border those of other entities and interact more
directly between or among those entities. Knowledge of the assigned nomenclature of those Elements
and Facilities improves situational awareness.
(3) R1, 1.6 and 1.8 - requirement language is not consistent. For example, ‘recipient’ and ‘receiver’ are
used but have the same meaning. Suggest beginning the requirements with the following text “Instances
where....”
Response: The SDT has modified the standard to address your concern.
(4) R2, R4 - the word ‘periodically’ should be inserted before ‘assess’ in each of these requirements for
consistency with the Measures and VSLs, which refer to ‘periodic assessments’.
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties performance to avoiding
communication related events that would generate a Reliability Directive.
(5) R2, R4 - the phrase ‘necessary to meet the expectations in its documented communication protocols’ is
ambiguous and will be difficult to interpret when assessing compliance. Is this statement to be the
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Organization
Question 4 Comment
interpretation of the drafter of the protocols as to what is, in their opinion ‘reasonably necessary’?
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties performance to avoiding
communication related events that would generate a Reliability Directive.
(6) R3, 3.2 and 3.3 - requirement language is not consistent. For example, ‘recipient’ and ‘receiver’ are
used but have the same meaning. Suggest beginning the requirements with the following text “Instances
where....”
Response: R3, Parts 3.2 and 3.3 have been eliminated in draft 6.
(7) General Measures - there is lack of guidance with respect to both who the documentation is to be
provided, and when. For example, periodically, upon request, etc.
Response: The OPCPSDT has made extensive changes to the draft 6 standard that required full changes to
the Measurements.
(8) M1 and M3 - ‘ / ‘ should be placed between the words ‘and’ and ‘or’.
Response: The OPCPSDT has made extensive changes to the draft 6 standard that required full changes to
the Measurements.
(9) Section D, Compliance, 1.1 - the paraphrased definition of ‘Compliance Enforcement Authority’ from the
Rules of Procedure is not the standard language for this section. Is there a reason that the standard CEA
language is not being used?
Response: The OPCPSDT is using the ERO’s standard Compliance language provided by the NERC legal
department.
Response: The OPCPSDT thanks you for your comments.
ACES Standards
Collaborators
(1) The sub-parts of the protocols have grammatical errors, where the sub-parts do not correlate to the
lead-in sentence. We recommend replacing the phrase “Require the recipient/receiver...” that is stated in
sub-parts 1.6, 1.8, 3.2 and 3.3 with “Instances in which the recipient/receiver is required to...” in order to
maintain consistency throughout the standard. Leaving these sections as mandates (verb phrases) could
confuse auditors into thinking that these are zero defect requirements.
Response: The OPCPSDT thanks you for your comments. The SDT has modified the standard to address your concern.
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Organization
Exelon
Question 4 Comment
1) In the COM-003 FAQ document the response to question 5 states that R3 and R4 apply to the “recipient
of the command” where the recipient is “expected to act, to change or preserve the state, status, output, or
Element of the [BES] of Facility of the [BES]. In many Registered Entity organizations, the commands from a
TOP, BA or an RC typically go through an intermediary dispatch control center. Then, if necessary, the
commands are passed through to the associated DP or GOP. How does COM-003 apply to such
organizations with respect to R3 and R4?
Response: The OPCPSDT has substantially altered the standard making it “results” oriented and directly
tying it to reliability. The draft 6 approach addresses some of the commenters concern, but sustains the
applicability of the DP and GOP that will receive “Operating Instructions” because they can and do have
the potential for impacting reliability on the BES.
2) In the COM-003 FAQ document the response to question 3 states that entities “develop their own
programs that support the requirements of COM-003.” Suggest that the SDT clarify that recorded lines are
not specifically required and that other tools such as documented direct supervisory observation could be
used.
Response: That discretion is contained in COM-003-1, D. Compliance: 1.2 Data Retention.
3) In R3 and R4 the term ‘operators’ is used, in generation stations this term is widely used and relates to
different job functions. Suggest clarifying the term by stating ‘operators who receive Operating Instructions
or Reliability Directives from a Balancing Authority, Reliability Coordinator or Transmission Operator’.
Response: The OPCPSDT has substantially altered the standard making it “results” oriented and directly
tying it to reliability. The draft 6 approach addresses does not refer to “operators”.
4) The COM-003 language that includes ‘reliability directives’ has the potential to create a compliance issue
with COM-002 related to “all calls” since some Transmission Operations use ‘all calls’ or ‘one way burst
messaging’ to communicate reliability directives. These communication methods typically do not allow for
a response or repeat back or for an acknowledgement of the response accuracy. The problems with COM002 cannot be solved by making edits to COM-003. Instead, changes to COM-002 should be made to clarify
that "all calls" or burst messaging systems can be used to deliver Reliability Directives.
Response: The OPCPSDT agrees with your comments and has elected to remove “all calls” from the
standard.
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Organization
Question 4 Comment
Response: The OPCPSDT thanks you for your comments.
Western Small Entity
Comment Group
1) R3 (formerly R2) apparently now applies to all of DP’s or GO’s operating communication expectations,
and not just to Operating Instructions or Reliability Directives. We fail to see what Reliability objective is
accomplished by entities presenting all their communication protocols for audit, when the only real
reliability concern is if the entity responds appropriately to an Operating Instruction or Reliability Directive.
Although 3.1, 3.2, and 3.3 deal only with Operating Instructions and Reliability Directives, R3 itself does not
share this limitation.
Response: The OPCPSDT has substantially altered the standard making it “results” oriented and directly
tying it to reliability. The proposed draft 6 approach addresses the commenters concern, but sustains the
applicability of the DP and GOP because they can and do have the potential for impacting reliability on
the BES. COM-003-1, R3, draft 6 does limit the DPs and GOPs to “Operating Instructions.”
2) We also note that by removing the “in a manner that identifies, assesses and corrects deficiencies”
language, R3 becomes a zero defect requirement and an entity becomes subject to sanction for a single
failure to implement the developed protocol. We don’t believe this was the SDT’s intent, but this was the
effect of moving the language to R4. R4 is simply an additional separate requirement an entity must comply
with. Taken together, we believe most auditors would look first to find failures to implement procedure
under R3. If any failure was found, they would assign a violation and move on to R4 to look for evidence of
corrective action following the occurrence. If none were found, a second violation would be assigned.
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties performance to avoiding
communication related events that would generate a Reliability Directive. The SDT has modified the
standard to address your concern. Draft 6 does not address or reference internal controls in its
requirements.
3) We suggest: “R3. Each Distribution Provider and Generator Operator shall develop and implement, in a
manner that identifies, assesses and corrects deficiencies, documented communication protocols that
outline the communications expectations for receipt of Operating Instructions and Reliability Directives by
its operators,” and that R4 be removed.
Response: Draft 6 eliminates R2 and R4 “assess and correct” language and ties performance to avoiding
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communication related events that would generate a Reliability Directive. The SDT has modified the
standard to address your concern. Draft 6 does not address or reference internal controls in its
requirements.
Response: The OPCPSDT thanks you for your comments.
City of Garland
1)COM-003 now includes “Reliability Directives” which is why COM-002-3 was developed and approved COM-002-3 does not need to exist if Reliability Directives are covered in COM-003
Response: The OPCPSDT agrees and has removed the term “Reliability Directive” from the Parts of
Requirement R1.
2) In the Background Section of the "Unoffical Comment Form", it is stated that the final goal of this
standard was to implement 3 part communication. It would seem that it would be simple to state in a
requirement that the entity has to develop a procedure to use 3 part communications for Operating
Instructions using English except where prohibited by law or regulation and then a 2nd requirement to
develop an assessment process with a corrective process if necessary. It is totally unnecessary to write a
requirement with 9 sub parts that must be accounted for in a policy and procedure for an industry wide
practice that already exists. As written, it only add burdensome and unnecessary paperwork to operations
and compliance departments that has to be maintained and audited - again for a process that already exists
industry wide.
Response: The OPCPSDT has reduced the number to five parts, eliminating the all call parts. The OPCPSDT
believes the remaining parts are proven protocols that will prevent misunderstandings that could result in
a compromised BES.
3) Why is the Time Horizon stated as "Long Term Planning" instead of "Real-Time"
Response: Requirements R2 and R3 are now Real Time – Time Horizons.
Response: The OPCPSDT thanks you for your comments.
Oklahoma Gas &
Electric
o We believe that this proposed Standard (COM-003-1) meets the intent of Paragraph 81 of the FERC
Order which notes that reliability standards that provide little protection to the reliable operations of the
BES are redundant or unnecessary. Although blackout occurrences in the past points to communication
issues, we believe it is not related to miscommunication. Instead, we believe it is due to lack of
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communication and communicating information that was incorrect to begin with.
Response: The OPCPSDT believes COM-003-1 addresses the recommendations in the 2003 Blackout
Report and FERC Order 693.
o In the Consideration of Comments from the Feb 14-15 conference, the SDT said “The OPCPSDT maintains
its position that three-part communication be addressed in documented communication protocols, where
applicable.” OG&E believes that while the opinions of the members of SDT are important, the SDT itself
should not maintain a “position” as such. Rather, the SDT should attempt to merge direction from FERC
with the comments from industry instead of rejecting industry comments out of hand. Per the Standards
Process Manual (pg.9), the roles of drafting teams are:
o Drafts proposed language for the Reliability Standards, definitions, Variances, and/or
Interpretations and associated implementation plans.
o Solicits, considers, and responds to comments related to the specific Reliability Standards
development project.
o Participates in industry forums to help build consensus on the draft Reliability Standards,
definitions, Variances, and/or Interpretations and associated implementation plans.
o Assists in developing the documentation used to obtain governmental approval of the Reliability
Standards, definitions, Variances, and/or Interpretations and associated implementation plans.
Response: The current draft reflects a culmination of responses to industry’s concerns, which the
OPCPSDT, also made up of industry experts, has given careful consideration to in order to balance the
direction from FERC with the concerns of the majority of the industry.
Response: The OPCPSDT thanks you for your comments.
Florida Municipal
Power Agency
As commented on several times previously, FMPA will not vote Affirmative (or recommend an Affirmative
vote) until the inconsistencies of COM-003-1 and COM-002-3 concerning Reliability Directives are resolved.
For a Reliability Directive delivered by an “All Call”, COM-003-1 does not require three part communication
whereas COM-002-3 does. This inconsistency will only be a source of confusion during the very time when
rapid response to communication is needed, which causes us to be concerned for reliability. FMPA
continues to recommend retiring COM-002-3 as part of the implementation plan of COM-003-1 and fails to
see a good reason not to do so. All that would need to be done is to retain the definition of Reliability
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Directive and include R1 of COM-002-3 into COM-003-1, and a slight modification to 1.5 of COM-003-1 to
require confirmation of a Reliability Directive.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT agrees and has removed the term “Reliability Directive”
from the Parts of Requirement R1.
NIPSCO
As per the effort of paragraph 81, we feel that COM-002 and COM-003 should be combined into one
standard. It is evident there is redundancy between these two standards which should be eliminated.
Response: The OPCPSDT thanks you for your comments. Based on other feedback, the OPCPSDT has chosen not to combine the
two standards. The OPCPSDT also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
CenterPoint Energy
Houston Electric L.L.C.
CenterPoint Energy appreciates the opportunity to comment. The Company recognizes the work of the SDT
however CenterPoint Energy still has large concerns with Draft 5. Specifically:
1) The addition of the term “Reliability Directive” to COM-003-1.
2) R1.9 coordination with other entities.
3) The addition of specifying the alpha-numeric format in R1.4.
4) The VSL’s.
1) The addition of the term “Reliability Directive” to COM-003-1 introduces a potential conflict with the
already industry and NERC BOD approved COM-002-3. Requirements R1.7 of the current draft of COM-0031 states: “Instances where the issuer of an oral Operating Instruction or Reliability Directive using a one-way
burst messaging system to communicate a common message to multiple parties in a short time period (e.g.
an All Call system) is required to verbally or electronically confirm receipt from at least one receiving party.”
(emphasis added) Requirements R1.8 and R3.3 of the current draft of COM-003-1 allow the recipient of a
Reliability Directive from a one way burst messaging system communication to “...request clarification from
the issuer if the communication is not understood.” (emphasis added) COM-002-3 makes no such
distinctions regarding the issuing or receiving of Reliability Directives. COM-002-3 is clear; whether an entity
is issuing or receiving a Reliability Directive 3-part communication must be employed. The Company firmly
believes this conflict could easily cause entities to follow COM-003-1 yet be non-compliant with COM-002-3.
In addition, since COM-002-3 already addresses emergency communications and has been reviewed and
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approved by industry stakeholders as well as the NERC BOD CenterPoint Energy believes there is no
additional reliability benefit to adding “Reliability Directive” to COM-003-1. CenterPoint Energy strongly
recommends deleting “Reliability Directive” from COM-003-1.
Response: The OPCPSDT agrees and has removed the term “Reliability Directive” from the Parts of
Requirement R1.
2) CenterPoint Energy has strong concerns regarding the addition of R1.9 to Draft 5 of COM-003-1. R1.9
requires that an entity’s documented communication protocols address coordination with affected RC’s,
BA’s, TOP’s, DP’s, and GOP’s communication protocols. For responsible entities that have interconnections
with multiple entities, this will be the equivalent of “herding cats”. The Company does not believe it will be
possible to coordinate with and come to a common agreement regarding the items in R1.1 - R1.8 with
multiple parties. For example: R1.4 requires the documented communication protocols to address the
format to be used when alpha-numeric clarifiers are necessary. Where a responsible entity is a TOP and is
interconnected with multiple other TOP’s, DP’s, GOP’s as well as its RC, and BA, it will be extremely difficult
for all parties to agree to a common alpha-numeric format. In addition, coordination will become an issue
when any of the parties decide to revise or amend its communication protocols. This will be an on-going
management issue for all entities. CenterPoint Energy strongly recommends R1.9 be deleted from COM003-1.
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC. There were many comments
supporting this decision because it promoted uniformity and relieved the DPs and GOPs from developing
their own distinct protocols. Requirement 1 Part 1.9 has been eliminated from draft 6.
3) CenterPoint Energy believes the addition to R1.4 requiring a responsible entity to specify the format to be
used where alpha-numeric clarifiers are necessary is an unnecessary and burdensome requirement. The
Company agrees with the SDT’s decision to add to R1 and R3 language that allows an entity to address,
where applicable, the items in the sub-requirements instead of requiring these items to be in the
communication protocols as it was in Draft 4. However, the addition of specifying the format for those
clarifiers is a step backwards. Draft 4 did not require documenting a specific format and therefore would
have allowed an entity the flexibility to use, for example, “Baker” or “Bravo” for the letter “B”. The Draft 5
version now sets up an operator for a possible violation if the protocol specifies “Baker” and the operator
inadvertently uses “Bravo”. The purpose of using alpha-numeric clarifiers is to ensure the recipient
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understands that the alpha component, in this case, is the letter “B” and not “E” or “D”. The use of “Baker”
or “Bravo” accomplishes that purpose. The Company believes having to specify a format to use does not
result in any reliability benefit and therefore CenterPoint Energy strongly recommends the deletion of the
format requirement from R1.4.
Response: The OPCPSDT believes an entity can resolve the concerns you cite by including them in their
documented communication protocols.
4) CenterPoint Energy firmly believes there should be no High or Severe VSL for simply failing to document a
process, policy, or procedure. High or Severe VSL’s should only apply to the most egregious violations that
have a high impact on the reliability of the BES. As NERC has stated on many occasions, the purpose of the
Reliability Standards is to enhance the reliable operation of the BES. Where an entity is performing the
process, procedure, or task required in an applicable Standard and therefore is reliably operating its portion
of the BES, yet has failed to document that process, procedure, or task, penalizing that entity with a High or
Severe VSL will not result in improved reliable operation of the BES. CenterPoint Energy recommends no
VSL’s higher than Moderate.
Response: The OPCPSDT believes that if an entity completely fails to develop and implement
communication protocols, it is an egregious violation and warrants a High or Severe VSL.
CenterPoint Energy supported Draft 4 of COM-003-1 however, the changes made by the SDT in Draft 5 has
caused the Company to rethink its position. If the SDT were to make the recommended changes
CenterPoint Energy would be able to support the Standard.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
Clark Public Utilities
Clark Public Utilities is concerned about the conflict between COM-002 and COM-003 regarding responses
to Reliability Directives. In the case of a one-way burst messaging used to issue a Reliability Directive, COM002 does not allow for only those responses required in COM-003 but instead requires a full 3-way
communication from all parties. This potentially sets up both the issuer and receiver for violating COM-002
if they respond to a one-way burst messaging Reliability Directive as the requirements indicate in COM-003.
In order to be fully compliant with BOTH standards, the receiver would have to contact the issuer, repeat
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what was said on the original burst message, then the issuer would confirm that the response was accurate
before acting on the message. Clark appreciates the responsiveness of the OPCPSDT in quickly posting an
FAQ once the COM-002/COM-003 issue was raised. The opinion of the OPCPSDT notwithstanding, Clark is
not reassured by the secondary documentation cited in the FAQ when the plain language of the two
Standards are in conflict. A simple solution would be to eliminate the words "Reliability Directive" from
COM-003, which after all is designed to address "Operating Instructions."
Response: The OPCPSDT thanks you for your comments. The OPCPSDT agrees and has removed the term “Reliability Directive”
from the Parts of Requirement R1.
Pacific Gas and Electric
Company
Draft 5 fails to address all of the communication gaps identified in the Standards Authorization Request
(SAR), FERC Order 693 and the recommendations of the August 2003 Blackout Report. The draft as written
does not require a consistent application of effective communications protocols but in turn requires each
functional entity to develop their own protocols with insufficient guidance on how to achieve better
consistency.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes it has addressed gaps identified in the Standards
Authorization Request (SAR), FERC Order 693, and the recommendations of the August 2003 Blackout Report. Industry comment in
the last five drafts has stated the opposite of your comment—requesting less prescriptive requirements. The OPCPSDT has modified
the standard by changing the R1 language to require the TOP, BA and RC to develop the protocols subject to the approval of the RC.
There were many comments supporting this decision because it promoted uniformity and relieved the DPs and GOPs from
developing their own distinct protocols.
Edison Mission
Marketing & Trading
EMMT agrees with the concepts put forth in COM-003, but have some concerns, particularly with the
proposed administrative burden associated with the Standard. EMMT offers the following comments:
1. R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP communication
protocols; this could result in a TOP having to coordinate with a hundred+ different entities communications
protocols. This coordination would not improve reliability, but only serve to create confusion and significant
communication time delays in real-time operations. Both R1 and R4 create significant documentation and
administrative burdens, without providing a comparable improvement to the reliability of the BES. As
reliability based Standard, COM-003 should focus on those actions that would have a direct impact on
reliability, while minimizing the administrative burden.
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Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC. The reason for the change is based on
other commenters’ recommendations to have the DP and GOP implement the protocols established by
the directing RC, BA and TOP. There were many comments supporting this decision because it promoted
uniformity and relieved the DPs and GOPs from developing their own distinct protocols.
2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They only receive
instructions from others. GOPs should have a communications procedure as part of their operations,
however, the methods used are properly business decisions made by the GOP. The content, thoroughness
and effectiveness of a communications plan are excellent items to consider when assessing an entity’s
internal compliance program.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
3. R4 raises the question of sufficiency of an entity’s corrective program. The RSAW requires the GO to turn
over records of monitoring communications as well as records of corrective actions and then prove the
“problem” is not still in place. This standard could easily turn into a high-profile audit target due to the
varying concepts of what does and does not constitute a sufficient corrective action program.
Response: The OPCPSDT eliminates R2 and R4 “assess and correct” language in Draft 6 and ties
performance to avoiding communication related events that would generate a Reliability Directive. The
OPCPSDT believes compliance will be uncomplicated and focused on stability on the BES.
4. EMMT recommends that the language to M4 be changed as follows:
M4. Each Distribution Provider and Generator Operator shall provide the results of its periodic assessment
and of any corrective actions (if any corrective actions were implemented) developed for Requirement R4.
Examples of sufficient periodic assessment programs include, but are not limited to, the following:
•
•
•
Documented review of voice logs for a total of at least one hour per calendar year for each operator
(does not need to be a single session)
Documented personal monitoring of communications for a total of at least one hour per calendar
year for each operator (does not need to be a single session)
Documented annual training Examples of sufficient corrective action programs include, but are not
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limited to, the following:
• Documented refresher training
• Documented meeting
• Documented “hot box” communication
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
5. The VSLs give a higher violation to a GOP than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GOP who fails to require 3-part responses when requested is
tagged with a Moderate violation, while the BA would receive a Lower.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
6. In the RSAW, the following passage should be expunged; “Where practicable, verify that deficient
communication practice was indeed corrected by reviewing evidence of Operator communications (such as
voice recordings) occurring after the date of the corrective action to determine if deficient communication
practice was corrected.” Differentiating between slips of the tongue and “deficient communication
practices” involves subjective judgments. The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of making
before-and-after voice recording comparisons. This is an open-ended matter that could very quickly
become an unreasonable compliance burden. RSAWs in general should not introduce new requirements,
measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
Electric Reliability
Council of Texas, Inc.
ERCOT recognizes and commends the drafting team’s efforts to respond to industry comments and is
supportive of draft 5 of COM-003-1.It should be clear in the definition and the standard that electronic
systematic interchanges are not Operating Instructions. Please consider modifying the last sentence of the
definition for Operating Instructions as below:”Discussions of general information and of potential options
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or alternatives to resolve BES operating concerns as well as electronic, system to system, interchanges are
not commands and are not considered Operating Instructions.”
Response: The OPCPSDT will keep the existing language in the definition of Operating Instructions. The
language of the requirements and parts narrow the focus of COM-003-1 to voice communication.
ERCOT ISO also maintains that the sub-requirements for R1 and R3 are not the “communication protocols”
that FERC Order 693 and Blackout Recommendation #26 intended to be addressed as they are solely
focused on “miscommunication”. However, ERCOT ISO believes that the structure of COM-003-1, in
allowing an entity to address subrequirements through development of its own documented
communication protocols and identification of the instances of needing to use such protocols, allows for
future revisions to focus on the subrequirements, as needed, leaving the construct in place to easily add,
modify, or delete such parts as necessary through such subsequent revisions. An example of such a revision
is where IRO-014-1 R1 has a similar construct and was modified to include an additional subrequirement
(R1.7) in version 2.
Response: The OPCPSDT acknowledges your position but believes it has properly addressed the protocols
as stated in FERC Order 693 and Blackout Recommendation #26.
ERCOT believes that oral and written operator communication requirements should be in a single reliability
standard and supports further refinement of the requirements and combining COM-002 and COM-003 into
a single reliability standard.
Response: Based on other feedback, the OPCPSDT has chosen not to combine the two standards. The
OPCPSDT also believes draft 6 requirements create a logical delineation between COM-002-3 and COM003-1.
Response: The OPCPSDT thanks you for your comments.
Georgia System
GSOC recommends that only R1 and R3 survive; eliminate R2 and R4.
Operations Corporation
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.
Georgia Transmission
If Requirements R3 and R4 are neither deleted nor reworded as suggested above, then changes should be
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Corporation
made in the standard to clearly define the term “operator” or disassociate the term from the DP function.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.
Indiana Municipal
Power Agency
IMPA believes there is a conflict between COM-003-1 and COM-002-3 when it comes to how an entity
replies back to an “All Call”. COM-003-1 does not require three part communication and it seems that
COM-002-3 does require it. This creates confusion and needs to be corrected.IMPA supports the use of one
communication standard to address proper communication protocols for Directives and Operating
Instructions. This could be accomplished by retiring COM-002-3 upon the implementation of COM-003-1.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has removed all “all call” references from COM-003-1.
Based on other feedback, the OPCPSDT has chosen not to combine the two standards. The OPCPSDT also believes draft 6
requirements create a logical delineation between COM-002-3 and COM-003-1.
American Electric
Power
It needs to be acknowledged by the project team that there are overlapping requirements between COM003-1 and COM-002-3. Although the project webpage states that “COM-003-1 establishes the practice of
using communication protocols for all Operating Instructions”, COM-003-1 explicitly includes Reliability
Directives along with the Operating Instructions. We understand Reliability Directives to be a subset of
Operating Instructions, so with respect to Reliability Directives, there are unnecessary overlaps which will
only cause confusion in adhering to the standard. In short, COM-003-1 should only be adopted with the
understanding that the overlapping requirements in COM-002 would then be retired.
Response: Based on other feedback, the OPCPSDT has chosen not to combine the two standards. The
OPCPSDT also believes draft 6 requirements create a logical delineation between COM-002-3 and COM003-1.
AEP supports the forward-looking approach advocated by NERC’s Reliability Assurance Initiative. We believe
this proposed standard puts “the cart before the horse” in that it mandates internal controls for a limited
number of requirements rather than taking a wholistic approach where internal controls are generally
required for all standards and where that language is housed outside of the standard itself.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
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AEP believes this R 1.3 is redundant with TOP-002 R18. Other requirements in this proposed standard are
already in place to drive clarity of communication.
Response: The OPCPSDT believes that structured awareness of interfaced transmission assets by adjoined
entities increases situational awareness, provides clear understanding and removes hesitation or doubt
when issuing or receiving Operating Instructions.
Response: The OPCPSDT thanks you for your comments.
Luminant
Luminant is generally supportive of the direction of this standard and agrees that requiring a documented
communication protocol and monitoring processes is the correct approach for this standard. While we
understand the need for the some Registered Entities (RE) to use a one-way burst messaging system to
make mass communication quicker and easier the inclusion of Reliability Directive in R1.7, R1.8 and R3.3
creates a conflict COM-002-3 R2 and R3. By including Reliability Directives in R1.7, R1.8 and R3.3 which
allows and electronic response or only one receipt to restate, the receiving REs will not be able to comply
with COM-002-3 R2 that requires EACH recipient of a Reliability Directive to repeat, restate, rephrase or
recapitulate the Reliability Directive. Removing Reliability Directive from those section would eliminate any
confusion and conflict between COM-002-3 and COM-001-3 and allow COM-001-3 to be passed and
implemented. Alternatively, COM-002-3 could be revised to CLEARLY STATE that it only applies to one-onone verbal (or written?) communication.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes that
will address your comments.
Occidental Energy
Ventures Corp
Occidental Energy Ventures Corp. (“OEVC”) is firmly on board with the strategy taken by the drafting team
to incorporate structure in the communication of Operating Instructions, while allowing each entity some
flexibility in the process. As a GOP, we take very seriously our responsibility to accurately capture and
execute all instructions from RCs, BAs, and TOPs that may affect the state of the Bulk Electric System. This
approach will allow us to differentiate between instructions issued orally, via email/messaging, and one-tomany broadcasts - which change rapidly as new communications technologies are introduced. In addition,
we agree that a risk-based compliance method is necessary - particularly in the case of oral
communications. Even the most perfectly trained operators can stumble on occasion, and the result should
not be a compliance violation unless the errors continue to manifest themselves. Furthermore, the amount
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of overhead necessary to ensure that every oral instruction is repeated back with time stamps, equipment
identifiers, and alpha-numeric clarifiers is extraordinary in the zero-defect model. However, we are not
convinced that these excellent intentions are captured in a manner that will assure consistent assessments
by Compliance Enforcement Authorities. It is clear from our reading of the FAQs recently posted by the
drafting team that many industry respondents are unclear how auditors will interpret COM-003-1’s
requirements over a wide range of operating scenarios - a concern that we share. This means that a
common understanding must be reached in an enforceable document that both operators and CEAs can
rely on for consistency. In our view, the RSAW is the logical vehicle for this approach. It is a fundamental
audit tool and has been traditionally used as a semi-binding reference in the evaluation of reliability
compliance. In addition, the concurrent development of the RSAW with COM-003-1 was instituted precisely
to ensure uniformity between the SDT’s intent and the standard’s enforcement. This implies that the RSAW
must contain a greater level of detail to address multiple situations - and we have provided specific
suggestions in our RSAW feedback form along these lines.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Lastly, we do not have a clear understanding how Requirement R1.9 will be implemented. As it is presently
written, it would seem that GOPs should expect some notification from their RCs, BAs, and TOPs that
communication policies are to be “coordinated.” Our experience has been that some entities simply post
instructions on their web-sites hidden among many other documents - which does not count as
coordination in our view. However, we are not sure that the issuers’ policies are consistent with all of R1’s
other sub-requirements. As such, OEVC recommends that R1.9 be removed.
Response: The OPCPSDT agrees and has changed the wording of R1, to eliminate Part 1.9.
Response: The OPCPSDT thanks you for your comments.
SPP Standards Review
Group
Our comments are listed with the specific question they address.
Response: The OPCPSDT thanks you for your comments.
San Diego Gas &
Electric
Please see comments:
NEW NERC RELIABILITY STANDARD - COM-003-1 - Version 5Version 5 comments R1.1 and R3.1 Proposed
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Updated Language:
Use of English language when issuing or responding to an oral or written Operating Instruction or Reliability
Directive, unless another language is mandated by law or regulation, or as otherwise agreed to by the
parties.
Comment: The Western Interconnection is interconnected with Mexico, south of the California, Arizona
and New Mexico borders and with Canadian provinces north of the Washington, Idaho and Montana
borders. SDG&E, which is located at the California-Mexico border, communicates almost daily with the
Mexico utility located in Baja California, CFE. When the standards became mandatory and enforceable, in
compliance with COM-001, R4, SDG&E maintained an agreement with CFE which documents that English
will typically be used, but in instances where communicating in Spanish is more effective in ensuring system
reliability, the personnel involved will use Spanish given that all parties involved are fluent in Spanish. CFE
does not have a mandate to be in compliance with the U.S. NERC Reliability Standards. The native language
in Mexico is Spanish, and SDG&E staffs its Electric Grid Operations department with personnel who are
fluent in Spanish, therefore its agreement with CFE is managed to insure that all communications with its
neighbor to the south are clear, concise, and understood. In addition, there are at least two generation
stations located south of the California border, interconnected with SDG&E, and the employees at those
stations are fluent in Spanish, therefore, because those generation station personnel will also communicate
with the California ISO and the WECC RC on occasion, those entities need the flexibility provided in COM001 R4 to be carried through to COM-003-1, R1.1. & R3.1. All policies and procedures developed by power
company entities south of the border are written in Spanish, and at times, written communication between
U.S. and entities in Mexico are in Spanish. Since SDG&E’s neighbors to the south do not have to comply with
U.S. NERC Reliability Standards, and U.S. entities are required to comply with U.S. NERC Reliability
Standards, SDG&E proposes the revisions to COM-003-1 R1.1 and R3.1 as identified above. This proposed
revision provides for the flexibility that already exists in COM-001 R4 that has effectively worked over the
last several years.
Response: The OPCPSDT developed the standard in a manner to permit the RC to direct the development
of the protocols within the RC control area. It is important for clarity that a singular language be used for
BES operating commands. Risk of miscommunication increases when multiple languages are permitted.
R1.2 Proposed Updated Language: Instances that require time identification when issuing an oral or written
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hour clock format and the Entity’s time zone.
Comment: SDG&E prefers the language proposed above. The proposed language leaves NO doubt
associated with how to reference a specific time for ALL entities. If one entity uses the 24 hour clock, and
another is using a.m. and p.m., it simply leaves the opportunity for some confusion that can be eloquently
avoided when stating that a 24 hour clock is to be used.
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC.
Response: The OPCPSDT thanks you for your comments.
Oncor Electric Delivery
Company LLC
R1.9 states that entities will address “Coordination with affected Reliability Coordinators’, Balancing
Authorities’, Transmission Operators’, Distribution Providers’, and Generator Operators’ communication
protocols.” Coordination with these entities in the ERCOT market will become cumbersome. Is it the SDT’s
intent to ensure all communication protocols are coordinated with multiple entities that a Transmission
Operator communicates with, including the RC, BA, other TOs, GOPs, and DPs? Oncor is unclear how an
entity with multiple registrations would communicate with itself in different functions. Would this require
an entity with multiple registration functions to designate personnel by functional entity and in turn,
personnel would have to identify which functional entity each person they interface with? It is impractical
and inefficient to require Entities to re-organize all personnel which would foster an inefficient structure
and could potentially lead teams to not communicate effectively. In addition, this could have a negative
impact on communications between companies. For example, in the ERCOT region, there are
approximately 15 local control centers and ERCOT who are all registered as TOPs. One might interpret
communications between neighboring TOPs or ERCOT and one of the local control centers are not subject
to the requirements of COM-003-1 since these are TOP to TOP communications. We strongly recommend
the SDT review this to greatly simplify COM-003-1. Potential alternative to the current language would be
“require entities to implement, in a manner ..., protocols that include three-part communication for
Operating Instructions” and eliminate the reference to Functional Entity.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT has modified the standard by changing the R1 language to
require the TOP, BA and RC to develop the protocols subject to the approval of the RC. The reason for the change is based on other
commenters’ recommendations to have the DP and GOP implement the protocols established by the directing RC, BA and TOP. There
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were many comments supporting this decision because it promoted uniformity and relieved the DPs and GOPs from developing their
own distinct protocols. The goal is to establish a high degree of communication uniformity within the RC operating area.
Salt River Project
R4 should be eliminated and R3 should end after the first sentence. GOs do not issue Operating Instructions.
They only receive instructions from others. GOs should have a communications procedure as part of their
operations. However, the methods used are properly business decisions made by the GO. The content,
thoroughness and effectiveness of a communications plan are excellent items to consider when assessing
an internal compliance program.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT eliminates R2 and R4 “assess and correct” language in draft 6
and ties performance to avoiding communication related events that would generate a Reliability Directive. The OPCPSDT believes it
has properly narrowed the GOPs and DPs roles to those who will only receive Operating Instructions.
SERC OC Standards
Review Group
Regarding question #1, the SERC OC Review Group agrees with the definition of Operating Instruction.
While we also can agree to the changes made to R1, we feel R3 in its entirety is unnecessary and
duplicative. Removal of the word “develop” would eliminate double-jeopardy concerns. R3 could be
acceptable if “develop and” are omitted and “as developed in R1” is inserted after “protocols” and before
“that.” It should be noted that this suggestion only applies to the sub-requirements in R1 that correspond to
the proposed sub-requirements in R3.Regarding question #2, R2 is acceptable and R4, as stated above for
R3, is unnecessary and duplicative. Regarding question #3, we agree with the VRFs and VSLs for R1 and R2.
Based on our previous comments, we do not agree with the need for R3 and R4, and therefore VRFs and
VSLs for these requirements are not needed. Additional SERC OC Standards Review Group supporting these
comments are James Wood with Southern Company and Kelly Casteel with TVA. The comments expressed
herein represent a consensus of the views of the above named members of the SERC OC Standards Review
Group only and should not be construed as the position of SERC Reliability Corporation, its board, or its
officers.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT eliminates R2 and R4 “assess and correct” language in draft
6 and ties performance to avoiding communication related events that would generate a Reliability Directive. The OPCPSDT
believes the proposed draft 6 has incorporated changes that will address your comments.
Cogentrix Energy
Power Management
Regarding question #1, the SERC OC Review Group agrees with the definition of Operating Instruction.
While we also can agree to the changes made to R1, we feel R3 in its entirety is unnecessary and
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duplicative. Removal of the word “develop” would eliminate double-jeopardy concerns. R3 could be
acceptable if “develop and” are omitted and “as developed in R1” is inserted after “protocols” and before
“that.” It should be noted that this suggestion only applies to the sub-requirements in R1 that correspond to
the proposed sub-requirements in R3.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Regarding question #2, R2 is acceptable and R4, as stated above for R3, is unnecessary and duplicative.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Regarding question #3, we agree with the VRFs and VSLs for R1 and R2. Based on our previous comments,
we do not agree with the need for R3 and R4, and therefore VRFs and VSLs for these requirements are not
needed.
The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.1.
R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP communication
protocols; this could result in a TOP having to coordinate with a hundred+ different entities communications
protocols. This coordination would not improve reliability, but only serve to create confusion and significant
communication time delays in real-time operations. Both R1 and R4 create significant documentation and
administrative burdens, without providing a comparable improvement to the reliability of the BES. As
reliability based Standard, COM-003 should focus on those actions that would have a direct impact on
reliability, while minimizing the administrative burden.
Response: The OPCPSDT has changed the coordination requirement in draft 6 by eliminating requirement
1, Part 1.9 and changing the R1 language to require the TOP, BA and RC to develop the protocols subject
to the approval of the RC. The reason for the change is based on other commenters’ recommendations to
have the DP and GOP implement the protocols established by the directing RC, BA and TOP. There were
many comments supporting this decision because it promoted uniformity and relieved the DPs and GOPs
from developing their own distinct protocols.
2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They only receive
instructions from others. GOPs should have a communications procedure as part of their operations,
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however, the methods used are properly business decisions made by the GOP. The content, thoroughness
and effectiveness of a communications plan are excellent items to consider when assessing an entity’s
internal compliance program.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
3. R4 raises the question of sufficiency of an entities corrective program. The RSAW requires the GO to turn
over records of monitoring communications as well as records of corrective actions and then prove the
“problem” is not still in place. This standard could easily turn into a high-profile audit target due to the
varying concepts of what does and does not constitute a sufficient corrective action program.
Response: The OPCPSDT eliminates R2 and R4 “assess and correct” language in draft 6 and ties
performance to avoiding communication related events that would generate a Reliability Directive.
4. The SRT recommends that the language to M4 be changed as follows:
M4. Each Distribution Provider and Generator Operator shall provide the results of its periodic assessment
and of any corrective actions (if any corrective actions were implemented) developed for Requirement R4.
Examples of sufficient periodic assessment programs include, but are not limited to, the following:
•
Documented review of voice logs for a total of at least one hour per calendar year for each operator
(does not need to be a single session)
• Documented personal monitoring of communications for a total of at least one hour per calendar
year for each operator (does not need to be a single session)
• Documented annual training
o Examples of sufficient corrective action programs include, but are not limited to, the
following:
Documented refresher training
Documented meeting
Documented “hot box” communication
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
5. The VSLs give a higher violation to a GOP than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GOP who fails to require 3-part responses when requested is
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tagged with a Moderate violation, while the BA would receive a Lower.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
6. In the RSAW, the following passage should be expunged; “Where practicable, verify that deficient
communication practice was indeed corrected by reviewing evidence of Operator communications (such as
voice recordings) occurring after the date of the corrective action to determine if deficient communication
practice was corrected.” Differentiating between slips of the tongue and “deficient communication
practices” involves subjective judgments. The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of making
before-and-after voice recording comparisons. This is an open-ended matter that could very quickly
become an unreasonable compliance burden. RSAWs in general should not introduce new requirements,
measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.
NERC
Requirement (R1.5) provides inadequate protection against a misunderstanding when directives are issued.
Granted, the Requirement does obligate the party receiving the directive to repeat back the directive.
However, if the recipient repeats the directive back to the person issuing the directive, and the "repeat
back" indicates the recipient has misunderstood the directive, this Requirement merely obligates the person
issuing the directive to state the directive again. The Requirement places no obligation on the person
issuing the directive, who knows he has been misunderstood, to explicitly and clealy bring to the attention
of the recipient that the recipient has misunderstood. All the party issuing the directive has to do is repeat
what he has already said. The party issuing the directive is under no obligation to make it clear that there
has been a misunderstanding. With respect, I suggest having the person issuing the directive merely repeat
it if he's been misunderstood, with no explicit statement that there has been a mistake, leaves open the
potential for the recipient to be unaware he has misunderstood and to execute a misunderstood directive.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes
that will address your comments.
American Tranmission
Requirement 1.9 requires “Coordination with affected Reliability Coordinators’, Balancing Authorities’,
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Company
Transmission Operators’, Distribution Providers’, and Generator Operators’ communication protocols.” This
requirement seems unnecessary since the requirements of COM-3-1 apply to all these entities. If everyone
is adhering to the requirements of COM-3-1 then the need for coordination is redundant as it becomes
automatic. If individual entities adopt slight nuances to this requirement, or are more restrictive then the
requirement then coordination between every entity becomes extremely difficult.
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA and RC to develop the
protocols subject to the approval of the RC.
Northeast Power
Coordinating Council
Requirement 3 is an administrative requirement that does little to benefit the reliable operation of the BES.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
By specifically calling out “Directives” in the requirement it creates the potential for double jeopardy with
other requirements such as COM-002, IRO-001 and TOP-001 which all speak to following Directives.
Response: The OPCPSDT believes draft 6 requirements create a logical delineation between COM-002-3
and COM-003-1.
Requiring a documented communications protocol when the only responsibility is repeat back the
instruction as received and seek clarification if the directive is misunderstood is beyond the intended scope
of the reliability program in general. This requirement should be removed.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Requirement 4 should be removed because it is unnecessary and excessive. The smaller entities that this
will affect do not record phone conversations and it would be difficult to assess performance based on the
very low number of “Operating Instructions” or “Directives” that these entities actually receive. The
performance of “Operating Instructions” should be the proof. A better approach would be to amend the
above mentioned standards (IRO, TOP, COM) to include “Operating Instructions” along with Directives.
Response: The OPCPSDT eliminates R2 and R4 “assess and correct” language in draft 6 and ties
performance to avoiding communication related events that would generate a Reliability Directive.
Operating Instructions.
The term “All Call” is used in Requirement 1 Part 1.8. It should be defined in the NERC Glossary. If it isn’t to
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be defined, then it should not be capitalized. Regarding Requirement 1 Part 1.8, and Requirement 3 Part
3.3, the receiver of an oral Operating Instruction or Reliability Directive from a one-way burst messaging
system is “to request clarification from the issuer is the communication is not understood.” What if the
receiver never gets the issued Operating Instruction or Reliability Directive? Regarding Requirement 1 Part
1.8, and Requirement 3 Part 3.3, suggest changing “using” to “from” to make them read “Require the
receiver of an Oral Operating Instruction or Reliability Directive from a one-way burst...”
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
Seattle City Light
Seattle City Light is concerned about the conflict between COM-002 and COM-003 regarding responses to
Reliability Directives. In the case of a one-way burst messaging used to issue a Reliability Directives, COM002 does not allow for only those responses required in COM-003 but instead requires a full 3-way
communication from all parties. This potentially sets up both the issuer and receiver for violating COM-002
if they respond to a one-way burst messaging Reliability Directive as the requirements indicate in COM-003.
In order to be fully compliant with BOTH standards, the receiver would have to contact the issuer, repeat
what was said on the original burst message, then the issuer would confirm that the response was accurate
before acting on the message.
Seattle City Light appreciates the responsiveness of the OPCPSDT in quickly posting an FAQ once the COM002/COM-003 issue was raised. The opinion of the OPCPSDT not withstanding, Seattle is not reassured by
the secondary documentation cited in the FAQ when the plain language of the two Standards are in conflict.
Past experience, such as illustrated in the 2008 PacifiCorp case, shows that where Standards are unclear or
in conflict, auditors have been prone to take the language at face value and disregard secondary
documents. In addition, entities charged with implementing the Standards are prone to change practices to
avoid ambiguous areas and compliance risk, which in this case could result in the phase-out of effective allcall or burst messaging systems for announcing reliability Directives. As a result, Seattle is sufficiently
concerned about the audit and reliability implications created by the present draft of COM-003 to change
from a YES position to NO at this time.
Seattle is prepared to support COM-003 once this conflict is addressed. A simple solution would be to
eliminate the words "Reliability Directive" from COM-003, which after all is designed to address "Operating
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Instructions."Inclusion of Reliability Directive language in COM-003 creates an additional complication, by
making R1.8 incomplete. R1.8 require the receiver of an oral Operating Instruction or Reliability Directive
using a one-way burst messaging system to communicate a common message to multiple parties in a short
time period (e.g. an All Call system) to request clarification from the issuer if the communication is not
understood. This language does not address the next step: if an entity receives a burst message from its RC
that is unclear, and is unable to reach the RC for clarification (perhaps because the RC is busy handling the
emergency situation), what is the entity to do? Implement to Reliability Directive to its best understanding?
Wait until it can clarify the Directive? Do nothing? Serious reliability and compliance risks attend all of these
possibilities, adn the Standard should be clear as to which is prefered. Seattle again recommends removing
"Relaibility Directive" language from COM-003 as a simple solution. If the Reliability Directive language
remains in COM-003, this potentiality should be addressed in the Standard as to which approach is
prefered.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.
The OPCPSDT also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
NIPSCO
See comments submitted on NIPSCO's behalf by Julaine Dyke
Response: The OPCPSDT thanks you for your comments. Please refer to our response at that location.
NIPSCO
see NIPSCO comments from Julaine Dyke, thanks
Response: The OPCPSDT thanks you for your comments. Please refer to our response at that location.
Southern Company Southern Company
Services, Inc.; Alabama
Power Company;
Georgia Power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
See Southern’s comments for R3 and R4 in the RSAW comments regarding use of the terms “Operator” and
“operator”. If Requirements R3 and R4 are neither deleted nor reworded as suggested above, then changes
should be made in either the standard or the RSAW to make the two terms consistent and to clearly define
the term “operator” if necessary.
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Generation; Southern
Company Generation
and Energy Marketing
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes that
will address your comments.
CPS Energy
Separate the Distribution Provider (DP) and Generator Operator (GOP) COM requirements into a separate
standard.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes keeping the applicable entities in the same standard
is more efficient.
SMUD/Balancing
Authority of Northern
California
SMUD would like to thank the Drafting Team for their efforts. While we agree with the intent of COM-003
we would like the Drafting Team to provide input on a possible conflict between the Board approved COM002-3 Requirement and Draft #5 of COM-003-1 Requirements R1, Part 1.7 & R3, Part 3.3. It appears that a
“One-way” burst messaging that includes either oral or electronic Operating Instructions or Reliability
Directives as depicted in the current COM-003 does not require practice of 3-way communication prior to
taking action. Since COM-002 Requirement R2 specifies that the recipient “shall repeat, restate, rephrase,
or recapitulate the Reliability Directive” it is unclear whether or not the receiving parties of a blast message
adhering to the COM-003 Standards would be in compliance with COM-002 requirement R2.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments. The OPCPSDT
also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
Tacoma Power
Tacoma Power believes the Standard Drafting Team made Draft 5 overly complex and confusing for the
System Operators and Operators to use. The Drafting Team needs to go back to the basics. The standard
should apply to all, BA, TO, RC, GO and DPs alike.
1. Require all parties to develop Communication Protocols, train their operating personnel to use them,
review their protocols annually and make improvements if necessary.
2. Require all parties to use “3-part communication” and forget the “oral two-party, person-to-person
Operating Instruction” that has different requirements for GO and DP. All responsible entities should have
the same requirements. The proposed Standard as written allows for the Instruction to be repeated back “if
requested” by the issuer. This exception creates a “compliance” trap for the people communicating -
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remove it.
BASIC 3-PART COMMUNICATION should include:
* A System Operator or Operator shall issue an Operating Instruction
* The person receiving the Operating Instruction shall repeat it back to the issuer, and/or request
clarification if needed* The System Operator or Operator will acknowledge as correct and/or discuss
clarifications as needed and agree on the final instruction.
3. We are not sure why “address nomenclature for Transmission interface Elements and Transmission
interface Facilities” has replaced the term “common line identifiers.” Entities should coordinate their
communication protocols with the other Entities that they commonly communicate with and agree on:
* Nomenclature for Lines and equipment
* A common system for Alpha Numeric clarifiers
* Use 24-hour clock and identify the time, time-zone and if day-light savings or standard time is in effect.
System Operators and Operators are too busy to be put in the position of trying to maintain compliance
with a standard that is so convoluted and confusing as to become a potential violation. Tacoma Power
supports the original premise of the proposed COM-003 and the concept to separate the technical
communication equipment requirements from communication protocol requirements but the drafting team
has gone too far away from the intent of the standard by trying to make exceptions for too many different
issues when they do not need to. Get back to the basics, i.e. Draft 2.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments.
Texas Reliability Entity
Texas RE voted "no" on this draft for reasons expressed in our comments submitted on prior drafts. In
particular, we are concerned about lack of coordination between COM-003 and COM-002.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes
that will address your comments. The OPCPSDT also believes draft 6 requirements create a logical delineation between COM-0023 and COM-003-1.
Western Electricity
Coordinating Council
The apparent conflict beteen COM-002-3 and COM-003-1 needs to be addressed. The information provided
in the Frequently Asked Questions document was helpful but it is not clear that a drafting team response to
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a frequently asked question can alter what is required in another standard. It s not clear that developeing a
communcations protocol that says three-part communcation is not necessry for a one-way burst message is
going to relieve a BA, RC, or TOP from the requirement to use three-part communcations for all Reliabliity
Directives. If the position is that thre-part communcaiton is not required for one-way burst messages, this
exception should be included in COM-002-3.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments. The OPCPSDT
also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
Santee Cooper
The latest version of COM-003 introduces a potential conflict with COM-002 related to use of one-way burst
messaging systems to issue a Reliability Directive. COM-002 does not allow for only those responses
required in COM-003 but instead requires a full 3 way communication from all parties. This potentially sets
up both the issuer and receiver for violating COM-002 if they respond to a one-way burst messaging RD as
the requirements indicate in COM-003.
In COM-003, the follow Requirements are included:
R1.7 Instances where the issuer of an oral Operating Instruction or Reliability Directive using a one-way
burst messaging system to communicate a common message to multiple parties in a short time period (e.g.
an All Call system) is required to verbally or electronically confirm receipt from at least one receiving party.
R1.8 Require the receiver of an oral Operating Instruction or Reliability Directive using a one-way burst
messaging system to communicate a common message to multiple parties in a short time period (e.g. an All
Call system) to request clarification from the issuer if the communication is not understood.
R3.3 Require the receiver of an oral Operating Instruction or Reliability Directive using a one-way burst
messaging system to communicate a common message to multiple parties in a short time period (e.g. an All
Call system) to request clarification from the issuer if the communication is not understood.
In other words, COM-003 allows one-way burst messaging to be used for Reliability Directives and
prescribes:
o issuer to confirm receipt from at least one receiving party
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o receiver to request clarification from the issuer if the communication is not understood
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments. The OPCPSDT
also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
MRO NSRF
The NSRF recommends the following issues be addressed in order to provide a less ambiguous
Requirement.
Regarding R1 and the term; ‘implement’. The “Blue Box” explanation is not carried forward when the
standard is filed with the Commission. The “Blue Box” explanation greatly expands the meaning “and
implement”. Our understanding of ‘implement’ is that you will use the documented communication
protocols in the manner outlined in your System Operator communications protocols. Training is not a
demonstration of implementing. Only actual System Operator communications demonstrating the use of
the communication protocols is demonstrating implementation. Recommend that “training” be removed
from the blue text box since training is inherent to assuring that protocols are followed. The Training issue
will also need to be removed from the RSAW.
Response: The OPCPSDT has eliminated the blue box. The OPCPSDT believes the proposed draft 6 has
incorporated changes that will address your comments.
Suggest R1.8 be removed. This requirement cannot be measured. How do you prove compliance? An
entity will be asked to prove the negative and demonstrate that my System Operators were not confused? I
can see where I might have to provide an attestation that states: “My System Operators were not confused
on any one-way burst messages.” This proposed requirement is a common sense issue.
Response: The OPCPSDT has removed R1.8.
R1.9, R3.3: the word “coordination with affected” is vague and open to many interpretations. Suggest this
requirement be deleted. Should the requirement be kept, suggest clarifying what is intended in the
requirement. Such as “RC, TOP’s BA’s... shall share their communication protocols with applicable RC, BA,
TOP, ... “ The NSRF does not understand if the intent is to share or coordinate protocols? Both have
different outcomes, please clarify.
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC.
The NSRF believes that the infrequent communications to a Distribution Provider, that are not already in
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scope of COM-002-3, do not carry any considerable risk to the BES. The administrative burden on the
Distribution Provider should be greatly reduced, as there would not be a measurable gain in reliability by
requiring them to formally document communication protocols and establish a monitoring program. To
address these concerns, we recommend that Distribution Provider be removed from the applicability in R3
and R4. Secondly, we suggest that an R5 be created similarly to COM-002-3, R2. Recommend the following
for how the new R5 might read:
R5. Each Distribution Provider that is the recipient of an oral Operating Instruction, other than Reliability
Directives, shall:
5.1 Use the English language, unless another language is mandated by law or regulation.
5.2 Repeat, restate, rephrase, or recapitulate the oral Operating Instruction, excluding oral Operating
Instructions issued as a one-way burst message.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
Public Service
Enterprise Group
The purpose statement needs to have “System Operators” limited to just those of RCs, TOPs, and BAs. The
definition of “System Operators” in the NERC Glossary includes GOPs. The capitalizd language added to the
Purpose statement below would clarify this:
Purpose: To provide System Operators OF RELIABILITY COORDINATORS, TRANSMISSION OPERATORS, AND
BALANCING AUTHORITIES predefined communications protocols that reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of BES.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT changed the language of the purpose statement to COM003-1 to address the commenter’s concern.
ISO/RTO Standards
Review Committee
The SRC recognizes and commends the Drafting Team’s efforts to respond to Industry comments and to
offer a revised pragmatic solution for this Project. The proposed changes do not create a common resultsbased standard that addresses let alone resolves any identified reliability problem. The SRC is concerned
that the posting as proposed the standard creates a fill-in-the-blanks solution that could discourage a
functional entity from employing anything more than a least common denominator solution.
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Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Technically the definition and proposal are improvements and the SRC would agree with the proposed
changes, if the definition and proposal were needed. The issue is with the need for this definition, and the
continuing debate this definition is generating. The SRC is opposed to having this term defined and added to
the NERC Glossary. The term operating instruction does not need to be defined. For years, system operators
deal with operating instructions on a daily if not minute-to-minute basis. Having a defined term, and calling
such communication as “Command” is unnecessary, and potentially could confuse operators from what
they understand to be the meaning of operating instructions. While the SDT has found that their previous
definitions were not appropriate for a NERC standard, and the subsequent incremental changes are useful,
the debate itself does not seem to be a productive use of the SDT’s or the Industry’s time. The SRC would
prefer that the objectives of the SAR (communications protocols) be handled through means other than a
Standard (e.g. the Operating Committee’s Reliability Guidelines on Communications). The reason being, a
standard requires zero-defect compliance, data retention, self-reporting, and requires these debates over
the proposed terms such as “Operating instruction” which diverts the Industry, NERC and the Regional
Entities from focusing on more productive reliability issues.
The proposed RSAW wording must be more objective as the current test contains too many subjective
requirements:
Page 3
o “... Identification of instances ...” - will this be viewed as identification of every instance or will one
instance be sufficient?
o “...when....necessary...” - who decides when there is a necessity? The auditor or the functional entity?
Page 4
o“...may include...” - this phraseology may be seen as meaning the listed following items are among the
items that are required but are themselves insufficient to meet the requirement.
Page 5
o “...reviews of System Operator voice recordings...: - it should be made clear that the “review” is of the
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sampled recordings used by the entity in its own self-assessments, and not a “review” of any voice
recording.
o “Where practicable” is subjective and inappropriate for a standard. To avoid confusion and misapplication
of the standard, the RSAW should include a statement that messaging systems are not oral communication
and not evaluated under the standard.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
North American
Generator Forum
Standards Review
Team
The SRT agrees with the concepts put forth in COM-003, but have some concerns, particularly with the
proposed administrative burden associated with the Standard. The SRT offers to following comments:
1. R1.9 requires a TOP, BA, and RC to coordinate with affected RC, BA, TOP, DP and GOP communication
protocols; this could result in a TOP having to coordinate with a hundred+ different entities'
communications protocols. This coordination would not improve reliability, but only serve to create
confusion and significant communication time delays in real-time operations. Both R1 and R4 create
significant documentation and administrative burdens, without providing a comparable improvement to the
reliability of the BES. As reliability based Standard, COM-003 should focus on those actions that would have
a direct impact on reliability, while minimizing the administrative burden.
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC.
2. R3 should end after the first sentence. GOPs do not issue Operating Instructions. They only receive
instructions from others. GOPs should have a communications procedure as part of their operations,
however, the methods used are properly business decisions made by the GOP. The content, thoroughness
and effectiveness of a communications plan are excellent items to consider when assessing an entity’s
internal compliance program.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
3. R4 raises the question of sufficiency of an entities corrective program. The RSAW requires the GO to turn
over records of monitoring communications as well as records of corrective actions and then prove the
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“problem” is not still in place. This standard could easily turn into a high-profile audit target due to the
varying concepts of what does and does not constitute a sufficient corrective action program.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
4. The SRT recommends that the language to M4 be changed as follows:
M4. Each Distribution Provider and Generator Operator shall provide the results of its periodic assessment
and of any corrective actions (if any corrective actions were implemented) developed for Requirement R4.
Examples of sufficient periodic assessment programs include, but are not limited to, the following:
-Documented review of voice logs for a total of at least one hour per calendar year for each operator (does
not need to be a single session)
-Documented personal monitoring of communications for a total of at least one hour per calendar year for
each operator (does not need to be a single session)
-Documented annual training Examples of sufficient corrective action programs include, but are not limited
to, the following:
-Documented refresher training-Documented meeting-Documented “hot box” communication
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
5. The VSLs give a higher violation to a GOP than a BA for exactly the same error, even though the
consequences with the BA are much greater. A GOP who fails to require 3-part responses when requested is
tagged with a Moderate violation, while the BA would receive a Lower.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
6. In the RSAW, the following passage should be expunged; “Where practicable, verify that deficient
communication practice was indeed corrected by reviewing evidence of Operator communications (such as
voice recordings) occurring after the date of the corrective action to determine if deficient communication
practice was corrected.” Differentiating between slips of the tongue and “deficient communication
practices” involves subjective judgments. The same is true for attempting to identify changes in an
operator’s degree of understanding, especially when doing so through the numbing process of making
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before-and-after voice recording comparisons. This is an open-ended matter that could very quickly
become an unreasonable compliance burden. RSAWs in general should not introduce new requirements,
measures or forms of evidence, so the GOP materials reviewed should be limited to the
protocols/procedures of R3, and the assessment forms and corrective action reports of R4.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
NYISO
The text presented in the blue box for Requirement 1 should be incorporated into Requirement #1. If the
requirement needs to be explained at this point, we recommend clarifying it in the text. In addition, by
using this definition we have now introduced a list of controls that we will be audited against.
Response: The blue text box has been eliminated. The OPCPSDT believes the proposed draft 6 has
incorporated changes that will address your comments.
The requirement should simply be to have a procedure. The controls assessment can be addressed during
the future RAI process. The current draft provides for a fill in the blank framework that allows for an entity
to define what is applicable for its communication protocol. A better approach would be to state that an
entity may include items from the list provided that the entity identifies them as critical. Then the entity
would only be required to show what is critical to its operations, rather than having to prove what is not
critical.
Response: The OPCPSDT eliminates R2 and R4 “assess and correct” language in draft 6 and ties
performance to avoiding communication related events that would generate a Reliability Directive.
The language in requirement 1.5 needs to be clarified. It is not clear on how an entity is required to
‘confirm’ the response was accurate. This could simply be a ‘2 part communication’, where once the
receiving entity repeats the instruction, the initiator may move on if he deems it correct. Or does the
confirmation need to be ‘confirmed’ with the receiving party as in ‘3 part communications’? If the
requirement is meant to initiate 2 part communication, the requirement should say that. If the requirement
is meant for ‘3 part communication,’ then we recommend utilizing the language from COM-002 R2 in place
of Requirements 1.5 and 1.6.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
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comments.
Response: The OPCPSDT thanks you for your comments.
PPL NERC Registered
Affiliates
These comments are submitted on behalf of the following PPL Companies: Louisville Gas and Electric
Company and Kentucky Utilities Company; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; and PPL
Generation, LLC, on behalf of its NERC registered subsidiaries. The PPL Companies are registered in six
regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP,
GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP. The PPL Companies believe that the revised COM-003
standard represents an improvement over previous drafts. Nevertheless, we have one concern with the
proposed standard and urge the Standard Drafting Team to add the following note to Requirements 1.7,
1.8, and 3.3 in the standard before it is submitted to NERC and FERC for their approval: Notwithstanding
anything in COM-002, the requirements set forth in COM-003 Requirements R1.7, R1.8 and R3.3 shall
govern the manner for responding to Reliability Directives that are issued through one-way burst messages
(e.g., an All Call system).
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes
that will address your comments. The OPCPSDT also believes draft 6 requirements create a logical delineation between COM-0023 and COM-003-1.
South Carolina Electric
and Gas
This standard is becoming overly complicated. The reason this COM standard is being developed is to
reduce the possibility of miscommunication of information when the BES is being altered. This proposed
standard is an administrative burden. Operators will be fearful that they will cause a NERC Compliance
Violation every time they communicate. Their focus will be on communicating compliantly and not on
operating the BES. Consideration should be given to simplifying this standard.
Below is an unrefined proposal for consideration:
R1: Applicable REs shall have a procedure that requires its personnel (whether as a receiver or as an
initiator) to use three-part communication when altering the state of the BES. Three-part communication is
defined as when an initiator issues a command, the receiver repeats the command back, and the initiator
confirms. Any misunderstandings are resolved during the repeat back. (3-part communication is the only
proven way to mitigate miscommunication. If personnel use three way communication then all issues
related to alpha-numeric clarifiers, time, etc should be resolved naturally during the repeat
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back/confirmation. Additionally, this requires operators and field personnel to remember one thing: when
changing the state of the BES they must use 3-part communication.)
R2: Each calendar month REs required to comply with R1 shall assess a random sample of communications
that occurred over the month to ensure that three-way communication was properly being utilized, when
the BES was being altered. In instances where deficiencies are found, REs shall require remedial training to
be completed by the individuals involved in the deficient communication. (Remedial training will act as a
deterrent for those who get lazy about using three-part communication. Additionally, peers will be aware of
who had to undergo remedial training, which will further act as deterrent. Requiring remedial training
would be an incentive to using three-part communication properly)
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes that
will address your comments.
MISO
To avoid confusion and misapplication of the standard, the RSAW should include a statement that electronic
messaging systems are not subject to compliance with this standard.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes
that will address your comments.
Tennessee Valley
Authority
TVA Nuclear Power’s Human Performance program is driven by INPO and includes
1) requirements for operations to use 3-way communication and the phonetic alphabet; and
2) a documented assessment process via an established observation program with corrective actions. Any
additional oversight process will contribute to distraction in the control room and promote overreliance on
process and procedure with a “checklist mentality” rather than focus on potential impacts of the task being
performed. If the RC, TOP, or BA specifically requests confirmation of a verbal communication (R1.6), our
nuclear plant operators will respond accordingly as they are already expected to do. The use of “periodic
assessment” in the measurements does not provide adequate guidance in the development of consistent,
effective measures of compliance.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes that
will address your comments. The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA and RC to
develop the protocols subject to the approval of the RC.
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The United Illuminating UI as its functional role of DP is voting No because of the conflict between COM-003 R 1.7, R1.8 and R3.3
Company
with COM-002 R2. COM-003 allows for the RC/TOP/BA communication protocol when issuing Reliability
Directives to overide the clearly stated requirement of COM-002 R2 that a DP SHALL REPEAT, RESTATE,
REPHRASE, OR RECAPITULATE the Reliability Directive. There is no leeway in COM-002 R2 to allow for solely
providing an affirmation of receipt of a verbal reliability directive or not repeating back the message when
the RC/TOP requests no repeat. As a DP, UI is placed in a position of attempting to comply with two
opposing requirement in the two standards. If the RC/TOP communication protocol clearly stated that
there will be no repeat back when receiving a verbal Reliability Directive and COM-003 requires a DP to
comply with the RC/TOP communication protocol, UI would have to choose between violating COM-002 or
COM-003. Since the VRF for COM-002 R2 is HIGH indicating a greater risk to reliability than COM-003 VRF
LOW, UI would comply with COM-002 R2. This issue can be resolved either by correcting COM-002 by
assigning the flexibility of opting out of repeat back to the RC/TOP/BA function, or removing the words
"Reliability Directive" from COM-003.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your comments. The OPCPSDT
also believes draft 6 requirements create a logical delineation between COM-002-3 and COM-003-1.
Hydro One Networks
Inc.
We are not convinced that a Standard is the best approach to routine communications, but we feel that the
latest draft is a reasonable compromise.
Response: The OPCPSDT thanks you for your comments.
ISO New England Inc.
We do not believe a Standard is needed, given other developments:
A. The SDT materials have not demonstrated the reliability gap/need for this Standard. Without having a
better sense of what the scope of the actual reliability risks are (frequency, impact, etc...), it’s difficult to
know if the proposed solution - as embodied in COM-003 Draft Version 5 - is “necessary to provide for
reliable operation of the bulk-power system”.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
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B. Moreover, the Requirements that the recipient repeat, restate, etc., if required/requested by the issuer
(1.6 & 3.2) suggest that a RC, BA or TOP needs to ensure a repeat back or be non-compliant even though
taking this extra time may, in fact, impact reliability.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments. The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC.
C. Lastly, the fact that the Ballot Body and Standard Drafting Team continue to have so many questions
about how to interpret these requirements (see the recently issued FAQs) suggests:
(a) that the Operating Committee would serve as a more effective forum for discussing what additional
communication practices, if any, are needed, and
(b) the requirements themselves may be unduly ambiguous. - Proposed Solution: We support
strengthening communications protocols such as contained in the pending COM-002 revisions and in the OC
White Paper. NERC Event Analysis Staff should work with the NERC OC to document the reported risks to
the system, continue to monitor system operator performance, and periodically report on findings.
If, however, it is determined that the Standard will move forward, then we would offer the following
suggestions:
A. We consider use of one-way burst messaging systems to be electronic and, as such, do not believe they
should be included in the Standard. Further, in accordance with 1.5, a one-way burst messaging system is
not a “oral two party, person-to-person Operating Instruction,” which would further justify its exclusion.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
B. Draft Version 5’s Requirements establish that each covered registered Entity shall develop its own
communication protocol outlining the communications expectations of its operators. This has the potential
for confusion as multiple Registered Entities within a single RC, BA or TOPs’ footprint may establish different
communication expectations.
- Proposed Solution: The Requirements should establish that if the RC, BA or TOP establish a
communication protocol for their System Operators, the RC, BA or TOP should share that protocol with
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Registered Entities operating within their footprint, those Registered Entities must follow the RC, BA or
TOP’s protocol, or adopt a consistent one for their company
Response: The OPCPSDT has modified the standard by changing the R1 language to require the TOP, BA
and RC to develop the protocols subject to the approval of the RC.
C. We agree with the SDT that the COM Standard need not employ a “zero tolerance/zero defect” approach,
because NERC Enforcement need not monitor and assess every Operator-to-Operator communication. In
Draft Version 5 (Measurements & RSAW), NERC, however, appears to adopt an approach of establishing
“zero tolerance” around a Company’s Internal Controls program. The RSAW states that registered entities
must provide “evidence that corrective actions necessary to meet the expectations in its documented
communication protocols... are taken” and “deficient communication practice was indeed corrected.” This type of approach to Standard drafting raises untested questions of how the Standard will be enforced,
whether it is a “fill-in-the-blank”-type Standard, and whether a new “zero tolerance” enforcement approach
to monitoring will, in fact, be maintained.
- Proposed solution: Draft a Standard that sets performance based expectations and allow the ERO to use
its enforcement discretion (e.g., through FFT and through review of internal control programs) to determine
how stringently to audit and sanction.
Response: The OPCPSDT believes the proposed draft 6 has incorporated changes that will address your
comments.
Response: The OPCPSDT thanks you for your comments.
Ameren
We would ask the SDT to consider for clarity to this standard that COM-002 only address Reliability
Directives and COM-003 only address Operating Instructions.
Response: The OPCPSDT thanks you for your comments. The OPCPSDT believes the proposed draft 6 has incorporated changes
that will address your comments. The OPCPSDT also believes draft 6 requirements create a logical delineation between COM-0023 and COM-003-1.
END OF REPORT
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot closed
June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Ballot closed
September 22, 2012.
9.
Version 4 draft of Standard posted November 2012 for Formal Comments, Ballot closed
December 13, 2012.
10. Version 5 draft of Standard posted March 2013 for Formal Comments, Ballot closed
April 5, 2013.
Description of Current Draft:
This is the sixth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Fourth Successive Ballot of Standard
June 2013
2. Recirculation ballot of standard.
July 2013
3. Board adopts standard.
August 2013
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Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A command, other than a Reliability Directive, by a System Operator of
a Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.
A discussion of general information and of potential options or alternatives to resolve Bulk
Electric System operating concerns is not a command and is not considered an Operating
Instruction. An Operating Instruction is exclusive and distinct from a Reliability Directive. There
is no overlap between an Operating Instruction and Reliability Directive.
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A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To strengthen communications for the issuance of Operating Instructions
with predefined communications protocols that reduce the possibility of
miscommunication that could adversely impact the reliability of the Bulk Electric
System.
4.
Applicability:
COM-003-1
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
B. Requirements
R1.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator, in
each Reliability Coordinator area, shall develop, subject to the Reliability
Coordinator’s approval, documented communication protocols for the issuance of
Operating Instructions in that Reliability Coordinator’s area.
The documented communication protocols will address, where applicable, the
following: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning]
1.1. The use of the English language when issuing or responding to an oral or
written Operating Instruction, unless another language is mandated by law
or regulation.
1.2. The instances, if any, that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.3. The nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
1.4. The instances, if any, where alpha-numeric clarifiers are necessary when
issuing an oral Operating Instruction and the format for those clarifiers.
1.5. The instances where the issuer of an oral two party, person-to-person
Operating Instruction requires the receiver to repeat, restate, rephrase, or
recapitulate the Operating Instruction and the issuer to:
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•
Confirm that the response from the recipient of the Operating Instruction
was accurate; or
•
Reissue the Operating Instruction to resolve a misunderstanding.
R2.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement its communication protocols developed in Requirement R1 so
that the failure to use the protocols by the issuer of an Operating Instruction does
not result in an operating condition that requires the issuance of a Reliability
Directive by the original issuer of the Operating Instruction or by another
Balancing Authority, Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium][Time Horizon: Real Time Operations ]
R3.
Each Balancing Authority, Transmission Operator, Generator Operator and
Distribution Provider shall repeat, restate, rephrase, or recapitulate an Operating
Instruction when required by the issuer of an Operating Instruction in its
communication protocols developed in Requirement R1 so that the failure to
repeat, restate, rephrase, or recapitulate the Operating Instruction does not result
in an operating condition that requires the issuance of a Reliability Directive by
the original issuer of the Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator. [Violation Risk Factor:
Medium][Time Horizon: Real Time Operations ]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator in each
Reliability Coordinator area, shall provide its documented communications protocols
developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence that it did not issue an Operating Instruction that resulted in an
operating condition that required the issuance of a Reliability Directive by the issuer or
another Balancing Authority, Reliability Coordinator, or Transmission Operator due to
the failure to use documented communications protocols developed for Requirement
R1. A Balancing Authority, Reliability Coordinator, and Transmission Operator may
need to coordinate with another Reliability Coordinator, Balancing Authority and
Transmission Operator to provide this evidence.
M3. Each Balancing Authority, Generator Operator, Distribution Provider, and
Transmission Operator shall provide evidence that it did not experience a failure to
repeat, restate, rephrase, or recapitulate an Operating Instruction, when required, that
resulted in an operating condition that required the issuance of a Reliability Directive
by the issuer or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator due to the failure to use the protocols. A Balancing Authority,
Generator Operator, Distribution Provider, and Transmission Operator may need to
coordinate with a Reliability Coordinator, Balancing Authority and Transmission
Operator to provide this evidence.
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D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R1 Measure M1 for the most
recent 90 days.
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R2 Measure M2 for the most
recent 90 days.
Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator shall retain evidence for Requirement R3 Measure M3
for the most recent 90 days.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
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Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
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R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1
Long Term
Planning
Low
The Responsible Entity did
not develop one (1) of the
five (5) parts of Requirement
R1in their documented
communication protocols as
required in Requirement R1.
Parts of Requirement R1,
(1.1 to 1.5) not applicable to
the Responsible Entity are
excluded
The Responsible Entity did
not develop two (2) of the five
(5) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1.
Parts of Requirement R1, (1.1
to 1.5) not applicable to the
Responsible Entity are
excluded
The Responsible
Entity did not develop
three (3) of the five (5)
parts of Requirement
R1 in their
documented
communication
protocols as required
in Requirement R1.
Parts of Requirement
R1, (1.1 to 1.5) not
applicable to the
Responsible Entity are
excluded
The Responsible Entity did
not develop four (4) or more
of the five (5) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1. Parts of
Requirement R1, (1.1 to 1.5)
not applicable to the
Responsible Entity are
excluded
R2
Real Time
Operations
Medium
N/A
N/A
N/A
The Responsible Entity
failed to use the protocols
developed in Requirement
R1 which resulted in an
operating condition that
required the issuance of a
Reliability Directive by the
original issuer of the
Operating Instruction or by
another Balancing Authority,
Reliability Coordinator, or
Transmission Operator.
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R3
Real Time
Operations
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Medium
N/A
N/A
N/A
Page 8 of 9
The Responsible Entity
failed repeat, restate,
rephrase, or recapitulate an
Operating Instruction when
required by the issuer of an
Operating Instruction in its
communication protocols
developed in Requirement
R1, which resulted in an
operating condition that
required the issuance of a
Reliability Directive by the
original issuer of the
Operating Instruction or
another Balancing
Authority, Reliability
Coordinator, or
Transmission Operator.
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
E. Regional Variances
None.
Version History
Version
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Date
Action
Change Tracking
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting SAR on June 8, 2007
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007
6. Version 1 draft of Standard posted November 2009 for Informal Comments closed
January 15 2010.
7. Version 2 draft of Standard posted May 2012 for Formal Comments, Initial Ballot closed
June 20 2012.
8. Version 3 draft of Standard posted August 2012 for Formal Comments, Ballot closed
September 22, 2012.
9.
Version 4 draft of Standard posted November 2012 for Formal Comments, Ballot closed
December 13, 2012.
10. Version 5 draft of Standard posted March 2013 for Formal Comments, Ballot closed
April 5, 2013.
Description of Current Draft:
This is the fifthsixth draft of a new standard requiring the use of standardized communication
protocols during normal and emergency operations to improve situational awareness and shorten
response time. The drafting team requests posting for a 30-day concurrent Formal Comment
period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. ThirdFourth Successive Ballot of StandardsStandard
MarchJune 2013
2. Recirculation ballot of standardsstandard.
AprilJuly 2013
3. Board adopts standardsstandard.
MayAugust 2013
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
When using terms or phrases contained in the Reliability Standards Glossary of Terms for
communications it should be cited as the source. When used in written communications, terms or
phrases contained in the Reliability Standards Glossary of Terms are capitalized.
Operating Instruction —A command, other than a Reliability Directive, by a System Operator of
a Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the command is expected to act, to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System.
Discussions
A discussion of general information and of potential options or alternatives to resolve Bulk
Electric System operating concerns are is not a commands and are is not considered Operating
Instructionsan Operating Instruction. An Operating Instruction is exclusive and distinct from a
Reliability Directive. There is no overlap between an Operating Instruction and Reliability
Directive.
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COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To provide System Operatorsstrengthen communications for the issuance
of Operating Instructions with predefined communications protocols that reduce the
possibility of miscommunication that could lead to action or inaction harmful
toadversely impact the reliability of the BESBulk Electric System.
4.
Applicability:
COM-003-1
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Generator Operator
4.1.4
Reliability Coordinator
4.1.5
Transmission Operator
(Proposed) Effective Date: First day of first calendar quarter, twelve (12) calendar
months following applicable regulatory approval; or, in those jurisdictions where no
regulatory approval is required, the first day of the first calendar quarter twelve (12)
calendar months from the date of Board of Trustee adoption.
B. Requirements
Implementation means (in R1, R2 R3 and R4)
R1.
incorporating the communication protocols
Each Balancing Authority, Reliability
into processes, policies, procedures, training
Coordinator, and Transmission Operator, in each
programs and assessment programs to support
Reliability Coordinator area, shall jointly develop
setting and attaining the communication
expectations of operators (R3) and System
and implement, subject to the Reliability
Operators (R1).
Coordinator’s approval, documented,
documented communication protocols for the
issuance of Operating Instructions in that outline
the communications expectations of its System Operators. Reliability
Coordinator’s area.
The documented communication protocols will address, where applicable, the
following: [Violation Risk Factor: Low] [Time Horizon: Long-term Planning ]
1.1. UseThe use of the English language when issuing or responding to an oral
or written Operating Instruction or Reliability Directive, unless another
language is mandated by law or regulation.
1.2. InstancesThe instances, if any, that requirerequire time identification when
issuing an oral or written Operating Instruction or Reliability Directive, and
the format for that time identification.
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1.3. NomenclatureThe nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction or Reliability Directive.
1.4. InstancesThe instances, if any, where alpha-numeric clarifiers are necessary
when issuing an oral Operating Instruction or Reliability Directive, and the
format for those clarifiers.
1.5. InstancesThe instances where the issuer of an oral two party, person-toperson Operating Instruction is requiredrequires the receiver to repeat,
restate, rephrase, or recapitulate the Operating Instruction and the issuer to:
•
Confirm that the response from the recipient of the Operating Instruction
was accurate,; or
•
Reissue the Operating Instruction to resolve a misunderstanding.
1.6. Require the recipient of an oral two party, person-to-person Operating Instruction
to repeat, restate, rephrase, or recapitulate the Operating Instruction, if requested
by the issuer.
1.7. Instances where the issuer of an oral Operating Instruction or Reliability Directive
using a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) is required to
verbally or electronically confirm receipt from at least one receiving party.
1.8. Require the receiver of an oral Operating Instruction or Reliability Directive using
a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request
clarification from the initiator if the communication is not understood.
1.9. Coordination with affected Reliability Coordinators’, Balancing Authorities’,
Transmission Operators’, Distribution Providers’, and Generator Operators’
communication protocols.
R2.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall develop method(s) to assess System Operators’ communication practices
and implement corrective actions necessary to meet the expectations in its
documented its communication protocols developed forin Requirement R1 so that
the failure to use the protocols by the issuer of an Operating Instruction does not
result in an operating condition that requires the issuance of a Reliability
Directive by the original issuer of the Operating Instruction or by another
Balancing Authority, Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium] [][Time Horizon: Real Time Operations
Planning, Operations Assessment ] ]
R1.
R2. Each Balancing Authority, Transmission Operator, Generator Operator and
Distribution Provider and Generator Operator shall develop and implement
documented communication protocols that outline the communications expectations
of its operators. The documented communication protocols will address, where
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applicable, the following: [Violation Risk Factor: Low] [Time Horizon: Long-term
Planning ]
3.1. Use of the English language repeat, restate, rephrase, or recapitulate an Operating
Instruction when responding torequired by the issuer of an oral or written
Operating Instruction or Reliability Directive, unless another language is
mandated by law or regulation.
3.2. Require the recipient of an oral two party, person-to-person Operating
Instructionin its communication protocols developed in Requirement R1 so that
the failure to repeat, restate, rephrase, or recapitulate the Operating Instruction, if
requested by the issuer.
3.3. Require the receiver of an oral Operating Instruction or Reliability Directive using
a one-way burst messaging system to communicate a common message to
multiple parties in a short time period (e.g. an All Call system) to request
clarification from the initiator if the communication is does not understood, if
required by the issuer.
R3.
Each Distribution Provider and Generator Operator shall develop method(s) to
assess operators’ communication practices and implement corrective actions
necessary to meet the expectationsresult in its documented communication
protocols developed for Requirement R3an operating condition that requires the
issuance of a Reliability Directive by the original issuer of the Operating
Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator. [Violation Risk Factor: Medium] [][Time Horizon: Real
Time Operations Planning /Operations Assessment ]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator in each
Reliability Coordinator area, shall provide its jointly developed documented
communications protocols developed for Requirement R1.
M1.M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall provide evidence that it implemented its documented communication protocols
that it developed for Requirement R1 which may include, but is not limited to, its
policies, procedures, and or operator training. did not issue an Operating Instruction
that resulted in an operating condition that required the issuance of a Reliability
Directive by the issuer or another Balancing Authority, Reliability Coordinator, or
Transmission Operator due to the failure to use documented communications protocols
developed for Requirement R1. A Balancing Authority, Reliability Coordinator, and
Transmission Operator may need to coordinate with another Reliability Coordinator,
Balancing Authority and Transmission Operator to provide this evidence.
M2. Each Balancing Authority, Reliability Coordinator, Generator Operator, Distribution
Provider, and Transmission Operator shall provide the results of its periodic
assessment and of any corrective actions (if any corrective actions were implemented)
developed for Requirement R2.
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M3. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R3. Each Distribution Provider,
and Generator Operator shall provide evidence that it implemented its documented
communication protocols that it developed for Requirement R3 which may include, but
isdid not limitedexperience a failure to, its policies, procedures, and repeat, restate,
rephrase, or operator training.
M4.M3. Each Distribution Provider andrecapitulate an Operating Instruction, when
required, that resulted in an operating condition that required the issuance of a
Reliability Directive by the issuer or by another Balancing Authority, Reliability
Coordinator, or Transmission Operator due to the failure to use the protocols. A
Balancing Authority, Generator Operator shall provide the results of its periodic
assessment and of any corrective actions (if any corrective actions were implemented)
developed for Requirement R4., Distribution Provider, and Transmission Operator may
need to coordinate with a Reliability Coordinator, Balancing Authority and
Transmission Operator to provide this evidence.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Transmission Operator, Balancing Authority, Reliability Coordinator,
Generator Operator, and Distribution Provider shall keep data or evidence to show
compliance as identified below unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation:
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R1 Measure M1 for the most
recent 90 days.
Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall retain evidence for Requirement R2 Measure M2 for the most
recent 18090 days.
Each Balancing Authority, Distribution Provider and, Generator Operator, and
Transmission Operator shall retain evidence for Requirement R3 Measure M3
for the most recent 90 days.
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Each
If a Balancing Authority, Distribution Provider and, Generator Operator shall
retain evidence for Requirement R4 Measure M4 for the most recent 180
days.
If a Transmission Operator, Balancing Authority, , Reliability Coordinator,
Generator or Transmission Operator or Distribution Provider is found noncompliant, it shall keep information related to the non-compliance until mitigation
is complete and approved or for the time period specified above, whichever is
longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
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R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R1
Long Term
Planning
Low
The Responsible Entity did
not address develop one (1)
of the ninefive (59) parts of
Requirement R1in their
documented communication
protocols as required in
Requirement R1. Parts of
Requirement R1, (1.1 to 1.5)
justifiably not applicable to
the Responsible Entity are
excluded
Moderate VSL
High VSL
Severe VSL
The Responsible Entity did
not address develop two (2) of
the nine five (59) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1. Parts of
Requirement R1, (1.1 to 1.5)
justifiably not applicable to the
Responsible Entity are
excluded
The Responsible
Entity did not address
develop three (3) of
the nine five (59)
parts of Requirement
R1 in their
documented
communication
protocols as required
in Requirement R1.
Parts of Requirement
R1, (1.1 to 1.5)
justifiably not
applicable to the
Responsible Entity are
excluded
The Responsible Entity did
not address develop four (4)
or more of the the nine five
(95) parts) parts of
Requirementof Requirement
R1 in their documented
communication protocols as
required in Requirement R1.
Parts of Requirement R1,
(1.1 to 1.5) justifiably not
applicable to the
Responsible Entity are
excluded
OR
The Responsible Entity did
not have any documented
communication protocols as
required in Requirement R1
OR
OR
The Responsible Entity did
not implement one (1) of the
nine (9) parts of
Requirement R1 in their
documented communication
protocols as required in
Requirement R1
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The Responsible Entity did
not implement two (2) of the
nine (9) parts of Requirement
R1 in their documented
communication protocols as
required in Requirement R1
The Responsible
Entity did not
implement three (3) of
the nine (9) parts of
Requirement R1 in
their documented
communication
protocols as required
in Requirement R1
P a g e 8 o f 12
OR
OR
The Responsible Entity did
not implement any
documented communication
protocols as required in
Requirement R1
COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R2
Operations
Planning
Medium
Operations
Assessmen
tReal Time
Operations
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The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented
50 % or more but not all
corrective action identified
in Requirement R2
necessary to meet the
expectations in its
documented communication
protocols developed for
Requirement R1.N/A
The Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented less
than 50 % of the corrective
actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.N/A
The Responsible
Entity performed
periodic assessments
of its System
Operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R2
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement
R1.N/A
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The Responsible Entity
failed to use the protocols
developed in Requirement
R1 which resulted in an
operating condition that
required the issuance of a
Reliability Directive by the
original issuer of the
Operating Instruction or by
another Balancing Authority,
Reliability Coordinator, or
Transmission Operator.The
Responsible Entity did not
perform periodic
assessments of its System
Operators’ communication
practices identified in
Requirement R2 necessary
to meet the expectations in
its documented
communication protocols
developed for Requirement
R1.
COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R3
Long Term
PlanningRe
al Time
Operations
LowMedi
um
N/A
N/A The Responsible Entity
did not address one (1) of the
three(3) parts of
Requirement R3in their
documented communication
protocols as required in
Requirement R3
N/AThe Responsible
Entity did not address
two (2) of the three(3)
parts of Requirement
R3 in their
documented
communication
protocols as required
in Requirement R3
OR
OR
The Responsible Entity did
not implement one (1) of the
three(3) parts of
Requirement R3
in their documented
communication protocols as
required in Requirement R3
The Responsible
Entity did not
implement two (2) of
the three(3) parts of
Requirement R3 in
their documented
communication
protocols as required
in Requirement R3
The Responsible Entity
failed repeat, restate,
rephrase, or recapitulate an
Operating Instruction when
required by the issuer of an
Operating Instruction in its
communication protocols
developed in Requirement
R1, which resulted in an
operating condition that
required the issuance of a
Reliability Directive by the
original issuer of the
Operating Instruction or
another Balancing
Authority, Reliability
Coordinator, or
Transmission Operator.The
Responsible Entity did not
address three (3) of the
three(3) parts of
Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
The Responsible Entity
did not develop any
documented communication
protocols as required in
Requirement R3
OR
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The Responsible Entity
did not implement any
documented communication
protocols as required in
Requirement R3
COM-003-1 Op era tin g P e rs o n n e l Com m u nic atio n s P ro to c ols
R4
Operations
Planning
Medium
Operations
Assessment
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The Responsible Entity
performed periodic
assessments of its
operators’
communication practices
and implemented 50 %
or more but not all
corrective action
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication protocols
developed for
Requirement R3.
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 %
of the corrective actions
identified in Requirement R4
necessary to meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
The Responsible Entity
performed periodic
assessments of its
operators’
communication
practices but did not
implement any
corrective actions
identified in
Requirement R4
necessary to meet the
expectations in its
documented
communication
protocols developed
for Requirement R3
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The Responsible Entity did
not perform assessments of
its operators’
communication practices
and did not meet the
expectations in its
documented communication
protocols developed for
Requirement R3.
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E. Regional Variances
None.
Version History
Version
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Date
Action
Change Tracking
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction — A command, other than a Reliability Directive, by a System Operator of a
Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the recipient
of the command is expected to act to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.
A discussion of general information and of potential options or alternatives to resolve BES operating
concerns is not a command and is not considered an Operating Instruction. An Operating Instruction is
exclusive and distinct from a Reliability Directive. There is no overlap between an Operating Instruction
and Reliability Directive.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
COM-001-1.1 Requirement R4
R4.Unless agreed to otherwise, each
Reliability Coordinator, Transmission
Operator, and Balancing Authority shall use
COM-003-1 Requirement R1 Part 1.1
R1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator,
in each Reliability Coordinator area, shall
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develop, subject to the Reliability
Coordinator’s approval, documented
communication protocols for the issuance
of Operating Instructions in that Reliability
Coordinator’s area. The documented
communication protocols will address,
where applicable, the following:[Violation
Risk Factor: Low] [Time Horizon: Long-term
Planning ]
English as the language for all communications
between and among operating personnel
responsible for the real-time generation
control and operation of the interconnected
Bulk Electric System. Transmission Operators
and Balancing Authorities may use an
alternate language for internal operations
1.1.
The use of the English language when
issuing or responding to an oral or written
Operating Instruction, unless another
language is mandated by law or regulation
Conform ing Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval, or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator must develop their
communication protocols prior to the effective date of COM-003-1 to satisfy Requirement R1.
COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-003-1 in the particular Jurisdiction in which COM-003-1 is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
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Implementation Plan
Project 2007-02 - Operating Personnel Communications Protocols
Implementation Plan for COM-003-1 – Operating Personnel Communications Protocols
Standard
Approvals Required
COM-003-1 – Operating Personnel Communications Protocols Standard
Prerequisite Approvals
None
R evisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
Operating Instruction — A command, other than a Reliability Directive, by a System Operator of a
Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the recipient
of the command is expected to act to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System.
A discussion of general information and of potential options or alternatives to resolve BES operating
concerns is not a command and is not considered an Operating Instruction. An Operating Instruction is
exclusive and distinct from a Reliability Directive. There is no overlap between an Operating Instruction
and Reliability Directive.
A command by a System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a
Balancing Authority, where the recipient of the command is expected to act to change or preserve the
state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. Discussions of general information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered Operating Instructions.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
R evisions or Retirem ents to Approved Standards
Approved Requirement to be Retired
Proposed Replacement Requirement(s)
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COM-001-1.1 Requirement R4
COM-003-1 Requirement R1 Part 1.1
R4.Unless agreed to otherwise, each
R1. Each Balancing Authority, Reliability
Reliability Coordinator, Transmission
Coordinator, and Transmission Operator,
Operator, and Balancing Authority shall use
in each Reliability Coordinator area, shall
English as the language for all communications
jointly develop, subject to the Reliability
between and among operating personnel
Coordinator’s approval, documented
responsible for the real-time generation
communication protocols for the issuance
control and operation of the interconnected
of Operating Instructions in that Reliability
Bulk Electric System. Transmission Operators
Coordinator’s area.Each Balancing
and Balancing Authorities may use an
Authority, Reliability Coordinator, and
alternate language for internal operations
Transmission Operator shall develop and
implement documented communication
protocols that outline the communications
expectations of its System Operators. The
documented communication protocols will
address, where applicable, the
following:[Violation Risk Factor: Low]
[Time Horizon: Long-term Planning ]
1.1.
Use The use of the English language when
issuing or responding to an oral or written
Operating Instruction or Reliability Directive,
unless another language is mandated by law
or regulation
Conform ing Changes to Other Standards
None
Effective Dates
COM-003-1 shall become effective the first day of first calendar quarter, twelve calendar months
following applicable regulatory approval, or as otherwise made effective pursuant to the laws applicable
to such ERO governmental authorities; or, in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter twelve calendar months from the date of Board of
Trustee adoption.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator must develop their
communication protocols prior to the effective date of COM-003-1 to satisfy Requirement R1.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
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COM-001-1.1 Requirement R4 shall expire midnight of the day immediately prior to the Effective Date
of COM-003-1 in the particular Jurisdiction in which COM-003-1 is becoming effective.
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Project 2007-02 Operating Personnel Communications
Protocols
Unofficial Comment Form for Standard COM-003-1 —Operating Personnel Communications
Protocols
Please DO NOT use this form. Please use the electronic comment form located at the link below to
submit comments on the proposed draft COM-003-1 Operating Personnel Communications Protocols
standard. Comments must be submitted by July 19, 2013. If you have questions please contact
Joseph Krisiak at [email protected] or by telephone at 609-651-0903.
http://www.nerc.com/filez/standards/Op_Comm_Protocol_Project_2007-02.html
Background Information:
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and
approved by the Standards Committee on June 8, 2007. It established the scope of work to be
done for Project 2007-02 Operating Personnel Communications Protocols (OPCP SDT). The scope
described in the SAR is to establish essential elements of communications protocols and
communications paths such that operators and users of the North American Bulk Electric System
will efficiently convey information and ensure mutual understanding. The August 2003 Blackout
Report, Recommendation Number 26, calls for a tightening of communications protocols. FERC
Order 693 paragraph 532 amplifies this need. This proposed standard’s goal is to ensure that
effective communication is practiced and delivered in clear language and standardized format.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and
mutually understood for communicating Operating Instructions.
The Purpose statement of COM 003-1 states: “To strengthen communications for the issuance of
Operating Instructions with predefined communications protocols that reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the Bulk Electric
System.”
1) New NERC Glossary terms: The SDT has added language to the previous definition of
“Operating Instructions” proposed in the Standard version 5 to further clarify the
distinction between an “Operating Instruction” and a “Reliability Directive.”
“Operating Instructions” differentiates the broad class of communications that deal
with changing or altering the state of the BES from general discussions of options or
alternatives; and from Reliability Directives that apply to Adverse Reliability Impacts and
Emergencies on the BES. Changes to the BES operating state with unclear communications
create increased opportunities for events that could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures.
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This term is proposed for addition to the NERC Glossary to establish meaning and usage
within the electricity industry.
2) COM-003-1, Draft 6 now features 3 requirements. The requirement structure and
language has been changed in draft 6 based on changes to the standard recommended by
Industry representatives who commented on draft 5 and from Industry representatives who
participated in the Informal Review of the proposed draft 6 standard. The language in COM003-1, draft 6, R1 retained from the “Communications in Operations” Conference of
February 14-15, 2013, in Atlanta still permits applicable entities flexibility to develop their
communication protocols, but requires applicable entities to develop the protocols,
subject to the Reliability Coordinator’s approval. This addresses commenters’ concerns
over uniformity within Reliability Coordinator control areas.
The assess and correct language has been removed (COM-003-1, draft 5, R2 and R4) based
on concerns over compliance with internal controls. Rather than focus on internal controls
and System Operator performance improvement controls, the COM-003-1, draft 6, R2 and
R3 requirements now focus on misuse or lack of use of the communication protocols
(developed in COM-003-1, draft 6, R1) resulting in the issuance of a Reliability
Directive. This approach requires the entity to manage the effective use of their governing
communication protocols to avoid a situation that will initiate an Adverse Reliability Impact
or an Emergency on the BES. This directly links communication to a reliability result, which
is a recommendation offered by commenters in the last 5 drafts.
Documented Communication Protocols: The OPCPSDT has retained requirement COM003-1, draft 5, Requirement R1 and eliminated COM-003-1, draft 5, Requirement R3, which
addressed communication protocols for entities that are solely receivers of Operating
Communications (DPs and GOPs). R1 in Draft 6 requires an applicable entity to jointly
develop, subject to the Reliability Coordinator’s approval, documented communication
protocols for the issuance of Operating Instructions in that Reliability Coordinator’s area,
that ,if applicable will address the following elements:
a. English language: Requirement R1 Part 1.1 – The use of the English language
when issuing or responding to an oral or written Operating Instruction, unless
another language is mandated by law or regulation.
b. Time Identification: Requirement R1 Part 1.2 – The instances, if any, which
require time identification when issuing an oral or written Operating Instruction and
the format for that time identification.
c. Line and Equipment Identifiers: Requirement R1 Part 1.3 – The nomenclature for
Transmission interface Elements and Transmission interface Facilities when issuing
oral or written Operating Instructions.
d. Alpha-numeric clarifiers: Requirement R1 Part 1.4 – The instances, if any, where
alpha-numeric clarifiers are necessary when issuing an oral Operating Instruction
and the format for those clarifiers.
Unofficial Comment Form
(Standard)
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e. Three-part Communication: Requirement R1 Part 1.5. The instances where the
issuer of an oral two party, person-to-person Operating Instruction requires the
receiver to repeat, restate, rephrase, or recapitulate the Operating Instruction and
the issuer to:
•
Confirm that the response from the recipient of the Operating Instruction
was accurate, or
•
Reissue the Operating Instruction to resolve a misunderstanding.
Eliminated in Draft 6 by OPCPSDT:
•
One-way burst messaging system to multiple parties (all call) based on
industry comments. Requirement R1 Part 1.7, Requirement R1 Part 1.8
•
One-way burst messaging system to multiple parties (all call) based on
industry comments. Requirement R3 Part 3.3
•
Uniformity of communication protocols among entities (Requirement R1 Part
1.9) Based on industry comments replaced 1.9 with change to R1 language to jointly
develop and issue communication protocols within a Reliability Control area.
3) VSL and VRF Changes from version five: The OPCPSDT modified the VRFs and VSLs
associated with R1, R2, and R3, to conform to NERC and FERC guidelines.
The SDT is proposing to retire Requirement R4 from COM-001-1 and incorporate it into
Requirement R1 of COM-003-1. Since Requirement R4 from COM-001-1 carries over essentially
unchanged there is no specific question related to it in this Comment Form.
The choice of VRFs was made on the basis of the potential impact on the Bulk Electric System of a
miscommunication during Operating Instructions. Requirements R1 is assigned a Low Violation Risk
Factor due to its level of risk on BES operations. Requirements R2 and R3 are assigned a Medium
Violation Risk Factor due to their more direct impact on BES reliability.
Time Horizons were selected to reflect the period within which the requirements applied.
Requirements R1 must be implemented in long term planning operations and therefore is assigned
a Time Horizon of Long Term Planning. R2 and R3 must be implemented in the Real Time Horizon.
The drafting team is posting the standard for industry comment for a 30-day comment period.
The Operating Personnel Communications Protocols Drafting Team would like to receive industry
comments on this draft standard. Accordingly, we request that you include your comments on this
form by July XX, 2013.
Unofficial Comment Form
(Standard)
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Comment Form
*Please use the electronic comment form to submit your final comments to NERC.
1. The OPCPSDT has proposed significant changes to the COM-003-1, draft 6. Do
you agree that COM-003-1, draft 6 addresses the August 2003 Blackout Report
Recommendation number 26, FERC Order 693 and the COM-003-1 SAR? If not,
please explain in the comment area of the last question.
Yes
No
Comments:
2. Do you agree with the VRFs and VSLs for Requirements R1, R2, and R3?
Yes
No
Comments:
Unofficial Comment Form
(Standard)
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Project 2007-02, COM-003-1 Operating
Personnel Communication Protocols
Rationale and Technical Justification
Justification for Requirements in Draft 6
Rationale and Technical Justification
I.
Introduction and Background
A.
Order No. 693
On March 16, 2007, the Federal Energy Regulatory Commission (“FERC” or
“Commission”) issued Order No. 693. Specifically, in paragraphs 512, 513 and 531-535
the Commission stated:1
512. The Commission finds that, during both normal and emergency
operations, it is essential that the transmission operator, balancing
authority and reliability coordinator have communications with
distribution providers. In response to APPA, as discussed above, any
distribution provider that is not a user, owner or operator of the BulkPower System would not be required to comply with COM-002-2, even
though the Commission is requiring the ERO to modify the Reliability
Standard to include distribution providers as applicable entities. APPA’s
concern that 2,000 public power systems would have to be added to the
compliance registry is misplaced, since, as we explain in our Applicability
discussion above, we are approving NERC’s registry process, including
the registry criteria. Therefore, we adopt our proposal to require the ERO
to modify COM-002-2 to apply to distribution providers through its
Reliability Standards development process.
513. The Commission believes that this Reliability Standard does not alter
who would operate a distribution provider’s system. It only concerns
communications, not the operation of the distribution system.
1
In Order No. 693-A at paragraph 41, the Commission also noted that “. . . as to COM-001-1 and COM-002-2, the
Commission was concerned [in Order 693] about having a reliability gap during normal and emergency operations.”
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531. We adopt our proposal to require the ERO to establish tightened
communication protocols, especially for communications during alerts and
emergencies, either as part of COM-002-2 or as a new Reliability
Standard. We note that the ERO’s response to the Staff Preliminary
Assessment supports the need to develop additional Reliability Standards
addressing consistent communications protocols among personnel
responsible for the reliability of the Bulk-Power System.
532. While we agree with EEI that EOP-001-0, Requirement R4.1 requires
communications protocols to be used during emergencies, we believe, and
the ERO agrees, that the communications protocols need to be tightened to
ensure Reliable Operation of the Bulk-Power System. We also believe an
integral component in tightening the protocols is to establish
communication uniformity as much as practical on a continent-wide basis.
This will eliminate possible ambiguities in communications during
normal, alert and emergency conditions. This is important because the
Bulk- Power System is so tightly interconnected that system impacts often
cross several operating entities’ areas. (Emphasis added)
533. Regarding APPA’s suggestion that it may be beneficial to include
communication protocols in the relevant Reliability Standard that governs
those types of emergencies, we direct that it be addressed in the Reliability
Standards development process.
534. In response to MISO’s contention that Blackout Report
Recommendation No. 26 has been fully implemented, we note that
Recommendation No. 26 addressed two matters. We believe MISO is
referring to the second part of the recommendation requiring NERC to
“[u]pgrade communication system hardware where appropriate” instead of
tightening communications protocols. While we commend the ERO for
taking appropriate action in upgrading its NERCNet, we remind the
industry to continue their efforts in addressing the first part of Blackout
Recommendation No. 26.
535. Accordingly, we direct the ERO to either modify COM-002-2 or
develop a new Reliability Standard that requires tightened
communications protocols, especially for communications during alerts
and emergencies.
540. ... In addition, pursuant to section 215(d)(5) of the FPA and § 39.5(f)
of our regulations, the Commission directs the ERO to develop a
modification to COM-002-2 through the Reliability Standards
development process that: (1) expands the applicability to include
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distribution providers as applicable entities; (2) includes a new
Requirement for the reliability coordinator to assess and approve actions
that have impacts beyond the area view of a transmission operator or
balancing authority and (3) requires tightened communications protocols,
especially for communications during alerts and emergencies.
Alternatively, with respect to this final issue, the ERO may develop a new
Reliability Standard that responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally, we direct the ERO to
include APPA’s suggestions to complete the Measures and Levels of NonCompliance in its modification of COM-002-2 through the Reliability
Standards development process. (Emphasis added)(footnotes omitted).
B. 2003 Blackout Report
The 2003 Blackout Report Recommendation No. 26 reads:
NERC should work with reliability coordinators and control area operators
to improve the effectiveness of internal and external communications
during alerts, emergencies, or other critical situations, and ensure that all
key parties, including state and local officials, receive timely and accurate
information. NERC should task the regional councils to work together to
develop communications protocols by December 31, 2004, and to assess
and report on the adequacy of emergency communications systems within
their regions against the protocols by that date.
C. COM-002-3
In response to the Commission’s determinations in Order No. 693, the NERC Board of
Trustees has approved COM-002-3 that addresses effective communications during
emergency circumstances. COM-002-3 states that:
R1. When a Reliability Coordinator, Transmission Operator, or Balancing
Authority requires actions to be executed as a Reliability Directive, the
Reliability Coordinator, Transmission Operator, or Balancing Authority shall
identify the action as a Reliability Directive to the recipient.
R2. Each Balancing Authority, Transmission Operator, Generator Operator,
and Distribution Provider that is the recipient of a Reliability Directive shall
repeat, restate, rephrase, or recapitulate the Reliability Directive.
R3. Each Reliability Coordinator, Transmission Operator, and Balancing
Authority that issues a Reliability Directive shall either:
• Confirm that the response from the recipient of the Reliability
Directive (in accordance with Requirement R2) was accurate, or
• Reissue the Reliability Directive to resolve a misunderstanding.
COM-002-3 also adds the following new definition:
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Reliability Directive: A communication initiated by a Reliability Coordinator,
Transmission Operator, or Balancing Authority where action by the recipient is
necessary to address an Emergency or Adverse Reliability Impact.
In COM-002-3, the identification of a communication as a Reliability Directive is
required to addresses communications related to an Emergency or Adverse Reliability
Impact, which are defined in the NERC Glossary of Terms Used in Reliability Standards
or are approved by the NERC Board of Trustees and pending FERC approval as follows:
Emergency: Any abnormal system condition that requires automatic or
immediate manual action to prevent or limit the failure of transmission
facilities or generation supply that could adversely affect the reliability of the
Bulk Electric System.
Adverse Reliability Impact: The impact of an event that results in Bulk
Electric System instability or Cascading.
D. NERC’s Operating Committee guideline
On September 19, 2012, the NERC Operating Committee issued a Reliability Guideline
entitled: “System Operator Verbal Communications – Current Industry Practices.” As
stated on page one, the purpose of the Reliability Guideline “. . . is to document and share
current verbal BES communications practices and procedures from across the industry
that have been found to enhance the effectiveness of system operator communications
programs.” Specifically, in the context of routine or normal operation communications,
the Guideline on pages 4-5 states that:
There are two schools of thought regarding utilization of three-part
communication for routine operating instructions. Every routine
communication opportunity has a different impact on the reliability of the
BES, and many routine communication opportunities have no impact on
reliability. While the industry has disparate viewpoints on the necessity
of the use of three-part communication for all real-time communications,
most agree that the point is to be effective when it counts for reliability —
not that every communication opportunity has a reliability impact. . . . If
an entity determines it would utilize the three-part communication
protocol for routine operating instructions, that entity should define when
its System Operators are expected to utilize the protocol, including
coordinating with entities regarding when the use of three-part
communication is expected. (Emphasis added).
The Guideline goes on to address barriers to effective communications and other related
subjects.
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II.
COM-003-1
Because COM-002-3 addresses effective communications during emergency circumstances,
COM-003-1 needs to focus on those communications during normal operations that impact
reliability. The latest draft of COM-003-1 implements a results-based approach to
strengthening normal operating communications, which focuses entities on communicating
Operating Instructions in a way that does not result in an operating condition that requires the
issuance of a Reliability Directive. Accordingly, COM-003-1 is reliability-driven, resultsbased approach that appropriately focuses on those communications during normal
operations that impact reliability. To elaborate on this approach, the definition of Operating
Instruction and the COM-003-1 requirements are set forth below followed by a discussion of
the impacts of the requirements.
A. Operating Instruction
The definition of Operating Instruction reads:
A command, other than a Reliability Directive, by a System
Operator of a Reliability Coordinator, or of a Transmission
Operator, or of a Balancing Authority, where the recipient of the
command is expected to act to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System. A discussion of general
information and of potential options or alternatives to resolve BES
operating concerns are not commands and are not considered an
Operating Instruction. An Operating Instruction is exclusive and
distinct from a Reliability Directive. There is no overlap between
an Operating Instruction and Reliability Directive.
This version of the definition of Operating Instruction clearly sets forth the types of
communications that are and are not Operating Instructions. It also clearly states that
there is no overlap between COM-003-1 with the requirements of COM-002-3 and its
definition of Reliability Directive. This emphasis on the exclusive and distinct difference
between an Operating Instruction and a Reliability Directive creates separation between
the two standards, ensuring that there is no confusion between the implementation of
COM-002-3 and COM-003-1 and eliminating any risk for double jeopardy with the two
standards. The separate definitions also convey the importance of issuing a Reliability
Directive versus an Operating Instruction.
B. Requirement R1
Requirement R1 requires the development of documented communication protocols for
the issuance of Operating Instructions in a Reliability Coordinator’s area. The
development of documented communication protocols is designed to strengthen the
issuance of Operating Instructions to guard against a miscommunication (i.e., failure to
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follow the protocols) of an Operating Instruction that results in an operating condition
that requires the issuance of a Reliability Directive (see Requirements 2 and 3).
Requirement R1 and its Parts read:
R1.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator, in each Reliability Coordinator area, shall
develop, subject to the Reliability Coordinator’s approval, documented
communication protocols for the issuance of Operating Instructions in
that Reliability Coordinator’s area.
The documented communication protocols will address, where
applicable, the following: [Violation Risk Factor: Low] [Time Horizon:
Long-term Planning]
1.1. The use of the English language when issuing or responding to an
oral or written Operating Instruction, unless another language is
mandated by law or regulation.
1.2. The instances, if any, that require time identification when issuing
an oral or written Operating Instruction and the format for that time
identification.
1.3. The nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written
Operating Instruction.
1.4. The instances, if any, where alpha-numeric clarifiers are necessary
when issuing an oral Operating Instruction and the format for those
clarifiers.
1.5. The instances where the issuer of an oral two party, person-toperson Operating Instruction requires the receiver to repeat, restate,
rephrase, or recapitulate the Operating Instruction and the issuer to:
•
Confirm that the response from the recipient of the
Operating
Instruction was accurate; or
•
Reissue the Operating Instruction to resolve a
misunderstanding.
It is appropriate for the entities with system responsibilities and a wide-area view of the
Bulk Electric System (i.e., Reliability Coordinators, Transmission Operators and
Balancing Authorities) to develop the documented communication protocols.
Development does not require that the protocols of a Reliability Coordinator,
Transmission Operator and Balancing Authority be identical, but rather requires these
entities to coordinate to develop protocols for their Reliability Coordinator area. Also,
given the reliability-driven, results-based construct set forth in Requirements R2 and R3,
there is no need, and, therefore, no requirement that the Distribution Provider or
Generator Operator develop documented protocols. The Distribution Provider and
Generator Operator are simply required to repeat, restate, rephrase, or recapitulate the
Operating Instruction when required by the issuer, following the protocol of the issuance
of the Operating Instruction.
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In addition, consistent with Order No. 693 and the Reliability Guideline, the Requirement
R1 documented communication protocols are appropriately tied to the execution of
Operating Instructions (Requirements R2 and R3), so that an Emergency or Adverse
Reliability Impact does not result due to miscommunication (i.e., need to issue a
Reliability Directive). Working in concert with Requirement R1, Requirements R2 and
R3 implement a results-based approach that promotes reliability, while eliminating any
operational and compliance environment that requires a mining of hundreds, thousands or
millions of routine/normal communications to prove compliance or make a finding of
reasonable assurance of compliance, and, instead, properly focuses on those Operating
Instructions that impact reliability.
C. Requirement R2
Requirement R2 is a reliability-driven, results-based requirement that is designed to
prevent miscommunications during normal operating conditions that would result in an
operating condition that requires the issuance of a Reliability Directive. To that end, the
requirement focuses entities’ behavior on implementing its documented communication
protocols, but focuses the compliance risk on instances where failure to use the protocols
by the issuer of an Operating Instruction results in an operating condition that requires the
issuance of a Reliability Directive. The requirement reads:
R2. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall implement its communication protocols
developed in Requirement R1 so that the failure to use the protocols by
the issuer of an Operating Instruction does not result in an operating
condition that requires the issuance of a Reliability Directive by the
original issuer of the Operating Instruction or by another Balancing
Authority, Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium][Time Horizon: Real Time
Operations]
The intent of Requirement R2 is to focus entities on use of the documented
communications protocols when a Balancing Authority, Reliability Coordinator, or
Transmission Operator issues an Operating Instruction. Rather than focus on all
miscommunications, the standard focuses compliance risk on instances where an entity
fails to follow its documented communication protocols and that failure to follow its
documented communication protocols results in an operating condition that requires the
issuance of a Reliability Directive. This captures those Operating Instructions that
impact reliability. This construct creates an operational defense-in-depth approach with
the use of Operating Instructions and Reliability Directives. COM-003-1 requires
implementation of documented communications protocols to prevent operating
conditions that would require the issuance of a Reliability Directive and even if that does
occur, a Reliability Directive would be issued to maintain the reliable operation of the
bulk electric system.
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This approach also appropriately focuses compliance on the instances in which both an
entity fails to follow its documented communication protocols and that failure to follow
its documented communication protocols results in an operating condition that requires
the issuance of a Reliability Directive, rather than all communications during normal
operating conditions. Accordingly, Requirement R2 is a reliability-driven, results-based
requirement that appropriately focuses operations and compliance on Operating
Instructions that impact reliability.
D. Requirement R3
Requirement R3 is designed to prevent miscommunications during normal operating
conditions where the failure to repeat, restate, rephrase, or recapitulate the Operating
Instruction, when required, would result in an operating condition that requires the
issuance of a Reliability Directive. The requirement reads:
R3. Each Balancing Authority, Transmission Operator, Generator
Operator and Distribution Provider shall repeat, restate, rephrase, or
recapitulate an Operating Instruction when required by the issuer of an
Operating Instruction in its communication protocols developed in
Requirement R1 so that the failure to repeat, restate, rephrase, or
recapitulate the Operating Instruction does not result in an operating
condition that requires the issuance of a Reliability Directive by the
original issuer of the Operating Instruction or by another Balancing
Authority, Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium][Time Horizon: Real Time
Operations]
Similar to Requirement R2, the intent of Requirement R3 is to focus on those instances in
which the recipient fails to follow the issuer’s three-way instructions (which are
instructions consistent with its protocols) and there is an impact to reliability, i.e., an
operating condition that requires the issuance of a Reliability Directive. Rather than
focus on all instances where three-way instructions are used, the standard focuses
compliance on instances where: (1) a Balancing Authority, Transmission Operator,
Generator Operator or Distribution Provider fails to repeat, restate, rephrase, or
recapitulate an Operating Instruction when required by the issuer; and (2) the use of this
repeat back protocol is required in the issuers communication protocols developed in
Requirement 1; and (3) the failure to use the repeat back protocol results in an operating
condition that requires the issuance of a Reliability Directive. 2
2
To assist in those instances where a Generator Operator or Distribution Provider, etc. may need an attestation or other
evidence such as log or voice recording from a Reliability Coordinator, Transmission Operator or Balancing Authority, the
Measures for Requirement 3 indicates the potential need for coordination between the entities.
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
E. VRF/VSLs
The VRF/VSLs and measures compliment the results-based approach by focusing on the
impact to reliability resulting from miscommunications and not the volume of Operating
Instructions or solely the development of communication protocols. By focusing on
communications that create operating conditions that result in the issuance of a
Reliability Directive, only those communications tied directly to the eventual issuance of
a Reliability Directive would be necessary from a compliance standpoint. As written,
there will likely be a smaller subset of Operating Instructions that are relevant to a
finding of a violation of Requirement R2 and R3, particularly given the instructional
value of the Requirement R1 communication protocols. However, a violation of
Requirements R2 and R3 are considered significant and thus the VRFs and VLSs reflect
that impact on reliability.
III.
Conclusion
COM-003-1 is scoped and designed to complement COM-002-3. COM-003-1 represents
a results-based standard that protects the reliability of the bulk electric system and that
appropriately balances compliance risk by focusing entities on the development and
implementation of documented communication protocols during normal operating
conditions that only impact reliability. The Operating Committee’s Reliability Guideline
on System Operator communications acts as a complimentary guidance document that
will be useful to entities during their joint development of documented communication
protocols under COM-003-1.
Project 2007-02, COM-003-1 Operating Personnel Communication Protocols Rationale and Technical Justification
9
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1.1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1.
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator, in each Reliability
Coordinator area, shall develop, subject to the
Reliability Coordinator’s approval, documented
communication protocols for the issuance of
Operating Instructions in that Reliability Coordinator’s
area. The documented communication protocols will
address, where applicable, the following:[Violation
Risk Factor: Low] [Time Horizon: Long-term Planning ]
1.1. The use of the English language when
issuing or responding to an oral or
written Operating Instruction, unless
another language is mandated by law
or regulation.
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
1. Mapping Document Showing Translation of COM-001-1.1, R4– Telecommunications into COM-003-1–Operating
Personnel Communications Protocol
Requirement in Approved Standard
R4.Unless agreed to otherwise, each Reliability
Coordinator, Transmission Operator, and Balancing
Authority shall use English as the language for all
communications between and among operating
personnel responsible for the real-time generation
control and operation of the interconnected Bulk
Electric System. Transmission Operators and Balancing
Authorities may use an alternate language for internal
operations
Translation to
New Standard or
Other Action
Moved into COM
003-1 R1.1
Comments
R1.
Each Balancing Authority, Reliability Coordinator,
and Transmission Operator, in each Reliability
Coordinator area, shall jointly develop, subject to the
Reliability Coordinator’s approval, documented
communication protocols for the issuance of
Operating Instructions in that Reliability Coordinator’s
area. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall develop
and implement documented communication
protocols that outline the communications
expectations of its System Operators. The
documented communication protocols will address,
where applicable, the following:[Violation Risk
Factor: Low] [Time Horizon: Long-term Planning ]
Project YYYY-##.# -
Project Name
Requirement in Approved Standard
: Operating Personnel Communication Protocols
Translation to
New Standard or
Other Action
Comments
1.1.
Mapping Document
The uUse of the English language when
issuing or responding to an oral or written
Operating Instruction or Reliability
Directive, unless another language is
mandated by law or regulation.
2
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL Justifications
2
Project YYYY-##.# - Project Name
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL Justifications
3
Project YYYY-##.# - Project Name
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL Justifications
4
Project YYYY-##.# - Project Name
VRF for COM-003-1:
There are three requirements in COM-003-1, draft 6 with the deletion of R4 (draft 5). Requirement R1 is assigned a “Low” VRF.
R1 now reads:”Each ….. in each Reliability Coordinator area, shall develop, subject to the Reliability Coordinator’s approval,
documented communication protocols for the issuance of Operating Instructions in that Reliability Coordinator’s area. The
documented communication protocols will address, where applicable, the following: “. Requirements R2 and R3 are assigned a
“Medium” VRF. The language change to R2 , which now reads:”Each ….. shall implement its communication protocols
developed in Requirement R1 so that the failure to use the protocols by the issuer of an Operating Instruction does not result in
an operating condition that requires the issuance of a Reliability Directive by the original issuer of the Operating Instruction or
by another Balancing Authority, Reliability Coordinator, or Transmission Operator. “ R2 warrants a VRF of “Medium” because it
links failed use of communication protocols to events that impact the reliability of the BES. The language change to R3, which
now reads:”Each ….. shall repeat, restate, rephrase, or recapitulate an Operating Instruction when required by the issuer of an
Operating Instruction in its communication protocols developed in Requirement R1 so that the failure to repeat, restate,
rephrase, or recapitulate the Operating Instruction does not result in an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator,
or Transmission Operator” warrants a VRF of “Medium” because it links failed use of three-part communication to events that
impact the reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
VRF and VSL Justifications
Moderate
Missing at least one
High
Missing more than one
Severe
Missing most or all of the significant
5
Project YYYY-##.# - Project Name
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
VRF and VSL Justifications
6
Project YYYY-##.# - Project Name
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low” which is
consistent with NERC guidelines
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-parts that are of equal importance and similarly address communication
FERC VRF G2 Discussion
VRF and VSL Justifications
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development of documented communication protocols by entities that issue
“Operating Instructions” that reduce the possibility of miscommunication which could eventually lead to
action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Low” which is consistent with NERC
guidelines for similar requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
develop one (1) of the five (5)
parts of Requirement R1 in
their documented
communication protocols as
VRF and VSL Justifications
Moderate
The Responsible Entity did not
develop two (2) of the five (5)
parts of Requirement R1 in
their documented
communication protocols as
High
The Responsible Entity did not
develop three of the five (5) parts
of Requirement R1 in their
documented communication
protocols as required in
Severe
The Responsible Entity did not
develop four or more of the five
(5) parts of Requirement R1 in
their documented communication
protocols as required in
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
required in Requirement R1
VRF and VSL Justifications
required in Requirement R1
Requirement R1
Requirement R1
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols were addressed at all or if the number of
required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Medium
NERC VRF Discussion
R2 is a requirement in Real Time Operations time frame that, if violated, could directly affect the electrical
state or the capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. However, violation of a medium risk requirement is unlikely to lead to bulk electric
system instability, separation, or cascading failures. The VRF for this requirement is “Medium” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for implementation of communication protocols developed in Requirement R1 so
that the failure to use the protocols by the issuer of an Operating Instruction does not result in an
operating condition that requires the issuance of a Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority, Reliability Coordinator, or Transmission Operator
in order to reduce the possibility of miscommunication which could eventually lead to action or inaction
harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement communication protocols developed in Requirement R1 so that the failure to use the
protocols by the issuer of an Operating Instruction results in an operating condition that requires the
issuance of a Reliability Directive could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL Justifications
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
N/A
Severe
The Responsible Entity failed to
use the protocols developed in
Requirement R1 which resulted in
an operating condition that
required the issuance of a
Reliability Directive by the original
issuer of the Operating Instruction
or by another Balancing Authority,
Reliability Coordinator, or
Transmission Operator.
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed a single binary , VSL, therefore it is Severe.
Guideline 2a:
The VSL assignment for R2 is binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
14
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a Real Time, time frame that, if violated, could directly affect the electrical state or
the capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of a medium risk requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures. The VRF for this requirement is “Medium” which is consistent
with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for an entity to repeat, restate, rephrase, or recapitulate an Operating Instruction
when required by the issuer of an Operating Instruction in its communication protocols developed in
Requirement R1 so that the failure to repeat, restate, rephrase, or recapitulate the Operating Instruction
does not result in an operating condition that requires the issuance of a Reliability Directive by the original
issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator to reduce the possibility of miscommunication which could eventually lead to
action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Medium” which is consistent with NERC
guidelines
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL Justifications
16
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
N/A
Severe
The Responsible Entity failed
repeat, restate, rephrase, or
recapitulate an Operating
Instruction when required by the
issuer of an Operating Instruction
in its communication protocols
developed in Requirement R1,
which resulted in an operating
condition that required the
issuance of a Reliability Directive
by the original issuer of the
Operating Instruction or another
Balancing Authority, Reliability
Coordinator, or Transmission
Operator.
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed one VSLbased on the failure to repeat, restate, rephrase,
or recapitulate an Operating Instruction when required by the issuer of an Operating Instruction in its
communication protocols developed in Requirement R1, which resulted in an operating condition that
required the issuance of a Reliability Directive. Therefore the VSL is Severe.
Guideline 2a:
The VSL assignment for R3 is binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
19
Project 2007-2 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM 003-1 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL Justifications
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In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL Justifications
3
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Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL Justifications
4
Project YYYY-##.# - Project Name
VRF for COM-003-1:
There are four three requirements in COM-003-1, draft 5 6 with the addition deletion of R3 and R4 (draft 5). Requirements R1
and R3 is are assigned a “Low” VRF. R1 and R3 now reads:”Each ….. in each Reliability Coordinator area, shall develop, subject
to the Reliability Coordinator’s approval, documented communication protocols for the issuance of Operating Instructions in that
Reliability Coordinator’s area. shall develop and implement documented communication protocols that outline the
communications expectations of its operators. The documented communication protocols will address, where applicable, the
following: “. Requirements R2 and R4 R3 are assigned a “Medium” VRF. and tThe language change to R2 and R4, which now
reads:”Each ….. shall implement its communication protocols developed in Requirement R1 so that the failure to use the
protocols by the issuer of an Operating Instruction does not result in an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator,
or Transmission Operator. shall perform a quarterly assessment of its System Operators’ communication practices and
implement corrective actions necessary to meet the expectations in its documented communication protocols developed for
Requirement RX “, R2 warrants raising thea VRF to of “Medium” because it features evaluation and correction of operatinglinks
failed use of communication protocols to events that impact the reliability of the BES. The language change to R3, which now
reads:”Each ….. shall repeat, restate, rephrase, or recapitulate an Operating Instruction when required by the issuer of an
Operating Instruction in its communication protocols developed in Requirement R1 so that the failure to repeat, restate,
rephrase, or recapitulate the Operating Instruction does not result in an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator,
or Transmission Operator” warrants raising thea VRF toof “Medium” because it links failed use of three-part communication to
events that impact the reliability of the BES.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
VRF and VSL Justifications
5
Project YYYY-##.# - Project Name
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
VRF and VSL Justifications
6
Project YYYY-##.# - Project Name
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM 003-1, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a long term planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low” which is
consistent with NERC guidelines
VRF and VSL Justifications
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements parts that are of equal importance and similarly address
communication protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development and implementation of documented communication protocols
by entities that will both issue and receive “Operating Instructions” that reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Low” which is consistent with NERC
guidelines for similar requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R1 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity did not
VRF and VSL Justifications
Moderate
The Responsible Entity did not
High
The Responsible Entity did not
Severe
The Responsible Entity did not
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
develop one (1) of the five (5)
parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
develop two (2) of the five (5)
parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
The Responsible Entity did not
address one (1) of the nine(9)
parts of Requirement R1in
their documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
implement one (1) of the nine
(9) parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
The Responsible Entity did not
address three (3) of the nine (9)
parts of Requirement R1 in their
documented communication
protocols as required in
Requirement R1
The Responsible Entity did not
address two (2) of the nine (9)
parts of Requirement R1 in
their documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
implement two (2) of the nine
(9) parts of Requirement R1 in
VRF and VSL Justifications
develop three of the five (5) parts
of Requirement R1 in their
documented communication
protocols as required in
Requirement R1
OR
The Responsible Entity did not
implement three (3) of the nine
(9) parts of Requirement R1 in
their documented communication
protocols as required in
Requirement R1
develop four or more of the five
(5) parts of Requirement R1 in
their documented communication
protocols as required in
Requirement R1
The Responsible Entity did not
address four (4) or more of the
nine (9) parts of Requirement R1
in their documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
have any documented
communication protocols as
required in Requirement R1
OR
The Responsible Entity did not
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
their documented
communication protocols as
required in Requirement R1
VRF and VSL Justifications
implement any documented
communication protocols as
required in Requirement R1
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols. If no communication protocols were addressed at all or if the number of
required protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
Proposed VRF
Medium
NERC VRF Discussion
R2 is a requirement in an Operations planning and Operations AssessmentReal Time, Operations time
frame that, if violated, could directly affect the electrical state or the capability of the bulk electric system,
or the ability to effectively monitor and control the bulk electric system. However, violation of a medium
risk requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures. if
violated, would not, under the emergency, abnormal, or restorative conditions anticipated by the
preparations, be expected to adversely affect the electrical state or capability of the bulk electric system
The VRF for this requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for implementation of communication protocols developed in Requirement R1 so
that the failure to use the protocols by the issuer of an Operating Instruction does not result in an
operating condition that requires the issuance of a Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority, Reliability Coordinator, or Transmission
Operatorthe assessment and correction of System Operators‘performance with documented
communication protocols by entities that will both issue and receive “Operating Instructions” in order to
reduce the possibility of miscommunication which could eventually lead to action or inaction harmful to
the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to implement communication protocols developed in Requirement R1 so that the failure to use the
protocols by the issuer of an Operating Instruction results in an operating condition that requires the
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL Justifications
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VRF G5 Discussion
issuance of a Reliability Directiveto assess and correct System Operators’ performance with proper
utilization of communication protocols could directly affect the electrical state or the capability of the bulk
electric system, or the ability to effectively monitor and control the bulk electric system. However,
violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R2 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/AThe Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented 50
% or more but not all corrective
action identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
VRF and VSL Justifications
Moderate
N/AThe Responsible Entity
performed periodic
assessments of its System
Operators’ communication
practices and implemented less
than 50 % of the corrective
actions identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
High
N/AThe Responsible Entity
performed periodic assessments of
its System Operators’
communication practices but did
not implement any corrective
actions identified in Requirement
R2 necessary to meet the
expectations in its documented
communication protocols
developed for Requirement R1.
Severe
The Responsible Entity failed to
use the protocols developed in
Requirement R1 which resulted in
an operating condition that
required the issuance of a
Reliability Directive by the original
issuer of the Operating Instruction
or by another Balancing Authority,
Reliability Coordinator, or
Transmission Operator.The
Responsible Entity did not perform
periodic assessments of its System
Operators’ communication
14
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VRF and VSL Justifications – COM 003-1, R2
practices identified in
Requirement R2 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R1.
VRF and VSL Justifications
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on quarterly assessments of an entity’s
System Operators’ communication practices and the administration of corrective actions. If no quarterly
assessments of an entity’s System Operators’ communication practices are conducted a single binary ,
then the VSL, therefore it is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
16
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VRF and VSL Justifications – COM 003-1, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a long term planningReal Time, time frame that, if violated, could directly affect the
electrical state or the capability of the bulk electric system, or the ability to effectively monitor and control
the bulk electric system. However, violation of a medium risk requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failureswould not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state
or capability of the bulk electric system. The VRF for this requirement is “LowMedium” which is consistent
with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements that are of equal importance and similarly address
communication protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for an entity to repeat, restate, rephrase, or recapitulate an Operating Instruction
when required by the issuer of an Operating Instruction in its communication protocols developed in
Requirement R1 so that the failure to repeat, restate, rephrase, or recapitulate the Operating Instruction
does not result in an operating condition that requires the issuance of a Reliability Directive by the original
issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operatorthe development and implementation of documented communication protocols by
entities that will only receive “Operating Instructions” that to reduce the possibility of miscommunication
which could eventually lead to action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
VRF and VSL Justifications
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “LowMedium” which is consistent with
NERC guidelines for requirements that are administrative.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R3 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
High
N/AThe Responsible Entity did
not address one (1) of the
three(3) parts of Requirement
R3in their documented
communication protocols as
required in Requirement R3
N/AThe Responsible Entity did
not address two (2) of the three(3)
parts of Requirement R3 in their
documented communication
protocols as required in
Requirement R3
OR
OR
The Responsible Entity did not
implement one (1) of the
three(3) parts of Requirement
The Responsible Entity did not
implement two (2) of the three(3)
parts of Requirement R3 in their
Severe
The Responsible Entity failed
repeat, restate, rephrase, or
recapitulate an Operating
Instruction when required by the
issuer of an Operating Instruction
in its communication protocols
developed in Requirement R1,
which resulted in an operating
condition that required the
issuance of a Reliability Directive
by the original issuer of the
Operating Instruction or another
19
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VRF and VSL Justifications – COM 003-1, R3
R3
in their documented
communication protocols as
required in Requirement R3
documented communication
protocols as required in
Requirement R3
Balancing Authority, Reliability
Coordinator, or Transmission
Operator.The Responsible Entity
did not address three (3) of the
three(3) parts of Requirement R3
in their documented
communication protocols as
required in Requirement R3
OR
The Responsible Entity did not
develop any documented
communication protocols as
required in Requirement R3
OR
The Responsible Entity did not
implement any documented
communication protocols as
required in Requirement R3
VRF and VSL Justifications
20
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four one VSLs based on the failure to repeat, restate,
rephrase, or recapitulate an Operating Instruction when required by the issuer of an Operating Instruction
in its communication protocols developed in Requirement R1, which resulted in an operating condition
that required the issuance of a Reliability Directive. Therefore misapplication or absence of common
communication protocols. If no communication protocols are used at all or if the number of required
protocols falls below the listed thresholds, then the VSL is Severe.
Guideline 2a:
The VSL assignment for R1 R3 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
21
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VRF and VSL Justifications – COM 003-1, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
22
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement in an Operations planning and Operations Assessment time frame that, if violated,
would not, under the emergency, abnormal, or restorative conditions anticipated by the preparations, be
expected to adversely affect the electrical state or capability of the bulk electric system The VRF for this
requirement is “Medium” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “Medium”
which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the assessment and correction of operators’ performance with documented
communication protocols that reduce the possibility of miscommunication which could eventually lead to
action or inaction harmful to the reliability of BES.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to assess and correct operators’ performance with proper utilization of communication protocols
could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. However, violation of the requirement is unlikely
to lead to bulk electric system instability, separation, or cascading failures. The VRF for this requirement is
“Medium” which is consistent with NERC guidelines
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-003-1, Requirement R4 contains only one objective which is to specify clear, formal and universally
applied communication protocols that reduce the possibility of miscommunication which could lead to
action or inaction harmful to the reliability of BES. Since the requirement has only one objective, only one
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
23
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
VRF was assigned.
Proposed VSL
Lower
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented 50 % or more but
not all corrective action
identified in Requirement R4
necessary to meet the
expectations in its documented
communication protocols
developed for Requirement R3.
VRF and VSL Justifications
Moderate
The Responsible Entity
performed periodic
assessments of its operators’
communication practices and
implemented less than 50 % of
the corrective actions identified
in Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3.
High
The Responsible Entity performed
periodic assessments of its
operators’ communication
practices but did not implement
any corrective actions identified in
Requirement R4 necessary to
meet the expectations in its
documented communication
protocols developed for
Requirement R3
Severe
The Responsible Entity did not
perform assessments of its
operators’ communication
practices and did not meet the
expectations in its documented
communication protocols
developed for Requirement R3.
24
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of quarterly
assessments or correction of an entity’s System Operators’ communication practices. If no quarterly
assessments of an entity’s System Operators’ communication practices are conducted, then the VSL is
Severe.
Guideline 2a:
The VSL assignment for R4 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
25
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 003-1, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications
26
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-003-1
Successive Ballot and Non-binding Poll now open through July 19, 2013
Now Available
A successive ballot of COM-003-1- Operating Personnel Communications Protocols and non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) is now open
through 8 p.m. Eastern on Friday, July 19, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
Next Steps
The ballot results for COM-003-1 will be announced and posted on the project page. The drafting
team will consider all comments received during the formal comment period and, if needed, make
revisions to the standard. If the comments do not show the need for significant revisions, the
standard will proceed to a final ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-003-1
Formal Comment Period:
June 20, 2013 – July 19, 2013
Upcoming
Successive Ballot and Non-binding Poll:
July 10, 2013 - July 19, 2013
Now Available
A 30-day formal comment period for COM-003-1- Operating Personnel Communications Protocols
is open through 8 p.m. Eastern on Friday, July 19, 2013.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps
A successive ballot of COM-003-1 and non-binding poll of the associated Violation Risk Factors (VRFs)
and Violation Severity Levels (VSLs) will be conducted from July 10, 2013 through July 19, 2013.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-003-1
Successive Ballot and Non-binding Poll Results
Now Available
A successive ballot of COM-003-1- Operating Personnel Communications Protocols and non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) concluded at 8
p.m. Eastern on Friday, July 19, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results for
the successive ballot.
Approval
Non-binding Poll Results
Quorum: 76.32%
Quorum: 76.20%
Approval: 58.36%
Supportive Opinions: 55.37%
Background information for this project can be found on the project page.
Next Steps
Options for the next step in the standards development process for this project are currently being
discussed and considered.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007 -02 COM-003-1 Successive Ballot
Password
Ballot Period: 7/10/2013 - 7/19/2013
Ballot Type: Successive
Log in
Total # Votes: 332
Register
Total Ballot Pool: 435
Quorum: 76.32 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
58.36 %
Vote:
Ballot Results: The drafting team will review comments received.
Home Page
Summary of Ballot Results
Affirmative
Segment
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals
Ballot Segment
Pool
Weight
110
11
103
39
93
53
0
12
5
9
435
#
Votes
1
1
1
1
1
1
0
0.5
0.1
0.9
7.5
#
Votes
Fraction
44
4
43
17
40
23
0
3
1
6
181
Negative
Fraction
0.543
0.364
0.558
0.68
0.556
0.676
0
0.3
0.1
0.6
4.377
Abstain
No
# Votes Vote
37
7
34
8
32
11
0
2
0
3
134
0.457
0.636
0.442
0.32
0.444
0.324
0
0.2
0
0.3
3.123
7
0
3
0
2
4
0
0
1
0
17
22
0
23
14
19
15
0
7
3
0
103
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
1
Organization
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Member
Kirit Shah
Paul B Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Ballot
Affirmative
Negative
Negative
Negative
Negative
Abstain
Affirmative
Comments
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Ohio Valley Electric Corp.
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan
Michael B Bax
Marco A Sustaita
Affirmative
Abstain
Affirmative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Michael Moltane
Affirmative
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Robert Mattey
Affirmative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
1
3
3
3
3
3
3
3
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Dave Markham
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Negative
Affirmative
Affirmative
Affirmative
Abstain
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
NW Electric Power Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
David McDowell
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Rick Paschall
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Turlock Irrigation District
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Steve Eldrige
Bo Jones
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
Keith Morisette
Steven C Hill
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
Affirmative
Negative
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North America,
LLC
Edison Mission Marketing & Trading Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
ICF International
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Mike D Kukla
Francis J. Halpin
Shari Heino
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Brent B Hebert
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
David Gordon
Affirmative
Steven Grego
Christopher Schneider
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Steven Grega
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Michiko Sell
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Affirmative
Negative
Affirmative
Affirmative
Negative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
TransAlta Corporation
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Rebbekka McFadden
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
10
10
10
10
10
10
10
10
10
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
APX
INTELLIBIND
JDRJC Associates
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Lujuanna Medina
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
Affirmative
Negative
David F Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Michael Johnson
Kevin Conway
Jim Cyrulewski
Frederick R Plett
Margaret Ryan
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Negative
Affirmative
Affirmative
Affirmative
Negative
Donald Nelson
Affirmative
Diane J. Barney
Abstain
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=fb12ec7a-4582-4d24-b22a-f27afa5f1bd3[7/22/2013 10:46:19 AM]
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-binding Poll Results
Project 2007-02 COM-003-1
Non-binding Poll Results
Non-binding Poll Name: Project 2007-02 COM-003-1 Non-binding Poll March 2013_sc_1
Poll Period: 7/10/2013 - 7/19/2013
Total # Opinions: 301
Total Ballot Pool: 395
76.20% of those who registered to participate provided an opinion or an
Summary Results: abstention; 55.37% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results
Segment
1
1
1
1
1
1
1
Organization
1
1
1
Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric,
LLC
Central Electric Power Cooperative
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City Utilities of Springfield, Missouri
City Water, Light & Power of
Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
1
1
1
1
1
1
Member
Kirit Shah
Paul B Johnson
Robert Smith
John Bussman
Glen Sutton
James Armke
Scott J Kinney
Opinions
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Kevin Smith
Abstain
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Abstain
Affirmative
Tony Kroskey
John C Fontenot
Affirmative
John Brockhan
Negative
Michael B Bax
Marco A Sustaita
Negative
Negative
Chang G Choi
Affirmative
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Affirmative
Negative
Affirmative
Negative
Comments
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative
Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company
Holdings Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New York Power Authority
New York State Electric & Gas Corp.
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
NStar Gas and Electric
Non-binding Poll – Project 2007-02
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Affirmative
Negative
Negative
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch
Affirmative
Abstain
Affirmative
Negative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Tino Zaragoza
Affirmative
Affirmative
Affirmative
Michael Moltane
Abstain
Ted Hobson
Walter Kenyon
Michael Gammon
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
Affirmative
Negative
Affirmative
Affirmative
John Burnett
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Terry Harbour
Mark Ramsey
Michael Jones
Cole C Brodine
Bruce Metruck
Raymond P Kinney
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
John Robertson
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
1
Pacific Gas and Electric Company
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New
Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
2
California ISO
Electric Reliability Council of Texas,
Inc.
Independent Electricity System
Operator
ISO New England, Inc.
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
Non-binding Poll – Project 2007-02
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore
Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Abstain
Affirmative
Abstain
Negative
Negative
Laurie Williams
Affirmative
Kenneth D. Brown
Abstain
Negative
Negative
Abstain
Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Noman Lee Williams
Beth Young
Larry G Akens
Steven Powell
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Cheryl Moseley
Affirmative
Barbara Constantinescu
Abstain
Negative
Negative
Kathleen Goodman
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System
Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Duke Energy Carolina
Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations
Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Non-binding Poll – Project 2007-02
Marie Knox
Alden Briggs
Gregory Campoli
Negative
Abstain
Abstain
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Charles Morgan
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Jose Escamilla
Kent Kujala
Henry Ernst-Jr
Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Abstain
Abstain
Affirmative
Scott McGough
Affirmative
Brian Glover
Paul C Caldwell
David Kiguel
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid
Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Orange and Rockland Utilities, Inc.
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Non-binding Poll – Project 2007-02
Mace D Hunter
Jason Fortik
Negative
Daniel D Kurowski
Affirmative
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Negative
Negative
Affirmative
Affirmative
Affirmative
Michael Schiavone
Affirmative
Skyler Wiegmann
Negative
William SeDoris
David McDowell
David Burke
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Sam Waters
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Abstain
Abstain
Affirmative
Abstain
Abstain
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Negative
Abstain
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations
Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of
Snohomish County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba
Lucky peak power plant project
Non-binding Poll – Project 2007-02
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
Abstain
Abstain
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Affirmative
Negative
Guy Andrews
Affirmative
Negative
Negative
Affirmative
Abstain
Bob C. Thomas
Diana U Torres
Jack Alvey
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Abstain
Affirmative
Negative
Affirmative
Henry E. LuBean
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Abstain
Negative
Negative
Abstain
Abstain
Steven McElhaney
Keith Morisette
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Matthew Pacobit
Edward F. Groce
Clement Ma
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Mike D Kukla
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Bonneville Power Administration
Brazos Electric Power Cooperative,
Inc.
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of
Springfield
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
E.ON Climate & Renewables North
America, LLC
Edison Mission Marketing & Trading
Inc.
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Liberty Electric Power LLC
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Non-binding Poll – Project 2007-02
Francis J. Halpin
Shari Heino
Affirmative
Negative
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Affirmative
Affirmative
Negative
Steve Rose
Affirmative
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Dana Showalter
Brenda J Frazer
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
Daniel Duff
Dennis Florom
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Kenneth Silver
Affirmative
Mike Laney
S N Fernando
Affirmative
David Gordon
Abstain
Steven Grego
Christopher Schneider
Affirmative
Affirmative
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
North Carolina Electric Membership
Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Non-binding Poll – Project 2007-02
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Negative
Abstain
Affirmative
Negative
Jeffrey S Brame
Affirmative
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Wayne Lewis
Tim Kucey
Affirmative
Affirmative
Affirmative
Affirmative
Steven Grega
Abstain
Negative
Affirmative
Negative
Abstain
Abstain
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Melissa Kurtz
Martin Bauer
Linda Horn
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Negative
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
APX
Non-binding Poll – Project 2007-02
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Negative
Affirmative
Affirmative
Abstain
Affirmative
Brad Packer
Affirmative
Brad Jones
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
John T Sturgeon
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Abstain
Affirmative
Affirmative
John J. Ciza
Affirmative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
Edward C Stein
James A Maenner
Roger C Zaklukiewicz
Michael Johnson
Affirmative
Negative
Negative
Negative
Affirmative
Abstain
Abstain
Negative
Abstain
Abstain
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Negative
9
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10
10
JDRJC Associates
Massachusetts Attorney General
Power Energy Group LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating
Council
Non-binding Poll – Project 2007-02
Jim Cyrulewski
Frederick R Plett
Peggy Abbadini
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann
William M Chamberlain
Affirmative
Negative
Donald Nelson
Affirmative
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
Donald G Jones
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Steven L. Rueckert
Abstain
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (80 Responses)
Name (50 Responses)
Organization (50 Responses)
Group Name (30 Responses)
Lead Contact (30 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING
ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (13 Responses)
Comments (80 Responses)
Question 1 (63 Responses)
Question 1 Comments (67 Responses)
Question 2 (44 Responses)
Question 2 Comments (67 Responses)
Individual
Tammy Porter
Oncor Electric Delivery
No
Draft 6 of COM-003-1 appears to go beyond the recommendations and FERC 693 directives
which were the basis for the SAR. The main objective to develop an operating protocol in
alignment with other communications standards to improve reliability. Oncor’s concerns with
Draft 6 are: (1) R1 - subject to the Reliability Coordinator’s approval: adding this to R1
potentially adds an administrative burden to an Entity/Industry without clear reliability
benefits. Operating protocol should support an Entity’s operations and functions which are not
a “one size fits all”. By requiring a RC’s approval, the requirement empowers the RC to
interpret the requirement (as well as defining “Operating Instructions”) which may not be
consistent with an Entity as well as the Regional Entitiy who will be enforcing the requirement.
(2) R2/R3 - there is the potential for multiple levels of interpretation of these requirements;
these requirement potentially creates a situation in which Operators will need to be able to
assess the transition from normal to emergency operations and could quite impact efficiency
and productivity of operations which is the opposite of the objective. In addition based on M2
& M3, Oncor has concerns with the administrative burden versus the reliability benefits gained
in proving a negative condition.
No
R2 – it is unclear how a “failure” of using an operating protocol results in a reliability directive
therefore the VSL indicates a zero tolerance level of performance which does not align to
reliability based performance. R3 – not all failures of using three-part communication will
automatically led to a Reliability Directive so the VSL should be designed to support more than
a failure to use the protocols by the issuer of an Operating Instruction does not result
Individual
Scott McGough
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Georgia System Operations
Yes
No
No, regarding R2 and R3, GSOC recommends to revise the wording as follows. In particular, we
believe it adventageous to use NERC's definition of Emergency (BES Emergency) to provide
entities escalting levels of severity as opposed to the single VSL - severe that appears in the
current Draft 6. R2 - Each Balancing Authority, Reliability Coordinator, and Transmission
Operator (R3 - Each Balancing Authority, Transmission Operator, Generator Operator and
Distribution Provider) shall implement its communication protocols developed in Requirement
R1 so that the failure to use the protocols by the issuer of an Operating Instruction does not
result in any of the following: • Any abnormal system condition that requires automatic or
immediate manual action to prevent the failure of transmission facilities or generation supply
that could adversely affect the reliability of the Bulk Electric System. • The failure of
transmission facilities or generation supply that could adversely affect the reliability of the Bulk
Electric System and automatic or immediate manual action to limit the failure was required. •
An Adverse Reliability Impact
Group
Northeast Power Coordinating Council
Guy Zito
No
The introduction of the condition in R2 “so that the failure to use the protocols by the issuer of
an Operating Instruction does not result in an operating condition that requires the issuance of
a Reliability Directive by the original issuer of the Operating Instruction or by another Balancing
Authority, Reliability Coordinator, or Transmission Operator.” creates a number of issues with
the standard. a. The issuance of a Reliability Directive may be caused by a number of reasons,
for example, the operating instruction (repeated or otherwise) may not be sufficient to address
a potential condition that has an Adverse Reliability Impact; b. The operating instruction that is
communicated, with or without adhering to the protocols developed in R1, is in fact moving
other system conditions from a reliable state to one that has a potential of having Adverse
Reliability Impact, for which a Reliability Directive needs to be issued after implementing the
communicated operating instruction. c. The operating personnel may second guess whether or
not a Reliability Directive will be issued if the established communication protocols are not
implemented (such as by requiring 3-part communication) before it takes the required action.
This puts the need to comply with a requirement into a condition assessment mode, which
defeats the purpose of having a reliability standard to manage risk and meet performance
expectation whose reliability outcome are predetermined, not on the fly. d. The added
condition is a compliance assessment element with which to gauge violation severity or
sanction; itself not a requirement. By introducing this to the requirement, it convolutes the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
requirement, adds nothing to meeting the reliability objectives, and may in fact jeopardize
reliability. And what if a Reliability Directive was not issued despite the failure of Responsible
Entity to implement its communication protocol? Is the Responsible Entity deemed compliant
with the requirement? If so, do Requirements R2 and R3 drive the right behaviors? If not, then
what’s the value and influence of the added condition in the assessment outcome?
Requirement R1 clearly requires the responsible entity to develop documented communication
protocols for the issuance of Operating Instructions. By Part 1.5, the instances where the issuer
of an oral two party, person-to-person Operating Instruction requiring the receiver to repeat,
restate, rephrase, or recapitulate the Operating Instruction and subsequent actions by the
issuer are already clearly stipulated in the documented communication protocols. Responsible
entities simply need to implement the protocols as documented, regardless of whether failure
to do so would result in having to issue a Reliability Directive, or any other possible outcomes,
for that matter. Similar comments apply to Requirement R3 when the responsible entities are
required to close out the last part of the 3-part communication. The suggested rephrasing of
the Purpose statement “To strengthen communications…” could be misleading.
Communications could be strengthened with better equipment as well, but the intent of COM003 is to deal only with communications protocols. Suggest changing the language to that
which is found in the technical guidance document, “Enhance the effectiveness of
communications…”
No
We agree with the VRFs, but not the VSLs because of the concerns with Requirements R2 and
R3. We do not agree with the Long-term Planning Time Horizon for R1. Developing and
documenting communication protocols for use during real-time operations is an operational
planning process (or mid-term planning, at most), not a long-term planning process. We
suggest to change the Time Horizon to Operations Planning. Regarding the Implementation
Plan, it conflicts with Ontario regulatory practice with regards to the effective date of the
standard. It is suggested that this conflict be removed by appending to the effective date
wording, after “applicable regulatory approval” in the Effective Dates Section of the
Implementation Plan: “, or, in those jurisdictions as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.”
Individual
Bill Fowler
City of Tallahassee
No
TAL has voted NO because the standard is still not “clear and unambiguous”. TAL is concerned
at the degree to which the proposed standard complicates compliance for Operating
Instructions without benefit to reliability. The FERC Directive was to tighten communications
during Emergencies and Alerts. Operating Instructions deserve separate consideration under
the standards. Requiring an entity’s procedure to be subject to the Reliability Coordinator’s
approval creates an undue burden on the RC with no measurable improvement in reliability.
While this addressed a commenter’s concerns over uniformity within RC control areas, it would
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
be simpler and more efficient to have the RC create a procedure and provide it to all the
entities in the footprint. Measure 3 should be changed to “when required by the issuer” in
order to provide clarity and consistency with R3.
Individual
Nazra Gladu
Manitoba Hydro
Yes
Although Manitoba Hydro is in general support of the proposed draft, we suggest the
following: (1) For clarity, consider rewriting the second paragraph of the definition of Operating
Instruction as follows, An Operating Instruction is not: (1) A discussion of general information
and of potential options or alternatives to resolve Bulk Electric System operating concerns (2)
Exclusive and distinct from a Reliability Directive. There is no overlap between an Operating
Instruction and Reliability Directive. (2) R1 and M1 - for consistency, add an “’s” to the second
instance of “Reliability Coordinator” as follows: “Each Balancing Authority, Reliability
Coordinator, and Transmission Operator, in each Reliability Coordinator’s area, shall…” (3) R1 –
the requirement instructs each BA, RC and TO develop separate communication protocols. Are
these duplicative efforts practical? (4) R1, 1.4 – alpha-numeric clarifiers are limited to oral
Operating Instructions only. For consistency with R1.1, 1.2 and 1.3, consider adding
applicabillity to written Operating Instructions as well. (5) R1, 1.5 – is limited to oral Operating
Instructions while R3 (which deals with the same situation) does not specify whether it is oral
or written or both. (6) M2 – the measure does not seem to match the requirement. The
requirement R2 states that the responsible entity implement its communication protocols so
that there is no failure to use the protocols which results in a certain operating condition. The
measure however requires that the responsible entity provide evidence that they did not
create the certain operating condition. Manitoba Hydro suggests that the measure should
more accurately require that the responsible entity provide evidence that it implemented its
communication protocol so that…
Yes
Group
Pepco Holdings Inc & Affiliates
David Thorne
Agree
Group
NERC Compliance Group
Bill Thompson
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Yes
As far as the August 2003 Blackout Report Recommendation, the COM-003-1 revisions address
this concern. However, the criteria for communication protocols that need to be used should
be established. The criteria needs to be applied to both COM-002 and COM-003. There is too
much room for interpretation when it comes to measuring compliance.
Yes
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
Yes
Yes
Hydro Québec TransÉnergie proposes to change the wording of R2 to reflect the language used
in M2. The current text has too many negative connotations and is difficult to understand. The
requirement should be written : Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall implement its communication protocols developed in
Requirement R1 so that the failure to use the protocols by the issuer of an Operating
Instruction does not result in an operating condition that requires the issuance of a Reliability
Directive by the original issuer of the Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator.
Group
PacifiCorp
Ryan Millard
Yes
No
PacifiCorp does not agree with the VRFs and VSLs associated with R2 because it is not clear
how R2 is measured. M2 would require an entity to provide evidence that it did not issue an
Operating Instruction that resulted in an operating condition that required the issuance of a
Reliability Directive by the issuer or another Balancing Authority, Reliability Coordinator, or
Transmission Operator due to the failure to use documented communications protocols
developed for Requirement R1. In essence, an entity is required to prove that it did not do
something that resulted in a condition which caused another entity to be issued a directive
(that it may or may not be privy to, depending upon whether or not it was the original issuer of
said directive). A requirement that is measured by the absence of evidence creates a
challenging auditing environment for the industry. PacifiCorp strongly recommends that the
drafting team reconsider the measures required for proving compliance with R2.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Joe O'Brien
NIPSCO
Agree
Julie Dyke , NIPSCO comments submitted Also, We would like to see COM-002 & 003 combined
into a single standard. In R1 1.5 it appears that three way communication need only to be
addressed in the communication protocol and not necessarily required. An operator may be
reluctant to issue an RD which would possibly expose entities to R2 & R3 non-compliance.
Individual
Thomas Foltz
American Electric Power
No
AEP cannot vote in the affirmative for COM-003-1 as long as COM-002-2 R2 would be in effect
at the same time. The standard establishes a higher bar for more routine communications than
would be required for emergency situations. This would only confuse operators in determining
which rules are to be followed under which specific circumstances. AEP still contends that it is
unnessary to obtain Reliability Coordinator’s approval on the resulting documented
communication protocols for the issuance of Operating Instructions in that Reliability
Coordinator’s area. Why would it be necessary to develop and document internal procedures
regarding communication protocols when the proposed standard itself already provides
specific instruction on the required communication? Is R 1.3 in any way redundant with TOP002-2 R18? AEP proposes the elimination of COM-002-2 R2 and changing COM-003-1 as
proposed below so that it covers all commands rather than a subset of commands. Operating
Instruction —A command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where the recipient of the command is
expected to act to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. A discussion of general information
and of potential options or alternatives to resolve Bulk Electric System operating concerns is
not a command and is not considered an Operating Instruction. R1. Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall adhere to the following
communication protocols for the issuance of Operating Instructions in that entity’s area. 1.1.
The use of the English language when issuing or responding to an oral or written Operating
Instruction, unless another language is mandated by law or regulation. 1.2. The instances, if
any, that require time identification when issuing an oral or written Operating Instruction,
specify the time zone unless the RC has previously established an operational timezone. 1.3.
The nomenclature for Transmission interface Elements and Transmission interface Facilities
when issuing an oral or written Operating Instruction. 1.4. The instances, when referencing
letters, utilize the phonetic alphabet when issuing an oral Operating Instruction (Reference
prior draft(s)) 1.5. In instances where the issuer of an oral two party, person-to-person
Operating Instruction requires the receiver to repeat, restate, rephrase, or recapitulate the
Operating Instruction and the issuer to: * Confirm that the response from the recipient of the
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Operating Instruction was accurate; or * Reissue the Operating Instruction to resolve a
misunderstanding. R2. Each Balancing Authority, Transmission Operator, Generator Operator
and Distribution Provider shall repeat, restate, rephrase, or recapitulate an Operating
Instruction when required by the issuer of an Operating Instruction
Individual
Angela P Gaines
Portland General Electric Company
No
Portland General Electric Company (PGE) thanks you for the opportunity to provide comments.
PGE is supportive of the intent of COM-003-1 and appreciates the work that the drafting team
has put into the development of the proposed standard. However, the language in R2 and R3 is
convoluted and confusing. The following is a suggestion for both R2 and R3: R2. Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall implement its
communication protocols developed in Requirement R1. Delete: so that the failure to use the
protocols by the issuer of an Operating Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive by the original issuer of the Operating
Instruction or by another Balancing Authority, Reliability Coordinator, or Transmission
Operator. [Violation Risk Factor: Medium][Time Horizon: Real Time Operations] R3. Each
Balancing Authority, Transmission Operator, Generator Operator and Distribution Provider
shall repeat, restate, rephrase, or recapitulate an Operating Instruction when required by the
issuer of an Operating Instruction in its communication protocols developed in Requirement
R1. Delete: so that the failure to repeat, restate, rephrase, or recapitulate the Operating
Instruction does not result in an operating condition that requires the issuance of a Reliability
Directive by the original issuer of the Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator. [Violation Risk Factor: Medium][Time
Horizon: Real Time Operations] Then add the following to each Measure, (and RSAW)
respectively: R2.1. Did the issuer of the Operating Instruction fail to use its approved Operating
Instruction protocols it developed in R1? (yes/no) R2.2. Did the failure to use the approved
Operating Instructions produce an operating condition requiring the issuance of an Reliability
Directive? R3.1. Did the BA, TOP, GOP and DP fail to repeat, restate, rephrase, or recapitulate
an Operating Instruction in its communications protocols developed in R1? R3.2 Did the failure
to repeat, restate, rephrase, or recapitulate an Operating Instruction produce a condition
requiring the issuance of an Reliability Directive? Also in R3, the phrase, “…in its
communications protocols” do you mean in the issuer’s protocol or the receiver’s protocol?
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
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Yes
Negative ballot cast on the Standard: For communication purposes, R1 should not include
Reliability Coordinator (RC) approval. If a regional requirement (RC approval) is deemed
necessary, then a regional standard should be developed that includes the procedure(s) and
requirements to obtain RC approval of communication protocols.
Yes
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
Add the word “verbal” before the word “Operating Instructions” so that Requirement R1 reads:
“R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator, in each
Reliability Coordinator area, shall develop, subject to the Reliability Coordinator’s approval,
documented communication protocols for the issuance of verbal Operating Instructions in that
Reliability Coordinator’s area." Also make similar changes where required elsewhere.
No
FERC requires that VSL’s be graded. The Requirement R3 VSL should be modified to reflect the
following graded proposal: “The first failure following the effective date of this standard is a
“Low VSL.” However, should failures be more frequent, then the severity level for such failures
should be increased. “For the second and subsequent failures following the effective date of
the standard a single failure within a given 12-month rolling period is a Moderate VSL. “For the
second and subsequent failures following the effective date of the standard and when there is
more than one failure within a given 12-month rolling period the failure is a Severe VSL.”
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
No
No, the 2003 Blackout recommendations were specific to control center and reliablity
coordinator entities. This standard appears to push down below to small DP entities that don't
have control centers. Also, the Blackout recommendations were clearly concerned with
"reliability" directives and did not contemplate a new category of Operating Instructions. The
existing authority in other standards for registered entities to respond to reliability directives
should be sufficient to addres the recommendations without this standard.
No
Individual
Michelle R D'Antuono
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Occidental Energy Ventures Corp.
Yes
Occidental Energy Ventures Corp. (“OEVC”) would like to compliment the drafting team for
finding a compliance solution that focuses only on the results of an improperly executed
Operating Instruction. The approaches in previous drafts could be construed that entities retain
proof that every applicable communication was monitored and verified – an impossible
administrative task. We believe that Draft 6 of COM-003-1 removes the onerus compliance
burden without freeing Operating entities from the obligation to perform responsibly. They are
free to choose the level of sample communications to monitor, the amount of training they
perform, and the internal disciplinary actions they take for non-compliance to the required
protocols. However, there are consequences if their oversight is inadequate. We do have two
concerns which we would like to air. First, that recipients of Operating Instructions must be
informed that formal communication is being done. Athough front-line Operators will be
trained to comply with the appropriate protocol documents, they will be naturally inclined to
follow the lead of the issuing entity – particularly if the communication is a borderline
instruction. For example, a request for equipment status may be part of discussion concerning
available alternatives, or information needed to confirm real-time stability. The recipient
should not be left in a position to guess what the needs of the immediate situation are.
Secondly, we would hope that the protocols developed by the various RCs, BAs, and TOPs are
generally consistent. Even though we agree that each individual organization may have specific
communications needs, it is in no one’s interest to have minor preferential differences
between entities. Perhaps this is an issue that NERC’s performance management team can
monitor – particularly as they have a highly vested interest in the resolution of Operating
Instruction errors. These comprise a high percentage of outage root causes, and we are sure
that uniformity will be a key improvement indicator.
Yes
Individual
Anthony Jablonski
ReliabilityFirst
No
ReliabilityFirst believes the newly included language in Requirement R1 “…subject to the
Reliability Coordinator’s approval…” introduces three issues which need to be addressed prior
to the draft standard being enforceable. The three issues include: 1) With the Reliability
Coordinator being an Applicable Entity within this requirement, it is unclear which entity will be
approving the Reliability Coordinator’s documented communication protocols? Based on the
current language, the Reliability Coordinator would need to seek approval from themselves as
the Reliability Coordinator. 2) There is no companion requirement requiring the Reliability
Coordinator to approve the Balancing Authority’s and Transmission Operator’s documented
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communication protocols. It is inferred, but there is no requirement which explicitly requires
the Reliability Coordinator to take action. Based on the current language in Requirement R1, if
a Reliability Coordinator never takes action (approval or disapproval), where does this leave an
entity for compliance purposes? 3) In the scenario where the Applicable Entity (Balancing
Authority, Transmission Operator) develops documented communication protocols (which
address the elements in sub parts 1.1 through 1.5) but the Reliability Coordinator disapproves,
will the Applicable Entity be non-compliant with Requirement R1? The Applicable Entity has no
control over action taken (approval or disapproval) by the Reliability Coordinator. Furthermore,
since Requirement R2 and Requirement R3 depend on the documented communication
protocols developed in Requirement R1, would the Applicable Entity be automatically found
non-compliant with those two requirements as well? ReliabilityFirst offers the following two
recommendations for the SDT to consider to address the ReliabilityFirst concerns with the
newly included language “…subject to the Reliability Coordinator’s approval…”: 1) Remove the
“…subject to the Reliability Coordinator’s approval…” language from Requirement R1. Add a
new requirement requiring the Applicable Entities to make their documented communication
protocols available to all the other Applicable Entities within in each Reliability Coordinator
area. 2) Make Requirement R1 applicable to only the Reliability Coordinator and remove the
“…subject to the Reliability Coordinator’s approval…” language. This will require the Reliability
Coordinator to develop one consistent set of documented communication protocols for all
entities within their Reliability Coordinator area. This will also allow the Reliability Coordinator
to tailor the documented communication protocols to address uniqueness among Balancing
Authorities and Transmission Operators (e.g., asset density, locations and organizational
structure) within their area. If the SDT agrees with either of these recommendations, the subparts for Requirement R1 and both Requirement R2 and Requirement R3 would remain
relatively unchanged.
No
ReliabilityFirst has a concern with the VSLs for Requirement R1. In the previous draft, the VSLs
for Requirement R1 were gradated based on missing “x” out of nine sub-parts. For example,
missing 44% (four out of nine) of the sub-parts was a Severe VSL). With the current draft only
including five sub-parts under Requirement R1, the gradation should be adjusted accordingly.
ReliabilityFirst believes that an entity not addressing more than half of the sub-parts within the
documented communication protocols is missing the intent of the requirement and should be
a Severe VSL. Furthermore, if the “…subject to the Reliability Coordinator’s approval…”
language continues to remain in Requirement R1 (against our recommendations in previous
comments), this “Reliability Coordinator approval” needs to be included in the VSLs as well.
ReliabilityFirst offers the following as an example for consideration: i. Lower VSL – none ii.
Moderate VSL – “…did not develop one (1) of the five (5) parts…” iii. High VSL – “…did not
develop one (2) of the five (5) parts…” iv. Severe VSL - “…did not develop one (3) of the five (5)
parts…” v. Severe VSL - “The Responsible Entity did not receive Reliability Coordinator approval
of its documented communication protocols as required in Requirement R1.”
Individual
Texas Reliability Entity
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Texas Reliability Entity
No
(1) Definition of Operating Instruction: We remain concerned about potential interference
between COM-002 and COM-003. While it has been made abundantly clear in this draft that an
Reliability Directive is not an Operating Instruction, it remains unclear exactly where the
boundary between them is. We are concerned that an operator faced with an imminent
emergency situation will have to stop to consider whether he needs to issue a Reliability
Directive or an Operating Instruction, and entities will be subject to second-guessing as to
whether they picked the right one. COM-002 and COM-003 should be melded into one
coherent standard that will not interfere with system operations. (2) The present draft does
not address one-to-many communications (hot-line calls, all-calls), which are commonly used
to convey Operating Instructions in critical situations. A repeat-back procedure for those calls
should be included in an entity’s documented communications protocols. (3) While we respect
the desire to avoid writing a “zero-defect” standard, we strongly object to the approach taken
in requirements R2 and R3. Compliance with these requirements should not be based on
whether a subsequent Reliability Directive was issued. Instead, compliance should be based on
whether the communication protocols are routinely and effectively implemented (perhaps
using an “identify/assess/correct” approach). The present draft allows system conditions over
which the entity may have little control (i.e. luck) to determine whether a deviation from its
protocols results in a violation. Importantly, the current draft may create an undesirable
incentive for an operator to avoid issuing a Reliability Directive in order to avoid scrutiny of
prior Operating Instructions. (4) We also object to basing compliance with R2 and R3 on
whether the entity’s conduct “resulted in” an adverse operating condition. The existence of a
violation should be based solely on the entity’s conduct, not on the results of that conduct on
system conditions. The proposed approach creates an unmanageable compliance assessment
burden, as parties will dispute whether events were causally related, which can be very difficult
to conclusively assess. Furthermore, what does “result in” mean? Does it require proximate
cause, direct cause, contributing cause, or some other measure of causal relationship? (5) The
proposed revisions in COM-003 interact with the revisions in TOP-001-2 to create a reliability
gap that will reduce the performance level required by the standards. The existing
requirements 3 and 4 of TOP-001-1a require TOP, BA, GOP, DP and LSE entities to comply with
reliability directives (not capitalized) issued by a TOP. We interpret “reliability directives” in
that standard to include all operating instructions related to reliable system operation,
including those that are proposed to be defined as both Reliability Directives and as Operating
Instructions. The new version TOP-001-2 (pending at FERC) limits the compliance requirement
to only Reliability Directives (defined term), and will no longer require compliance with
Operating Instructions issued by TOPs. This problem is enhanced by the proposed definition of
Operating Instructions, which now emphasizes that Operating Instructions and Reliability
Directives are mutually exclusive. There needs to be a reliability standard that requires
compliance with Operating Instructions issued by TOPs, and the absence of such a standard
creates a reliability gap.
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Group
City of Garland
Ronnie Hoeinghaus
No
Three part communications is a standard business practice in transmission and distribution
operations across the country. If by chance there is / was a company that was not using three
part communications, that company would have had to develop a procedure / policy for three
part communications to be compliant with COM-002-2 R2 (COM-002-3 R2 future). Therefore,
the proposed COM-003 R1 requiring companies to develop “documented communication
protocols” that have to be approved by the Reliability Coordinator is nothing more than a
compliance burden to maintain documentation for an audit. Furthermore, COM-003 R3
requires use of three part communications and should be the only requirement in COM-003.
Because of COM-002-2 R2 and COM-003 R3, COM-003 R1 is merely a paperwork compliance
burden and should be deleted. COM-003 R2 relies on R1 and therefore it should be deleted
also. As previously stated, COM-003 should only contain the requirement listed in the current
R3.
No
R2 & R3 only have a “Severe VSL” listing - As I understand it, NERC has recognized that
“perfect” historical compliance is not practical and is one of the reasons NERC is moving to
implement the RAI program. R2 & R3 Severe VSL only listings require 100% perfection - Real life
operations is not perfect (as recongnized by the RAI) – VSLs should be a gradient from “lower”
to “severe”
Individual
Dennis Schmidt
City of Anaheim
Yes
The proposed Standard language appears to address the requirements of FERC Order 693.
However, R3 is still confusing and appears to assume that the distribution provider or
generator operator would have some way of knowing if an Operating Instruction would “result
in an operating condition that requires the issuance of a Reliability Directive by the original
issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator,
or Transmission Operator.” Also, more clarification is needed with respect to the terms
"restate", "rephrase" and "recapitulate". We suggest the the following language for R3:
“Balancing Authorities, Transmission Operators, Generator Operators and Distribution
Providers shall repeat or restate an Operating Instruction given to them when required by the
issuer of that Operating Instruction.”
Group
Dominion
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Connie Lowe
Yes
Dominion appreciates the SDT efforts on this project as we know it has not been an easy task
to satisfy industry concerns while at the same time, addressing FERC directives relative to this
issue. We believe that having a requirement that the communication protocol be approved by
the RC, while possibly considered an administrative burden by them, greatly enhances
consistency of such protocols. And, we greatly appreciate the fact that recipients are required
to repeat, restate, rephrase, or recapitulate only when required by those approved protocol.
Yes
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
No
These comments are submitted on behalf of the following PPL NERC Registered Affiliates (PPL):
Louisville Gas and Electric Company and Kentucky Utilities Company; PPL Electric Utilities
Corporation, PPL EnergyPlus, LLC; and PPL Generation, LLC, on behalf of its NERC registered
affiliates. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC, RFC,
SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA,
LSE, PA, PSE, RP, TO, TOP, TP, and TSP. PPL has generally supported draft 4 and draft 5 of the
COM-003 standard. However, the significant changes proposed in draft 6 introduce ambiguity,
as well as several other issues that need to be addressed. First, the proposed definition of an
“Operating Instruction” continues to require clarification. PPL NERC Registered Affiliates
suggest the following definition to address the above issue: “Operating Instruction - A Realtime Operations command, other than a Reliability Directive, by a System Operator of a
Reliability Coordinator, or of a Transmission Operator, or of a Balancing Authority, where the
recipient of the Real-time Operations command is expected to act to change or preserve the
state, status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk
Electric System. A discussion of general information, potential options and/or alternatives to
resolve Bulk Electric System operating concerns is not a command and is not an Operating
Instruction. An Operating Instruction is exclusive and distinct from a Reliability Directive. There
is no overlap between an Operating Instruction and Reliability Directive.” The focus of COM003 is on operations, and therefore the communications subject to the COM-003 requirement
should be those requiring action in the Real-time Operations time horizon — i.e., actions
required within one hour or less. (See definition provided in a NERC document at:
http://www.nerc.com/files/Time_Horizons.pdf). During the Q/A portion of the November 27,
2012 conference call hosted by the SDT, the SDT stated that they intended to narrow the focus
of the timeframe of an Operating Instruction to the Real-time Operations time horizon. .
Second, there is inconsistency in the wording of some parts of R1. Specifically, PPL
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recommends revising part 1.5 as follows: “The instances, if any, where the issuer…” or
removing the ‘if any’ from R1.2 and R1.4, since it is redundant to the R1 ‘where applicable’ and
the use of ‘when, that, etc.’ in the sub requirements. Third, both R2 and R3 as currently written
may not aid in enhancing reliability. PPL suggests R2 be revised to require the BA, RC, and/or
TOP provide their communication protocols to the GOPs, DPs with whom they communicate.
PPL suggests language for R3 be revised to read as follows: “Each Balancing Authority,
Distribution Provider, Generator Operator, Reliability Coordinator, and Transmission Operator
shall assess its adherence to the applicable documented communication protocols developed
for R1 and R2.” As currently drafted, R2 and R3 appear to require that entities issuing or
receiving Operating Instructions must prove that no BA, RC or TOP issued a Reliability Directive
as a result of their lack of use of the R1 protocol or of three-part communication. The R2 draft
language says that the BA/RC/TOP communication protocols must be developed such that
even when the communication protocols are not used, there is still no need for a Reliability
Directive. This could imply that if no Reliability Directive is required, the failure to use the
protocols created no risk and the communication protocol was not needed. This appears to
make inconsequential any reliability benefit of R1 of the Standard. Also, R3 has requirements
for entities that may not have received the communication protocols developed by the
BA/RC/TOP. Fourth, there is ambiguity introduced in R2 and R3 through the use of the phrase
“that requires the issuance.” It is unclear who would determine whether the Reliability
Directive was “required.” Likewise, if there are multiple incidents which contribute to the
issuance of a Reliability Directive, it is not clear what weight would be given to the lack of use
of communication protocols, nor is it clear how that determination is made. Finally, M2 and M3
introduce an expectation that applicable entities will need to coordinate to produce evidence.
PPL recommends that M2 and M3 be revised to align with the changes made to R2 and R3 as
noted above.
Individual
Matthew P Beilfuss
Wisconsin Electric Power Company
No
Version 6 of the standard does not explicitly limit the timeframe prior to the issuance of a
Directive subject to review for compliance with communication protocol requirements.
Additionally, the draft Standard and definition of Operating Instruction do not adequately
define instances where Operating Instructions would require 3-way communications. The
process by which a Reliability Coordinator approves instances where communication protocols
are required will define the substantial requirements in the standard. Establishing the
Reliability Coordinator as an approval authority for BA or TOP internal procedures implies the
RC will have responsibility for operational activities and/or procedures owned by the BA or TOP
and essentially outsources the standard development to the Reliability Coordinator.
Individual
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Kathleen Goodman
ISO New England Inc.
Agree
ISO/RTO Standards Review Committee (SRC)
Individual
Joe Tarantino
Sacramento Municipal Utility District
Yes
Although SMUD agrees with the draft 6 of COM-003-1. Also, we are in support of the finding
from the Independent Standards Review Panel’s final report for mitigating BPS risks as noted:
~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
~~~~~~~~~~~~~~~~~~~~~ Resolve COM-002 and COM-003 by requiring three-part
communication for operational directives and for registered entity defined operational
instructions that involve taking specific actions or steps that would cause a change in status or
output of the BPS or a generator. This does not include three-part communication for myriad
of conversations where information is being exchanged or options are being discussed.
~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~
~~~~~~~~~~~~~~~~~~~~~~
Group
North American Generator Forum Standards Review Team
Patrick Brown
No
R3 can present an excessive or even impossible compliance burden, in that all parties receiving
Operating Instructions must prove that no BA, RC or TOP issued a Reliability Directive as a
result of their lack of three-part communication. This is not a matter of simply obtaining
annually a “No known errors” letter from the BA, RC and TOP with which a receiving-end entity
is directly involved, since all the neighboring BAs, RCs and TOPs are drawin-in by R3 as well.
There is meanwhile no requirement that BAs, RCs or TOPs issue such letters when requested to
do so, or that they must share any information at all regarding Reliability Directives issued. This
leaves GOPs and other entities that receive Operating Instructions in danger of self-certifying
compliance to R3, then being later confronted with evidence of non-compliance from a source
from whom they had previously heard nothing. The issue of interpretation also creates undue
ambiguity. Who will make the determination of cause when a Reliability Directive is issued, and
is that opinion subject to review if objections are raised? If all GOPs in a region were instructed
to bring all available generators online at their Emergency Rating due to tripping of a 2000 MW
nuclear plant, for example, and the operator of a 10 MW blackstart unit did not respond in the
prescribed fashion, and a Reliability Directive ultimately had to be issued to shed some load,
did that 10 MW unit “cause” the load shedding? R3 should be revised to match the draft that
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was issued for comments several weeks ago, and which the NAGF found acceptable. That is, R3
should state that “Each Balancing Authority, Distribution Provider, Generator Operator,
Reliability Coordinator, and Transmission Operator shall develop method(s) to assess, as
applicable, System Operators’ and operators’ communication practices and implement
corrective actions necessary to meet the expectations in its documented communication
protocols developed for Requirement R1 and R2.”
No
The VRF and VSL language for R3 should be changed to that of the draft version of Draft 6 that
was commented-on by the NAGF several weeks ago.
Individual
Michael Falvo
Independent Electricity System Operator
No
Despite we have always held a position that this standard was not needed given the approved
COM-002-3 and the NERC OC’s operating guide on operating personnel communication, we
supported the previous version of COM-003-1 (Draft 5) as it was a clearly written standard
which would be an acceptable compromise for meeting the FERC directive and BoT’s direction
without overburdening industry participants having to repeat every operating instruction. This
latest version, Draft 6, however, turns an acceptable standard into one that is ambiguous and
provides an escape clause for operating personnel to not comply with the basic requirement
(R1). The introduction of the condition in R2 “so that the failure to use the protocols by the
issuer of an Operating Instruction does not result in an operating condition that requires the
issuance of a Reliability Directive by the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or Transmission Operator.” creates a
number of issues with the standard, as follows: a. The issuance of a Reliability Directive may be
caused by a number of reasons, for example: the operating instruction (repeated or otherwise)
may not be sufficient to address a potential condition that has an Adverse Reliability Impact; b.
The operating instruction that is communicated, with or without adhering to the protocols
developed in R1, is in fact moving other system conditions from a reliable state to one that has
a potential of having Adverse Reliability Impact, for which a Reliability Directive needs to be
issued after implementing the communicated operating instruction. c. The operating personnel
may second guess whether or not a Reliability Directive will be issued if the established
communication protocols are not implemented (such as by requiring 3-part communication)
before it takes the required action. This puts the need to comply with a requirement into a
“condition assessment” mode, which defeats the purpose of having a reliability standard to
manage risk and meet performance expectation whose reliability outcome are predetermined,
not on the fly. d. The added condition is a compliance assessment element with which to gauge
violation severity or sanction; itself is not a requirement. By introducing this to the
requirement, it convolutes the requirement, adds nothing to meeting the reliability objectives,
and may in fact jeopardize reliability. And what if a Reliability Directive was not issued despite
the failure of Responsible Entity to implement its communication protocol. Is the Responsible
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Entity deemed compliant with the requirement? If so, do Requirements R2 and R3 drive the
right behaviors? If not, then what’s the value and influence of the added condition in the
assessment outcome? Requirement R1 clearly requires the responsible entity to develop
documented communication protocols for the issuance of Operating Instructions. By Part 1.5,
the instances where the issuer of an oral two party, person-to-person Operating Instruction
requiring the receiver to repeat, restate, rephrase, or recapitulate the Operating Instruction
and subsequent actions by the issuer are already clearly stipulated in the documented
communication protocols. Responsible entities simply need to implement the protocols as
documented, regardless of whether failure to do so would result in having to issue a Reliability
Directive, or any other possible outcomes, for that matter. Similar comments apply to
Requirement R3 when the responsible entities are required to close out the last part of the 3part communication.
Yes
We agree with the VRFs, but not the VSL since we do not agree with Requirements R2 and R3.
We offer the following two additional comments: 1. We do not agree with the Long-term
Planning Time Horizon for R1. Developing and documenting communication protocols for use
during real-time operations is an operational planning process (or mid-term planning, at most),
not a long-term planning process. We suggest to change the Time Horizon to Operations
Planning. 2. The proposed Implementation Plan conflicts with Ontario regulatory practice with
respect to the effective date of the standard. It is suggested that this conflict be removed by
appending to the effective date wording, after “applicable regulatory approval” in the Effective
Dates Section of the Implementation Plan, to the following effect: “, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.” Prior to the
wording “; or, In those jurisdiction….”. Alternatively, the same language in the Effective Dates
Section of the Implementation Plan could be used.
Individual
Terry Bilke
MISO
No
The blackout recommendation 26 had little or nothing to do with operator communications.
The recommendation was to implement some type of communication system to keep Regions,
NERC and regulators informed during emergencies. Here is the recommendation: “NERC should
work with reliability coordinators and control area operators to improve the effectiveness of
internal and external communications during alerts, emergencies, or other critical situations,
and ensure that all key parties, including state and local officials, receive timely and accurate
information. NERC should task the regional councils to work together to develop
communications protocols by December 31, 2004, and to assess and report on the adequacy of
emergency communications systems within their regions against the protocols by that date.”
These are our comments on what is presented in this revision of COM-003-1. • We’re generally
OK with a requirement to develop a set of communication protocols and whereby the
applicable entity does a periodic assessment of its operators’ adherence to the protocols. •
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While we believe that it is acceptable for a BA and TOP to develop their own protocols, it
would be preferable that they be allowed to use a set of protocols developed by the RC. • We
disagree that the RC should approve others’ protocols. What are the criteria for approval?
NERC should not put RCs in the role of de-facto compliance monitors. • There is a likely
unintended consequence of the latest draft. This will plant a seed of doubt in an operator’s
mind whether or not to issue a reliability directive due to the scrutiny and second guessing that
will be the outcome of each investigation associated with a directive. This standard will result
in investigations associated with each directive. • We were OK with the previous version. We’d
be OK with a revision to the current draft if there was an ex post assessment of operating
instructions following the issuance of a directive. There should not be a rabbit-trail
investigation following the issuance of each directive.
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
Individual
Alice Ireland
Xcel Energy
We are electing to not respond directly to this question, as we have expressed concern with
the advancement of this project many times in the past. While this draft seems far superior to
the others, the proposed change to R1 raises concern over the portion that dictates that the
Reliability Coordinator has approval authority over the communications protocols for
Operating Instructions. The majority of the Operating Instructions, as defined by the standard,
will be between the System Operator at a Balancing Authority or Transmission Operator and
their respective field personnel. Communications between System Operators of BAs and TOPs
and field personnel have well-established protocols and should not necessarily be held to the
same protocol as communications between BAs or TOPs and the Reliability Coordinator. In
essence, the proposed change to R1 places the Reliability Coordinator in a position to dictate
communication protocols that may breakdown the well-established protocols of the BAs and
TOPs and create more burdensome communication with their field personnel.
Individual
Mary Downey
City of Redding
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Agree
SMUD
Individual
Jack Stamper
Clark Public Utilities
No
Requirement 1 does adequately address the concerns. Requirements 2 and 3 are confusing and
difficult interpret. It was not until I rea the FAQ on COM-003 that I understood R2 and R3. I
believe R2 and R3 should be revsed as described below. R2. R2 needs to indicate that it is only
applicable to issuers of Operating Instructions. R2 should be revised to read as follows: Each
Balancing Authority, Reliability Coordinator, and Transmission Operator that issues an
Operating Instruction shall implement its communication protocols developed in Requirement
R1 so that the failure to use the protocols by the issuer of an Operating Instruction does not
result in an operating condition that requires the issuance of a Reliability Directive by the
original issuer of the Operating Instruction or by another Balancing Authority, Reliability
Coordinator, or Transmission Operator. With the change it is clearer that the standard is saying
that an issuer of an Operating Instruction is supposed to have a communication protocol(R1).
R2 is stating the issuer of an Operating Instruction needs to use the communication protocol
and if the issuer's failure to use the communication protocol results in the issuance of a
Reliabilty Directive, a violation has occured. R3. R3 needs to indicate that it is only applicable to
recipients of Operating Instructions. R3 should be revised to read as follows: Each Balancing
Authority, Transmission Operator, Generator Operator and Distribution Provider that receives
an Operating Instruction shall repeat, restate, rephrase, or recapitulate the Operating
Instruction when required by the issuer of the Operating Instruction (in accordance with the
issuer's communication protocols developed in Requirement R1) so that the failure to repeat,
restate, rephrase, or recapitulate the Operating Instruction does not result in an operating
condition that requires the issuance of a Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator. With the change it is clearer that the standard is saying that a recipient
of an Operating Instruction is supposed to to repeat, restate, rephrase, or recapitulate the
Operating Instruction when required by the issuer and if the recipient's failure to repeat,
restate, rephrase, or recapitulate the Operating Instruction (as long as it is required in the
issuer's communication protocol) results in the issuance of a Reliabilty Directive, a violation has
occured.
Yes
Group
Southern Company: Southern Company Services, Inc; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation
and Energy Marketing
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Marcus Pelt
Yes
Yes
R1 • The phrase “subject to the Reliability Coordinator’s approval” is included in the
requirement, but there is no reference to RC approval in the measure. It is unclear exactly what
the expectations are for TOPs and BAs in this requirement. Are they to develop protocols and
submit to the RC for approval, and have a record of this approval for compliance evidence? If
so, the SDT needs to modify this requirement to make the required actions very clear. EOP005-2 is an example of the TOP getting approval from the RC on its restoration plan. This may
be a better model to use as it is more clear. • In addition, the RC is required to approve its TOPs
/ BAs protocols; however there is no guidance on what criteria to base this approval on. There
needs to be very clear guidance that RCs are to ensure that the protocols are compatible with
its protocol and that RCs are not “auditing” the TOPs / BAs protocols to confirm they include all
the subparts of requirement R1. R3 • R3 can present an excessive or even impossible
compliance burden, in that all parties receiving Operating Instructions must prove that no BA,
RC or TOP issued a Reliability Directive as a result of their lack of three-part communication.
This is not a matter of simply obtaining annually a “No known errors” letter from the BA, RC
and TOP with which a receiving-end entity is directly involved, since all the neighboring BAs,
RCs and TOPs are drawin-in by R3 as well. There is meanwhile no requirement that BAs, RCs or
TOPs issue such letters when requested to do so, or that they must share any information at all
regarding Reliability Directives issued. This leaves GOPs and other entities that receive
Operating Instructions in danger of self-certifying compliance to R3, then being later
confronted with evidence of non-compliance from a source from whom they had previously
heard nothing.
Individual
Bob Thomas
Illinois Municipal Electric Agency
Agree
Florida Municipal Power Agency, and SERC OC Standards Working Group
Group
Oklahoma Gas & Electric
Terri Pyle
Yes
There is still concern that the intent of Recommendation 26 was strictly for emergency
situations which are covered by COM-002-3. While well intentioned, based upon the spirit of
the Paragraph 81 initiative, OG&E believes the current draft of the COM-003-1 standard to be
more of an administrative burden than an improvement to reliability.
Yes
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There were a couple of typos in the VSLs: R1 – Insert a space between ‘R1’ and ‘in’ in the Lower
VSL. R3 – Insert ‘to’ between ‘failed’ and ‘repeat’ in the Severe VSL.
Individual
Don Weaver
New Brunswick System Operator
No
The introduction of the condition in R2 “so that the failure to use the protocols by the issuer of
an Operating Instruction does not result in an operating condition that requires the issuance of
a Reliability Directive by the original issuer of the Operating Instruction or by another Balancing
Authority, Reliability Coordinator, or Transmission Operator.” creates a number of issues. • The
issuance of a Reliability Directive may be caused by a number of reasons, for example: the
operating instruction may not be sufficient to address a potential condition that has an Adverse
Reliability Impact; • R2 has the unintended consequence of making Reliability Directives a
subject of a Root Cause analysis. Whenever a Reliability Directive is issued it would be
necessary for the issuer to prove that that Reliability Directive was not linked to an Operating
Instruction protocol failure.
Individual
Steven R. Wallace
Seminole Electric Cooperative, Inc.
No
While the draft may meet the Blackout Recommendation and Order 693, the draft is
problematic and is resulting in Seminole changing its votes from prior affirmation to negative
with this ballot. The reasons are: 1. The requirement for RC approval of entity developed
communications protocols (R1), which impose an unreasonable administrative and associated
cost burden upon all of the applicable entities. 2. The new connection to Reliability Directives
issued by an RC, TOP, or BA, which are due to the failure of an applicable entity to properly
implement its communication protocols for Operating Instructions, seemingly implies
compliance investigation following the issuance of any RC Reliability Directive, for all entities
affecting the RC area’s footprint (R2&3). 3. The term Operating Instruction is so broad, that
every System Operator communication might require logging, recording and compliance
review.
No
The VSL’s are far too high given the ambiguity inherent to the R2 and R3 requirements as
written.
Individual
Greg LeGrave
Wisconsin Public Service Corp
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Yes
Also, since enforcement and compliance under Version 6 hinges on a Reliability Directive being
issued, am I correct to assume that if emergency conditions requiring actions on the BES were
to occur, but an issuing entity failed to announce their request for action as a Reliability
Directive – then NO Directive was issued, and therefore there could be no COM-003 violation
for that event and no need to analyze if preceding Operating Instructions were given which
may have lead up to the Emergency condition? Note: COM-003 Rev. 6, R3 “… an operating
condition that requires the issuance of a Reliability Directive…” so put another way, what if a
Reliability Directive was required – but not clearly identified as in COM-002 V3, R1? The future
COM-002 V3, R1 requires an issuing RC, TOP, or BA (or LBA) in part, to clearly call a Reliability
Directive a Reliability Directive. I couldn’t find similar language for Operating Instructions in
Rev. 6 of COM-003. Is it intended that this will need to be included in each entities
communications protocol, along with the need for the issuing entity to clearly communicate
“…and I will need you to repeat this back.”? My concern here is that while I like the SDT’s
approach with R3 in Rev. 6, if only R3 applies to DP’s and GOP’s (and therefore they are not
required to have or to implement communications protocols), if the issuer of an Operating
Instruction doesn’t clearly identify it as such AND tell the recipient in advance that he requires
a repeat-back, it will be difficult for the recipient who is a DP or GOP to meet the R3
requirement. Conversely, based on the high number of Operating Instructions occurring each
day, perhaps it was the intent of the SDT that DP’s and GOP’s which are limited to simply how
to respond to Directives and/or Instructions with repeat-backs. Please clarify. Lastly, I
mentioned the concern under M3. Rather than just stating it is confusing, I’m listing a proposed
change for consideration if the Standard doesn’t get approved as is. We hope it is more clear in
its wording and its expectation that the issuer of any Directive should lead efforts to complete
an analysis of what lead up to a Directive. Draft 6 proposal for M3: Each Balancing Authority,
Generator Operator, Distribution Provider, and Transmission Operator shall provide evidence
that it did not experience a failure to repeat, restate, rephrase, or recapitulate an Operating
Instruction, when required, that resulted in an operating condition that required the issuance
of a Reliability Directive by the issuer or by another Balancing Authority, Reliability
Coordinator, or Transmission Operator due to the failure to use the protocols. A Balancing
Authority, Generator Operator, Distribution Provider, and Transmission Operator may need to
coordinate with a Reliability Coordinator, Balancing Authority and Transmission Operator to
provide this evidence. WPS proposal for M3: The issuer of a Reliability Directive shall provide
evidence that a failure to repeat, restate, rephrase, or recapitulate an Operating Instruction,
when required, resulted in an operating condition that required the issuance of a Reliability
Directive. A Balancing Authority, Generator Operator, Distribution Provider, and Transmission
Operator may need to coordinate with a Reliability Coordinator, Balancing Authority and
Transmission Operator to provide this evidence.
Yes
Individual
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Carter B. Edge
SERC Reliability Corporation
Yes
It addresses parts of each. While a reliability standard may not be the most appropriate control
to address the reliability concern, this standard, in conjunction with COM-003-2 does address
the Standards Authorization Request to require that real time system operators use
standardized communication protocols during normal and emergency operations to improve
situational awareness and shorten response time. There is concern with making protocols (and
any revisions) available to those who are expected to comply. R1 states that the RC must
approve; M1 states that each...shall provide. It is not clear that those who must comply will
have the latest version. Suggest that the Measure be tightened up to state that the RC must
provide the approved communication protocols to the .... in thier footprint.
No comment
Individual
Randi Nyholm
Minnesota Power
Minnesota Power supports comments submitted by the MRO NERC Standards Review Forum
(NSRF).
No
Similar to Restoration Plans, Registered Entities are capable of coordinating communication
protocols with their neighbors without Reliability Coordinator approval. Minnesota Power
recommends removing Reliability Coordinator approval from the Requirements.
No
Group
SERC OC Review Group
Stuart Goza
Yes
We agree on a very limited view that Recommendation 26 is addressed. However, when
looking at reliability we are concerned that the administrative burden, and uncertainty of
which Operating Instruction will become a Reliability Directive may negatively impact BES
reliability in the reluctance of issuing a Reliability Directive. Therefore, we strongly recommend
that the SDT review this draft and redraft to clarify these points. Measure 3 should be changed
to “when required by the issuer” in order to provide clarity and consistency with R3. In
addition, we believe that a statement needs to be added in R1 that includes providing or
distributing those communication protocols developed by a BA or TOP to their associated DPs
and GOPs. This would address a potential gap of DPs and GOPs not aware of the
communication expectations when communicating with BAs and TOPs when given an
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Operating Instruction.
The comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Review Group only and should not be construed as the position of
the SERC Reliability Corporation, or its board or its officers.
Group
ACES Standards Collaborators
Ben Engelby
No
(1) While we understand that there are numerous approaches to satisfy the FERC order and the
2003 Blackout Report, we disagree that the drafting team addresses these concerns in a
measurable and uniform process. The FERC Order and the Blackout Report both call for a
“tightening of communications.” We are not convinced that giving the RC the authority to
approve communication protocols will result in less confusion and a tightening of
communications. There are currently 15 Reliability Coordinators in the NERC Compliance
Registry, which leaves 15 opportunities for inconsistent application of what constitutes an
“Operating Instruction.” (2) Further, we are concerned that by granting the Reliability
Coordinator the authority to approve a registered entity’s communication protocol, there may
be differing protocols among the various RC areas, which would negatively impact registered
entities that are located in more than one RC area. For entities that operate in multiple RC
areas, there could be different criteria for what constitutes an Operating Instruction, differing
line and equipment identifiers, and other nuances that result in confusion and lead to an
increase in miscommunication. The standard does not require uniform communication
protocols among the various Reliability Coordinators. (3) In addition, how would an entity
communicate to a neighboring BA and TOP who are in a different RC area with different
protocols? This draft poses significant issues for registered entities located on the seams of RC
areas that communicate to other entities in other RC areas. (4) We have an issue with the
language in the Measure M2. Measure M2 requires a registered entity to prove the negative
that no reliability directives occurred. This presents an issue because some regions are
reluctant to accept attestations as evidence. This approach is an increased compliance burden
on registered entities. This draft did not include an RSAW for review and we recommend the
drafting team provide further clarification that an attestation is acceptable for compliance and
continue to work with NERC compliance on this issue. (5) Finally, we disagree with the revised
definition of Operating Instruction and the approach of Requirement R2 and R3. Under the
revised definition, an Operating Instruction is separate from a Reliability Directive, but an
entity will only be in violation for failing to communicate effectively that would result in the
issuance of a Reliability Directive. This is double jeopardy. An entity could be in violation of
both COM-002 and COM-003 for failing to communicate effectively that results in an event on
the Bulk Electric System. This issue has been stated in our earlier comments that the definitions
and the two COM standards would be better as a combined standard instead of the separate
projects to avoid this potential compliance issue.
No
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(1) We disagree with the VSL for R1. The compliance violation should fall on the RC for failing to
approve the communication protocol and it should be up to the RC to ensure the sub-parts 1.1
through 1.5 are included in the protocol. Under the current draft, the RC has approval
authority without any accountability. The VSL would find the entity in violation of R1, even
though it would be at the mercy of the RC to approve its protocol. (2) The VSLs for R2 and R3
imply that a violation of COM-002 also occurred. We cannot support a standard that has the
potential for multiple violations.
Group
Southwest Power Pool Regional Entity
Emily Pennel
Yes
What is the expected time frame for the RC’s initial approval of the protocols? NERC needs to
clarify the protocol approval dates in relation to the effective/enforceable date.
Yes
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
No
AECI strongly supports the SERC OC Q1 comments posted for this draft. In addition, AECI
believes that COM-003 fails to properly address related topics found within the August 2003
Blackout Report Recommendation number 26 and FERC Order 693, primarily because of the
SDT's having included DPs within the COM-003 scope, and thereby overreaching these two
citation's intended scope. In the case of the August 2003 Blackout Recommendation 26, while
its terse two-sentences appear to be met by COM-003, the same report's pp 161-162 clarifies
its intended scope being "during alerts, emergencies or critical situations." That same section's
"particularly during alerts and emergencies", might be stretched to include COM-003 Operating
Instructions for DPs, yet FERC's determination, expressed within Order 693 paragraphs 493,
509-512, suggests that NERC COM-003 is attempting to tread where FERC itself dared not go.
Within that paragraph 493, FERC's rationale cites no more than "when generators with
blackstart capability must be placed in service and nearby loads restored as an initial step in
system restoration", in support of exercising governance over DP telecommunications. These
two limited conditions for communication appear confined to COM-002, and not COM-003's
drafted governance over external communications with DPs. Paragraph 509's real-time staffing
requirement omits DPs. Paragraph 510.3 cites DPs as applicable under COM-002, and 510.4
"requires tightened communications protocols, especially for communications during alerts
and emergencies" and then par 510 goes on to propose a new standard (COM-003?) for
addressing the Blackout Report Recommendation 26. Paragraph 512's assertion "that, during
both normal and emergency operations, it is essential that the transmission operator,
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balancing authority and reliablity coordinator have communications with distribution
providers" appears to conflict with earlier par 509 with regard to levels of "essential", and then
asserts that many DPs are "not a user, owner or operator of the Bulk-Power System" so not
required to comply with COM-002 (nor therefore COM-003). However COM-003 fails to
provide for such differentiation within its Applicability section 4.1.2, for its scope of governance
over DP communications during "normal operations". AECI recommends that DP applicability
be dropped from COM-003 and reserved for COM-002 where these citations rationale for
inclusion is clear. Finally, because industry balloting appears highly conflicted over the terms
under which COM-003's rules would be developed, AECI strongly suggests that the SDT limit
scope to only communications between RCs and their external communicating parties. This
stance would have stronger backing from the above citations, and would make more sense,
because only RCs communicate changes to the BES. New governance over the exact manner in
which communicated changes become executed, is where industry appears to have heartburn.
This may be occuring because much of industry has already tweaked and tuned those
operational methodologies long before RCs came into existence, and therefore see much
greater Compliance risk being ventured, for relatively little BES-reliability gains.
No
See AECI comment to Q1 above, with respect to DPs. While the SDT did follow Guideline 5, the
resulting VSLs with respect to communication with these functional entities under normal
operating conditions, hardly merits a medium risk assessment, whereas COM-002 might.
Further, the SDT's VRF and VSL justification for COM 003-1, R2 "FERC VRF G1 Discussion"'
assertion that R2 is consistent with Recommendation of 26...", ignores the same report's
"particularly during..." qualifier. See AECI response to Q1 above.
Group
seattle city light
paul haase
No
Seattle remains confused as to the intent of the draft Standard. R1 appears to require a
protocol for communications that need not be followed in R2 or R3, because only
communications problems leading to a Reliability Directive are to be audited. Seattle does not
know if this position satisfies the FERC Order or the SAR. As proposed, the present Standard
draft could be simplified to a single requirement to "communicate in such a way as to avoid
Reliability Directives." On the other hand, if the intent is to REQUIRE three-way
communications, then present draft R2 and R3 do not do so.
Yes
Individual
Kayleigh Wilkerson
Lincoln Electric System
Agree
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MRO NERC Standards Review Forum (NSRF)
Group
Tennessee Valley Authority
Brandy Spraker
Agree
SERC OC Standards Review Group
Group
MRO NERC Standards Review Forum (NSRF)
Russel Mountjoy
No
The NSRF does not believe that this Standard is nessecary to address recommendation 26 of
the Blackout Report, thus this project should be terminated. The NSRF suggests that COM-0023 be filed with FERC as approved by the NERC BOT, as we believe it adequately addresses the
Blackout recommendation 26 and FERC Order 693. However, if the NERC SC wants to continue
with this development, we provide the following recommendations. For Measure 2 and
Measure 3 , the SDT is requiring each registered entity to ‘prove the negative’ by requiring
each entity to demonstrate that each Operating Instruction issued by its System Operators did
not result in an operating condition that required the issuance of a Reliability Directive. From
the webinar on July 2, the SDT stated that all an entity needs to do is request an attestation
letter from its, RC and neighboring TOPs and BAs. Some entities are reluctant to issue such
blanket attestation letters and some Regional Entities do not accept attestion letters as proof
of compliance. The SDT went on to say the Reliability Directives are rare. The NSRF suggests
changing M2 & M3 to state: M2. When a Reliability Directive is issued, demonstrate that it was
not the result of a Reliability Coordinator, Transmission Operator or Balancing Authority’s
failure to use documented protocols when issuing an Operating Instruction developed for
Requirement 1. M3. When a Reliability Directive is issued, demonstrate that it was not the
result of a failure of the Reliability Coordinator, Transmission Operator, Balancing Authority,
Generator Operator or Distribution Provider to repeat, restate, rephrase, or recapitulate an
Operating Instruction, when required by another Reliability Coordinator, Transmission
Operator or Balancing Authority.
No
Individual
Kenneth A Goldsmith
Alliant Energy
Agree
MRO NSRF
Individual
Andrew Z. Pusztai
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American Transmission Company, LLC
Yes
And ATC supports the communication protocols identified in R1. However, ATC proposes
changing R2 and R3 to make the protocols for issuing and receiving Operational Instructions
consistent with the protocols for issuing and receiving Reliability Directives as defined in R2 and
R3 of proposed Reliability Standard COM-002-3 as follows: R2. When instructed by a Balancing
Authority, Reliability Coordinator, or Transmission Operator to repeat, restate, rephrase, or
recapitulate an Operational Instruction, each Balancing Authority, Transmission Operator,
Generator Operator, or Distribution Provider,that is the recipient of a Operational Instruction,
shall repeat, restate, rephrase, or recapitulate the Operational Instruction. R3. Each Reliability
Coordinator, Transmission Operator, and Balancing Authority that issues a Operational
Instruction shall either: • Confirm that the response from the recipient of the Operational
Instruction (in accordance with Requirement R2) was accurate, or • Reissue the Operational
Instruction to resolve a misunderstanding. Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall implement its communication protocols developed in
Requirement R1 in a manner which identifies and corrects deficiencies in said communication
protocols.
Individual
John Bee
Exelon and its affiliates
Yes
Exelon supports COM-003 Draft 6 but would like to submit the following comments for
consideration by the SDT: Suggest rewording the last sentence of M2 to read: A Balancing
Authority, Reliability Coordinator, and Transmission Operator shall coordinate with another
Reliability Coordinator, Balancing Authority and Transmission Operator to provide this
evidence. Suggest rewording the last sentence of M3 to read: A Balancing Authority, Generator
Operator, Distribution Provider, and Transmission Operator shall coordinate with a Reliability
Coordinator, Balancing Authority and Transmission Operator to provide this evidence.
Individual
Ryan Walter
Tri-State Generation and Transmission Association, Inc.
No
We appreciate the drafting team’s efforts and persistence in the drafting of this new standard.
We believe that this proposal goes beyond what was contemplated in the Blackout
Recommendation as well as FERC Order 693 directives 1 and 3 of paragraph 540. We urge the
drafting team to reconsider the need for a new COM-003 standard, we already have a standard
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
for communication (COM-002), the requirements of the FERC Order can be added to COM-002
with minimal effort reducing the need for yet another standard. Additionally, we feel that a
new term to define “Operating Instruction” is not warranted or required to fulfill either the
FERC directive or Blackout Recommendations.
No
No, we believe that the minimal changes to address the FERC directives and Blackout
Recommendations should be included as a revision to COM-002, not in a new Standard.
Additionally, the requirements to develop and document protocols were not contemplated or
warranted in either the FERC Directives or the Blackout Recommendations. We recommend
that the drafting team reconsider their decision to develop a new COM-003 and investigate
incorporating the requirements into the existing COM-002.
Group
DTE Electric
Kathleen Black
Agree
DTE Electric
Group
Florida Municipal Power Agency
Frank Gaffney
No
Although FMPA voted affirmative, there are still significant improvements that can be made,
and enough significant weaknesses remain to make this a difficult voting decision for FMPA. It
still artificially separates COM-002-3 and Reliability Directives and COM-003-1 and Operating
Instructions when in reality Reliability Directives (RD) are a subset of Operating Instructions.
Contrary to the white paper, there will likely be confusion as to whether an instruction should
or should not be a Reliability Directive, i.e., the only real difference is whether an Emergency
condition exists or not. The only certain distinguishing factor in practice is that the issuer of an
RD needs to identify it as an RD per COM-002-3. There will still be significant Monday morning
quarterbacking after an event as to whether an Operating Instruction should have been issued
as an RD or not, i.e., whether or not the issuer should have recognized an Emergency or not.
The better solution is to treat RD and Operating Instructions the same and only differentiate
with VRFs (as an alalogy, look at difference between R1 and R2 of FAC-003-2) and whether
there should be a difference in treatment regarding “zero tolerance” for RDs and some
tolerance for Operating Instructions. Reliability Directives on “all-calls” are still a problem It still
makes 3-part communication optional for Operating Instructions. Does “optional” meet FERC’s
directive, i.e.” requires tightened communications protocols, especially for communications
during alerts and emergencies” (Order 693, P 540) and ”(w)e also believe an integral
component in tightening the protocols is to establish communication uniformity as much as
practical on a continent-wide basis … This is important because the Bulk- Power System is so
tightly interconnected that system impacts often cross several operating entities’ areas.”
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(Order 693, P 532)? At minimum, the standard should require 3-part communication for alerts
in addition to Emergencies. R2 and R3 try to limit potential violations for failure to follow the
subject of the requirement (i.e., R2: “Each (responsible entity) shall implement its
communication protocols developed in Requirement R1”) would not actually result in a
violation unless an Emergency occurred as described in the predicate, (e.g., R2: “so that the
failure to use the protocols by the issuer of an Operating Instruction does not result in an
operating condition that requires the issuance of a Reliability Directive ….”). Remember,
Reliability Directives are only given in a state of Emergency (Reliability Directive: “A
communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing
Authority where action by the recipient is necessary to address an Emergency or Adverse
Reliability Impact”). Does this serve reliability well, must we get to a state of Emergency to
have a violation to the standard – and doesn’t that just highlight potential double jeopardy and
overlap between COM-002-3 and COM-003-1, e.g., if an Operating Instruction is issued in COM003-1 that is not followed that results in the same instruction being given as a Reliability
Directive? This of course begs the question of whether or not the System Operator should have
issued an RD in the first place. Does this address FERC’s requirement to tighten communication
protocols, including emergencies and alerts? In addition, we don’t think the actual language
limits the potential violations to those that meet the predicate as intended (i.e.., we do not
think the predicate – “so that …” – modifies the subject so much as it describes and repeats the
purpose of the standard. In other words, to us the requirements can be interpreted that the
subject must always be met “so that” the purpose/predicate is accomplished. Hence, we do
not think that it solves the zero tolerance issue without stating the requirement in a smilar
manner as the Measure is stated). Note that the Measure confirms that an Emergency is
intended for potential violation: “Each (responsible entity) shall provide evidence that it did not
issue an Operating Instruction that resulted in an operating condition that required the
issuance of a Reliability Directive …”. We still strongly believe that the better solution is to
cause COM-003-1 to address Reliability Directives and retire COM-002-3. After all, when issuing
a Reliability Directive, don’t we want the issuer to speak English, use a consistent clock time
with their neighbors, etc., for which COM-002-3 is silent but COM-003-1 specifies? We still
have not heard a good reason why this is not being done. We also think that it is necessary to
require 3-part communication for “alerts” to meet FERC’s directives. Don’t we want 3-part
communication to be followed during alerts?
Individual
John Brockhan
CenterPoint Energy Houston Electric LLC.
No
No
As stated in its Draft 5 comments, CenterPoint Energy firmly believes there should be no High
or Severe VSL for simply failing to document a process, protocol, or procedure. It is
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counterintuitive to allow for a scenario where an entity's System Operators are communicating
effectively and correctly and yet that has the entity penalized with the highest severity level for
not having the appropriate documentation. Additionally, CenterPoint Energy disagrees with the
assignment of Severe VSL for R3, when a comparable violation in COM-002-3 R2 is also a
Severe VSL. The VSL for failing to repeat an O.I. and for failing to repeat an R.D. should not be
the same. CenterPoint Energy also has concerns with the following two aspects of Draft 6: 1.
CenterPoint Energy disagrees with R1’s stipulation that the RC must approve the BA’s and the
TOP’s communication protocols, especially given the SDT’s assertion that a possible outcome is
for the RC to unilaterally develop the protocols and impose them on the BA and the TOP.
Instead, CenterPoint Energy recommends that R1 be modified to state “Each Reliability
Coordinator shall develop, and each Balancing Authority and Transmission Operator shall
develop collaboratively with the Reliability Coordinator, documented communication
protocols...” 2. CenterPoint Energy appreciates the efforts of the SDT to revamp COM-003-1 so
that its Operating Instruction is compartmentalized from COM-002-3’s Reliability Directive,
effectively reducing the industry’s compliance burden. However, the revision does not ease a
System Operator’s practical operational burden of having to distinguish in real-time whether a
command that is about to be issued is an O.I. or an R.D. Rather than focusing solely on
maintaining the integrity of the BES, an Operator may now be distracted by what to label that
command and the consequences of assigning the incorrect label. The industry and NERC have
been working on the proposed COM-003 standard for nearly four years, ever since the posting
of draft 1 in 2009. The proposed standard is now at draft 6, and it is becoming apparent that
the industry is struggling to achieve consensus on the specifications for COM-003.
Furthermore, it’s been more than nine years since the release of the Blackout Report and six
years since Order 693. In that interim, the industry has improved and evolved in numerous
areas, including operator communication effectiveness. Most of all, the industry and NERC
have already approved COM-002-3 and its associated definition of Reliability Directive, which,
once enforceable, will undoubtedly further tighten communication. Perhaps it is time then for
NERC and the industry to start a dialogue with FERC to reevaluate the purpose and the need
for COM-003 and to request from FERC refreshed, clear guidance on this subject.
Individual
Stanley T Rzad
Keys Energy Services
Agree
Florida Municipal Power Agency
Individual
Scott Berry
Indiana Municipal Power Agency
There is no place to submit “other” comments, so Indiana Municipal Power Agency (IMPA) is
submitting comments under this question. For requirement R3, how will entities (BA, TOP,
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GOP, and DP) who are responsible for the repeat back of the Operating Instruction know the
“when required by the issuer” part of the requirement is in place or being required by the
issuer? Will the issuer be stating their request is an Operating Instruction or be asking for the
receiver to please repeat the Operating Instruction back to them? Maybe the issuer of the
Operating Instruction can make their communication protocol available to the receiving
entities in Requirement R3 to allow them to be familiar with their protocols which may help
with know when a repeat back is required by the issuer.
Individual
Daniel Mason
HHWP
No
The draft standard does not clearly articulate the purpose nor an appropriate results based
approach to addressing FERC objective to ensure clear communications between operators and
users of the BES.
Group
Bureau of Reclamation
Erika Doot
No
The Bureau of Reclamation believes that the proposed changes to COM-003-1 do not
adequately address Order 693 directives or 2003 Blackout Report Recommendation No. 26.
First, Order 693 Paragraph 512 directed the ERO to modify COM-002-2 to address “both
normal and emergency operations,” and because each Transmission Operator (TOP), Balancing
Authority (BA), and Reliability Coordinator (RC) is able to design their own Operating
Instructions under R1 of the proposed revision, Reclamation is unable to ascertain whether
Operating Instructions will apply to normal operations. Second, Paragraph 532 of Order 693
specified that “an integral component in tightening [communication] protocols is to establish
communication uniformity as much as practical on a continent-wide basis.” As written, R1
would allow each BA and TOP to develop their own Operating Instructions, which does not
promote the continent-wide uniformity called for by FERC in Order 693. Third, the 2003
Blackout Report Recommendation No. 26 specified that NERC should improve internal and
external communications during “alerts, emergencies, or other critical situations.” Under the
proposed definition of Operating Instruction and R1, it seems that BAs and TOPs have
discretion to determine under what conditions Operating Instructions are issued in their
operating area, so it is not possible for Reclamation to determine whether Recommendation
No. 26 is adequately addressed by the standard. In addition, Reclamation would like to
emphasize that the revised definition of Operating Instruction is not clear enough to distinguish
between real-time operations coordination (“discussion of general information and potential
options”?), Operating Instructions (applicable in circumstances as defined by various TOPs and
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BAs), and Reliability Directives (real-time emergency conditions addressed by COM-002). COM003 does not clearly define the timeframe for Operating Instructions, and should make clear
what the line of demarcation is between “real-time emergency” communications governed by
COM-002 and other alert conditions governed by COM-003. If each BA and TOP is allowed to
define separate circumstances under which “Operating Instructions” apply, Reclamation
believes that COM-003 will not achieve continent-wide standardization of communications
protocol that FERC recommended in Order 693. Also, Reclamation does not believe that
violations of R3 should be tied to a failure to repeat an Operating Instruction only if it “result[s]
in an operating condition that required the issuance of a Reliability Directive.” To reinforce the
importance of repeat-back communications, repeat-back communications should be required
under all circumstances like in the aviation industry. Further, Reclamation believes that
Generator Operators (GOPs) and Distribution Providers should provide concurrence or have a
role in Operating Instructions development required under R1 to avoid potential
miscommunications (e.g., in nomenclature for Transmission interface elements). Lastly,
Reclamation believes that COM-002 should include provisions parallel to IRO-001 and TOP-001
that allow Generator Operators to inform the TOP, BA, or RC that they are unable to comply
with an Operating Instruction because the actions requested “would violate safety, equipment,
regulatory or statutory requirements” so that the TOP, BA, or RC “can implement alternate
remedial actions,” If the intent of the standard is to avoid Operating Instructions escalating to
Reliability Directives, GOPs should be able to inform the TOP, BA or RC of their “inability to
perform” the Operating Instruction like they are able to inform the TOP, BA, or RC of the
inability to perform a Reliability Directive. The Bureau is proactive about assisting with
transmission system events, but at certain times of year dramatic changes in reservoir levels
could endanger the public in reservoirs or on rivers, could cause unlawful total dissolved gas
(TDG) levels, or violate Endangered Species Act requirements. Other safety and equipment
circumstances could also lead to an inability to follow an Operating Instruction. Reclamation
suggests that the previous draft of the standard was clearer and that perhaps the drafting team
could revisit it.
No
Reclamation does not believe that R3 should only be accompanied by a Severe Violation
Severity Level (VSL), especially because BA and TOP “Operating Instruction” protocols could
vary significantly among BAs and TOPS. Reclamation reiterates that if the intent of the standard
is to avoid Operating Instructions escalating to Reliability Directives, GOPs should be able to
inform the TOP, BA or RC of their “inability to perform” an Operating Instruction because it
“would violate safety, equipment, regulatory, or statutory requirements” so that the Operating
Instruction does not become a Reliability Directive. Reclamation suggests that the drafting
team develop thresholds for failure to repeat that would amount to low, medium, high or
severe violations.
Individual
Daniel Duff
Liberty Electric Power
Agree
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Essential Power
Group
Hydro One Networks Inc.
Sasa Maljukan
No
We support this proposed draft (version 6) of the standard on the basis of it being a
compromise between what the industry would like to see and what the US regulator is
mandating. That said, we still have concerns with the proposed standard (comment below). As
proposed, the standard may be ambiguous and difficult to measure. For example, Requirement
2, states that the entity shall implement its communication protocols in such a way that failure
to use them would not result in an operating condition that requires the issuance of a
Reliability Directive. How does the SDT envision enforcing such requirement? It is difficult to
determine if the failure to follow the protocols when addressing Operating Instructions is truly
the reason for a new operating condition that requires issuance of a Reliability Directive or is
the result of the original instruction being insufficient or in error. Also, the corresponding
measure M2 puts the burden on the entities to provide evidence that it did not have any such
cases. We see this as an ever encompassing and burdensome approach for collecting and
presenting evidence. The issue of three-part communications has always been very central to
the development of this standard. So far the SDT has not been able to produce a draft standard
to achieve industry consensus on this issue. While at least partially addressing FERC orders, we
believe that the approach the SDT chose, makes the day-to-day duties inside the control room
more complicated, cumbersome and hard to implement. If the current version 6 does not
achieve the required industry approval rate, we still stand by our prior comments and
consideration should be given to modify the COM-002 standard to incorporate into it the
matters that COM-003 has been trying to address, all in one communications standard.
Yes
Group
FirstEnergy
Larry Raczkowski
Yes
(1) FirstEnergy (FE) believes that Requirement 2 is confusing as worded, and as such, we
propose the following for clarity: [R2. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues an Operating Instruction shall follow its documented
communication protocols developed in Requirement R1 such that it does not result in an
operating condition that requires the issuance of a Reliability Directive by the original issuer of
the Operating Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator.] (2) FE believes that clarity will also be attained with clear and precise
RSAWs. The latest RSAW that has been posted is applicable to Draft 4 and provides no
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guidance to stakeholders the intent of the requirements from Draft 6. FE appreciates the FAQs
from July 2, 2013 Industry Webinar the SDT has provided and would recommend the SDT
incorporate into the RSAW for Requirement 2 the intent of the response to Question 2
regarding when an evaluation to an Operating Instruction shall be used as evidence.
Yes
Individual
John Seelke
Public Service Enterprise Group
Agree
Essential Power, LLC
Individual
Karen Webb
City of Tallahassee - Electric Utility
No
TAL has voted NO because the standard is still not “clear and unambiguous”. TAL is concerned
at the degree to which the proposed standard complicates compliance for Operating
Instructions without benefit to reliability. The FERC Directive was to tighten communications
during Emergencies and Alerts. Operating Instructions deserve separate consideration under
the standards. Requiring an entity’s procedure to be subject to the Reliability Coordinator’s
approval creates an undue burden on the RC with no measurable improvement in reliability.
While this addressed a commenter’s concerns over uniformity within RC control areas, it would
be simpler and more efficient to have the RC create a procedure and provide it to all the
entities in the footprint. Measure 3 should be changed to “when required by the issuer” in
order to provide clarity and consistency with R3.
Group
DTE Electric
Kathleen Black
Agree
Individual
Scott Langston
City of Tallahassee
No
TAL has voted NO because the standard is still not “clear and unambiguous”. TAL is concerned
at the degree to which the proposed standard complicates compliance for Operating
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Instructions without benefit to reliability. The FERC Directive was to tighten communications
during Emergencies and Alerts. Operating Instructions deserve separate consideration under
the standards. Requiring an entity’s procedure to be subject to the Reliability Coordinator’s
approval creates an undue burden on the RC with no measurable improvement in reliability.
While this addressed a commenter’s concerns over uniformity within RC control areas, it would
be simpler and more efficient to have the RC create a procedure and provide it to all the
entities in the footprint. Measure 3 should be changed to “when required by the issuer” in
order to provide clarity and consistency with R3.
Individual
Philip Tice
Deseret Power Electric Cooperative
No
As written, R1 would allow each BA and TOP to develop their own Operating Instructions,
which does not promote the continent-wide uniformity called for by FERC in Order 693. The
revised definition of Operating Instruction is not clear enough to distinguish between real-time
operations coordination ("discussion of general information and potential options"?),
Operating Instructions (applicable in circumstances as defined by various TOPs and BAs), and
Reliability Directives (real-time emergency conditions addressed by COM-002). COM-003 does
not clearly define the time frame for Operating Instructions, and should make clear what the
line of demarcation is between "real-time emergency" communications governed by COM-002
and other alert conditions governed by COM-003. If each BA and TOP is allowed to define
separate circumstances under which "Operating Instructions" apply, Reclamation believes that
COM-003 will not achieve continent-wide standardization of communications protocol that
FERC recommended in Order 693. COM-003 should include provisions parallel to IRO-001 and
TOP-001 that allow Generator Operators to inform the TOP, BA, or RC that they are unable to
comply with an Operating Instruction because the actions requested "would violate safety,
equipment, regulatory or statutory requirements" so that the TOP, BA, or RC "can implement
alternate remedial actions," If the intent of the standard is to avoid Operating Instructions
escalating to Reliability Directives, GOPs should be able to inform the TOP, BA or RC of their
"inability to perform" the Operating Instruction like they are able to inform the TOP, BA, or RC
of the inability to perform a Reliability Directive.
No
R3 should only be accompanied by a Severe Violation Severity Level (VSL), especially because
BA and TOP "Operating Instruction" protocols could vary significantly among BAs and TOPS. If
the intent of the standard is to avoid Operating Instructions escalating to Reliability Directives,
GOPs should be able to inform the TOP, BA or RC of their "inability to perform" an Operating
Instruction because it "would violate safety, equipment, regulatory, or statutory requirements"
so that the Operating Instruction does not become a Reliability Directive. The drafting team
should develop thresholds for failure to repeat that would amount to low, medium, high or
severe violations.
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Individual
Michael Lowman
Duke Energy
Yes
Duke Energy agrees in part that draft 6 of the proposed COM-003-1 does address the
recommendations of the 2003 Blackout Report, FERC Order 693, and the COM-003-1 SAR.
However, Duke Energy believes that this draft has gone beyond the expectations outlined in
the documents mentioned above. Measure 3 should be changed to “when required by the
issuer” in order to provide clarity and consistency with R3. Requirement 2 language leads to
uncertainty (risk) as to when an Operating Instruction will become a Reliability Directive. This
could negatively impact BES reliability in creating reluctance, by the entity, to issue a Reliability
Directive and furthermore places Operators in the position of acting in compliance with the
Requirement at the time only to be deemed non-compliant later when circumstances change.
This is an untenable position and leads to less reliability. Such a finding of non-compliance
cannot be mitigated leaving the Responsible Entity without means to “control” performance.
We are also concerned with the language in Requirement 2 “so that”. This vague language can
be interpreted as to intent which is unmeasurable and therefore adds to the uncertainty (risk).
In addition, Duke Energy believes that a statement needs to be added in R1 that includes
providing or distributing those communication protocols developed by a BA or TOP to their
associated DPs and GOPs. This would address a potential gap of DPs and GOPs not aware of the
communication expectations when communicating with BAs and TOPs when given an
Operating Instruction. Lastly, while Duke Energy applauds the efforts made by the SDT, we are
not convinced that a standard can be developed that will garner the requisite support from
industry stakeholders. Duke Energy recommends the SDT to delineate other options, such as a
Guideline document or White Paper, before addressing the recommendations in the 2003
Blackout Report.
No
Duke Energy believes that the VSL(s) need to use the same language as in the standard
requirements. In order to stay consistent with the VSL(s), we believe that “Functional Entities”
should be replaced with “Responsible Entities” in the Applicability Section of this standard.
Individual
Wryan Feil
Northeast Utilities
Yes
No
Requirements R2 and R3 need to be written to clarify requirements. The current draft could
result in differing interpretations.
Individual
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
John Hagen
Pacific Gas and Electric Company
No
Pacific Gas and Electric believes that the proposed changes to COM-003-1 do not adequately
address Order 693 directives or 2003 Blackout Report Recommendation No. 26. First, Order
693 Paragraph 512 directed the ERO to modify COM-002-2 to address "both normal and
emergency operations," and because each Transmission Operator (TOP), Balancing Authority
(BA), and Reliability Coordinator (RC) is able to design their own Operating Instructions under
R1 of the proposed revision, PG&E is unable to ascertain whether Operating Instructions will
apply to normal operations. Second, Paragraph 532 of Order 693 specified that "an integral
component in tightening [communication] protocols is to establish communication uniformity
as much as practical on a continent-wide basis." As written, R1 would allow each BA and TOP to
develop their own Operating Instructions, which does not promote the continent-wide
uniformity called for by FERC in Order 693. Third, the 2003 Blackout Report Recommendation
No. 26 specified that NERC should improve internal and external communications during
"alerts, emergencies, or other critical situations." Under the proposed definition of Operating
Instruction and R1, it seems that BAs and TOPs have discretion to determine under what
conditions Operating Instructions are issued in their operating area, so it is not possible to
determine whether Recommendation No. 26 is adequately addressed by the standard. In
addition, PG&E would like to emphasize that the revised definition of Operating Instruction is
not clear enough to distinguish between real-time operations coordination ("discussion of
general information and potential options"?), Operating Instructions (applicable in
circumstances as defined by various TOPs and BAs), and Reliability Directives (real-time
emergency conditions addressed by COM-002). COM-003 does not clearly define the
timeframe for Operating Instructions, and should make clear what the line of demarcation is
between "real-time emergency" communications governed by COM-002 and other alert
conditions governed by COM-003. If each BA and TOP is allowed to define separate
circumstances under which "Operating Instructions" apply, PG&E believes that COM-003 will
not achieve continent-wide standardization of communications protocol that FERC
recommended in Order 693. Also, PG&E does not believe that violations of R3 should be tied to
a failure to repeat an Operating Instruction only if it "result[s] in an operating condition that
required the issuance of a Reliability Directive." To reinforce the importance of repeat-back
communications, repeat-back communications should be required under all circumstances like
in the aviation industry. The use of three-way communication has been proven as an effective
error prevention tool in the military, aviation, and in the nuclear power industry. It is time that
the same discipline and rigor be implemented in the electric industry. The current version of
this Standard is moving away from reliability and will be difficult for compliance and
enforcement. Further, Generator Operators (GOPs) and Distribution Providers should provide
concurrence or have a role in Operating Instructions development required under R1 to avoid
potential miscommunications (e.g., in nomenclature for Transmission interface elements).
PG&E suggests that the previous draft of the standard was clearer and that perhaps the
drafting team could revisit it.
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No
PG&E does not believe that R3 should only be accompanied by a Severe Violation Severity
Level (VSL), especially because BA and TOP "Operating Instruction" protocols could vary
significantly among BAs and TOPS. Reclamation reiterates that if the intent of the standard is to
avoid Operating Instructions escalating to Reliability Directives, GOPs should be able to inform
the TOP, BA or RC of their "inability to perform" an Operating Instruction because it "would
violate safety, equipment, regulatory, or statutory requirements" so that the Operating
Instruction does not become a Reliability Directive.
Group
Puget Sound Energy
Denise Lietz
No
Puget Sound Energy appreciates the drafting team's work to simplify the requirements of this
standard and believes that the standard's language is moving in the right direction. However,
Puget Sound Energy cannot vote to approve this standard for the following reasons.
Requirement R1, by requiring the Reliability Coordinator (RC) to approve each communication
protocol, is unnecessarily burdensome on the RC and all the entities that must receive that
approval. This type of approval makes sense for restoration plans (EOP-005-2) because of the
required coordination in an emergency situation, but not for the communications protocols
that apply in non-emergency situations. There is certainly a benefit to uniformity of
communication protocols within an interconnection; however, uniformity should be achieved
by requiring the RC to specify its requirements for communication protocols and then requiring
Balancing Authorities and Transmission Operators to comply with that specification (similar to
the approach of IRO-010). There should be an additional requirement for Reliability
Coordinators, Balancing Authorities and Transmission Operators to provide information about
the communication protocol requirements that apply to other entities within their area to
those entities. It is only appropriate to hold an entity responsible for complying with
communication protocol requirements when it has advance notice of what those requirements
will be. The language connecting miscommunications to Reliability Directives in requirements
R2 and R3, along with the associated VSLs, should address degrees of compliance. While the
approach does narrow the scope of possible violations, it seems that the language could easily
lead to a debate on whether a miscommunication "results in" an impact. Typically, events have
many elements that contribute to their occurrence and in some cases a miscommunication
might only indirectly or tangentially relate to the event. Given the assigned VSL of severe for all
violations of these requirements, a miscommunication with an indirect relationship to a
subsequent Reliability Directive will likely have the same compliance impact as one that has a
more direct and substantial relationship. Thank you for your consideration of these comments.
Individual
Clay Young
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
SCE&G
No
FERC Order 693 states "We also believe an integral component in tightening the protocols is to
establish communication uniformity as much as practical on a continent-wide basis." R1 allows
each BA, RC, and TOP to develop their own, separate communication protocols. Criteria 1.1
thru 1.5 are open-ended. As a result, each BA and TOP will have different protocols that they
submit to the RC for approval. The standard does not give RCs guidance on how to evaluate
submitted protocols for consistency/uniformity before approval. Without such guidance, it is
unclear how consistency and uniformity will be promoted among the various BA/TOP
documented protocols. Furthermore, if such criteria were added, the standard would still only
promote uniformity within an RC footprint. It would not promote uniformity across the
continent, as directed within Order 693, or even the regions. It seems the only way for the SDT
to fully address the FERC directive, is for the SDT to specify the specific protocols they want BAs
TOPs and RCs to use. Many entities are opposed to this approach because they are concerned
about monitoring and maintaining compliance with such a standard. These concerns could be
alleviated if the SDT writes the standard in a way such that a violation only occurs if a BES
Emergency results from failure to use the specified protocols.
Individual
Catherine Wesley
PJM Interconnection, L.L.C.
No
PJM does not support Draft 6 of this standard. There is a concern specific to the potential,
unintended compliance responsibility in R2 because of the way the requirement is written, as
well as the associated M2. Applicable entities will be required to prove a negative which may
result in unnecessary Root Cause Analysis (RCA) efforts that are not required and are solely
performed to satisfy an administrative, compliance item, yet adds no discernible reliability
value.
Group
Santee Cooper
S. Tom Abrams
No
Santee Cooper believes the issuing authority should specifically identify a communication as an
Operating Instruction, thereby triggering the need for three-part communications, and the
receiver to use three part.
Yes
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Group
Cooper Compliance Corp
Mary Jo Cooper
No
While we agree that the proposed Standard addresses the FERC Order 693, we do not feel that
R3 is well drafted and assumes that the distribution provider or generator operator would be
able to determine if the Operating Instruction would “result in an operating condition that
requires the issuance of a Reliability Directive by the original issuer of the Operating Instruction
or by another Balancing Authority, Reliability Coordinator, or Transmission Operator.” In
addition, the dictionary term for restate, rephrase, or recapitulate all have the same meaning
and it seems odd that an auditor would be able to distinguish any difference. We suggest the
drafting team simplify R3 as follows: “Each Balancing Authority, Transmission Operator,
Generator Operator and Distribution Provider shall repeat or restate an Operating Instruction
when required by the issuer of an Operating Instruction.”
Yes
Individual
Brenda Hampton
Luminant Energy Company LLC
Yes
While draft 6 of COM-003-1 is largely acceptable, the wording of R3 may create confusion
about what is required. R3 reads, in part: R3. Each Balancing Authority, Transmission Operator,
Generator Operator and Distribution Provider shall repeat, restate, rephrase, or recapitulate an
Operating Instruction when required by the issuer of an Operating Instruction in its
communication protocols developed in Requirement R1 so … This language suggests that the
receiving entity must know what is in the issuer's communication protocol and repeat, restate,
rephrase or recapitulate the Operating Instruction without any prompts from the issuer. If that
is the case, then there needs to be a requirement that the developer of a communication
protocol must provide that communication protocol to all relevant parties prior to
implementation. However, after reading the Technical Justification, that doesn't appear to be
the intent. Rather the intent is that the issuer will request the receiver to repeat the Operating
Instruction back during the phone call. To make that clear, Luminant suggests the following
language change to R3: R3. Each Balancing Authority, Transmission Operator, Generator
Operator and Distribution Provider shall repeat, restate, rephrase, or recapitulate an Operating
Instruction when requested by the issuer of an Operating Instruction in accordance with the
communication protocols developed in Requirement R1 so … With this change, we would be in
support of this draft standard.
Yes
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Group
IRC Standards Review Committee
Gregory Campoli
The SRC has reviewed the current COM-003 posting and offer the following comments that
augments previously provided comments on the standard. • Requirement R1 now requires
each BA and TOP’s to have protocols approved by the RC. One question certain SRC Members
have is whether the RC is being asked to “assess” whether the BA/TOP’s protocols are
“compliant” with the Standard. Another question is whether the RC is being asked to
“approve” the TOP communication protocols with other Registered Entities (e.g., TOs).
Depending on the answers to these questions, the SRC proposes that the “approval”
requirement could be revised to a “coordination” obligation. • Requirement R2 now has add a
trigger for non compliance for not implementing the communications protocol if following an
operating instruction, a reliability directive is issued to correct the problem caused by a failure
to implement its communication protocol. We ask NERC to comment on whether this will
produce an obligation for compliance authorities to begin a compliance investigation on every
Reliability Directive to assess whether communication protocols were followed. Reliability
Directives are an important means of communications to address all emergencies. Poor
communications have yet to be clearly identified as a root cause. The SRC would also like NERC
and the SDT to consider comments provided by NERC at the recent FERC Technical Conference
stating, ‘complementary approaches should also be examined where the risks to reliability can
effectively be mitigated through other means, such as through guidelines, data collection or
other technical approaches. ‘ NERC should continue to consider the effectiveness of the NERC
Operating Committee communications protocol. Note, ERCOT and PJM, members of the IRC
Standards Review Committee did not join these joint comments and have submitted individual
comments.
Individual
Brett Holland
Kansas City Power & Light
No
We feel that this standard is not necessary if the COM-002 standard is properly followed. Also,
R3 could cause an over burdensome amount of effort to prove compliance with COM-003.
No
Group
SPP Standards Review Group
Robert Rhodes
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Yes
Although there still remain some concerns that the intent of Recommendation 26 was strictly
for emergency situations which are covered by COM-002-3.
Yes
There were a couple of typos in the VSLs. R1 – Insert a space between ‘R1’ and ‘in’ in the Lower
VSL. R3 – Insert ‘to’ between ‘failed’ and ‘repeat’ in the Severe VSL.
Individual
Kaleb Brimhall
Colorado Springs Utilities
No
Colorado Springs Utilities appreciates the commitment and long, hard work of the Drafting
Team as well as the opportunity to comment on this draft. R.1: The clause, “subject to the
Reliability Coordinator’s approval” is unclear in its intent. If the intent is that the RC must
review and approve all Communication Protocols, there should be discrete requirements (a la
EOP-005-2 & EOP-006-2) in the Standard. If that is not the explicit intent, what is? If the intent
is to make it optional or suggested for the RC to review and approve Protocols, then that is not
a Standard – it is a suggestion. Please state whatever is the intent clearly in the requirement.
CSU proposes the clause be removed entirely. R1.3: Should be removed. This requirement is
redundant to TOP-002-2.1b, R18; “Neighboring Balancing Authorities, Transmission Operators,
Generator Operators, Transmission Service Providers and Load Serving Entities shall use
uniform line identifiers when referring to transmission facilities of an interconnected network.”
R2 & R3: CSU prefers the language along the lines of the previous draft (R2 & R4). The clause,
“failure to use the protocols by the issuer of an (or R3- failure to repeat, restate, rephrase, or
recapitulate the) Operating Instruction does not result in an operating condition that requires
the issuance of a Reliability Directive” is unworkable, probably unauditable, and definitely an
evidentiary nightmare. If one entity issues a Reliability Directive, what chain of evidence from
how many other entities is required to prove that no other entity failed to use its
communications protocols in such a way that failure resulted in the operating condition
requiring the first entity to issue a Reliability Directive? Or, to view it from the other direction:
if CSU is being audited on compliance with COM-003-1, how shall it prove that it did not have a
failure to properly implement any communication protocol which then contributed to
operating conditions which may have required any other reliability entity in the western
interconnect to have to issue a Reliability Directive? How does one establish the causal
relationship, or lack thereof? In lieu of a return to the previous draft’s language, CSU
recommends adding another sub-part to R1, “R1.6 A method to assess System Operator’s
communication practices and implement improvements as necessary to meet the expectations
in its documented communications protocols developed for this Requirement.” Then R2 could
be written, “Each … shall implement its communication protocols developed in R1.” R3 could
state, “Each … shall repeat, restate, rephrase, or recapitulate an Operating Instruction, when
required by the issuer in its communication protocols developed in requirement R1, to the
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satisfaction of the issuing System Operator.” M2 & M3: Reliability Standards need to get away
from asking for negative evidence. The Standard is probably written incorrectly if negative
evidence is required for compliance. Even sticking with the negative theme; “Each … shall
provide evidence that it did not fail to use its documented communications protocols
developed for Requirement R1 in a way that resulted in an operating condition that required
to issue a Reliability Directive,” comes closer to supporting the Requirement as
drafted. Thank you! Sincerely, Colorado Springs Utilities
Yes
No Comments
“…current comments and voting on behalf of DTE Electric Co. The vote is still negative and both
Kent Kujala and Daniel Herring agree with this vote and comments.”
Comments - Eizans:
In response to request for comment number 1 and a literal reading of the question and
associated documents:
The August 2003 Blackout Report Recommendation number 26 speaks to “tightening
communication protocols, especially for communications during alerts and emengencies.” In
the context of the entire document, it highlights the lack of sharing of critical information
during the blackout event. It does not really address “Operating Instructions” or mention a
failure to correctly understand, follow or execute a direction/instruction. The focus is on what
information would have assisted the operators in dealing with the event, not mistakes in
execution of Operating Instructions. Page 109 of the report summarizes “Effecitiveness of
Communications” and states “Under normal conditions, parties with reliability responsibility
need to communicate important and prioritized information to each other in a timely way, to
help preserve the integrity of the grid. This is especially important in emergencies. During
emergencies, operators should be relieved of duties unrelated to preserving the grid. A
common factor in several of the events described above was that information about outages
occurring in one system was not provided to neighboring systems.” Information exchange
seems to be the focus, not communication of Operating Instruction.
FERC Order 693 (which refers back to the Blackout Report) also requires tightening
communication protocols “especially for communications during alerts and emergencies” to
“establish communication uniformity” and “eliminate ambiguities.” The proposed standard is
focused on Operating Instructions and lacks requirements regarding consistency in information
sharing.
Regarding COM-003-1 SAR, the SAR states its’s scope is “to establish essential elements of
communications protocols and communications paths such that operators and users of the
North American bulk electric system will efficiently convey information and ensure mutual
understanding. “ It also states that the purpose of the standard is “to ensure that effective
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communication is practiced and delivered in clear language via pre-established communications
paths among pre-identified operating entities.” Version 6 of COM-003-1 does not address
Applicablity number 1 “relay critical reliability-related information in a timely and effective
manner.” It also does not address Applicablity number 3: “requirements for entities that
experience abnormal conditions to use pre-defined terms such as proposed in the “Alert Level
Guideline” (attached) to communicate the operating condition to other entities that are in a
position to either assist in resolving the operating situation condition or to entities that are
impacted by the operating condition.” It only focuses on Operating Instructions, not
communication of the status/condition of the electrical system. The SAR Scope mentions
“consistency across regions,” yet the standard does not address RC to RC communications
within/across regions.
The purpose of COM-003-1 revision 1 was closer to addressing the above than the purpose in
revision 6. It seems the standard has strayed from the intent and although there may be value
in having a standard that addresses protocols for issuance of Operating Instructions, this
version does not address the concerns laid out in the documents listed above. Items such as
sharing of tie line trips, major generation loss trips, high risk situations/evolutions (possibly
tripping critical items), loss of EMS capabilities/control center functionality, declared
alerts/emergencies and other pertinent information would be the types of information would
be standardized and addressed in a standard in order to meet the objectives of the SAR and
FERC rather than Operating Instructions.
General comments regarding revision 6 of the standard “as written,” the purpose of which is
different from the question asked in the comment form:
As this standard seems to focus on verbal communication, written communications should not
be included this standard. It is not clear what is intended to be in scope for “written” Operating
Instruction. The standard should not introduce vague terminology subject to different
interpretations. If there is a need (or reliability reason) to address written Operating
Instructions, they should be included in a separate standard. Focus on 3-way communication
and use of alpha-numeric clarifiers in COM-003-1 do not readily fit written communications.
Not sure how R2 and R3 would be applied to written Operating Instruction.
Since COM-003-1 has emphasized the difference between Operating Instruction and Reliability
Directive as exclusive and distinct, it appears that COM-003-1 communication protocols are
more strict for Operating Instruction (regarding use of time zone, alpha-numeric clarifiers, etc.)
than COM-002-3 requiring only 3-way communication (no time zone, etc.). If COM-003-1
protocols (other than 3-way communication) are not followed for Reliability Directives, there is
no standard violation of either COM-002-3 or COM-003-1. This seems to leave a reliability gap.
Should NOT require RC approval of an entity’s communication protocol. By requiring RC
approval of each responsible entity’s communication protocol document,it sets up the
possibility of disagreements. Entities should be responsible to develop protocols that are
compatible with RC protocols, but that may differ on the “downstream” side (i.e. with entity’s
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field personel). This may be required if RC demands use of Standard Time and BA must
communicate with field personel in Daylight Time. RC should not be able to dictate these types
of issues. No defined resolution process in cases of disagreement. If RC is final word, then
standard should require RC to develop protocol with input from other entities and all entities
should use RC protocol (no requirement for individual protocols). Who would “approve” RC to
RC communication protocols?
R2 and R3 documentation is onerous. It really requires a coordinated investigation into every
Reliability Directive that is issued to verify it was NOT caused by a communication protocol
violation somewhere in the chain (as it may not be between just two responsible
entities/protocol documents).
How wide a net needs to be cast in gathering attestations of “No Reliability Directives issued?”
How deep in connected systems or entities? An entity may issue a Reliability Directive to a
different entity than violated the communication protocol if that problem surfaces in their
system.
Comments - Stefaniak:
R1.1, R 1.2, R1.3: It is not clear what is intended to be in scope for “written” Operating
Instruction. The standard should not introduce vague terminology subject to different
interpretations.
R2, R3: Failing to use communication protocols would not directly lead to an operating
condition that requires the issuance of a Reliability Directive. It is more likely that failing to use
communication protocols could cause an Operating Instruction to be incorrectly executed. Such
an error could lead to an operating condition that requires the issuance of a Reliability
Directive. Consider changing R2 and R3 as follows:
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement its communication protocols developed in Requirement R1 so that the failure to use
the protocols by the issuer of an Operating Instruction does not result in an Operating
Instruction to be incorrectly executed thus leading to an operating condition that requires the
issuance of a Reliability Directive by the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or Transmission Operator. [Violation Risk
Factor: Medium][Time Horizon: Real Time Operations ]
R3. Each Balancing Authority, Transmission Operator, Generator Operator and Distribution
Provider shall repeat, restate, rephrase, or recapitulate an Operating Instruction when required
by the issuer of an Operating Instruction in its communication protocols developed in
Requirement R1 so that the failure to repeat, restate, rephrase, or recapitulate the Operating
Instruction does not result in an Operating Instruction to be incorrectly executed thus leading
to an operating condition that requires the issuance of a Reliability Directive by the original
issuer of the Operating Instruction or by another Balancing Authority, Reliability Coordinator, or
Transmission Operator. [Violation Risk Factor: Medium][Time Horizon: Real Time Operations ]
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Consideration of Comments
Project 2007-02 Operating Personnel Communications
The Project 2007-02 Drafting Team thanks all commenters who submitted comments on COM-003-1
standard for System Protection Coordination. The standard was posted for a 30-day formal comment
period from June 20, 2013 through July 19, 2013. Stakeholders were asked to provide feedback on the
standard and associated documents through a special electronic comment form. There were 80 responses
from approximately 50 different organizations or individuals.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.
Summary Consideration of all Comments Received
1. The OPCPSDT has proposed significant changes to the COM-003-1, draft 6. Do you agree that
COM-003-1, draft 6 addresses the August 2003 Blackout Report Recommendation number 26,
FERC Order 693 and the COM-003-1 SAR? If not, please explain in the comment area of the last
question.
Since the last posting, the Board of Trustees - Standards Oversight and Technology Committee (SOTC)
issued a recommendation to the NERC Board of Trustees for consideration at its November 2013 meeting.
The recommendation suggests that the Board direct the Standards Committee and the relevant standard
drafting team to develop a combined COM-002 and COM-003 standard that addresses, at a minimum,
certain essential elements. In light of the recommendation to combine the COM-002 and COM-003
standard and because the OPCPSDT has not had the opportunity to ballot a combined standard, the OPCP
SDT has created draft 7 as COM-002-4, which creates a single combined standard. The OPCP SDT also
considered the essential elements and evaluated whether they should be included within the combined
standard.
Commenters provided various comments in response to Question 1 on whether COM-003-1 draft 6
addresses the August 2003 Blackout Report Recommendation number 26, FERC Order 693 and the COM003-1 SAR. The OPCPSDT appreciates the feedback on draft 6 regarding these issues. The comments
were considered by the drafting team in deciding to move away from the approach in draft 6. Numerous
commenters provided comments on the Reliability Coordinator (RC) approval of the protocols in
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Requirement R1 and on aspects of Requirements R2 and R3 and the associated Measures. Because the
OPCPSDT has taken a different approach in draft 7 that moves away from the construct reflected in
Requirements R2 and R3, the standard drafting team will not address each comment individually. The
comments were considered by the drafting team to understand the industry’s perspective on the
approach in draft 6 and will be useful in crafting solutions in draft 7 and to NERC staff in creating a
compliance approach to draft 7. In response to comments, the OCPCSDT has removed the approval of the
RC from Requirement R1.
The OPCPSDT responds to other comments not addressed above in the responses below.
Organization
Oncor Electric Delivery
Yes/No
No
Comment
Draft 6 of COM-003-1 appears to go beyond the
recommendations and FERC 693 directives which were
the basis for the SAR. The main objective to develop an
operating protocol in alignment with other
communications standards to improve reliability.
Oncor’s concerns with Draft 6 are: (1) R1 - subject to the
Reliability Coordinator’s approval: adding this to R1
potentially adds an administrative burden to an
Entity/Industry without clear reliability benefits.
Operating protocol should support an Entity’s
operations and functions which are not a “one size fits
all”. By requiring a RC’s approval, the requirement
empowers the RC to interpret the requirement (as well
as defining “Operating Instructions”) which may not be
consistent with an Entity as well as the Regional Entitiy
who will be enforcing the requirement.
(2) R2/R3 - there is the potential for multiple levels of
interpretation of these requirements; these
requirement potentially creates a situation in which
Operators will need to be able to assess the transition
from normal to emergency operations and could quite
impact efficiency and productivity of operations which is
the opposite of the objective. In addition based on M2 &
M3, Oncor has concerns with the administrative burden
versus the reliability benefits gained in proving a
negative condition.
Response: The RC approval has been removed from the
draft 7. Also, the language of R2 and R3 has been
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changed to reflect the new approach.
Georgia System
Operations
Guy Zito/NPCC
Yes
No response
No
The introduction of the condition in R2 “so that the
failure to use the protocols by the issuer of an Operating
Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive by
the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or
Transmission Operator.” creates a number of issues with
the standard. a. The issuance of a Reliability Directive
may be caused by a number of reasons, for example, the
operating instruction (repeated or otherwise) may not
be sufficient to address a potential condition that has an
Adverse Reliability Impact; b. The operating instruction
that is communicated, with or without adhering to the
protocols developed in R1, is in fact moving other
system conditions from a reliable state to one that has a
potential of having Adverse Reliability Impact, for which
a Reliability Directive needs to be issued after
implementing the communicated operating instruction.
c. The operating personnel may second guess whether
or not a Reliability Directive will be issued if the
established communication protocols are not
implemented (such as by requiring 3-part
communication) before it takes the required action. This
puts the need to comply with a requirement into a
condition assessment mode, which defeats the purpose
of having a reliability standard to manage risk and meet
performance expectation whose reliability outcome are
predetermined, not on the fly. d. The added condition is
a compliance assessment element with which to gauge
violation severity or sanction; itself not a requirement.
By introducing this to the requirement, it convolutes the
requirement, adds nothing to meeting the reliability
objectives, and may in fact jeopardize reliability. And
what if a Reliability Directive was not issued despite the
failure of Responsible Entity to implement its
communication protocol? Is the Responsible Entity
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deemed compliant with the requirement? If so, do
Requirements R2 and R3 drive the right behaviors? If
not, then what’s the value and influence of the added
condition in the assessment outcome? Requirement R1
clearly requires the responsible entity to develop
documented communication protocols for the issuance
of Operating Instructions. By Part 1.5, the instances
where the issuer of an oral two party, person-to-person
Operating Instruction requiring the receiver to repeat,
restate, rephrase, or recapitulate the Operating
Instruction and subsequent actions by the issuer are
already clearly stipulated in the documented
communication protocols. Responsible entities simply
need to implement the protocols as documented,
regardless of whether failure to do so would result in
having to issue a Reliability Directive, or any other
possible outcomes, for that matter. Similar comments
apply to Requirement R3 when the responsible entities
are required to close out the last part of the 3-part
communication.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
City of Tallahassee
No
The suggested rephrasing of the Purpose statement “To
strengthen communications…” could be misleading.
Communications could be strengthened with better
equipment as well, but the intent of COM-003 is to deal
only with communications protocols. Suggest changing
the language to that which is found in the technical
guidance document, “Enhance the effectiveness of
communications…”
TAL has voted NO because the standard is still not “clear
and unambiguous”. TAL is concerned at the degree to
which the proposed standard complicates compliance
for Operating Instructions without benefit to reliability.
The FERC Directive was to tighten communications
during Emergencies and Alerts. Operating Instructions
deserve separate consideration under the standards.
Requiring an entity’s procedure to be subject to the
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Reliability Coordinator’s approval creates an undue
burden on the RC with no measurable improvement in
reliability. While this addressed a commenter’s concerns
over uniformity within RC control areas, it would be
simpler and more efficient to have the RC create a
procedure and provide it to all the entities in the
footprint. Measure 3 should be changed to “when
required by the issuer” in order to provide clarity and
consistency with R3.
Response: The RC approval has been removed from the
draft 7.
Manitoba Hydro
Yes
Although Manitoba Hydro is in general support of the
proposed draft, we suggest the following: (1) For clarity,
consider rewriting the second paragraph of the
definition of Operating Instruction as follows, An
Operating Instruction is not: (1) A discussion of general
information and of potential options or alternatives to
resolve Bulk Electric System operating concerns (2)
Exclusive and distinct from a Reliability Directive. There
is no overlap between an Operating Instruction and
Reliability Directive. (2) R1 and M1 - for consistency, add
an “’s” to the second instance of “Reliability
Coordinator” as follows: “Each Balancing Authority,
Reliability Coordinator, and Transmission Operator, in
each Reliability Coordinator’s area, shall…” (3) R1 – the
requirement instructs each BA, RC and TO develop
separate communication protocols. Are these
duplicative efforts practical? (4) R1, 1.4 – alpha-numeric
clarifiers are limited to oral Operating Instructions only.
For consistency with R1.1, 1.2 and 1.3, consider adding
applicabillity to written Operating Instructions as well.
Response: The SDT is unclear what added benefit alphanumeric clarifiers would provide for written Operating
Instructions.
(5) R1, 1.5 – is limited to oral Operating Instructions
while R3 (which deals with the same situation) does not
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Pepco Holdings Inc &
Affiliates
NERC Compliance Group
Yes
Yes
specify whether it is oral or written or both. (6) M2 – the
measure does not seem to match the requirement. The
requirement R2 states that the responsible entity
implement its communication protocols so that there is
no failure to use the protocols which results in a certain
operating condition. The measure however requires that
the responsible entity provide evidence that they did
not create the certain operating condition. Manitoba
Hydro suggests that the measure should more
accurately require that the responsible entity provide
evidence that it implemented its communication
protocol so that…
No response
As far as the August 2003 Blackout Report
Recommendation, the COM-003-1 revisions address this
concern. However, the criteria for communication
protocols that need to be used should be established.
The criteria needs to be applied to both COM-002 and
COM-003. There is too much room for interpretation
when it comes to measuring compliance.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hydro-Quebec
TransEnergie
PacifiCorp
NIPSCO
American Electric Power
Yes
Yes
Yes
No
Julie Dyke , NIPSCO comments submitted Also, We
would like to see COM-002 & 003 combined into a single
standard. In R1 1.5 it appears that three way
communication need only to be addressed in the
communication protocol and not necessarily required.
An operator may be reluctant to issue an RD which
would possibly expose entities to R2 & R3 noncompliance.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
AEP cannot vote in the affirmative for COM-003-1 as
long as COM-002-2 R2 would be in effect at the same
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time. The standard establishes a higher bar for more
routine communications than would be required for
emergency situations. This would only confuse
operators in determining which rules are to be followed
under which specific circumstances.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
AEP still contends that it is unnessary to obtain
Reliability Coordinator’s approval on the resulting
documented communication protocols for the issuance
of Operating Instructions in that Reliability Coordinator’s
area. Why would it be necessary to develop and
document internal procedures regarding communication
protocols when the proposed standard itself already
provides specific instruction on the required
communication?
Response: The RC approval has been removed from the
draft 7.
Is R 1.3 in any way redundant with TOP-002-2 R18?
Response: Project 2007-03 chose to eliminate TOP-0022a Requirement R18 when it developed TOP-002-3. This
Requirement states “Neighboring Balancing Authorities,
Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities
shall use uniform line identifiers when referring to
transmission facilities of an interconnected network.”
This standard, while reintroducing the concept of line
identifiers, limits the scope to only Transmission
interface Elements or Transmission interface Facilities
(e.g. tie lines and tie substations). This ensures that both
parties are readily familiar with each other’s interface
Elements and Facilities, eliminating hesitation and
confusion when referring to equipment for the
Operating Instruction. This shortens response time and
improves situational awareness.
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AEP proposes the elimination of COM-002-2 R2 and
changing COM-003-1 as proposed below so that it
covers all commands rather than a subset of commands.
Operating Instruction —A command by a System
Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority,
where the recipient of the command is expected to act
to change or preserve the state, status, output, or input
of an Element of the Bulk Electric System or Facility of
the Bulk Electric System. A discussion of general
information and of potential options or alternatives to
resolve Bulk Electric System operating concerns is not a
command and is not considered an Operating
Instruction. R1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall adhere to
the following communication protocols for the issuance
of Operating Instructions in that entity’s area. 1.1. The
use of the English language when issuing or responding
to an oral or written Operating Instruction, unless
another language is mandated by law or regulation. 1.2.
The instances, if any, that require time identification
when issuing an oral or written Operating Instruction,
specify the time zone unless the RC has previously
established an operational timezone. 1.3. The
nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or
written Operating Instruction. 1.4. The instances, when
referencing letters, utilize the phonetic alphabet when
issuing an oral Operating Instruction (Reference prior
draft(s)) 1.5. In instances where the issuer of an oral two
party, person-to-person Operating Instruction requires
the receiver to repeat, restate, rephrase, or recapitulate
the Operating Instruction and the issuer to: * Confirm
that the response from the recipient of the Operating
Instruction was accurate; or * Reissue the Operating
Instruction to resolve a misunderstanding. R2. Each
Balancing Authority, Transmission Operator, Generator
Operator and Distribution Provider shall repeat, restate,
rephrase, or recapitulate an Operating Instruction when
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required by the issuer of an Operating Instruction
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Portland General Electric
Company
No
Portland General Electric Company (PGE) thanks you for
the opportunity to provide comments. PGE is supportive
of the intent of COM-003-1 and appreciates the work
that the drafting team has put into the development of
the proposed standard. However, the language in R2
and R3 is convoluted and confusing. The following is a
suggestion for both R2 and R3: R2. Each Balancing
Authority, Reliability Coordinator, and Transmission
Operator shall implement its communication protocols
developed in Requirement R1. Delete: so that the failure
to use the protocols by the issuer of an Operating
Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive by
the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or
Transmission Operator. [Violation Risk Factor:
Medium][Time Horizon: Real Time Operations] R3. Each
Balancing Authority, Transmission Operator, Generator
Operator and Distribution Provider shall repeat, restate,
rephrase, or recapitulate an Operating Instruction when
required by the issuer of an Operating Instruction in its
communication protocols developed in Requirement R1.
Delete: so that the failure to repeat, restate, rephrase,
or recapitulate the Operating Instruction does not result
in an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium][Time Horizon: Real Time
Operations] Then add the following to each Measure,
(and RSAW) respectively: R2.1. Did the issuer of the
Operating Instruction fail to use its approved Operating
Instruction protocols it developed in R1? (yes/no) R2.2.
Did the failure to use the approved Operating
Instructions produce an operating condition requiring
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the issuance of an Reliability Directive? R3.1. Did the BA,
TOP, GOP and DP fail to repeat, restate, rephrase, or
recapitulate an Operating Instruction in its
communications protocols developed in R1? R3.2 Did
the failure to repeat, restate, rephrase, or recapitulate
an Operating Instruction produce a condition requiring
the issuance of an Reliability Directive? Also in R3, the
phrase, “…in its communications protocols” do you
mean in the issuer’s protocol or the receiver’s protocol?
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Arizona Public Service
Company
Yes
Negative ballot cast on the Standard: For
communication purposes, R1 should not include
Reliability Coordinator (RC) approval. If a regional
requirement (RC approval) is deemed necessary, then a
regional standard should be developed that includes the
procedure(s) and requirements to obtain RC approval of
communication protocols.
Response: The RC approval has been removed from the
draft 7.
Consolidated Edison Co.
of NY, Inc.
No
Add the word “verbal” before the word “Operating
Instructions” so that Requirement R1 reads: “R1. Each
Balancing Authority, Reliability Coordinator, and
Transmission Operator, in each Reliability Coordinator
area, shall develop, subject to the Reliability
Coordinator’s approval, documented communication
protocols for the issuance of verbal Operating
Instructions in that Reliability Coordinator’s area." Also
make similar changes where required elsewhere.
Response: The standard is intended to cover both oral
and written communication.
Flathead Electric
Cooperative, Inc.
No
No, the 2003 Blackout recommendations were specific
to control center and reliablity coordinator entities. This
standard appears to push down below to small DP
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entities that don't have control centers. Also, the
Blackout recommendations were clearly concerned with
"reliability" directives and did not contemplate a new
category of Operating Instructions. The existing
authority in other standards for registered entities to
respond to reliability directives should be sufficient to
addres the recommendations without this standard.
Occidental Energy
Ventures Corp.
Yes
Response: The DP was added in response to directive in
FERC Order 693.
Occidental Energy Ventures Corp. (“OEVC”) would like to
compliment the drafting team for finding a compliance
solution that focuses only on the results of an
improperly executed Operating Instruction. The
approaches in previous drafts could be construed that
entities retain proof that every applicable
communication was monitored and verified – an
impossible administrative task. We believe that Draft 6
of COM-003-1 removes the onerus compliance burden
without freeing Operating entities from the obligation to
perform responsibly. They are free to choose the level of
sample communications to monitor, the amount of
training they perform, and the internal disciplinary
actions they take for non-compliance to the required
protocols. However, there are consequences if their
oversight is inadequate. We do have two concerns
which we would like to air. First, that recipients of
Operating Instructions must be informed that formal
communication is being done. Athough front-line
Operators will be trained to comply with the appropriate
protocol documents, they will be naturally inclined to
follow the lead of the issuing entity – particularly if the
communication is a borderline instruction. For example,
a request for equipment status may be part of
discussion concerning available alternatives, or
information needed to confirm real-time stability. The
recipient should not be left in a position to guess what
the needs of the immediate situation are. Secondly, we
would hope that the protocols developed by the various
RCs, BAs, and TOPs are generally consistent. Even
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though we agree that each individual organization may
have specific communications needs, it is in no one’s
interest to have minor preferential differences between
entities. Perhaps this is an issue that NERC’s
performance management team can monitor –
particularly as they have a highly vested interest in the
resolution of Operating Instruction errors. These
comprise a high percentage of outage root causes, and
we are sure that uniformity will be a key improvement
indicator.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
ReliabilityFirst
No
ReliabilityFirst believes the newly included language in
Requirement R1 “…subject to the Reliability
Coordinator’s approval…” introduces three issues which
need to be addressed prior to the draft standard being
enforceable. The three issues include: 1) With the
Reliability Coordinator being an Applicable Entity within
this requirement, it is unclear which entity will be
approving the Reliability Coordinator’s documented
communication protocols? Based on the current
language, the Reliability Coordinator would need to seek
approval from themselves as the Reliability Coordinator.
2) There is no companion requirement requiring the
Reliability Coordinator to approve the Balancing
Authority’s and Transmission Operator’s documented
communication protocols. It is inferred, but there is no
requirement which explicitly requires the Reliability
Coordinator to take action. Based on the current
language in Requirement R1, if a Reliability Coordinator
never takes action (approval or disapproval), where
does this leave an entity for compliance purposes? 3) In
the scenario where the Applicable Entity (Balancing
Authority, Transmission Operator) develops
documented communication protocols (which address
the elements in sub parts 1.1 through 1.5) but the
Reliability Coordinator disapproves, will the Applicable
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Entity be non-compliant with Requirement R1? The
Applicable Entity has no control over action taken
(approval or disapproval) by the Reliability Coordinator.
Furthermore, since Requirement R2 and Requirement
R3 depend on the documented communication
protocols developed in Requirement R1, would the
Applicable Entity be automatically found non-compliant
with those two requirements as well? ReliabilityFirst
offers the following two recommendations for the SDT
to consider to address the ReliabilityFirst concerns with
the newly included language “…subject to the Reliability
Coordinator’s approval…”: 1) Remove the “…subject to
the Reliability Coordinator’s approval…” language from
Requirement R1. Add a new requirement requiring the
Applicable Entities to make their documented
communication protocols available to all the other
Applicable Entities within in each Reliability Coordinator
area. 2) Make Requirement R1 applicable to only the
Reliability Coordinator and remove the “…subject to the
Reliability Coordinator’s approval…” language. This will
require the Reliability Coordinator to develop one
consistent set of documented communication protocols
for all entities within their Reliability Coordinator area.
This will also allow the Reliability Coordinator to tailor
the documented communication protocols to address
uniqueness among Balancing Authorities and
Transmission Operators (e.g., asset density, locations
and organizational structure) within their area. If the
SDT agrees with either of these recommendations, the
sub-parts for Requirement R1 and both Requirement R2
and Requirement R3 would remain relatively
unchanged.
Response: The RC approval has been removed from the
draft 7.
Texas Reliability Entity
No
(1) Definition of Operating Instruction: We remain
concerned about potential interference between COM002 and COM-003. While it has been made abundantly
clear in this draft that an Reliability Directive is not an
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Operating Instruction, it remains unclear exactly where
the boundary between them is. We are concerned that
an operator faced with an imminent emergency
situation will have to stop to consider whether he needs
to issue a Reliability Directive or an Operating
Instruction, and entities will be subject to secondguessing as to whether they picked the right one. COM002 and COM-003 should be melded into one coherent
standard that will not interfere with system operations.
Response: The RC approval has been removed from the
draft 7.
(2) The present draft does not address one-to-many
communications (hot-line calls, all-calls), which are
commonly used to convey Operating Instructions in
critical situations. A repeat-back procedure for those
calls should be included in an entity’s documented
communications protocols.
Response: The concept of all-calls is addressed in draft
7.
(3) While we respect the desire to avoid writing a “zerodefect” standard, we strongly object to the approach
taken in requirements R2 and R3. Compliance with these
requirements should not be based on whether a
subsequent Reliability Directive was issued. Instead,
compliance should be based on whether the
communication protocols are routinely and effectively
implemented (perhaps using an
“identify/assess/correct” approach). The present draft
allows system conditions over which the entity may
have little control (i.e. luck) to determine whether a
deviation from its protocols results in a violation.
Importantly, the current draft may create an undesirable
incentive for an operator to avoid issuing a Reliability
Directive in order to avoid scrutiny of prior Operating
Instructions. (4) We also object to basing compliance
with R2 and R3 on whether the entity’s conduct
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“resulted in” an adverse operating condition. The
existence of a violation should be based solely on the
entity’s conduct, not on the results of that conduct on
system conditions. The proposed approach creates an
unmanageable compliance assessment burden, as
parties will dispute whether events were causally
related, which can be very difficult to conclusively
assess. Furthermore, what does “result in” mean? Does
it require proximate cause, direct cause, contributing
cause, or some other measure of causal relationship?
Response: The language of R2 and R3 has been changed
to reflect the new approach.
(5) The proposed revisions in COM-003 interact with the
revisions in TOP-001-2 to create a reliability gap that will
reduce the performance level required by the standards.
The existing requirements 3 and 4 of TOP-001-1a require
TOP, BA, GOP, DP and LSE entities to comply with
reliability directives (not capitalized) issued by a TOP.
We interpret “reliability directives” in that standard to
include all operating instructions related to reliable
system operation, including those that are proposed to
be defined as both Reliability Directives and as
Operating Instructions. The new version TOP-001-2
(pending at FERC) limits the compliance requirement to
only Reliability Directives (defined term), and will no
longer require compliance with Operating Instructions
issued by TOPs. This problem is enhanced by the
proposed definition of Operating Instructions, which
now emphasizes that Operating Instructions and
Reliability Directives are mutually exclusive. There needs
to be a reliability standard that requires compliance with
Operating Instructions issued by TOPs, and the absence
of such a standard creates a reliability gap.
Response: This scope of this standard, as defined by the
SAR, only considers communication protocols. The
obligation to follow “directives” is defined elsewhere in
the body of standards. The gap you have identified
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would be present whether or not this project existed.
City of Garland
City of Anaheim
No
Yes
Three part communications is a standard business
practice in transmission and distribution operations
across the country. If by chance there is / was a
company that was not using three part communications,
that company would have had to develop a procedure /
policy for three part communications to be compliant
with COM-002-2 R2 (COM-002-3 R2 future). Therefore,
the proposed COM-003 R1 requiring companies to
develop “documented communication protocols” that
have to be approved by the Reliability Coordinator is
nothing more than a compliance burden to maintain
documentation for an audit. Furthermore, COM-003 R3
requires use of three part communications and should
be the only requirement in COM-003. Because of COM002-2 R2 and COM-003 R3, COM-003 R1 is merely a
paperwork compliance burden and should be deleted.
COM-003 R2 relies on R1 and therefore it should be
deleted also. As previously stated, COM-003 should only
contain the requirement listed in the current R3.
Response: This scope of this standard, as defined by the
SAR, considers communication protocols, not just threepart communications.
The proposed Standard language appears to address the
requirements of FERC Order 693. However, R3 is still
confusing and appears to assume that the distribution
provider or generator operator would have some way of
knowing if an Operating Instruction would “result in an
operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator.” Also,
more clarification is needed with respect to the terms
"restate", "rephrase" and "recapitulate". We suggest the
the following language for R3: “Balancing Authorities,
Transmission Operators, Generator Operators and
Distribution Providers shall repeat or restate an
Operating Instruction given to them when required by
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the issuer of that Operating Instruction.”
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Dominion
Yes
Dominion appreciates the SDT efforts on this project as
we know it has not been an easy task to satisfy industry
concerns while at the same time, addressing FERC
directives relative to this issue. We believe that having a
requirement that the communication protocol be
approved by the RC, while possibly considered an
administrative burden by them, greatly enhances
consistency of such protocols. And, we greatly
appreciate the fact that recipients are required to
repeat, restate, rephrase, or recapitulate only when
required by those approved protocol.
Response: The RC approval has been removed from the
draft 7.
PPL NERC Registered
Affiliates
No
These comments are submitted on behalf of the
following PPL NERC Registered Affiliates (PPL): Louisville
Gas and Electric Company and Kentucky Utilities
Company; PPL Electric Utilities Corporation, PPL
EnergyPlus, LLC; and PPL Generation, LLC, on behalf of
its NERC registered affiliates. The PPL NERC Registered
Affiliates are registered in six regions (MRO, NPCC, RFC,
SERC, SPP, and WECC) for one or more of the following
NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP,
TO, TOP, TP, and TSP. PPL has generally supported draft
4 and draft 5 of the COM-003 standard. However, the
significant changes proposed in draft 6 introduce
ambiguity, as well as several other issues that need to
be addressed. First, the proposed definition of an
“Operating Instruction” continues to require
clarification. PPL NERC Registered Affiliates suggest the
following definition to address the above issue:
“Operating Instruction - A Real-time Operations
command, other than a Reliability Directive, by a System
Operator of a Reliability Coordinator, or of a
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Transmission Operator, or of a Balancing Authority,
where the recipient of the Real-time Operations
command is expected to act to change or preserve the
state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. A
discussion of general information, potential options
and/or alternatives to resolve Bulk Electric System
operating concerns is not a command and is not an
Operating Instruction. An Operating Instruction is
exclusive and distinct from a Reliability Directive. There
is no overlap between an Operating Instruction and
Reliability Directive.” The focus of COM-003 is on
operations, and therefore the communications subject
to the COM-003 requirement should be those requiring
action in the Real-time Operations time horizon — i.e.,
actions required within one hour or less. (See definition
provided in a NERC document at:
http://www.nerc.com/files/Time_Horizons.pdf). During
the Q/A portion of the November 27, 2012 conference
call hosted by the SDT, the SDT stated that they
intended to narrow the focus of the timeframe of an
Operating Instruction to the Real-time Operations time
horizon. . Second, there is inconsistency in the wording
of some parts of R1. Specifically, PPL recommends
revising part 1.5 as follows: “The instances, if any, where
the issuer…” or removing the ‘if any’ from R1.2 and R1.4,
since it is redundant to the R1 ‘where applicable’ and
the use of ‘when, that, etc.’ in the sub requirements.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
Third, both R2 and R3 as currently written may not aid in
enhancing reliability. PPL suggests R2 be revised to
require the BA, RC, and/or TOP provide their
communication protocols to the GOPs, DPs with whom
they communicate. PPL suggests language for R3 be
revised to read as follows: “Each Balancing Authority,
Distribution Provider, Generator Operator, Reliability
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Coordinator, and Transmission Operator shall assess its
adherence to the applicable documented
communication protocols developed for R1 and R2.” As
currently drafted, R2 and R3 appear to require that
entities issuing or receiving Operating Instructions must
prove that no BA, RC or TOP issued a Reliability Directive
as a result of their lack of use of the R1 protocol or of
three-part communication. The R2 draft language says
that the BA/RC/TOP communication protocols must be
developed such that even when the communication
protocols are not used, there is still no need for a
Reliability Directive. This could imply that if no Reliability
Directive is required, the failure to use the protocols
created no risk and the communication protocol was not
needed. This appears to make inconsequential any
reliability benefit of R1 of the Standard. Also, R3 has
requirements for entities that may not have received
the communication protocols developed by the
BA/RC/TOP. Fourth, there is ambiguity introduced in R2
and R3 through the use of the phrase “that requires the
issuance.” It is unclear who would determine whether
the Reliability Directive was “required.” Likewise, if
there are multiple incidents which contribute to the
issuance of a Reliability Directive, it is not clear what
weight would be given to the lack of use of
communication protocols, nor is it clear how that
determination is made. Finally, M2 and M3 introduce an
expectation that applicable entities will need to
coordinate to produce evidence. PPL recommends that
M2 and M3 be revised to align with the changes made
to R2 and R3 as noted above.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Wisconsin Electric Power
Company
No
Version 6 of the standard does not explicitly limit the
timeframe prior to the issuance of a Directive subject to
review for compliance with communication protocol
requirements. Additionally, the draft Standard and
definition of Operating Instruction do not adequately
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define instances where Operating Instructions would
require 3-way communications. The process by which a
Reliability Coordinator approves instances where
communication protocols are required will define the
substantial requirements in the standard. Establishing
the Reliability Coordinator as an approval authority for
BA or TOP internal procedures implies the RC will have
responsibility for operational activities and/or
procedures owned by the BA or TOP and essentially
outsources the standard development to the Reliability
Coordinator.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
ISO New England Inc.
Sacramento Municipal
Utility District
Yes
Yes
Although SMUD agrees with the draft 6 of COM-003-1.
Also, we are in support of the finding from the
Independent Standards Review Panel’s final report for
mitigating BPS risks as noted: Resolve COM-002 and
COM-003 by requiring three-part communication for
operational directives and for registered entity defined
operational instructions that involve taking specific
actions or steps that would cause a change in status or
output of the BPS or a generator. This does not include
three-part communication for myriad of conversations
where information is being exchanged or options are
being discussed.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
North American
Generator Forum
Standards Review Team
No
R3 can present an excessive or even impossible
compliance burden, in that all parties receiving
Operating Instructions must prove that no BA, RC or TOP
issued a Reliability Directive as a result of their lack of
three-part communication. This is not a matter of simply
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obtaining annually a “No known errors” letter from the
BA, RC and TOP with which a receiving-end entity is
directly involved, since all the neighboring BAs, RCs and
TOPs are drawin-in by R3 as well. There is meanwhile no
requirement that BAs, RCs or TOPs issue such letters
when requested to do so, or that they must share any
information at all regarding Reliability Directives issued.
This leaves GOPs and other entities that receive
Operating Instructions in danger of self-certifying
compliance to R3, then being later confronted with
evidence of non-compliance from a source from whom
they had previously heard nothing. The issue of
interpretation also creates undue ambiguity. Who will
make the determination of cause when a Reliability
Directive is issued, and is that opinion subject to review
if objections are raised? If all GOPs in a region were
instructed to bring all available generators online at
their Emergency Rating due to tripping of a 2000 MW
nuclear plant, for example, and the operator of a 10 MW
blackstart unit did not respond in the prescribed fashion,
and a Reliability Directive ultimately had to be issued to
shed some load, did that 10 MW unit “cause” the load
shedding? R3 should be revised to match the draft that
was issued for comments several weeks ago, and which
the NAGF found acceptable. That is, R3 should state that
“Each Balancing Authority, Distribution Provider,
Generator Operator, Reliability Coordinator, and
Transmission Operator shall develop method(s) to
assess, as applicable, System Operators’ and operators’
communication practices and implement corrective
actions necessary to meet the expectations in its
documented communication protocols developed for
Requirement R1 and R2.”
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Independent Electricity
System Operator
No
Despite we have always held a position that this
standard was not needed given the approved COM-0023 and the NERC OC’s operating guide on operating
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personnel communication, we supported the previous
version of COM-003-1 (Draft 5) as it was a clearly written
standard which would be an acceptable compromise for
meeting the FERC directive and BoT’s direction without
overburdening industry participants having to repeat
every operating instruction. This latest version, Draft 6,
however, turns an acceptable standard into one that is
ambiguous and provides an escape clause for operating
personnel to not comply with the basic requirement
(R1). The introduction of the condition in R2 “so that the
failure to use the protocols by the issuer of an Operating
Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive by
the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or
Transmission Operator.” creates a number of issues with
the standard, as follows: a. The issuance of a Reliability
Directive may be caused by a number of reasons, for
example: the operating instruction (repeated or
otherwise) may not be sufficient to address a potential
condition that has an Adverse Reliability Impact; b. The
operating instruction that is communicated, with or
without adhering to the protocols developed in R1, is in
fact moving other system conditions from a reliable
state to one that has a potential of having Adverse
Reliability Impact, for which a Reliability Directive needs
to be issued after implementing the communicated
operating instruction. c. The operating personnel may
second guess whether or not a Reliability Directive will
be issued if the established communication protocols
are not implemented (such as by requiring 3-part
communication) before it takes the required action. This
puts the need to comply with a requirement into a
“condition assessment” mode, which defeats the
purpose of having a reliability standard to manage risk
and meet performance expectation whose reliability
outcome are predetermined, not on the fly. d. The
added condition is a compliance assessment element
with which to gauge violation severity or sanction; itself
is not a requirement. By introducing this to the
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requirement, it convolutes the requirement, adds
nothing to meeting the reliability objectives, and may in
fact jeopardize reliability. And what if a Reliability
Directive was not issued despite the failure of
Responsible Entity to implement its communication
protocol. Is the Responsible Entity deemed compliant
with the requirement? If so, do Requirements R2 and R3
drive the right behaviors? If not, then what’s the value
and influence of the added condition in the assessment
outcome? Requirement R1 clearly requires the
responsible entity to develop documented
communication protocols for the issuance of Operating
Instructions. By Part 1.5, the instances where the issuer
of an oral two party, person-to-person Operating
Instruction requiring the receiver to repeat, restate,
rephrase, or recapitulate the Operating Instruction and
subsequent actions by the issuer are already clearly
stipulated in the documented communication protocols.
Responsible entities simply need to implement the
protocols as documented, regardless of whether failure
to do so would result in having to issue a Reliability
Directive, or any other possible outcomes, for that
matter. Similar comments apply to Requirement R3
when the responsible entities are required to close out
the last part of the 3-part communication.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
MISO
No
The blackout recommendation 26 had little or nothing
to do with operator communications. The
recommendation was to implement some type of
communication system to keep Regions, NERC and
regulators informed during emergencies. Here is the
recommendation: “NERC should work with reliability
coordinators and control area operators to improve the
effectiveness of internal and external communications
during alerts, emergencies, or other critical situations,
and ensure that all key parties, including state and local
officials, receive timely and accurate information. NERC
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should task the regional councils to work together to
develop communications protocols by December 31,
2004, and to assess and report on the adequacy of
emergency communications systems within their
regions against the protocols by that date.” These are
our comments on what is presented in this revision of
COM-003-1. • We’re generally OK with a requirement to
develop a set of communication protocols and whereby
the applicable entity does a periodic assessment of its
operators’ adherence to the protocols. • While we
believe that it is acceptable for a BA and TOP to develop
their own protocols, it would be preferable that they be
allowed to use a set of protocols developed by the RC. •
We disagree that the RC should approve others’
protocols. What are the criteria for approval? NERC
should not put RCs in the role of de-facto compliance
monitors. • There is a likely unintended consequence of
the latest draft. This will plant a seed of doubt in an
operator’s mind whether or not to issue a reliability
directive due to the scrutiny and second guessing that
will be the outcome of each investigation associated
with a directive. This standard will result in
investigations associated with each directive. • We were
OK with the previous version. We’d be OK with a
revision to the current draft if there was an ex post
assessment of operating instructions following the
issuance of a directive. There should not be a rabbit-trail
investigation following the issuance of each directive.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
Bonneville Power
Administration
Xcel Energy
Yes
No
We are electing to not respond directly to this question,
as we have expressed concern with the advancement of
this project many times in the past. While this draft
seems far superior to the others, the proposed change
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to R1 raises concern over the portion that dictates that
the Reliability Coordinator has approval authority over
the communications protocols for Operating
Instructions. The majority of the Operating Instructions,
as defined by the standard, will be between the System
Operator at a Balancing Authority or Transmission
Operator and their respective field personnel.
Communications between System Operators of BAs and
TOPs and field personnel have well-established
protocols and should not necessarily be held to the
same protocol as communications between BAs or TOPs
and the Reliability Coordinator. In essence, the proposed
change to R1 places the Reliability Coordinator in a
position to dictate communication protocols that may
breakdown the well-established protocols of the BAs
and TOPs and create more burdensome communication
with their field personnel.
Response: The RC approval has been removed from the
draft 7.
City of Redding
Clark Public Utilities
Yes
No
Requirement 1 does adequately address the concerns.
Requirements 2 and 3 are confusing and difficult
interpret. It was not until I rea the FAQ on COM-003 that
I understood R2 and R3. I believe R2 and R3 should be
revsed as described below. R2. R2 needs to indicate that
it is only applicable to issuers of Operating Instructions.
R2 should be revised to read as follows: Each Balancing
Authority, Reliability Coordinator, and Transmission
Operator that issues an Operating Instruction shall
implement its communication protocols developed in
Requirement R1 so that the failure to use the protocols
by the issuer of an Operating Instruction does not result
in an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator. With
the change it is clearer that the standard is saying that
an issuer of an Operating Instruction is supposed to have
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a communication protocol(R1). R2 is stating the issuer of
an Operating Instruction needs to use the
communication protocol and if the issuer's failure to use
the communication protocol results in the issuance of a
Reliabilty Directive, a violation has occured. R3. R3
needs to indicate that it is only applicable to recipients
of Operating Instructions. R3 should be revised to read
as follows: Each Balancing Authority, Transmission
Operator, Generator Operator and Distribution Provider
that receives an Operating Instruction shall repeat,
restate, rephrase, or recapitulate the Operating
Instruction when required by the issuer of the Operating
Instruction (in accordance with the issuer's
communication protocols developed in Requirement R1)
so that the failure to repeat, restate, rephrase, or
recapitulate the Operating Instruction does not result in
an operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator. With
the change it is clearer that the standard is saying that a
recipient of an Operating Instruction is supposed to to
repeat, restate, rephrase, or recapitulate the Operating
Instruction when required by the issuer and if the
recipient's failure to repeat, restate, rephrase, or
recapitulate the Operating Instruction (as long as it is
required in the issuer's communication protocol) results
in the issuance of a Reliabilty Directive, a violation has
occured.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Southern Company:
Yes
Southern Company
Services, Inc; Alabama
Power Company; Georgia
Power Company; Gulf
Power Company;
Mississippi Power
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Company; Southern
Company Generation and
Energy Marketing
Illinois Municipal Electric Yes
Agency
Florida Municipal Power Yes
Agency, and SERC OC
Standards Working
Group
Oklahoma Gas & Electric Yes
New Brunswick System
Operator
No
There is still concern that the intent of Recommendation
26 was strictly for emergency situations which are
covered by COM-002-3. While well intentioned, based
upon the spirit of the Paragraph 81 initiative, OG&E
believes the current draft of the COM-003-1 standard to
be more of an administrative burden than an
improvement to reliability.
The introduction of the condition in R2 “so that the
failure to use the protocols by the issuer of an Operating
Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive by
the original issuer of the Operating Instruction or by
another Balancing Authority, Reliability Coordinator, or
Transmission Operator.” creates a number of issues. •
The issuance of a Reliability Directive may be caused by
a number of reasons, for example: the operating
instruction may not be sufficient to address a potential
condition that has an Adverse Reliability Impact; • R2
has the unintended consequence of making Reliability
Directives a subject of a Root Cause analysis. Whenever
a Reliability Directive is issued it would be necessary for
the issuer to prove that that Reliability Directive was not
linked to an Operating Instruction protocol failure.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Seminole Electric
Cooperative, Inc.
No
While the draft may meet the Blackout
Recommendation and Order 693, the draft is
problematic and is resulting in Seminole changing its
votes from prior affirmation to negative with this ballot.
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The reasons are: 1. The requirement for RC approval of
entity developed communications protocols (R1), which
impose an unreasonable administrative and associated
cost burden upon all of the applicable entities.
Response: The RC approval has been removed from the
draft 7.
2. The new connection to Reliability Directives issued by
an RC, TOP, or BA, which are due to the failure of an
applicable entity to properly implement its
communication protocols for Operating Instructions,
seemingly implies compliance investigation following
the issuance of any RC Reliability Directive, for all
entities affecting the RC area’s footprint (R2&3).
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Wisconsin Public Service
Corp
3. The term Operating Instruction is so broad, that every
System Operator communication might require logging,
recording and compliance review.
Also, since enforcement and compliance under Version
6 hinges on a Reliability Directive being issued, am I
correct to assume that if emergency conditions requiring
actions on the BES were to occur, but an issuing entity
failed to announce their request for action as a
Reliability Directive – then NO Directive was issued, and
therefore there could be no COM-003 violation for that
event and no need to analyze if preceding Operating
Instructions were given which may have lead up to the
Emergency condition? Note: COM-003 Rev. 6, R3 “… an
operating condition that requires the issuance of a
Reliability Directive…” so put another way, what if a
Reliability Directive was required – but not clearly
identified as in COM-002 V3, R1? The future COM-002
V3, R1 requires an issuing RC, TOP, or BA (or LBA) in
part, to clearly call a Reliability Directive a Reliability
Directive. I couldn’t find similar language for Operating
Instructions in Rev. 6 of COM-003. Is it intended that this
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will need to be included in each entities communications
protocol, along with the need for the issuing entity to
clearly communicate “…and I will need you to repeat
this back.”? My concern here is that while I like the
SDT’s approach with R3 in Rev. 6, if only R3 applies to
DP’s and GOP’s (and therefore they are not required to
have or to implement communications protocols), if the
issuer of an Operating Instruction doesn’t clearly
identify it as such AND tell the recipient in advance that
he requires a repeat-back, it will be difficult for the
recipient who is a DP or GOP to meet the R3
requirement. Conversely, based on the high number of
Operating Instructions occurring each day, perhaps it
was the intent of the SDT that DP’s and GOP’s which are
limited to simply how to respond to Directives and/or
Instructions with repeat-backs. Please clarify. Lastly, I
mentioned the concern under M3. Rather than just
stating it is confusing, I’m listing a proposed change for
consideration if the Standard doesn’t get approved as is.
We hope it is more clear in its wording and its
expectation that the issuer of any Directive should lead
efforts to complete an analysis of what lead up to a
Directive. Draft 6 proposal for M3: Each Balancing
Authority, Generator Operator, Distribution Provider,
and Transmission Operator shall provide evidence that it
did not experience a failure to repeat, restate, rephrase,
or recapitulate an Operating Instruction, when required,
that resulted in an operating condition that required the
issuance of a Reliability Directive by the issuer or by
another Balancing Authority, Reliability Coordinator, or
Transmission Operator due to the failure to use the
protocols. A Balancing Authority, Generator Operator,
Distribution Provider, and Transmission Operator may
need to coordinate with a Reliability Coordinator,
Balancing Authority and Transmission Operator to
provide this evidence. WPS proposal for M3: The issuer
of a Reliability Directive shall provide evidence that a
failure to repeat, restate, rephrase, or recapitulate an
Operating Instruction, when required, resulted in an
operating condition that required the issuance of a
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Reliability Directive. A Balancing Authority, Generator
Operator, Distribution Provider, and Transmission
Operator may need to coordinate with a Reliability
Coordinator, Balancing Authority and Transmission
Operator to provide this evidence.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
SERC Reliability
Corporation
Yes
It addresses parts of each. While a reliability standard
may not be the most appropriate control to address the
reliability concern, this standard, in conjunction with
COM-003-2 does address the Standards Authorization
Request to require that real time system operators use
standardized communication protocols during normal
and emergency operations to improve situational
awareness and shorten response time. There is concern
with making protocols (and any revisions) available to
those who are expected to comply. R1 states that the RC
must approve; M1 states that each...shall provide. It is
not clear that those who must comply will have the
latest version. Suggest that the Measure be tightened up
to state that the RC must provide the approved
communication protocols to the .... in thier footprint.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Hopefully this will address your concern.
Minnesota Power
No
SERC OC Review Group
Yes
Minnesota Power supports comments submitted by the
MRO NERC Standards Review Forum (NSRF).
We agree on a very limited view that Recommendation
26 is addressed. However, when looking at reliability we
are concerned that the administrative burden, and
uncertainty of which Operating Instruction will become
a Reliability Directive may negatively impact BES
reliability in the reluctance of issuing a Reliability
Directive. Therefore, we strongly recommend that the
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SDT review this draft and redraft to clarify these points.
Measure 3 should be changed to “when required by the
issuer” in order to provide clarity and consistency with
R3. In addition, we believe that a statement needs to be
added in R1 that includes providing or distributing those
communication protocols developed by a BA or TOP to
their associated DPs and GOPs. This would address a
potential gap of DPs and GOPs not aware of the
communication expectations when communicating with
BAs and TOPs when given an Operating Instruction.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
ACES Standards
Collaborators
No
(1) While we understand that there are numerous
approaches to satisfy the FERC order and the 2003
Blackout Report, we disagree that the drafting team
addresses these concerns in a measurable and uniform
process. The FERC Order and the Blackout Report both
call for a “tightening of communications.” We are not
convinced that giving the RC the authority to approve
communication protocols will result in less confusion
and a tightening of communications. There are currently
15 Reliability Coordinators in the NERC Compliance
Registry, which leaves 15 opportunities for inconsistent
application of what constitutes an “Operating
Instruction.” (2) Further, we are concerned that by
granting the Reliability Coordinator the authority to
approve a registered entity’s communication protocol,
there may be differing protocols among the various RC
areas, which would negatively impact registered entities
that are located in more than one RC area. For entities
that operate in multiple RC areas, there could be
different criteria for what constitutes an Operating
Instruction, differing line and equipment identifiers, and
other nuances that result in confusion and lead to an
increase in miscommunication. The standard does not
require uniform communication protocols among the
various Reliability Coordinators. (3) In addition, how
would an entity communicate to a neighboring BA and
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TOP who are in a different RC area with different
protocols? This draft poses significant issues for
registered entities located on the seams of RC areas that
communicate to other entities in other RC areas.
Response: The RC approval has been removed from the
draft 7.
(4) We have an issue with the language in the Measure
M2. Measure M2 requires a registered entity to prove
the negative that no reliability directives occurred. This
presents an issue because some regions are reluctant to
accept attestations as evidence. This approach is an
increased compliance burden on registered entities. This
draft did not include an RSAW for review and we
recommend the drafting team provide further
clarification that an attestation is acceptable for
compliance and continue to work with NERC compliance
on this issue. (5) Finally, we disagree with the revised
definition of Operating Instruction and the approach of
Requirement R2 and R3. Under the revised definition, an
Operating Instruction is separate from a Reliability
Directive, but an entity will only be in violation for failing
to communicate effectively that would result in the
issuance of a Reliability Directive. This is double
jeopardy. An entity could be in violation of both COM002 and COM-003 for failing to communicate effectively
that results in an event on the Bulk Electric System. This
issue has been stated in our earlier comments that the
definitions and the two COM standards would be better
as a combined standard instead of the separate projects
to avoid this potential compliance issue.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Southwest Power Pool
Regional Entity
Yes
What is the expected time frame for the RC’s initial
approval of the protocols? NERC needs to clarify the
protocol approval dates in relation to the
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effective/enforceable date.
Response: The RC approval has been removed from the
draft 7.
Associated Electric
Cooperative, Inc. JRO00088
No
AECI strongly supports the SERC OC Q1 comments
posted for this draft. In addition, AECI believes that
COM-003 fails to properly address related topics found
within the August 2003 Blackout Report
Recommendation number 26 and FERC Order 693,
primarily because of the SDT's having included DPs
within the COM-003 scope, and thereby overreaching
these two citation's intended scope. In the case of the
August 2003 Blackout Recommendation 26, while its
terse two-sentences appear to be met by COM-003, the
same report's pp 161-162 clarifies its intended scope
being "during alerts, emergencies or critical situations."
That same section's "particularly during alerts and
emergencies", might be stretched to include COM-003
Operating Instructions for DPs, yet FERC's
determination, expressed within Order 693 paragraphs
493, 509-512, suggests that NERC COM-003 is
attempting to tread where FERC itself dared not go.
Within that paragraph 493, FERC's rationale cites no
more than "when generators with blackstart capability
must be placed in service and nearby loads restored as
an initial step in system restoration", in support of
exercising governance over DP telecommunications.
These two limited conditions for communication appear
confined to COM-002, and not COM-003's drafted
governance over external communications with DPs.
Paragraph 509's real-time staffing requirement omits
DPs. Paragraph 510.3 cites DPs as applicable under
COM-002, and 510.4 "requires tightened
communications protocols, especially for
communications during alerts and emergencies" and
then par 510 goes on to propose a new standard (COM003?) for addressing the Blackout Report
Recommendation 26. Paragraph 512's assertion "that,
during both normal and emergency operations, it is
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seattle city light
No
essential that the transmission operator, balancing
authority and reliablity coordinator have
communications with distribution providers" appears to
conflict with earlier par 509 with regard to levels of
"essential", and then asserts that many DPs are "not a
user, owner or operator of the Bulk-Power System" so
not required to comply with COM-002 (nor therefore
COM-003). However COM-003 fails to provide for such
differentiation within its Applicability section 4.1.2, for
its scope of governance over DP communications during
"normal operations". AECI recommends that DP
applicability be dropped from COM-003 and reserved for
COM-002 where these citations rationale for inclusion is
clear. Finally, because industry balloting appears highly
conflicted over the terms under which COM-003's rules
would be developed, AECI strongly suggests that the SDT
limit scope to only communications between RCs and
their external communicating parties. This stance would
have stronger backing from the above citations, and
would make more sense, because only RCs
communicate changes to the BES. New governance over
the exact manner in which communicated changes
become executed, is where industry appears to have
heartburn. This may be occuring because much of
industry has already tweaked and tuned those
operational methodologies long before RCs came into
existence, and therefore see much greater Compliance
risk being ventured, for relatively little BES-reliability
gains.
Seattle remains confused as to the intent of the draft
Standard. R1 appears to require a protocol for
communications that need not be followed in R2 or R3,
because only communications problems leading to a
Reliability Directive are to be audited. Seattle does not
know if this position satisfies the FERC Order or the SAR.
As proposed, the present Standard draft could be
simplified to a single requirement to "communicate in
such a way as to avoid Reliability Directives." On the
other hand, if the intent is to REQUIRE three-way
communications, then present draft R2 and R3 do not
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do so.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Lincoln Electric System
Tennessee Valley
Authority
MRO NERC Standards
Review Forum (NSRF)
Yes
Yes
No
The NSRF does not believe that this Standard is
nessecary to address recommendation 26 of the
Blackout Report, thus this project should be terminated.
The NSRF suggests that COM-002-3 be filed with FERC as
approved by the NERC BOT, as we believe it adequately
addresses the Blackout recommendation 26 and FERC
Order 693. However, if the NERC SC wants to continue
with this development, we provide the following
recommendations. For Measure 2 and Measure 3 , the
SDT is requiring each registered entity to ‘prove the
negative’ by requiring each entity to demonstrate that
each Operating Instruction issued by its System
Operators did not result in an operating condition that
required the issuance of a Reliability Directive. From the
webinar on July 2, the SDT stated that all an entity needs
to do is request an attestation letter from its, RC and
neighboring TOPs and BAs. Some entities are reluctant
to issue such blanket attestation letters and some
Regional Entities do not accept attestion letters as proof
of compliance. The SDT went on to say the Reliability
Directives are rare. The NSRF suggests changing M2 &
M3 to state: M2. When a Reliability Directive is issued,
demonstrate that it was not the result of a Reliability
Coordinator, Transmission Operator or Balancing
Authority’s failure to use documented protocols when
issuing an Operating Instruction developed for
Requirement 1. M3. When a Reliability Directive is
issued, demonstrate that it was not the result of a
failure of the Reliability Coordinator, Transmission
Operator, Balancing Authority, Generator Operator or
Distribution Provider to repeat, restate, rephrase, or
recapitulate an Operating Instruction, when required by
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another Reliability Coordinator, Transmission Operator
or Balancing Authority.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Alliant Energy
American Transmission
Company, LLC
Yes
Yes
And ATC supports the communication protocols
identified in R1. However, ATC proposes changing R2
and R3 to make the protocols for issuing and receiving
Operational Instructions consistent with the protocols
for issuing and receiving Reliability Directives as defined
in R2 and R3 of proposed Reliability Standard COM-0023 as follows: R2. When instructed by a Balancing
Authority, Reliability Coordinator, or Transmission
Operator to repeat, restate, rephrase, or recapitulate an
Operational Instruction, each Balancing Authority,
Transmission Operator, Generator Operator, or
Distribution Provider,that is the recipient of a
Operational Instruction, shall repeat, restate, rephrase,
or recapitulate the Operational Instruction. R3. Each
Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Operational Instruction
shall either: • Confirm that the response from the
recipient of the Operational Instruction (in accordance
with Requirement R2) was accurate, or • Reissue the
Operational Instruction to resolve a misunderstanding.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall implement its
communication protocols developed in Requirement R1
in a manner which identifies and corrects deficiencies in
said communication protocols.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Exelon and its affiliates
Yes
Exelon supports COM-003 Draft 6 but would like to
submit the following comments for consideration by the
SDT: Suggest rewording the last sentence of M2 to read:
A Balancing Authority, Reliability Coordinator, and
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Tri-State Generation and
Transmission
Association, Inc.
No
DTE Electric
Florida Municipal Power
Agency
Yes
No
Transmission Operator shall coordinate with another
Reliability Coordinator, Balancing Authority and
Transmission Operator to provide this evidence. Suggest
rewording the last sentence of M3 to read: A Balancing
Authority, Generator Operator, Distribution Provider,
and Transmission Operator shall coordinate with a
Reliability Coordinator, Balancing Authority and
Transmission Operator to provide this evidence.
We appreciate the drafting team’s efforts and
persistence in the drafting of this new standard. We
believe that this proposal goes beyond what was
contemplated in the Blackout Recommendation as well
as FERC Order 693 directives 1 and 3 of paragraph 540.
We urge the drafting team to reconsider the need for a
new COM-003 standard, we already have a standard for
communication (COM-002), the requirements of the
FERC Order can be added to COM-002 with minimal
effort reducing the need for yet another standard.
Additionally, we feel that a new term to define
“Operating Instruction” is not warranted or required to
fulfill either the FERC directive or Blackout
Recommendations.
Although FMPA voted affirmative, there are still
significant improvements that can be made, and enough
significant weaknesses remain to make this a difficult
voting decision for FMPA. It still artificially separates
COM-002-3 and Reliability Directives and COM-003-1
and Operating Instructions when in reality Reliability
Directives (RD) are a subset of Operating Instructions.
Contrary to the white paper, there will likely be
confusion as to whether an instruction should or should
not be a Reliability Directive, i.e., the only real difference
is whether an Emergency condition exists or not. The
only certain distinguishing factor in practice is that the
issuer of an RD needs to identify it as an RD per COM002-3. There will still be significant Monday morning
quarterbacking after an event as to whether an
Operating Instruction should have been issued as an RD
or not, i.e., whether or not the issuer should have
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recognized an Emergency or not. The better solution is
to treat RD and Operating Instructions the same and
only differentiate with VRFs (as an alalogy, look at
difference between R1 and R2 of FAC-003-2) and
whether there should be a difference in treatment
regarding “zero tolerance” for RDs and some tolerance
for Operating Instructions.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Reliability Directives on “all-calls” are still a problem It
still makes 3-part communication optional for Operating
Instructions. Does “optional” meet FERC’s directive, i.e.”
requires tightened communications protocols, especially
for communications during alerts and emergencies”
(Order 693, P 540) and ”(w)e also believe an integral
component in tightening the protocols is to establish
communication uniformity as much as practical on a
continent-wide basis … This is important because the
Bulk- Power System is so tightly interconnected that
system impacts often cross several operating entities’
areas.” (Order 693, P 532)? At minimum, the standard
should require 3-part communication for alerts in
addition to Emergencies. R2 and R3 try to limit potential
violations for failure to follow the subject of the
requirement (i.e., R2: “Each (responsible entity) shall
implement its communication protocols developed in
Requirement R1”) would not actually result in a violation
unless an Emergency occurred as described in the
predicate, (e.g., R2: “so that the failure to use the
protocols by the issuer of an Operating Instruction does
not result in an operating condition that requires the
issuance of a Reliability Directive ….”). Remember,
Reliability Directives are only given in a state of
Emergency (Reliability Directive: “A communication
initiated by a Reliability Coordinator, Transmission
Operator, or Balancing Authority where action by the
recipient is necessary to address an Emergency or
Adverse Reliability Impact”). Does this serve reliability
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well, must we get to a state of Emergency to have a
violation to the standard – and doesn’t that just
highlight potential double jeopardy and overlap
between COM-002-3 and COM-003-1, e.g., if an
Operating Instruction is issued in COM-003-1 that is not
followed that results in the same instruction being given
as a Reliability Directive? This of course begs the
question of whether or not the System Operator should
have issued an RD in the first place. Does this address
FERC’s requirement to tighten communication
protocols, including emergencies and alerts? In addition,
we don’t think the actual language limits the potential
violations to those that meet the predicate as intended
(i.e.., we do not think the predicate – “so that …” –
modifies the subject so much as it describes and repeats
the purpose of the standard. In other words, to us the
requirements can be interpreted that the subject must
always be met “so that” the purpose/predicate is
accomplished. Hence, we do not think that it solves the
zero tolerance issue without stating the requirement in
a smilar manner as the Measure is stated). Note that the
Measure confirms that an Emergency is intended for
potential violation: “Each (responsible entity) shall
provide evidence that it did not issue an Operating
Instruction that resulted in an operating condition that
required the issuance of a Reliability Directive …”. We
still strongly believe that the better solution is to cause
COM-003-1 to address Reliability Directives and retire
COM-002-3. After all, when issuing a Reliability
Directive, don’t we want the issuer to speak English, use
a consistent clock time with their neighbors, etc., for
which COM-002-3 is silent but COM-003-1 specifies? We
still have not heard a good reason why this is not being
done. We also think that it is necessary to require 3-part
communication for “alerts” to meet FERC’s directives.
Don’t we want 3-part communication to be followed
during alerts?
Response: The language of R2 and R3 has been changed
to reflect the new approach.
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CenterPoint Energy
Houston Electric LLC.
Keys Energy Services
Indiana Municipal Power
Agency
No
No explanation
Yes
There is no place to submit “other” comments, so
Indiana Municipal Power Agency (IMPA) is submitting
comments under this question. For requirement R3,
how will entities (BA, TOP, GOP, and DP) who are
responsible for the repeat back of the Operating
Instruction know the “when required by the issuer” part
of the requirement is in place or being required by the
issuer? Will the issuer be stating their request is an
Operating Instruction or be asking for the receiver to
please repeat the Operating Instruction back to them?
Maybe the issuer of the Operating Instruction can make
their communication protocol available to the receiving
entities in Requirement R3 to allow them to be familiar
with their protocols which may help with know when a
repeat back is required by the issuer.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
HHWP
No
Bureau of Reclamation
No
The draft standard does not clearly articulate the
purpose nor an appropriate results based approach to
addressing FERC objective to ensure clear
communications between operators and users of the
BES.
The Bureau of Reclamation believes that the proposed
changes to COM-003-1 do not adequately address Order
693 directives or 2003 Blackout Report
Recommendation No. 26. First, Order 693 Paragraph
512 directed the ERO to modify COM-002-2 to address
“both normal and emergency operations,” and because
each Transmission Operator (TOP), Balancing Authority
(BA), and Reliability Coordinator (RC) is able to design
their own Operating Instructions under R1 of the
proposed revision, Reclamation is unable to ascertain
whether Operating Instructions will apply to normal
operations. Second, Paragraph 532 of Order 693
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specified that “an integral component in tightening
[communication] protocols is to establish
communication uniformity as much as practical on a
continent-wide basis.” As written, R1 would allow each
BA and TOP to develop their own Operating Instructions,
which does not promote the continent-wide uniformity
called for by FERC in Order 693. Third, the 2003 Blackout
Report Recommendation No. 26 specified that NERC
should improve internal and external communications
during “alerts, emergencies, or other critical situations.”
Under the proposed definition of Operating Instruction
and R1, it seems that BAs and TOPs have discretion to
determine under what conditions Operating Instructions
are issued in their operating area, so it is not possible for
Reclamation to determine whether Recommendation
No. 26 is adequately addressed by the standard. In
addition, Reclamation would like to emphasize that the
revised definition of Operating Instruction is not clear
enough to distinguish between real-time operations
coordination (“discussion of general information and
potential options”?), Operating Instructions (applicable
in circumstances as defined by various TOPs and BAs),
and Reliability Directives (real-time emergency
conditions addressed by COM-002). COM-003 does not
clearly define the timeframe for Operating Instructions,
and should make clear what the line of demarcation is
between “real-time emergency” communications
governed by COM-002 and other alert conditions
governed by COM-003. If each BA and TOP is allowed to
define separate circumstances under which “Operating
Instructions” apply, Reclamation believes that COM-003
will not achieve continent-wide standardization of
communications protocol that FERC recommended in
Order 693. Also, Reclamation does not believe that
violations of R3 should be tied to a failure to repeat an
Operating Instruction only if it “result[s] in an operating
condition that required the issuance of a Reliability
Directive.” To reinforce the importance of repeat-back
communications, repeat-back communications should
be required under all circumstances like in the aviation
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industry. Further, Reclamation believes that Generator
Operators (GOPs) and Distribution Providers should
provide concurrence or have a role in Operating
Instructions development required under R1 to avoid
potential miscommunications (e.g., in nomenclature for
Transmission interface elements).
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Lastly, Reclamation believes that COM-002 should
include provisions parallel to IRO-001 and TOP-001 that
allow Generator Operators to inform the TOP, BA, or RC
that they are unable to comply with an Operating
Instruction because the actions requested “would
violate safety, equipment, regulatory or statutory
requirements” so that the TOP, BA, or RC “can
implement alternate remedial actions,” If the intent of
the standard is to avoid Operating Instructions
escalating to Reliability Directives, GOPs should be able
to inform the TOP, BA or RC of their “inability to
perform” the Operating Instruction like they are able to
inform the TOP, BA, or RC of the inability to perform a
Reliability Directive. The Bureau is proactive about
assisting with transmission system events, but at certain
times of year dramatic changes in reservoir levels could
endanger the public in reservoirs or on rivers, could
cause unlawful total dissolved gas (TDG) levels, or
violate Endangered Species Act requirements. Other
safety and equipment circumstances could also lead to
an inability to follow an Operating Instruction.
Reclamation suggests that the previous draft of the
standard was clearer and that perhaps the drafting team
could revisit it.
Response: This scope of this standard, as defined by the
SAR, only considers communication protocols. The
obligation to follow “directives” is defined elsewhere in
the body of standards.
Liberty Electric Power
Yes
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Hydro One Networks Inc.
No
We support this proposed draft (version 6) of the
standard on the basis of it being a compromise between
what the industry would like to see and what the US
regulator is mandating. That said, we still have concerns
with the proposed standard (comment below). As
proposed, the standard may be ambiguous and difficult
to measure. For example, Requirement 2, states that the
entity shall implement its communication protocols in
such a way that failure to use them would not result in
an operating condition that requires the issuance of a
Reliability Directive. How does the SDT envision
enforcing such requirement? It is difficult to determine if
the failure to follow the protocols when addressing
Operating Instructions is truly the reason for a new
operating condition that requires issuance of a
Reliability Directive or is the result of the original
instruction being insufficient or in error. Also, the
corresponding measure M2 puts the burden on the
entities to provide evidence that it did not have any such
cases. We see this as an ever encompassing and
burdensome approach for collecting and presenting
evidence.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
The issue of three-part communications has always been
very central to the development of this standard. So far
the SDT has not been able to produce a draft standard
to achieve industry consensus on this issue. While at
least partially addressing FERC orders, we believe that
the approach the SDT chose, makes the day-to-day
duties inside the control room more complicated,
cumbersome and hard to implement. If the current
version 6 does not achieve the required industry
approval rate, we still stand by our prior comments and
consideration should be given to modify the COM-002
standard to incorporate into it the matters that COM003 has been trying to address, all in one
communications standard.
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Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
FirstEnergy
yes
(1) FirstEnergy (FE) believes that Requirement 2 is
confusing as worded, and as such, we propose the
following for clarity: [R2. Each Balancing Authority,
Reliability Coordinator, and Transmission Operator that
issues an Operating Instruction shall follow its
documented communication protocols developed in
Requirement R1 such that it does not result in an
operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator.] (2) FE
believes that clarity will also be attained with clear and
precise RSAWs. The latest RSAW that has been posted is
applicable to Draft 4 and provides no guidance to
stakeholders the intent of the requirements from Draft
6. FE appreciates the FAQs from July 2, 2013 Industry
Webinar the SDT has provided and would recommend
the SDT incorporate into the RSAW for Requirement 2
the intent of the response to Question 2 regarding when
an evaluation to an Operating Instruction shall be used
as evidence.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Public Service Enterprise
Group
Deseret Power Electric
Cooperative
Yes
No
As written, R1 would allow each BA and TOP to develop
their own Operating Instructions, which does not
promote the continent-wide uniformity called for by
FERC in Order 693. The revised definition of Operating
Instruction is not clear enough to distinguish between
real-time operations coordination ("discussion of
general information and potential options"?), Operating
Instructions (applicable in circumstances as defined by
various TOPs and BAs), and Reliability Directives (real-
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time emergency conditions addressed by COM-002).
COM-003 does not clearly define the time frame for
Operating Instructions, and should make clear what the
line of demarcation is between "real-time emergency"
communications governed by COM-002 and other alert
conditions governed by COM-003. If each BA and TOP is
allowed to define separate circumstances under which
"Operating Instructions" apply, Reclamation believes
that COM-003 will not achieve continent-wide
standardization of communications protocol that FERC
recommended in Order 693. COM-003 should include
provisions parallel to IRO-001 and TOP-001 that allow
Generator Operators to inform the TOP, BA, or RC that
they are unable to comply with an Operating Instruction
because the actions requested "would violate safety,
equipment, regulatory or statutory requirements" so
that the TOP, BA, or RC "can implement alternate
remedial actions," If the intent of the standard is to
avoid Operating Instructions escalating to Reliability
Directives, GOPs should be able to inform the TOP, BA or
RC of their "inability to perform" the Operating
Instruction like they are able to inform the TOP, BA, or
RC of the inability to perform a Reliability Directive.
Duke Energy
Yes
Response: This scope of this standard, as defined by the
SAR, only considers communication protocols. The
obligation to follow “directives” is defined elsewhere in
the body of standards.
Duke Energy agrees in part that draft 6 of the proposed
COM-003-1 does address the recommendations of the
2003 Blackout Report, FERC Order 693, and the COM003-1 SAR. However, Duke Energy believes that this
draft has gone beyond the expectations outlined in the
documents mentioned above. Measure 3 should be
changed to “when required by the issuer” in order to
provide clarity and consistency with R3. Requirement 2
language leads to uncertainty (risk) as to when an
Operating Instruction will become a Reliability Directive.
This could negatively impact BES reliability in creating
reluctance, by the entity, to issue a Reliability Directive
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and furthermore places Operators in the position of
acting in compliance with the Requirement at the time
only to be deemed non-compliant later when
circumstances change. This is an untenable position and
leads to less reliability. Such a finding of non-compliance
cannot be mitigated leaving the Responsible Entity
without means to “control” performance. We are also
concerned with the language in Requirement 2 “so
that”. This vague language can be interpreted as to
intent which is unmeasurable and therefore adds to the
uncertainty (risk).
Response: The language of R2 and R3 has been changed
to reflect the new approach.
In addition, Duke Energy believes that a statement
needs to be added in R1 that includes providing or
distributing those communication protocols developed
by a BA or TOP to their associated DPs and GOPs. This
would address a potential gap of DPs and GOPs not
aware of the communication expectations when
communicating with BAs and TOPs when given an
Operating Instruction. Lastly, while Duke Energy
applauds the efforts made by the SDT, we are not
convinced that a standard can be developed that will
garner the requisite support from industry stakeholders.
Duke Energy recommends the SDT to delineate other
options, such as a Guideline document or White Paper,
before addressing the recommendations in the 2003
Blackout Report.
Northeast Utilities
Pacific Gas and Electric
Company
Yes
No
Pacific Gas and Electric believes that the proposed
changes to COM-003-1 do not adequately address Order
693 directives or 2003 Blackout Report
Recommendation No. 26. First, Order 693 Paragraph
512 directed the ERO to modify COM-002-2 to address
"both normal and emergency operations," and because
each Transmission Operator (TOP), Balancing Authority
(BA), and Reliability Coordinator (RC) is able to design
their own Operating Instructions under R1 of the
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proposed revision, PG&E is unable to ascertain whether
Operating Instructions will apply to normal operations.
Second, Paragraph 532 of Order 693 specified that "an
integral component in tightening [communication]
protocols is to establish communication uniformity as
much as practical on a continent-wide basis." As written,
R1 would allow each BA and TOP to develop their own
Operating Instructions, which does not promote the
continent-wide uniformity called for by FERC in Order
693. Third, the 2003 Blackout Report Recommendation
No. 26 specified that NERC should improve internal and
external communications during "alerts, emergencies, or
other critical situations." Under the proposed definition
of Operating Instruction and R1, it seems that BAs and
TOPs have discretion to determine under what
conditions Operating Instructions are issued in their
operating area, so it is not possible to determine
whether Recommendation No. 26 is adequately
addressed by the standard. In addition, PG&E would like
to emphasize that the revised definition of Operating
Instruction is not clear enough to distinguish between
real-time operations coordination ("discussion of
general information and potential options"?), Operating
Instructions (applicable in circumstances as defined by
various TOPs and BAs), and Reliability Directives (realtime emergency conditions addressed by COM-002).
COM-003 does not clearly define the timeframe for
Operating Instructions, and should make clear what the
line of demarcation is between "real-time emergency"
communications governed by COM-002 and other alert
conditions governed by COM-003. If each BA and TOP is
allowed to define separate circumstances under which
"Operating Instructions" apply, PG&E believes that
COM-003 will not achieve continent-wide
standardization of communications protocol that FERC
recommended in Order 693. Also, PG&E does not
believe that violations of R3 should be tied to a failure to
repeat an Operating Instruction only if it "result[s] in an
operating condition that required the issuance of a
Reliability Directive." To reinforce the importance of
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repeat-back communications, repeat-back
communications should be required under all
circumstances like in the aviation industry. The use of
three-way communication has been proven as an
effective error prevention tool in the military, aviation,
and in the nuclear power industry. It is time that the
same discipline and rigor be implemented in the electric
industry. The current version of this Standard is moving
away from reliability and will be difficult for compliance
and enforcement. Further, Generator Operators (GOPs)
and Distribution Providers should provide concurrence
or have a role in Operating Instructions development
required under R1 to avoid potential
miscommunications (e.g., in nomenclature for
Transmission interface elements).
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Puget Sound Energy
No
PG&E suggests that the previous draft of the standard
was clearer and that perhaps the drafting team could
revisit it.
Puget Sound Energy appreciates the drafting team's
work to simplify the requirements of this standard and
believes that the standard's language is moving in the
right direction. However, Puget Sound Energy cannot
vote to approve this standard for the following reasons.
Requirement R1, by requiring the Reliability Coordinator
(RC) to approve each communication protocol, is
unnecessarily burdensome on the RC and all the entities
that must receive that approval. This type of approval
makes sense for restoration plans (EOP-005-2) because
of the required coordination in an emergency situation,
but not for the communications protocols that apply in
non-emergency situations. There is certainly a benefit to
uniformity of communication protocols within an
interconnection; however, uniformity should be
achieved by requiring the RC to specify its requirements
for communication protocols and then requiring
Balancing Authorities and Transmission Operators to
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comply with that specification (similar to the approach
of IRO-010). There should be an additional requirement
for Reliability Coordinators, Balancing Authorities and
Transmission Operators to provide information about
the communication protocol requirements that apply to
other entities within their area to those entities. It is
only appropriate to hold an entity responsible for
complying with communication protocol requirements
when it has advance notice of what those requirements
will be.
Response: The RC approval has been removed from the
draft 7.
The language connecting miscommunications to
Reliability Directives in requirements R2 and R3, along
with the associated VSLs, should address degrees of
compliance. While the approach does narrow the scope
of possible violations, it seems that the language could
easily lead to a debate on whether a miscommunication
"results in" an impact. Typically, events have many
elements that contribute to their occurrence and in
some cases a miscommunication might only indirectly or
tangentially relate to the event. Given the assigned VSL
of severe for all violations of these requirements, a
miscommunication with an indirect relationship to a
subsequent Reliability Directive will likely have the same
compliance impact as one that has a more direct and
substantial relationship. Thank you for your
consideration of these comments.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
SCE&G
No
FERC Order 693 states "We also believe an integral
component in tightening the protocols is to establish
communication uniformity as much as practical on a
continent-wide basis." R1 allows each BA, RC, and TOP
to develop their own, separate communication
protocols. Criteria 1.1 thru 1.5 are open-ended. As a
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result, each BA and TOP will have different protocols
that they submit to the RC for approval. The standard
does not give RCs guidance on how to evaluate
submitted protocols for consistency/uniformity before
approval. Without such guidance, it is unclear how
consistency and uniformity will be promoted among the
various BA/TOP documented protocols. Furthermore, if
such criteria were added, the standard would still only
promote uniformity within an RC footprint. It would not
promote uniformity across the continent, as directed
within Order 693, or even the regions. It seems the only
way for the SDT to fully address the FERC directive, is for
the SDT to specify the specific protocols they want BAs
TOPs and RCs to use. Many entities are opposed to this
approach because they are concerned about monitoring
and maintaining compliance with such a standard. These
concerns could be alleviated if the SDT writes the
standard in a way such that a violation only occurs if a
BES Emergency results from failure to use the specified
protocols.
Response: The RC approval has been removed from the
draft 7.
PJM Interconnection,
L.L.C.
No
PJM does not support Draft 6 of this standard. There is a
concern specific to the potential, unintended
compliance responsibility in R2 because of the way the
requirement is written, as well as the associated M2.
Applicable entities will be required to prove a negative
which may result in unnecessary Root Cause Analysis
(RCA) efforts that are not required and are solely
performed to satisfy an administrative, compliance item,
yet adds no discernible reliability value.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Santee Cooper
No
Santee Cooper believes the issuing authority should
specifically identify a communication as an Operating
Instruction, thereby triggering the need for three-part
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Cooper Compliance Corp
No
communications, and the receiver to use three part.
While we agree that the proposed Standard addresses
the FERC Order 693, we do not feel that R3 is well
drafted and assumes that the distribution provider or
generator operator would be able to determine if the
Operating Instruction would “result in an operating
condition that requires the issuance of a Reliability
Directive by the original issuer of the Operating
Instruction or by another Balancing Authority, Reliability
Coordinator, or Transmission Operator.” In addition, the
dictionary term for restate, rephrase, or recapitulate all
have the same meaning and it seems odd that an
auditor would be able to distinguish any difference. We
suggest the drafting team simplify R3 as follows: “Each
Balancing Authority, Transmission Operator, Generator
Operator and Distribution Provider shall repeat or
restate an Operating Instruction when required by the
issuer of an Operating Instruction.”
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Luminant Energy
Company LLC
Yes
While draft 6 of COM-003-1 is largely acceptable, the
wording of R3 may create confusion about what is
required. R3 reads, in part: R3. Each Balancing Authority,
Transmission Operator, Generator Operator and
Distribution Provider shall repeat, restate, rephrase, or
recapitulate an Operating Instruction when required by
the issuer of an Operating Instruction in its
communication protocols developed in Requirement R1
so … This language suggests that the receiving entity
must know what is in the issuer's communication
protocol and repeat, restate, rephrase or recapitulate
the Operating Instruction without any prompts from the
issuer. If that is the case, then there needs to be a
requirement that the developer of a communication
protocol must provide that communication protocol to
all relevant parties prior to implementation. However,
after reading the Technical Justification, that doesn't
appear to be the intent. Rather the intent is that the
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issuer will request the receiver to repeat the Operating
Instruction back during the phone call. To make that
clear, Luminant suggests the following language change
to R3: R3. Each Balancing Authority, Transmission
Operator, Generator Operator and Distribution Provider
shall repeat, restate, rephrase, or recapitulate an
Operating Instruction when requested by the issuer of
an Operating Instruction in accordance with the
communication protocols developed in Requirement R1
so … With this change, we would be in support of this
draft standard.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
IRC Standards Review
Committee
No
The SRC has reviewed the current COM-003 posting and
offer the following comments that augments previously
provided comments on the standard. • Requirement R1
now requires each BA and TOP’s to have protocols
approved by the RC. One question certain SRC Members
have is whether the RC is being asked to “assess”
whether the BA/TOP’s protocols are “compliant” with
the Standard. Another question is whether the RC is
being asked to “approve” the TOP communication
protocols with other Registered Entities (e.g., TOs).
Depending on the answers to these questions, the SRC
proposes that the “approval” requirement could be
revised to a “coordination” obligation.
Response: The RC approval has been removed from the
draft 7.
• Requirement R2 now has add a trigger for non
compliance for not implementing the communications
protocol if following an operating instruction, a
reliability directive is issued to correct the problem
caused by a failure to implement its communication
protocol. We ask NERC to comment on whether this will
produce an obligation for compliance authorities to
begin a compliance investigation on every Reliability
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Directive to assess whether communication protocols
were followed. Reliability Directives are an important
means of communications to address all emergencies.
Poor communications have yet to be clearly identified as
a root cause. The SRC would also like NERC and the SDT
to consider comments provided by NERC at the recent
FERC Technical Conference stating, ‘complementary
approaches should also be examined where the risks to
reliability can effectively be mitigated through other
means, such as through guidelines, data collection or
other technical approaches. ‘ NERC should continue to
consider the effectiveness of the NERC Operating
Committee communications protocol. Note, ERCOT and
PJM, members of the IRC Standards Review Committee
did not join these joint comments and have submitted
individual comments.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Kansas City Power &
Light
No
SPP Standards Review
Group
Yes
Colorado Springs Utilities
No
We feel that this standard is not necessary if the COM002 standard is properly followed. Also, R3 could cause
an over burdensome amount of effort to prove
compliance with COM-003.
Although there still remain some concerns that the
intent of Recommendation 26 was strictly for
emergency situations which are covered by COM-002-3.
Colorado Springs Utilities appreciates the commitment
and long, hard work of the Drafting Team as well as the
opportunity to comment on this draft. R.1: The clause,
“subject to the Reliability Coordinator’s approval” is
unclear in its intent. If the intent is that the RC must
review and approve all Communication Protocols, there
should be discrete requirements (a la EOP-005-2 & EOP006-2) in the Standard. If that is not the explicit intent,
what is? If the intent is to make it optional or suggested
for the RC to review and approve Protocols, then that is
not a Standard – it is a suggestion. Please state whatever
is the intent clearly in the requirement. CSU proposes
the clause be removed entirely.
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Response: The RC approval has been removed from the
draft 7.
R1.3: Should be removed. This requirement is redundant
to TOP-002-2.1b, R18; “Neighboring Balancing
Authorities, Transmission Operators, Generator
Operators, Transmission Service Providers and Load
Serving Entities shall use uniform line identifiers when
referring to transmission facilities of an interconnected
network.”
Response: Project 2007-03 chose to eliminate TOP-0022a Requirement R18 when it developed TOP-002-3.
This standard, while reintroducing the concept of line
identifiers, limits the scope to only Transmission
interface Elements or Transmission interface Facilities
(e.g. tie lines and tie substations). This ensures that both
parties are readily familiar with each other’s interface
Elements and Facilities, eliminating hesitation and
confusion when referring to equipment for the
Operating Instruction. This shortens response time and
improves situational awareness.
R2 & R3: CSU prefers the language along the lines of the
previous draft (R2 & R4). The clause, “failure to use the
protocols by the issuer of an (or R3- failure to repeat,
restate, rephrase, or recapitulate the) Operating
Instruction does not result in an operating condition
that requires the issuance of a Reliability Directive” is
unworkable, probably unauditable, and definitely an
evidentiary nightmare. If one entity issues a Reliability
Directive, what chain of evidence from how many other
entities is required to prove that no other entity failed to
use its communications protocols in such a way that
failure resulted in the operating condition requiring the
first entity to issue a Reliability Directive? Or, to view it
from the other direction: if CSU is being audited on
compliance with COM-003-1, how shall it prove that it
did not have a failure to properly implement any
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communication protocol which then contributed to
operating conditions which may have required any other
reliability entity in the western interconnect to have to
issue a Reliability Directive? How does one establish the
causal relationship, or lack thereof? In lieu of a return to
the previous draft’s language, CSU recommends adding
another sub-part to R1, “R1.6 A method to assess
System Operator’s communication practices and
implement improvements as necessary to meet the
expectations in its documented communications
protocols developed for this Requirement.” Then R2
could be written, “Each … shall implement its
communication protocols developed in R1.” R3 could
state, “Each … shall repeat, restate, rephrase, or
recapitulate an Operating Instruction, when required by
the issuer in its communication protocols developed in
requirement R1, to the satisfaction of the issuing System
Operator.” M2 & M3: Reliability Standards need to get
away from asking for negative evidence. The Standard is
probably written incorrectly if negative evidence is
required for compliance. Even sticking with the negative
theme; “Each … shall provide evidence that it did not fail
to use its documented communications protocols
developed for Requirement R1 in a way that resulted in
an operating condition that required to issue
a Reliability Directive,” comes closer to supporting the
Requirement as drafted. Thank you! Sincerely, Colorado
Springs Utilities
Response: The language of R2 and R3 has been changed
to reflect the new approach.
DTE Electric Co
No
In response to request for comment number 1 and a
literal reading of the question and associated
documents:
The August 2003 Blackout Report Recommendation
number 26 speaks to “tightening communication
protocols, especially for communications during alerts
and emengencies.” In the context of the entire
document, it highlights the lack of sharing of critical
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information during the blackout event. It does not really
address “Operating Instructions” or mention a failure to
correctly understand, follow or execute a
direction/instruction. The focus is on what information
would have assisted the operators in dealing with the
event, not mistakes in execution of Operating
Instructions. Page 109 of the report summarizes
“Effecitiveness of Communications” and states “Under
normal conditions, parties with reliability responsibility
need to communicate important and prioritized
information to each other in a timely way, to help
preserve the integrity of the grid. This is especially
important in emergencies. During emergencies,
operators should be relieved of duties unrelated to
preserving the grid. A common factor in several of the
events described above was that information about
outages occurring in one system was not provided to
neighboring systems.” Information exchange seems to
be the focus, not communication of Operating
Instruction.
FERC Order 693 (which refers back to the Blackout
Report) also requires tightening communication
protocols “especially for communications during alerts
and emergencies” to “establish communication
uniformity” and “eliminate ambiguities.” The proposed
standard is focused on Operating Instructions and lacks
requirements regarding consistency in information
sharing.
Regarding COM-003-1 SAR, the SAR states its’s scope is
“to establish essential elements of communications
protocols and communications paths such that
operators and users of the North American bulk electric
system will efficiently convey information and ensure
mutual understanding. “ It also states that the purpose
of the standard is “to ensure that effective
communication is practiced and delivered in clear
language via pre-established communications paths
among pre-identified operating entities.” Version 6 of
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COM-003-1 does not address Applicablity number 1
“relay critical reliability-related information in a timely
and effective manner.” It also does not address
Applicablity number 3: “requirements for entities that
experience abnormal conditions to use pre-defined
terms such as proposed in the “Alert Level Guideline”
(attached) to communicate the operating condition to
other entities that are in a position to either assist in
resolving the operating situation condition or to entities
that are impacted by the operating condition.” It only
focuses on Operating Instructions, not communication
of the status/condition of the electrical system. The SAR
Scope mentions “consistency across regions,” yet the
standard does not address RC to RC communications
within/across regions.
The purpose of COM-003-1 revision 1 was closer to
addressing the above than the purpose in revision 6. It
seems the standard has strayed from the intent and
although there may be value in having a standard that
addresses protocols for issuance of Operating
Instructions, this version does not address the concerns
laid out in the documents listed above. Items such as
sharing of tie line trips, major generation loss trips, high
risk situations/evolutions (possibly tripping critical
items), loss of EMS capabilities/control center
functionality, declared alerts/emergencies and other
pertinent information would be the types of information
would be standardized and addressed in a standard in
order to meet the objectives of the SAR and FERC rather
than Operating Instructions.
General comments regarding revision 6 of the standard
“as written,” the purpose of which is different from the
question asked in the comment form:
As this standard seems to focus on verbal
communication, written communications should not be
included this standard. It is not clear what is intended to
be in scope for “written” Operating Instruction. The
standard should not introduce vague terminology
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subject to different interpretations. If there is a need (or
reliability reason) to address written Operating
Instructions, they should be included in a separate
standard. Focus on 3-way communication and use of
alpha-numeric clarifiers in COM-003-1 do not readily fit
written communications. Not sure how R2 and R3 would
be applied to written Operating Instruction.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Since COM-003-1 has emphasized the difference
between Operating Instruction and Reliability Directive
as exclusive and distinct, it appears that COM-003-1
communication protocols are more strict for Operating
Instruction (regarding use of time zone, alpha-numeric
clarifiers, etc.) than COM-002-3 requiring only 3-way
communication (no time zone, etc.). If COM-003-1
protocols (other than 3-way communication) are not
followed for Reliability Directives, there is no standard
violation of either COM-002-3 or COM-003-1. This
seems to leave a reliability gap.
Response: The posted version of COM-002-4 combines
COM-002-3 and COM-003-1 into a single standard.
Should NOT require RC approval of an entity’s
communication protocol. By requiring RC approval of
each responsible entity’s communication protocol
document,it sets up the possibility of disagreements.
Entities should be responsible to develop protocols that
are compatible with RC protocols, but that may differ on
the “downstream” side (i.e. with entity’s
field personel). This may be required if RC demands use
of Standard Time and BA must communicate with field
personel in Daylight Time. RC should not be able to
dictate these types of issues. No defined resolution
process in cases of disagreement. If RC is final word,
then standard should require RC to develop protocol
with input from other entities and all entities should use
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RC protocol (no requirement for individual protocols).
Who would “approve” RC to RC communication
protocols?
Response: The RC approval has been removed from the
draft 7.
R2 and R3 documentation is onerous. It really requires a
coordinated investigation into every Reliability Directive
that is issued to verify it was NOT caused by a
communication protocol violation somewhere in the
chain (as it may not be between just two responsible
entities/protocol documents). How wide a net needs to
be cast in gathering attestations of “No Reliability
Directives issued?” How deep in connected systems or
entities? An entity may issue a Reliability Directive to a
different entity than violated the communication
protocol if that problem surfaces in their system.
Response: The language of R2 and R3 has been changed
to reflect the new approach.
Comments - Stefaniak: R1.1, R 1.2, R1.3: It is not clear
what is intended to be in scope for “written” Operating
Instruction. The standard should not introduce vague
terminology subject to different interpretations.
R2, R3: Failing to use communication protocols would
not directly lead to an operating condition that requires
the issuance of a Reliability Directive. It is more likely
that failing to use communication protocols could cause
an Operating Instruction to be incorrectly executed.
Such an error could lead to an operating condition that
requires the issuance of a Reliability Directive. Consider
changing R2 and R3 as follows:
R2. Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall implement its
communication protocols developed in Requirement R1
so that the failure to use the protocols by the issuer of
an Operating Instruction does not result in an Operating
Instruction to be incorrectly executed thus leading to an
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operating condition that requires the issuance of a
Reliability Directive by the original issuer of the
Operating Instruction or by another Balancing Authority,
Reliability Coordinator, or Transmission Operator.
[Violation Risk Factor: Medium][Time Horizon: Real Time
Operations ]
R3. Each Balancing Authority, Transmission Operator,
Generator Operator and Distribution Provider shall
repeat, restate, rephrase, or recapitulate an Operating
Instruction when required by the issuer of an Operating
Instruction in its communication protocols developed in
Requirement R1 so that the failure to repeat, restate,
rephrase, or recapitulate the Operating Instruction does
not result in an Operating Instruction to be incorrectly
executed thus leading to an operating condition that
requires the issuance of a Reliability Directive by the
original issuer of the Operating Instruction or by another
Balancing Authority, Reliability Coordinator, or
Transmission Operator. [Violation Risk Factor:
Medium][Time Horizon: Real Time Operations ]
2. Do you agree with the VRFs and VSLs for Requirements R1, R2, and R3?
In light of the recommendation to combine the COM-002 and COM-003 standard and because the
OPCPSDT has not had the opportunity to ballot a combined standard, the OPCP SDT has created draft 7 as
COM-002-4, which creates a single combined standard. The OPCP SDT also considered the essential
elements and evaluated whether they should be included within the combined standard. This change in
the proposed standard led to changes in VRFs and VSLs. Given that, the comments below are not
responded to individually because they are no longer relevant to the current version of the standard.
Organization
Yes/No
Comment
Oncor Electric Delivery
No
R2 – it is unclear how a “failure” of using an operating
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GSOC
NO
NPCC
No
protocol results in a reliability directive therefore the
VSL indicates a zero tolerance level of performance
which does not align to reliability based performance.
R3 – not all failures of using three-part communication
will automatically led to a Reliability Directive so the VSL
should be designed to support more than a failure to
use the protocols by the issuer of an Operating
Instruction does not result
No, regarding R2 and R3, GSOC recommends to revise
the wording as follows. In particular, we believe it
adventageous to use NERC's definition of Emergency
(BES Emergency) to provide entities escalting levels of
severity as opposed to the single VSL - severe that
appears in the current Draft 6. R2 - Each Balancing
Authority, Reliability Coordinator, and Transmission
Operator (R3 - Each Balancing Authority, Transmission
Operator, Generator Operator and Distribution
Provider) shall implement its communication protocols
developed in Requirement R1 so that the failure to use
the protocols by the issuer of an Operating Instruction
does not result in any of the following: • Any abnormal
system condition that requires automatic or immediate
manual action to prevent the failure of transmission
facilities or generation supply that could adversely affect
the reliability of the Bulk Electric System. • The failure of
transmission facilities or generation supply that could
adversely affect the reliability of the Bulk Electric System
and automatic or immediate manual action to limit the
failure was required. • An Adverse Reliability Impact
We agree with the VRFs, but not the VSLs because of the
concerns with Requirements R2 and R3. We do not
agree with the Long-term Planning Time Horizon for R1.
Developing and documenting communication protocols
for use during real-time operations is an operational
planning process (or mid-term planning, at most), not a
long-term planning process. We suggest to change the
Time Horizon to Operations Planning. Regarding the
Implementation Plan, it conflicts with Ontario regulatory
practice with regards to the effective date of the
standard. It is suggested that this conflict be removed by
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appending to the effective date wording, after
“applicable regulatory approval” in the Effective Dates
Section of the Implementation Plan: “, or, in those
jurisdictions as otherwise made effective pursuant to
the laws applicable to such ERO governmental
authorities.”
Manitoba Hydro
NERC Compliance Group
PacifiCorp
Yes
Yes
No
Arizona Public Service
Company
Consolidated Edison Co.
of NY, Inc.
Yes
No
PacifiCorp does not agree with the VRFs and VSLs
associated with R2 because it is not clear how R2 is
measured. M2 would require an entity to provide
evidence that it did not issue an Operating Instruction
that resulted in an operating condition that required the
issuance of a Reliability Directive by the issuer or
another Balancing Authority, Reliability Coordinator, or
Transmission Operator due to the failure to use
documented communications protocols developed for
Requirement R1. In essence, an entity is required to
prove that it did not do something that resulted in a
condition which caused another entity to be issued a
directive (that it may or may not be privy to, depending
upon whether or not it was the original issuer of said
directive). A requirement that is measured by the
absence of evidence creates a challenging auditing
environment for the industry. PacifiCorp strongly
recommends that the drafting team reconsider the
measures required for proving compliance with R2.
FERC requires that VSL’s be graded. The Requirement R3
VSL should be modified to reflect the following graded
proposal: “The first failure following the effective date
of this standard is a “Low VSL.” However, should failures
be more frequent, then the severity level for such
failures should be increased. “For the second and
subsequent failures following the effective date of the
standard a single failure within a given 12-month rolling
period is a Moderate VSL. “For the second and
subsequent failures following the effective date of the
standard and when there is more than one failure within
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a given 12-month rolling period the failure is a Severe
VSL.”
Flathead Electric
Cooperative, Inc.
Occidental Energy
Ventures Corp.
ReliabilityFirst
No
City of Garland
No
Dominion
Yes
Yes
No
ReliabilityFirst has a concern with the VSLs for
Requirement R1. In the previous draft, the VSLs for
Requirement R1 were gradated based on missing “x” out
of nine sub-parts. For example, missing 44% (four out of
nine) of the sub-parts was a Severe VSL). With the
current draft only including five sub-parts under
Requirement R1, the gradation should be adjusted
accordingly. ReliabilityFirst believes that an entity not
addressing more than half of the sub-parts within the
documented communication protocols is missing the
intent of the requirement and should be a Severe VSL.
Furthermore, if the “…subject to the Reliability
Coordinator’s approval…” language continues to remain
in Requirement R1 (against our recommendations in
previous comments), this “Reliability Coordinator
approval” needs to be included in the VSLs as well.
ReliabilityFirst offers the following as an example for
consideration: i. Lower VSL – none ii. Moderate VSL –
“…did not develop one (1) of the five (5) parts…” iii. High
VSL – “…did not develop one (2) of the five (5) parts…”
iv. Severe VSL - “…did not develop one (3) of the five (5)
parts…” v. Severe VSL - “The Responsible Entity did not
receive Reliability Coordinator approval of its
documented communication protocols as required in
Requirement R1.”
R2 & R3 only have a “Severe VSL” listing - As I
understand it, NERC has recognized that “perfect”
historical compliance is not practical and is one of the
reasons NERC is moving to implement the RAI program.
R2 & R3 Severe VSL only listings require 100% perfection
- Real life operations is not perfect (as recongnized by
the RAI) – VSLs should be a gradient from “lower” to
“severe”
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North American
Generator Forum
Standards Review Team
Independent Electricity
System Operator
No
Yes
Bonneville Power
Yes
Administration
Clark Public Utilities
Yes
Southern Company:
Southern Company
Services, Inc; Alabama
Power Company; Georgia
Power Company; Gulf
Power Company;
Mississippi Power
Company; Southern
Company Generation and
Energy Marketing
The VRF and VSL language for R3 should be changed to
that of the draft version of Draft 6 that was commentedon by the NAGF several weeks ago.
We agree with the VRFs, but not the VSL since we do not
agree with Requirements R2 and R3. We offer the
following two additional comments: 1. We do not agree
with the Long-term Planning Time Horizon for R1.
Developing and documenting communication protocols
for use during real-time operations is an operational
planning process (or mid-term planning, at most), not a
long-term planning process. We suggest to change the
Time Horizon to Operations Planning. 2. The proposed
Implementation Plan conflicts with Ontario regulatory
practice with respect to the effective date of the
standard. It is suggested that this conflict be removed by
appending to the effective date wording, after
“applicable regulatory approval” in the Effective Dates
Section of the Implementation Plan, to the following
effect: “, or as otherwise made effective pursuant to the
laws applicable to such ERO governmental authorities.”
Prior to the wording “; or, In those jurisdiction….”.
Alternatively, the same language in the Effective Dates
Section of the Implementation Plan could be used.
R1 • The phrase “subject to the Reliability Coordinator’s
approval” is included in the requirement, but there is no
reference to RC approval in the measure. It is unclear
exactly what the expectations are for TOPs and BAs in
this requirement. Are they to develop protocols and
submit to the RC for approval, and have a record of this
approval for compliance evidence? If so, the SDT needs
to modify this requirement to make the required actions
very clear. EOP-005-2 is an example of the TOP getting
approval from the RC on its restoration plan. This may
be a better model to use as it is more clear. • In
addition, the RC is required to approve its TOPs / BAs
protocols; however there is no guidance on what criteria
to base this approval on. There needs to be very clear
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Oklahoma Gas & Electric
Yes
Seminole Electric
Cooperative, Inc.
Wisconsin Public Service
Corp
Minnesota Power
No
ACES Standards
Collaborators
No
guidance that RCs are to ensure that the protocols are
compatible with its protocol and that RCs are not
“auditing” the TOPs / BAs protocols to confirm they
include all the subparts of requirement R1. R3 • R3 can
present an excessive or even impossible compliance
burden, in that all parties receiving Operating
Instructions must prove that no BA, RC or TOP issued a
Reliability Directive as a result of their lack of three-part
communication. This is not a matter of simply obtaining
annually a “No known errors” letter from the BA, RC and
TOP with which a receiving-end entity is directly
involved, since all the neighboring BAs, RCs and TOPs
are drawin-in by R3 as well. There is meanwhile no
requirement that BAs, RCs or TOPs issue such letters
when requested to do so, or that they must share any
information at all regarding Reliability Directives issued.
This leaves GOPs and other entities that receive
Operating Instructions in danger of self-certifying
compliance to R3, then being later confronted with
evidence of non-compliance from a source from whom
they had previously heard nothing.
There were a couple of typos in the VSLs: R1 – Insert a
space between ‘R1’ and ‘in’ in the Lower VSL. R3 – Insert
‘to’ between ‘failed’ and ‘repeat’ in the Severe VSL.
The VSL’s are far too high given the ambiguity inherent
to the R2 and R3 requirements as written.
Yes
No
Minnesota Power supports comments submitted by the
MRO NERC Standards Review Forum (NSRF).
(1) We disagree with the VSL for R1. The compliance
violation should fall on the RC for failing to approve the
communication protocol and it should be up to the RC
to ensure the sub-parts 1.1 through 1.5 are included in
the protocol. Under the current draft, the RC has
approval authority without any accountability. The VSL
would find the entity in violation of R1, even though it
would be at the mercy of the RC to approve its protocol.
(2) The VSLs for R2 and R3 imply that a violation of COM002 also occurred. We cannot support a standard that
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has the potential for multiple violations.
Southwest Power Pool
Regional Entity
Associated Electric
Cooperative, Inc. JRO00088
Yes
seattle city light
MRO NERC Standards
Review Forum (NSRF)
Tri-State Generation and
Transmission
Association, Inc.
Yes
No
CenterPoint Energy
Houston Electric LLC.
No
No
See AECI comment to Q1 above, with respect to DPs.
While the SDT did follow Guideline 5, the resulting VSLs
with respect to communication with these functional
entities under normal operating conditions, hardly
merits a medium risk assessment, whereas COM-002
might. Further, the SDT's VRF and VSL justification for
COM 003-1, R2 "FERC VRF G1 Discussion"' assertion that
R2 is consistent with Recommendation of 26...", ignores
the same report's "particularly during..." qualifier. See
AECI response to Q1 above.
No, we believe that the minimal changes to address the
FERC directives and Blackout Recommendations should
be included as a revision to COM-002, not in a new
Standard. Additionally, the requirements to develop and
document protocols were not contemplated or
warranted in either the FERC Directives or the Blackout
Recommendations. We recommend that the drafting
team reconsider their decision to develop a new COM003 and investigate incorporating the requirements into
the existing COM-002.
As stated in its Draft 5 comments, CenterPoint Energy
firmly believes there should be no High or Severe VSL for
simply failing to document a process, protocol, or
procedure. It is counterintuitive to allow for a scenario
where an entity's System Operators are communicating
effectively and correctly and yet that has the entity
penalized with the highest severity level for not having
the appropriate documentation. Additionally,
CenterPoint Energy disagrees with the assignment of
Severe VSL for R3, when a comparable violation in COM002-3 R2 is also a Severe VSL. The VSL for failing to
repeat an O.I. and for failing to repeat an R.D. should not
be the same. CenterPoint Energy also has concerns with
the following two aspects of Draft 6: 1. CenterPoint
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Bureau of Reclamation
No
Energy disagrees with R1’s stipulation that the RC must
approve the BA’s and the TOP’s communication
protocols, especially given the SDT’s assertion that a
possible outcome is for the RC to unilaterally develop
the protocols and impose them on the BA and the TOP.
Instead, CenterPoint Energy recommends that R1 be
modified to state “Each Reliability Coordinator shall
develop, and each Balancing Authority and Transmission
Operator shall develop collaboratively with the
Reliability Coordinator, documented communication
protocols...” 2. CenterPoint Energy appreciates the
efforts of the SDT to revamp COM-003-1 so that its
Operating Instruction is compartmentalized from COM002-3’s Reliability Directive, effectively reducing the
industry’s compliance burden. However, the revision
does not ease a System Operator’s practical operational
burden of having to distinguish in real-time whether a
command that is about to be issued is an O.I. or an R.D.
Rather than focusing solely on maintaining the integrity
of the BES, an Operator may now be distracted by what
to label that command and the consequences of
assigning the incorrect label. The industry and NERC
have been working on the proposed COM-003 standard
for nearly four years, ever since the posting of draft 1 in
2009. The proposed standard is now at draft 6, and it is
becoming apparent that the industry is struggling to
achieve consensus on the specifications for COM-003.
Furthermore, it’s been more than nine years since the
release of the Blackout Report and six years since Order
693. In that interim, the industry has improved and
evolved in numerous areas, including operator
communication effectiveness. Most of all, the industry
and NERC have already approved COM-002-3 and its
associated definition of Reliability Directive, which, once
enforceable, will undoubtedly further tighten
communication. Perhaps it is time then for NERC and
the industry to start a dialogue with FERC to reevaluate
the purpose and the need for COM-003 and to request
from FERC refreshed, clear guidance on this subject.
Reclamation does not believe that R3 should only be
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accompanied by a Severe Violation Severity Level (VSL),
especially because BA and TOP “Operating Instruction”
protocols could vary significantly among BAs and TOPS.
Reclamation reiterates that if the intent of the standard
is to avoid Operating Instructions escalating to Reliability
Directives, GOPs should be able to inform the TOP, BA or
RC of their “inability to perform” an Operating
Instruction because it “would violate safety, equipment,
regulatory, or statutory requirements” so that the
Operating Instruction does not become a Reliability
Directive. Reclamation suggests that the drafting team
develop thresholds for failure to repeat that would
amount to low, medium, high or severe violations.
Hydro One Networks Inc
FirstEnergy
Deseret Power Electric
Cooperative
Yes
Yes
No
Duke Energy
no
Northeast Utilities
No
R3 should only be accompanied by a Severe Violation
Severity Level (VSL), especially because BA and TOP
"Operating Instruction" protocols could vary significantly
among BAs and TOPS. If the intent of the standard is to
avoid Operating Instructions escalating to Reliability
Directives, GOPs should be able to inform the TOP, BA or
RC of their "inability to perform" an Operating
Instruction because it "would violate safety, equipment,
regulatory, or statutory requirements" so that the
Operating Instruction does not become a Reliability
Directive. The drafting team should develop thresholds
for failure to repeat that would amount to low, medium,
high or severe violations.
Duke Energy believes that the VSL(s) need to use the
same language as in the standard requirements. In order
to stay consistent with the VSL(s), we believe that
“Functional Entities” should be replaced with
“Responsible Entities” in the Applicability Section of this
standard.
Requirements R2 and R3 need to be written to clarify
requirements. The current draft could result in differing
interpretations
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Pacific Gas and Electric
Company
No
Santee Cooper
Cooper Compliance Corp
Luminant Energy
Company LLC
Kansas City Power &
Light
SPP Standards Review
Group
Yes
Yes
Yes
Colorado Springs Utilities
Yes
PG&E does not believe that R3 should only be
accompanied by a Severe Violation Severity Level (VSL),
especially because BA and TOP "Operating Instruction"
protocols could vary significantly among BAs and TOPS.
Reclamation reiterates that if the intent of the standard
is to avoid Operating Instructions escalating to Reliability
Directives, GOPs should be able to inform the TOP, BA or
RC of their "inability to perform" an Operating
Instruction because it "would violate safety, equipment,
regulatory, or statutory requirements" so that the
Operating Instruction does not become a Reliability
Directive.
No
Yes
There were a couple of typos in the VSLs. R1 – Insert a
space between ‘R1’ and ‘in’ in the Lower VSL. R3 – Insert
‘to’ between ‘failed’ and ‘repeat’ in the Severe VSL.
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COM-002-4 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting of the SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of COM-003-1 Standard posted November 2009 for Informal Comments
closed January 15, 2010.
7. Version 2 draft of COM-003-1 Standard posted May 2012 for Formal Comments, Initial
Ballot closed June 20, 2012.
8. Version 3 draft of COM-003-1 Standard posted August 2012 for Formal Comments,
Ballot closed September 22, 2012.
9. Version 4 draft of COM-003-1 Standard posted November 2012 for Formal Comments,
Ballot closed December 13, 2012.
10. Version 5 draft of COM-003-1 Standard posted March 2013 for Formal Comments,
Ballot closed April 5, 2013.
11. Version 6 draft of COM-003-1 Standard posted June 2013 for Formal Comments, Ballot
closed July 19, 2013.
Description of Current Draft:
This is the first draft of a revised standard (seventh posting of a communications standard)
requiring the use of standardized communication protocols during normal and emergency
operations to improve situational awareness and shorten response time. The drafting team is
posting this standard for a 15-day concurrent Formal Comment period and Ballot.
Future Development Plan:
Anticipated Actions
Anticipated Date
1. Additional ballot of Standard
October 2013
2. Final ballot of Standard.
November 2013
3. Board adopts standard.
November 2013
Draft 7
October 21, 2013
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COM-002-4 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Operating Instruction — A command by operating personnel responsible for the Real-time
generation control and operation of the interconnected Bulk Electric System to change or
preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System. A discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is not a command and is not
considered an Operating Instruction. A Reliability Directive is one type of an Operating
Instruction.
Draft 7
October 21, 2013
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COM-002-4 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To tighten communications for the issuance of Operating Instructions with
predefined communications protocols to reduce the possibility of miscommunication
that could lead to action or inaction harmful to the reliability of the Bulk Electric
System (BES).
4.
Applicability:
COM-002-4
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
(Proposed) Effective Date: The standard shall become effective on the first day of
the first calendar quarter that is twelve (12) months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
have documented communications protocols. The protocols shall, at a minimum:
[Violation Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require the issuer of a Reliability Directive to identify the action as a Reliability
Directive to the receiver.
1.2. Require the issuer and receiver of an oral or written Operating Instruction to use
the English language, unless agreed to otherwise. An alternate language may be
used for internal operations.
1.3. Require the issuer of an oral two-party, person-to-person Operating Instruction
to wait for a response from the receiver. Once a response is received, or if no
response is received, require the issuer to take one of the following actions:
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Confirm the receiver’s response if the repeated information is correct.
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COM-002-4 Operating Personnel Communications Protocols
Reissue the Operating Instruction if the repeated information is incorrect,
if the receiver does not issue a response, or if requested by the receiver.
1.4. Require the receiver of an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
Repeat the Operating Instruction and wait for confirmation from the issuer
that the repetition was correct.
Request that the issuer reissue the Operating Instruction.
1.5. Require the issuer of an oral Operating Instruction to verbally or electronically
confirm receipt by at least one receiver when issuing the Operating Instruction
through a one-way burst messaging system used to communicate a common
message to multiple parties in a short time period (e.g., an all call system).
1.6. Require the receiver of an oral Operating Instruction to request clarification
from the issuer if the communication is not understood when receiving the
Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g.,
an all call system).
1.7. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.8. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
1.9. Specify the instances where alpha-numeric clarifiers are required when issuing
an oral Operating Instruction and the format for those clarifiers.
R2. Each Distribution Provider and Generator Operator shall have documented
communications protocols. The protocols shall, at a minimum: [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
2.1. Require the receiver of an oral or written Operating Instruction to respond using
the English language, unless agreed to otherwise. An alternate language may be
used for internal operations.
2.2. Require the receiver of an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
Repeat the Operating Instruction and wait for confirmation from the issuer
that the repetition was correct.
Request that the issuer reissue the Operating Instruction.
2.3. Require the receiver of an oral Operating Instruction to request clarification
from the issuer if the communication is not understood when receiving the
Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g.,
an all call system).
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COM-002-4 Operating Personnel Communications Protocols
R3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement the documented communications protocols developed in Requirement R1.
[Violation Risk Factor: High][Time Horizon: Real-time Operations]
R4. Each Distribution Provider and Generator Operator shall implement the documented
communications protocols developed in Requirement R2. [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement a method to evaluate the communications protocols developed in
Requirement R1 that: [Violation Risk Factor: Low][Time Horizon: Operations
Planning]
5.1. Assesses adherence to the communications protocols to provide feedback to
issuers and receivers of Operating Instructions.
5.2. Assesses the effectiveness of the communications protocols and modifies those
protocols, as necessary.
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R2.
M3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence that it implemented the documented communication protocols which
may include, but is not limited to, descriptions of the management practices in place
that provide the entity reasonable assurance that protocols established in Requirement
R1 are being followed by personnel responsible for the real-time generation control and
operation of the interconnected Bulk Electric System, spreadsheets, memos, or logs,
evidencing periodic, independent review of operating personnel’s adherence to the
protocols established in Requirement R1 and the remediation of noted exceptions in
fulfillment of Requirement R5.
M4. Each Distribution Provider and Generator Operator shall provide evidence that it
implemented the documented communication protocols which may include, but is not
limited to, descriptions of the management practices in place that provide the entity
reasonable assurance that protocols established in Requirement R2 are being followed
by personnel responsible for the real-time generation control and operation of the
interconnected Bulk Electric System, spreadsheets, memos, or logs, evidencing
periodic, independent review of operating personnel’s adherence to the protocols
established in Requirement R2.
M5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide descriptions and associated evidence of the management practices in place that
demonstrate a review of communications with operating personnel responsible for the
real-time generation control and operation of the interconnected Bulk Electric System
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COM-002-4 Operating Personnel Communications Protocols
and evidence that the entity evaluates the effectiveness of its documented
communications protocols in fulfillment of Requirement R5.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
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COM-002-4 Operating Personnel Communications Protocols
None
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COM-002-4 Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
The responsible entity did
not specify the instances that
require time identification
when issuing an oral or
written Operating Instruction
and the format for that time
identification, as required in
Requirement R1, Part 1.7
The responsible entity did not
require the issuer and receiver
of an oral or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R1, Part 1.2. An
alternate language may be used
for internal operations.
The responsible entity
did not include
Requirement R1, Part
1.5 in its documented
communication
protocols
The responsible entity did
not include Requirement R1,
Part 1.1 in its documented
communications protocols
OR
The responsible entity did
not specify the
nomenclature for
Transmission interface
Elements and Transmission
interface Facilities when
issuing an oral or written
Operating Instruction, as
required in Requirement R1,
Part 1.8
OR
The responsible entity
did not include
Requirement R1, Part
1.6 in its documented
communications
protocols.
The responsible entity did
not include Requirement R1,
Part 1.3 in its documented
communications protocols
OR
The responsible entity did
not include Requirement R1,
Part 1.4 in its documented
communications protocols
OR
The responsible entity did
not develop any documented
communications protocols as
required in Requirement R1.
OR
The responsible entity did
not specify the instances
where alpha-numeric
clarifiers are required when
issuing an oral Operating
Instruction and the format
for those clarifiers, as
required in Requirement R1,
Part 1.9.
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OR
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COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R2
R3
Long-term
Planning
Real-time
Operations
Low
High
N/A
N/A
Moderate VSL
High VSL
Severe VSL
The responsible entity did not
require the receiver of an oral
or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R2, Part 2.1. An
alternate language may be used
for internal operations.
The responsible entity
did not include
Requirement R2, Part
2.3 in its documented
communication
protocols.
The responsible entity did
not include Requirement R2,
Part 2.2 in its documented
communications protocols
N/A
The responsible entity
demonstrates a
consistent pattern of
not using the
documented
communications
protocols developed in
Requirement R1 for
The responsible entity did
not develop any documented
communications protocols as
required in Requirement R2.
Operating
Instructions that are
not Reliability
Directives.
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October 21, 2013
OR
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The responsible entity did
not use the documented
communications protocols
developed in Requirement
R1 when issuing or
receiving a Reliability
Directive.
COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Real-time
Operations
High
N/A
Moderate VSL
N/A
High VSL
The responsible entity
demonstrates a
consistent pattern of
not using the
documented
communications
protocols developed in
Requirement R2 for
Severe VSL
The responsible entity did
not use the documented
communications protocols
developed in Requirement
R2 when receiving a
Reliability Directive.
Operating
Instructions that are
not Reliability
Directives.
R5
Operations
Planning
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October 21, 2013
Low
N/A
N/A
N/A
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The responsible entity did
not implement a method for
evaluating its
communications protocols as
specified in Requirement
R5.
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COM-002-4 Operating Personnel Communications Protocols
E. Regional Variances
None.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
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Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
COM‐002‐4 – Operating Personnel Communications Protocols
Retirements:
COM‐001‐1.1 Requirement R4 – Telecommunications
COM‐002‐2 – Communication and Coordination
COM‐002‐3 – Communication and Coordination
Prerequisite Approvals
Approval of the definition of “Reliability Directive”
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real‐time generation control and operation of
the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System. A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System operating concerns
is not a command and is not considered an Operating Instruction. A Reliability Directive is one type of
an Operating Instruction.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
None
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Effective Date
COM‐002‐4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM‐001‐1.1 Requirement R4, COM‐002‐2, and COM‐002‐3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM‐002‐4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007‐02 – Operating Personnel Communications Protocols
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Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4 Operating Personnel Communications Protocols
Please DO NOT use this form. Please use the electronic comment form to submit comments on the
proposed draft COM-002-4 Operating Personnel Communications Protocols standard. Comments must
be submitted by November 4, 2013. If you have questions please contact Stephen Eldridge or by
telephone at 404-446-9686.
http://www.nerc.com/pa/Stand/Pages/Op_Comm_Protocol_Project_2007-02.aspx
Background Information:
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES. The seventh posting of Project 2007-02 combines COM-002-3 and COM003-1 into one standard titled COM-002-4 that addresses communications protocols for operating
personnel in Emergency, alert, and non-emergency situations.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and approved
by the Standards Committee on June 8, 2007. It established the scope of work for Project 2007-02
Operating Personnel Communications Protocols (OPCP). The scope described in the SAR is to establish
essential elements of communications protocols and communications paths such that operators and
users of the North American BES will efficiently convey information and ensure mutual understanding.
The August 2003 Blackout Report, Recommendation Number 26, calls for a tightening of
communications protocols. Federal Energy Regulatory Commission (FERC) Order 693 paragraph 532
reiterates this need. This proposed standard’s goal is to ensure that effective communication is
practiced and delivered in clear and consistent language.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and mutually
understood for communicating Operating Instructions.
The Purpose statement of COM-002-4 states: “To tighten communications for the issuance of Operating
Instructions with predefined communications protocols to reduce the possibility of miscommunication
that could lead to action or inaction harmful to the reliability of the Bulk Electric System.”
1) New NERC Glossary term: The OPCP Standards Drafting Team (SDT) revised the definition of
Operating Instructions from its previous drafts. The definition states that a Reliability Directive
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is a type of Operating Instruction. The proposed term differentiates the class of
communications that deal with changing or altering the state of the BES from general
discussions of options or alternatives. Changes to the BES operating state with unclear
communications create increased opportunities for events that could place the BES at an
unacceptable risk of instability, separation, or cascading failures. This term is proposed for
addition to the North American Electric Reliability Corporation (NERC) Glossary to establish
meaning and usage within the electricity industry.
2) Project 2007-02, Posting 7 combines COM-002-3 and COM-003-1 into COM-002-4. The OPCP
SDT combined COM-002-3 and COM-003-1 into one standard in order to simplify
communications protocols for operating personnel. The OPCP SDT determined that one
communications protocols standard that addresses Emergency, alert, and non-emergency
situations will improve communications because system operators will not need to refer to a
different set of protocols during an emergency situation. The OPCP SDT believed this will
improve consistency of communications and mitigate confusion during stressful emergency
situations. Similarly, the Independent Experts Review Panel and NERC management
recommended a single standard that addresses emergency and non-emergency
communications protocols. The OPCP SDT decided to combine the standards under the title
COM-002-4 to further reduce confusion. The COM-002-4 title keeps the numbering of COM
standards consecutive (e.g., COM-001, COM-002).
3) Project 2007-02, Posting 7 features 5 requirements. The The OPCP SDT developed the
requirement structure and language in posting 7 to incorporate Emergency, alert, and nonemergency communications protocols. The language in COM-002-4, Requirement R1 permits
applicable entities flexibility to develop their communication protocols but requires a set of
minimum elements in the communications protocols. Requirement R1 requires
communications protocols to include the following elements:
a. Reliability Directive Identification: Requirement R1, Part 1.1 – Require the issuer of a
Reliability Directive to identify the action as a Reliability Directive to the receiver.
b. English Language: Requirement R1, Part 1.2 – Require the issuer and receiver of an oral
or written Operating Instruction to use the English language, unless agreed to
otherwise. An alternate language may be used for internal operations.
c. Three-part Communication for Oral Operating Instructions: Requirement R1, Parts 1.3
and 1.4 – Require three-part communication for issuers and receivers of oral two-party,
person-to-person Operating Instructions.
d. One-way Burst Message Receipt Confirmation and Clarification: Requirement R1, Parts
1.5 and 1.6 – Require the issuer of an oral Operating Instruction to verbally or
electronically confirm receipt by at least one receiver when issuing the Operating
Instruction through a one-way burst messaging system used to communicate a common
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | October 2013
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message to multiple parties in a short time period (e.g., an all call system). Require
receiver to request clarification if not understood.
e. Time Identification: Requirement R1, Part 1.7 – Specify the instances that require time
identification when issuing an oral or written Operating Instruction and the format for
that time identification.
f. Transmission Interface Elements and Facilities Nomenclature: Requirement R1, Part
1.8 – Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
g. Alpha-numeric Clarifiers: Requirement R1, Part 1.9 – Specify the instances where
alpha-numeric clarifiers are required when issuing an oral Operating Instruction and the
format for those clarifiers.
Requirement R2 establishes minimum requirements in communications protocols for entities
that typically only receive Operating Instructions. Requirement R2 requires Generator
Operators and Distribution Providers to include the following elements in their
communications protocols:
a. English Language: Requirement R2, Part 2.1 – Require the receiver of an oral or written
Operating Instruction to respond using the English language, unless agreed to
otherwise. An alternate language may be used for internal operations.
b. Three-part Communication for Oral Operating Instructions: Requirement R2, Part 2.2 –
Require the receiver of an oral two-party, person-to-person Operating Instruction to
either repeat the Operating Instruction and receive confirmation from the issuer or
request the issuer to reissue the Operating Instruction.
c. One-way Burst Message Receipt Clarification: Requirement R2, Part 2.3 – Require the
receiver of an oral Operating Instruction to request clarification from the issuer if the
communication is not understood when receiving the Operating Instruction through a
one-way burst messaging system used to communicate a common message to multiple
parties in a short time period (e.g., an all call system).
Requirements R3 and R4 require entities to implement the communications protocols in
Requirements R1 and R2. The OPCP SDT included these requirements to ensure that entities
would include COM-002-4 in their training programs under PER-005-1. Finally, Requirement
R5 requires each Balancing Authority, Reliability Coordinator, and Transmission Operator to
assess personnel’s adherence to communications protocols to provide feedback to issuers
and receivers of Operating Instructions and to assess the effectiveness of the communications
protocols.
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | October 2013
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The OPCP SDT is posting the standard for industry comment for a 15-day comment period. The OPCP
SDT received a waiver of the 45-day comment period required in the NERC Standards Processes
Manual from the NERC Standards Committee. Accordingly, we request that you include your
comments on the electronic form by November 4, 2013.
Questions
1. The OPCP SDT combined COM-002-3 and COM-003-1 into the COM-002-4 standard. Do you
agree that COM-002-4 addresses the August 2003 Blackout Report Recommendation number
26, FERC Order 693, and the COM-003-1 SAR? If not, please explain in the comment area of the
last question.
Yes
No
Comments:
2. Do you agree with the VRFs and VSLs for Requirements R1, R2, R3, R4, and R5? If not, please
explain.
Yes
No
Comments:
3. Do you have any additional comments? Please provide them here.
Yes
No
Comments:
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | October 2013
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Project 2007-02, COM-002-4 Operating
Personnel Communications Protocols
Rationale and Technical Justification
Justification for Requirements in Posting 7
Background
Posting 7 of Project 2007-02 – Operating Personnel Communications Protocols combines COM-002-3
and former draft COM-003-1 into one standard that addresses communications protocols for operating
personnel in Emergency, alert and non-emergency conditions. The Operating Personnel
Communications Protocols Standard Drafting Draft (OPCP SDT) determined that one communications
protocols standard that addresses emergency and non-emergency situations will improve
communications because system operators will not need to refer to a different set of protocols during the
issuance of a Reliability Directive. The OPCP SDT believe this will improve consistency of
communications and mitigate confusion during stressful emergency situations. As a result of the
combination, the standard has been renumbered as COM-002-4 to maintain the consecutive numbering
of the standards (e.g., COM-001, COM-002) since the combined standard will replace COM-002-2 and
COM-002-3, where necessary.
In preparing COM-002-4, the Operating Personnel Communications Protocols Standard Drafting Team
(OPCP SDT) considered the comments provided on draft 6 of COM-003-1 and also reviewed the
recommendation of the NERC Board of Trustees (Board) Standards Oversight and Technology
Committee (SOTC). In this posting, the OPCP SDT seeks industry comment on a combined
communications standard. This provides an opportunity for industry to comment and ballot a combined
standard prior to the Board’s consideration of a communications standard at the November 2013
meeting of the Board.
The latest draft reflects a results-based approach to strengthening communications during nonemergency, alert, and emergency operating conditions. The following sections outline the OPCP SDT’s
revisions to the communications standards and rationale.
Definition of Operating Instruction
The proposed definition of “Operating Instruction” has been revised to read as follows:
A command by operating personnel responsible for the Real-time
generation control and operation of the interconnected Bulk Electric
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System to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric
System. A discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is not a
command and is not considered an Operating Instruction. A Reliability
Directive is one type of an Operating Instruction.
As opposed to the definition used in draft 6 of COM-003-1, this revised definition characterizes a
Reliability Directive as a type of Operating Instruction. Retaining the definition of Reliability Directive
and including it within the scope of the definition of Operating Instruction is necessary since it is
currently used in other Reliability Standards (e.g., TOP-001-2 and IRO-001-3).
A “command” as used in the definition refers to both oral and written commands by operating
personnel. In the requirements of COM-002-4, the OPCP SDT has specified “oral” or “written” as
needed to define which Operating Instructions are covered by the requirement. The definition continues
to clarify that general discussions are not considered Operating Instructions.
Applicability
In addition to Balancing Authorities, Reliability Coordinators, and Transmission Operators, the
proposed standard applies to Distribution Providers and Generator Operators. The OPCP SDT added
these Functional Entities in the Applicability section because they are often on the receiving end of
Operating Instructions. The OPCP SDT determined that it would leave a gap to not cover them in a
communications standard that addresses operating personnel. Recognizing that Generator Operators and
Distribution Providers typically only receive Operating Instructions, the OPCP SDT proposed that only
Requirements R2 and R4 apply to these Functional Entities. As a result, Generator Operators and
Distribution Providers need only develop communications protocols governing receipt of Operating
Instructions.
Requirements in COM‐002‐4
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to have
documented communications protocols that include a minimum set of elements, outlined in Parts 1.1
through 1.9 of the requirement. Because Operating Instructions affect Facilities and Elements of the
Bulk Electric System, the communication of those Operating Instructions must be understood by all
involved parties, especially when those communications occur between Functional Entities. An EPRI
study reviewed nearly 400 switching mishaps by electric utilities and found that roughly 19% of errors
(generally classified as loss of load, breach of safety, or equipment damage) were due to communication
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failures.1 This was nearly identical to another study of dispatchers from 18 utilities representing nearly
2000 years of operating experience that found that 18% of the operators’ errors were due to
communication problems.2 The necessary protocols include the use of the English language unless
agreed to otherwise (except for internal operations), time formatting, specified nomenclature for
Transmission interface Elements, alpha-numeric clarifiers, and three-part communications.
The OPCP SDT drafted Requirement R1 to ensure consistency among communications protocols while
also allowing flexibility for entities to develop additional communications protocols. The OPCP SDT
determined that the inclusion of the elements in Parts 1.1 through 1.9 are necessary to tighten
communications protocols but are not overly prescriptive. The OPCP SDT determined that this
approach is the best way to promote effective communications while maintaining flexibility for entities
to include additional communications protocols based on its own operating environment.
On September 19, 2012, the NERC Operating Committee issued a Reliability Guideline entitled:
“System Operator Verbal Communications – Current Industry Practices.” As stated on page one, the
purpose of the Reliability Guideline “. . . is to document and share current verbal BES communications
practices and procedures from across the industry that have been found to enhance the effectiveness of
system operator communications programs.” This guideline serves as an additional source of
information on best practices that entities can draw on in creating the documented communications
protocols.
The term documented communication protocols in R1 refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. An entity should include as
much detail as it believes necessary in their documented protocols, but they must address all of the
applicable parts of Requirement R1. Where an entity does not already have a set of documented
protocols that meet the parts of Requirement R1, the entity must develop the necessary communications
protocols. Entities may also adopt the documented protocols of another entity as its own
communications protocols, but the entity must maintain its own set of documented communications
protocols to meet Requirement R1.
Each part of Requirement R1 is discussed below:
1.1.
Require the issuer of a Reliability Directive to identify the action as a Reliability
Directive to the receiver.
1
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
2
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
Project 2007-02, COM-002-4 Operating Personnel Communications Protocols Rationale and Technical Justification
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The OPCP SDT has included this part to ensure consistency with TOP-001-2, which requires
compliance with the identified Reliability Directive by the Transmission Operator. This identification
must be required in order to meet the performance expected in TOP-001-2. TOP-001-2 requires each
Balancing Authority, Generator Operator, Distribution Provider, and Load-Serving Entity
to comply with each Reliability Directive issued and identified as such by its Transmission
Operator(s), unless such action would violate safety, equipment, regulatory, or statutory
requirements.
1.2.
Require the issuer and receiver of an oral or written Operating Instruction to use the
English language, unless agreed to otherwise. An alternate language may be used for internal
operations.
The OPCP SDT has included this part to carry forward the same use of English language included in
COM-001-1, Requirement R4. Retirement of this Requirement in COM-001-1 was specifically referred
to Project 2007-02. The requirement continues to permit the issuer and receiver to use an agreed to
alternate language. This has been retained since use of an alternate language on a case-by-case basis
may serve to better facilitate effective communications where the use of English language may create
additional opportunities for miscommunications. Part 1.2 requires the use of English language when
issuing oral or written (e.g. switching orders) Operating Instructions. This creates a standard language
(unless agreed to otherwise) for use when issuing commands that could change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. It also clarifies that an alternate language can be used internally within the organization.
1.3.
Require the issuer of an oral two-party, person-to-person Operating Instruction to wait
for a response from the receiver. Once a response is received, or if no response is received,
require the issuer to take one of the following actions:
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect, if the
receiver does not issue a response, or if requested by the receiver.
The OPCP SDT has included this part to require communications protocols for the use of three-part
communications for oral two-party, person-to-person Operating Instructions by the issuer. This carries
forward the requirement to use three-part communications in COM-002-2 and COM-002-3.
The reliability benefits of using three-part communication (R1, parts 1.3 and 1.4) are threefold:
1. The removal of any doubt that communication protocols will be used and when they will be
used. This will reduce the opportunity for confusion and misunderstanding among entities
that may have different doctrine. An example is: One entity uses three-part for emergencies,
and the other uses it for all operating conditions.
Project 2007-02, COM-002-4 Operating Personnel Communications Protocols Rationale and Technical Justification
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2. There will be no mental “transition” when operating conditions shift from normal to
Emergency. The communication protocols for the operators will remain standard during
transitions through all conditions.
3. The formal requirement for three-part communication will create a heightened sense of
awareness in operators that the task they are about to execute is critical, and recognize the
risk to the reliable operation of the BES is increased if the communication is misunderstood.
1.4.
Require the receiver of an oral two-party, person-to-person Operating Instruction to take
one of the following actions:
•
Repeat the Operating Instruction and wait for confirmation from the issuer that
the repetition was correct.
•
Request that the issuer reissue the Operating Instruction.
The OPCP SDT has included this part to require communications protocols for the use of three-part
communications for oral two-party, person-to-person Operating Instructions by the receiver. This is
consistent with the approach to using three-part communications in COM-002-2 and COM-002-3.
1.5.
Require the issuer of an oral Operating Instruction to verbally or electronically confirm
receipt by at least one receiver when issuing the Operating Instruction through a one-way burst
messaging system used to communicate a common message to multiple parties in a short time
period (e.g., an all call system).
The OPCP SDT has included this part to require communications protocols for an issuer for the use of a
one-way burst messaging system. The drafting team has included this because the use of three-part
communications is not practically possible when utilizing this type of communication. Therefore, it is
necessary to include a different set of protocols for these situations.
1.6.
Require the receiver of an oral Operating Instruction to request clarification from the
issuer if the communication is not understood when receiving the Operating Instruction through
a one-way burst messaging system used to communicate a common message to multiple parties
in a short time period (e.g., an all call system).
The OPCP SDT has included this part to require communications protocols for a receiver for the use of a
one-way burst messaging system. The drafting team has included this because the use of three-part
communications is not practically possible when utilizing this type of communication. Therefore, it is
necessary to include a different set of protocols for these situations.
1.7.
Specify the instances that require time identification when issuing an oral or written
Operating Instruction and the format for that time identification.
Project 2007-02, COM-002-4 Operating Personnel Communications Protocols Rationale and Technical Justification
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The OPCP SDT has included this part to add necessary clarity to Operating Instructions to reduce the
risk of mistakes. Clarifying time and time zone (where necessary) contributes to reducing
misunderstandings and reduce the risk of a grave error during BES operations.
1.8.
Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
Project 2007-03 chose to eliminate TOP-002-2a Requirement R18 when it developed TOP-002-3. This
Requirement states “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers
when referring to transmission facilities of an interconnected network.” COM-002-4, while
reintroducing the concept of line identifiers, limits the scope to only Transmission interface Elements or
Transmission interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are
readily familiar with each other’s interface Elements and Facilities, eliminating hesitation and confusion
when referring to equipment for the Operating Instruction. This shortens response time and improves
situational awareness.
1.9.
Specify the instances where alpha-numeric clarifiers are required when issuing an oral
Operating Instruction and the format for those clarifiers.
The OPCP SDT has included this part to avoid miscommunications due to the fact that several letters in
the English language sound alike and can be confused in stressful or noisy situations. For example, some
letters sound alike when spoken, and can easily be confused; such as “D” and “B.” The phonetic
alphabet specifies a common word for each letter of the English alphabet. By using a word for each
letter, there is less chance that the person listening will confuse the letters. Using the phonetic alphabet,
“Delta” and “Bravo” are more easily differentiated. The effects of noise, weak telephone or radio
signals, and an individual's accent are reduced through the use of the phonetic alphabet.
Requirement R2
Requirement R2 requires the development of documented communications protocols for Generator
Operators and Distribution Providers receiving Operating Instructions. As Generator Operators and
Distribution Providers typically only receive Operating Instructions, the OPCP SDT determined that a
separate requirement for these Functional Entities covers their communications protocols but does not
subject them to the additional requirements imposed upon entities who issue Operating Instructions.
The requirement includes similar parts requiring the inclusion in communications protocols of the use of
English language, three-part communications, and protocols for the use of a one-way burst messaging
system.
Requirements R3 and R4
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Requirement R3 requires entities that issue and receive Operating Instructions to implement the
documented communications protocols in Requirement R1. Requirement R4 requires Generator
Operators and Distribution Providers who receive Operating Instructions to implement the documented
communications protocols in Requirement R2.
The associated Measures for R3 and R4 explain that evidence demonstrating compliance may include,
but is not limited to, descriptions of the management practices in place that provide the entity reasonable
assurance that protocols established in Requirement R1 are being followed by personnel responsible for
the real-time generation control and operation of the interconnected Bulk Electric System, spreadsheets,
memos, or logs, evidencing periodic, independent review of operating personnel’s adherence to the
protocols established in Requirement R1 and the remediation of noted exceptions in fulfillment of
Requirement R5. The VSLs for Requirement R3 and R4 have also been designed to reflect the
identification of a pattern of not using the documented communications protocols developed in
Requirement R1 and R2 as the VSL for Operating Instructions that are not Reliability Directives, also in
addition to the severe VSL for not using the documented communications protocols developed in
Requirement R1 and R2 when issuing or receiving a Reliability Directive.
Requirement R5
Requirement R5 requires entities that are subject to Requirement R1 to continually assess the
communications protocols and determine whether personnel adhere to them. The OPCP SDT
determined that communications protocols need to be evaluated but allowed flexibility for entities to
determine when to evaluate and how to assess or modify those communications protocols. The OPCP
SDT believed this creates a learning environment through the use of feedback and most effectively
promotes reliable communications.
Project 2007-02, COM-002-4 Operating Personnel Communications Protocols Rationale and Technical Justification
7
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
COM-001-1.1 to COM-002-4
Board Approved Standard
COM-001-1.1
R4.Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use English
as the language for all communications between and among
operating personnel responsible for the real-time generation
control and operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
Proposed Replacement Requirement(s)
COM-002-4
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented
communications protocols. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Longterm Planning]
1.2. Require the issuer and receiver of an oral or written
Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may
be used for internal operations
R2. Each Distribution Provider and Generator Operator shall have
documented communications protocols. The protocols shall,
at a minimum: [Violation Risk Factor: Low][Time Horizon:
Long-term Planning]
2.1. Require the receiver of an oral or written Operating
Instruction to use the English language, unless agreed
to otherwise. An alternate language may be used for
Project 2007-02: Operating Personnel Communication Protocols
Board Approved Standard
Proposed Replacement Requirement(s)
internal operations
Notes: Moved COM-001-1 R4 into COM 002-4 Requirement R1 Part 1.2 and Requirement R2 Part 2.1
COM-002-2 to COM-002-3
Board Approved Standard
COM-002-2
R1. Each Transmission Operator, Balancing Authority, and
Generator Operator shall have communications (voice and data
links) with appropriate Reliability Coordinators, Balancing
Authorities, and Transmission Operators. Such communications
shall be staffed and available for addressing a real-time emergency
condition. [Violation Risk Factor: High]
Proposed Replacement Requirement(s)
The RC SDT retired COM-002-2, R1 and R1.1. The following
rational was provided by that drafting team:
The communications requirements of R1 are addressed in existing
COM-001-1.1 as well as the proposed COM-001-2 requirements.
Additionally, IRO-010-1a addresses data provisions.
The RC SDT contends that COM-002-2, R1.1 is a low level
facilitating requirement that is more appropriately and inherently
R1.1 Each Balancing Authority and Transmission Operator shall
monitored under various higher level performance-based
notify its Reliability Coordinator, and all other potentially affected reliability requirements for each entity throughout the body of
Balancing Authorities and Transmission Operators through
standards. Examples include:
predetermined communication paths of any condition that could
• EOP-002-1, R3 – outlines BA to RC communications.IROthreaten the reliability of its area or when firm load shedding is
001-1, R3 requires adequate telecommunication for the
anticipated. [Violation Risk Factor: High]
Reliability Coordinator to direct actions of multiple
entities, including TOPs and BAs.
•
Mapping Document
TOP-001-1, R3 requires adequate telecommunications
facilities for the TOP, BA, and GOP to be able to receive
directives from the RC.
2
Project 2007-02: Operating Personnel Communication Protocols
Board Approved Standard
Proposed Replacement Requirement(s)
•
TOP-001-1, R5 requires communications between TOPs
and RCs for emergency situations.
•
TOP-005-1, R1 and R3 require adequate
telecommunications for BAs and TOPs to provide each
other with operating data as well as providing data to the
RC.
•
TOP-006-1, R1 requires adequate telecommunications for
the GOP to inform the BA and TOP of resources. The BA
and TOP will then inform the RC, other TOP and BAs of all
transmission and generation available for use.
•
PER-001-1, R1 and PER-004-1, R1 set forth the staffing
requirements.
Notes: The RC SDT contends that COM-002-2, R1 and its sub-requirements are low level facilitating requirements that are more
appropriately and inherently monitored under various higher-level performance-based reliability requirements for each entity
throughout the body of standards. These include standards within the COM, IRO, and TOP body of standards and are specifically
identified in the mapping table below.
COM-002-2
COM-002-3
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and
definitive manner; shall ensure the recipient of the directive
repeats the information back correctly; and shall acknowledge the
response as correct or repeat the original statement to resolve any
misunderstandings. [Violation Risk Factor: Medium]
The RC SDT expanded COM-002-2 R2 into three requirements in
COM-002-3:
Mapping Document
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
Horizon: Real-Time]
3
Project 2007-02: Operating Personnel Communication Protocols
Board Approved Standard
Proposed Replacement Requirement(s)
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
•
Reissue the Reliability Directive to resolve any
misunderstandings.
Notes: The RC SDT expanded the list of responsible entities to include the DP and GOP and subdivided the requirement to improve
clarity.
COM-002-3 to COM-002-4
Board Approved Standard
Proposed Replacement Requirement(s)
COM-002-3
COM-002-4
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented communications
protocols. The protocols shall, at a minimum: [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
Mapping Document
4
Project 2007-02: Operating Personnel Communication Protocols
Board Approved Standard
Horizon: Real-Time]
Proposed Replacement Requirement(s)
1.1.
Require the issuer of a Reliability Directive to identify the
action as a Reliability Directive to the receiver.
Notes: Moved COM-002-3 R1 into COM 002-4 Requirement 1 Part 1.1
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time Horizon:
Real-Time]
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented communications
protocols. The protocols shall, at a minimum: [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
1.4.
Require the receiver of an oral two-party, person-toperson Operating Instruction to take one of the following
actions:
•
Repeat the Operating Instruction and wait for
confirmation from the issuer that the repetition was
correct.
•
Request that the issuer reissue the Operating
Instruction.
R2. Each Distribution Provider and Generator Operator shall have
documented communications protocols. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
2.2.
Require the receiver of an oral two-party, person-toperson Operating Instruction to take one of the following
actions:
•
Mapping Document
Repeat the Operating Instruction and wait for
confirmation from the issuer that the repetition was
5
Project 2007-02: Operating Personnel Communication Protocols
Board Approved Standard
Proposed Replacement Requirement(s)
correct.
•
Request that the issuer reissue the Operating
Instruction.
Notes: Moved COM-002-3 R2 into COM 002-4 Requirement R1 Part 1.4 and Requirement R2 Part 2.2. Additional language was added to
provide clarity for the responsibility of the receiver of three-part communication.
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
•
Reissue the Reliability Directive to resolve any
misunderstandings.
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented communications
protocols. The protocols shall, at a minimum: [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
1.3.
Require the issuer of an oral two-party, person-to-person
Operating Instruction to wait for a response from the
receiver. Once a response is received, or if no response is
received, require the issuer to take one of the following
actions:
•
Confirm the receiver’s response if the repeated
information is correct.
•
Reissue the Operating Instruction if the repeated
information is incorrect, if the receiver does not issue a
response, or if requested by the receiver.
Notes: Moved COM-002-3 R3 into COM 002-4 Requirement R1 Part 1.3. Additional language was added to provide clarity for the
responsibility of the issuer of three-part communication.
Mapping Document
6
Project 2007-02 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM-002-4 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
Project YYYY-##.# - Project Name
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
VRF and VSL Justifications
2
Project YYYY-##.# - Project Name
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
•
•
•
•
•
•
•
•
•
•
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
VRF and VSL Justifications
3
Project YYYY-##.# - Project Name
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs in the first instance and therefore concentrated its approach
on the reliability impact of the requirements.
VRF and VSL Justifications
4
Project YYYY-##.# - Project Name
VRF for COM-002-4:
There are five requirements in COM-002-4, draft 1. Requirements R1 and R2 are assigned a “Low” VRF. R1 now reads:”Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall have documented communications protocols. The
protocols shall, at a minimum:.“ R2 now reads:”Each Distribution Provider and Generator Operator shall have documented
communications protocols. The protocols shall, at a minimum:.“ Requirements R3 and R4 are assigned a “High” VRF. R3 now
reads:” Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement the documented
communications protocols developed in Requirement R1.“ R4 now reads:” Each Distribution Provider and Generator Operator
shall implement the documented communications protocols developed in Requirement R2.“ These Requirements warrant VRFs
of “High” because failure to use the communications protocols during an emergency could directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures. Requirement R5 is assigned a “Low” VRF. R5 now reads:” R5.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement a method to evaluate the
communications protocols developed in Requirement R1 that:.“
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
VRF and VSL Justifications
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
5
Project YYYY-##.# - Project Name
measured has significant
value as it almost meets the
full intent of the
requirement.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VRF and VSL Justifications
6
Project YYYY-##.# - Project Name
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
The drafting team will complete the following table, providing of analysis and justification for each VRF and VSL, for each requirement.
VRF and VSL Justifications – COM-002-4, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communications protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development of documented communications protocols by entities that will
both issue and receive “Operating Instructions” that reduce the possibility of miscommunication which
FERC VRF G2 Discussion
FERC VRF G3 Discussion
VRF and VSL Justifications
7
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
FERC VRF G4 Discussion
FERC VRF G5 Discussion
could eventually lead to action or inaction harmful to the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “ Low,” which is consistent with NERC
guidelines for similar requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R1 contains only one objective which is to document clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
only one objective, only one VRF was assigned.
Proposed VSL
Lower
Moderate
High
The responsible entity did not
specify the instances that
require time identification
when issuing an oral or written
Operating Instruction and the
format for that time
identification, as required in
Requirement R1, Part 1.7
The responsible entity did not
require the issuer and receiver
of an oral or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R1, Part 1.2. An
alternate language may be
used for internal operations.
The responsible entity did not
include Requirement R1, Part 1.5
in its documented communication
protocols
The responsible entity did not
include Requirement R1, Part 1.1
in its documented
communications protocols
OR
OR
VRF and VSL Justifications
Severe
The responsible entity did not
The responsible entity did not
include Requirement R1, Part 1.6
include Requirement R1, Part 1.3
in its documented communications in its documented
8
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
OR
The responsible entity did not
specify the nomenclature for
Transmission interface
Elements and Transmission
interface Facilities when issuing
an oral or written Operating
Instruction, as required in
Requirement R1, Part 1.8
OR
The responsible entity did not
specify the instances where
alpha-numeric clarifiers are
required when issuing an oral
Operating Instruction and the
format for those clarifiers, as
required in Requirement R1,
Part 1.9.
VRF and VSL Justifications
protocols.
communications protocols
OR
The responsible entity did not
include Requirement R1, Part 1.4
in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1
9
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols, with varied VSLs based on the severity of the potential risk to the bulk electric
system if the protocols were not used. If no communication protocols were addressed at all then the VSL
is Severe.
Guideline 2a:
The VSL assignment for R1 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R1.
10
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R1
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
11
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
Proposed VRF
Low
NERC VRF Discussion
R2 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 establishes communication protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for the development of documented communication protocols by entities that will
only receive “Operating Instructions” that reduce the possibility of miscommunication which could
eventually lead to action or inaction harmful to the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could directly affect the electrical state or the
capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. However, violation of the requirement is unlikely to lead to bulk electric system instability,
separation, or cascading failures. The VRF for this requirement is “Low,” which is consistent with NERC
guidelines for similar requirements.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R2 contains only one objective which is to document clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
12
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
only one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
The responsible entity did not
require the receiver of an oral
or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R2, Part 2.1. An
alternate language may be
used for internal operations.
High
The responsible entity did not
include Requirement R2, Part 2.3
in its documented communication
protocols.
Severe
The responsible entity did not
include Requirement R2, Part 2.2
in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R2
13
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed three VSLs based on misapplication or absence of common
communication protocols, with varied VSLs based on the severity of the potential risk to the bulk electric
system if the protocols were not used. If no communication protocols were addressed at all then the VSL
is Severe.
Guideline 2a:
The VSL assignment for R2 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R1.
14
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM-002-4, R2
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
15
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
Proposed VRF
High
NERC VRF Discussion
R3 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures due to
failure to use the communications protocols during an emergency. The VRF for this requirement is “High,”
which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which
is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for implementation of communication protocols developed in Requirement R1 to
reduce the possibility of miscommunication which could eventually lead to action or inaction harmful to
the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
R3 is a requirement in a Real Time- time frame that, if violated, could directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric
system at an unacceptable risk of instability, separation, or cascading failures due to failure to use the
communications protocols during an emergency. The VRF for this requirement is “High,” which is
consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R3 contains only one objective which is to implement clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
16
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
only one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
The responsible entity
demonstrates a consistent pattern
of not using the documented
communications protocols
developed in Requirement R1 for
Operating Instructions that are not
Reliability Directives.
Severe
The responsible entity did not use
the documented communications
protocols developed in
Requirement R1 when issuing or
receiving a Reliability Directive.
17
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed two VSLs to establish the severity of an entity not
implementing their communications protocols. If an entity demonstrates a consistent pattern of not using
their protocols over time for Operating Instructions that are not Reliability Directives, then they are
deemed to not have implemented their communications protocols at a “high” level. If an entity does not
use their protocols when issuing or receiving a Reliability Directive, then they are deemed to not have
implemented their communications protocols at a “severe” level.
Guideline 2a:
The VSL assignment for R3 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
18
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R3
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
19
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
Proposed VRF
High
NERC VRF Discussion
R4 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures due to
failure to use the communications protocols during an emergency. The VRF for this requirement is “High,”
which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R4 falls under Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which
is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for implementation of communication protocols developed in Requirement R2 to
reduce the possibility of miscommunication which could eventually lead to action or inaction harmful to
the reliability of the bulk electric system.
Guideline 4- Consistency with NERC Definitions of VRFs:
R4 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures due to
failure to use the communications protocols during an emergency. The VRF for this requirement is “High”
which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R4 contains only one objective which is to implement clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
20
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
only one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
The responsible entity
demonstrates a consistent pattern
of not using the documented
communications protocols
developed in Requirement R2 for
Operating Instructions that are not
Reliability Directives.
Severe
The responsible entity did not use
the documented communications
protocols developed in
Requirement R2 when receiving a
Reliability Directive.
21
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed two VSLs to establish the severity of an entity not
implementing their communications protocols. If an entity demonstrates a consistent pattern of not using
their protocols over time for Operating Instructions that are not Reliability Directives, then they are
deemed to not have implemented their communications protocols at a “high” level. If an entity does not
use their protocols when receiving a Reliability Directive, then they are deemed to not have implemented
their communications protocols at a “severe” level.
Guideline 2a:
The VSL assignment for R4 is not binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
22
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R4
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
23
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
Proposed VRF
Low
NERC VRF Discussion
R5 is a requirement in an Operations Planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system The VRF for this requirement is “Low,”
which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R5 establishes a method to evaluate communication protocols, which is consistent with FERC guideline
G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has sub-requirements that are of equal importance and similarly address communication
protocols; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement establishes a method to evaluate communication protocols developed in Requirement
R1 to reduce the possibility of miscommunication which could eventually lead to action or inaction
harmful to the reliability of the bulk electric system, which is not inconsistent with any other Reliability
Standards.
Guideline 4- Consistency with NERC Definitions of VRFs:
R5 is a requirement in an Operations Planning time frame that, if violated, would not, under the
emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely
affect the electrical state or capability of the bulk electric system The VRF for this requirement is “Low,”
which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R5 contains only one objective which is to establish a method to evaluate
communication protocols developed in Requirement R1 to reduce the possibility of miscommunication
which could lead to action or inaction harmful to the reliability of the bulk electric system. Since the
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
VRF and VSL Justifications
24
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
requirement has only one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
VRF and VSL Justifications
Moderate
N/A
High
N/A
Severe
The responsible entity did not
implement a method for
evaluating its communications
protocols as specified in
Requirement R5.
25
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
VRF and VSL Justifications
Based on the VSL Guidance, the SDT developed one VSL based on the failure to establish a method to
evaluate the communication protocols developed in Requirement R1. Therefore the VSL is Severe.
Guideline 2a:
The VSL assignment for R5 is binary.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
26
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R5
Corresponding Requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
Non CIP
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Non CIP
VRF and VSL Justifications
27
Table of Issues and Directives
Project 2007-02
Operating Personnel Communications Protocols
Table of Issues and Directives Associated with COM-002-4
Source
FERC Order No.
693, P 512, 513,
540 (Part1)
Directive Language
512. The Commission finds that, during both
normal and emergency operations, it is
essential that the transmission operator,
balancing authority and reliability coordinator
have communications with distribution
providers. In response to APPA, as discussed
above, any distribution provider that is not a
user, owner or operator of the Bulk-Power
System would not be required to comply with
COM-002-2, even though the Commission is
requiring the ERO to modify the Reliability
Standard to include distribution providers as
applicable entities. APPA’s concern that 2,000
public power systems would have to be added
to the compliance registry is misplaced, since,
as we explain in our Applicability discussion
above, we are approving NERC’s registry
process, including the registry criteria.
Therefore, we adopt our proposal to require
Disposition
Distribution Providers have been included as
applicable entities in COM-002-4
Section and/or
Requirement(s)
Applicability 4.1.2
Requirements R2, R4,
R5.
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
the ERO to modify COM-002-2 to apply to
distribution providers through its Reliability
Standards development process.
513. The Commission believes that this
Reliability Standard does not alter who would
operate a distribution provider’s system. It only
concerns communications, not the operation of
the distribution system.
540. ... In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our
regulations, the Commission directs the ERO to
develop a modification to COM-002-2 through
the Reliability Standards development process
that: (1) expands the applicability to include
distribution providers as applicable entities; (2)
includes a new Requirement for the reliability
coordinator to assess and approve actions that
have impacts beyond the area view of a
transmission operator or balancing authority
and (3) requires tightened communications
protocols, especially for communications
during alerts and emergencies. Alternatively,
with respect to this final issue, the ERO may
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
2
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
develop a new Reliability Standard that
responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally,
we direct the ERO to include APPA’s
suggestions to complete the Measures and
Levels of Non-Compliance in its modification of
COM-002-2 through the Reliability Standards
development process.
FERC Order No.
693, P 531, 534,
535, 540 (Part 3)
531. We adopt our proposal to require the ERO
to establish tightened communication
protocols, especially for communications
during alerts and emergencies, either as part of
COM-002-2 or as a new Reliability Standard.
We note that the ERO’s response to the Staff
Preliminary Assessment supports the need to
develop additional Reliability Standards
addressing consistent communications
protocols among personnel responsible for the
reliability of the Bulk-Power System.
COM-002-4 tightens protocols for Operating
Instructions, which cover necessary nonemergency communications and
communications that are Reliability
Directives. Reliability Directives include both
alert and emergency communications.
Definition of Operating
Instruction
Requirements R1, R2,
R3, R4, R5
534. In response to MISO’s contention that
Blackout Report Recommendation No. 26 has
been fully implemented, we note that
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
3
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
Recommendation No. 26 addressed two
matters. We believe MISO is referring to the
second part of the recommendation requiring
NERC to “[u]pgrade communication system
hardware where appropriate” instead of
tightening communications protocols. While we
commend the ERO for taking appropriate
action in upgrading its NERCNet, we remind the
industry to continue their efforts in addressing
the first part of Blackout Recommendation No.
26. (Emphasis added)
535. Accordingly, we direct the ERO to either
modify COM-002-2 or develop a new Reliability
Standard that requires tightened
communications protocols, especially for
communications during alerts and
emergencies.
FERC Order No.
693, P 532
532. While we agree with EEI that EOP-001-0,
Requirement R4.1 requires communications
protocols to be used during emergencies, we
believe, and the ERO agrees, that the
communications protocols need to be
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
Reliability Standard EOP-001-2.1b —
Emergency Operations Planning (successor
standard to EOP-001-0) requires that the
emergency plans for each Transmission
Operator and Balancing Authority include:
Requirements R1, R3, R5
4
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
tightened to ensure Reliable Operation of the
Bulk-Power System. We also believe an integral
component in tightening the protocols is to
establish communication uniformity as much as
practical on a continent-wide basis. This will
eliminate possible ambiguities in
communications during normal, alert and
emergency conditions. This is important
because the Bulk- Power System is so tightly
interconnected that system impacts often cross
several operating entities’ areas.
Disposition
Section and/or
Requirement(s)
communications protocols to be used during
emergencies (Requirement R3.1). This
requirement is compatible with COM-002-4,
which establishes the communications
protocols and requires their use.
COM-002-4 requires a set of protocols be
used by all applicable entities, establishing
communication uniformity as much as
practical on a continent-wide basis
533. Regarding APPA’s suggestion that it may
be beneficial to include communication
protocols in the relevant Reliability Standard
that governs those types of emergencies, we
direct that it be addressed in the Reliability
Standards development process.
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
5
Table of Issues and Directives Associated with COM-002-4
Source
FERC Order No.
693, P 514, 515
Directive Language
Disposition
514. APPA notes that the Levels of NonCOM-002-4 includes Measures, VRFs and VSLs
Compliance for COM-002-2 are inadequate in
for each requirement.
two respects: (1) reliability coordinators are not
included in any Level of Non-Compliance and
(2) the Levels of Non-Compliance for
transmission operators and balancing
authorities in Compliance D.2 do not reference
Requirements R1 and R2. Therefore, APPA
would support approval of COM-002-2 as a
mandatory Reliability Standard, but would not
support levying penalties for violating
incomplete portions of the Reliability Standard.
Section and/or
Requirement(s)
Section C, Measures
Section D, Compliance
515. As stated in the Common Issues section, a
Reliability Standard is enforceable even if it
does not contain Levels of Non-Compliance.
However, the Commission agrees with APPA
that this Reliability Standard could be improved
by incorporating the changes proposed by
APPA. Therefore, when reviewing the Reliability
Standard through the Reliability Standards
development process, the ERO should consider
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
6
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
APPA’s concerns.
2003 Blackout
Report
Recommendation
No. 26
NERC should work with reliability coordinators
and control area operators to improve the
effectiveness of internal and external
communications during alerts, emergencies, or
other critical situations, and ensure that all key
parties, including state and local officials,
receive timely and accurate information. NERC
should task the regional councils to work
together to develop communications protocols
by December 31, 2004, and to assess and
report on the adequacy of emergency
communications systems within their regions
against the protocols by that date.
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – October 2013
The requirements in COM-002-4 will improve
the effectiveness of internal and external
communications during alerts, emergencies,
and other critical situations.
Requirements R1, R2,
R3, R4, R5
7
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Reliability Standard Audit Worksheet1
COM-002-4 – Operating Personnel Communications Protocols
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s)2:
Compliance Monitoring Method:
Names of Auditors:
Audit ID if available; or REG‐NCRnnnnn‐YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
Audit
Supplied by CEA
Applicability of Requirements [RSAW developer to insert correct applicability]
R1
R2
R3
R4
R5
BA
X
X
X
DP
X
X
GO
GOP
X
X
IA
LSE
PA
PSE
RC
X
X
X
RP
RSG
TO
TOP
X
X
X
TP
TSP
1
NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered
entity’s compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW
should choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the
methodology that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a
substitute for the Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language
contained in the Reliability Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability
Standards can be found on NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the
same frequency. Therefore, it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability
Standard. It is the responsibility of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable
governmental authority, relevant to its registration status.
The NERC RSAW language contained within this document provides a non‐exclusive list, for informational purposes only, of examples of the types of evidence a
registered entity may produce or may be asked to produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples
contained within this RSAW does not necessarily constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW
reserves the right to request additional evidence from the registered entity that is not included in this RSAW. Additionally, this RSAW includes excerpts from FERC
Orders and other regulatory references. The FERC Order cites are provided for ease of reference only, and this document does not necessarily include all applicable
Order provisions. In the event of a discrepancy between FERC Orders, and the language included in this document, FERC Orders shall prevail.
2
Compliance Assessment Date(s): The date(s) the actual compliance assessment (on‐site audit, off‐site spot check, etc.) occurs.
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DRAFT NERC Reliability Standard Audit Worksheet
Subject Matter Experts
Identify Subject Matter Expert(s) responsible for this Reliability Standard. (Insert additional rows if necessary)
Registered Entity Response (Required):
SME Name
Title
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
2
Organization
Requirement(s)
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DRAFT NERC Reliability Standard Audit Worksheet
R1 Supporting Evidence and Documentation
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall have documented
communications protocols. The protocols shall, at a minimum:
1.1. Require the issuer of a Reliability Directive to identify the action as a Reliability Directive to the recipient.
1.2. Require the issuer and receiver of an oral or written Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may be used for internal operations.
1.3. Require the issuer of an oral two‐party, person‐to‐person Operating Instruction to wait for a response
from the receiver. Once a response is received, or if no response is received, require the issuer to take
one of the following actions:
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect, if the receiver does not
issue a response, or if requested by the receiver..
1.4. Require the receiver of an oral two‐party, person‐to‐person Operating Instruction to take one of the
following actions:
Repeat the Operating Instruction and wait for confirmation from the issuer that the repetition was
correct.
Request that the issuer reissue the Operating Instruction.
1.5. Require the issuer of an oral Operating Instruction to verbally or electronically confirm receipt by at least
one receiver when issuing the Operating Instruction through a one‐way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g., an all call system).
1.6. Require the receiver of an oral Operating Instruction to request clarification from the issuer if the
communication is not understood when receiving the Operating Instruction through a one‐way burst
messaging system used to communicate a common message to multiple parties in a short time period
(e.g., an all call system).
1.7. Specify the instances that require time identification when issuing an oral or written Operating
Instruction and the format for that time identification.
1.8. Specify the nomenclature for Transmission interface Elements and Transmission interface Facilities when
issuing an oral or written Operating Instruction.
1.9. Specify the instances where alpha‐numeric clarifiers are required when issuing an oral Operating
Instruction and the format for those clarifiers.
Definition of Operating Instruction
A command by operating personnel responsible for the Real‐time generation control and operation of the
interconnected Bulk Electric System to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. A discussion of general information and of potential
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
3
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options or alternatives to resolve Bulk Electric System operating concerns is not a command and is not considered
an Operating Instruction. A Reliability Directive is one type of an Operating Instruction.
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide its documented
communications protocols developed for Requirement R1.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
Evidence Requested3:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
A copy of the documented communication protocols that cover the Requirements outlined in Requirement R1
Parts 1.1 to 1.9.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM‐002‐4, R1
This section to be completed by the Compliance Enforcement Authority
Review the documented communications protocols provided by entity and ensure they address the sub‐
requirements of R1 as follows:
(1.1) Requires the issuer of a Reliability Directive to identify the action as a Reliability Directive to the
3 Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
4
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recipient
Requires the issuer and receiver of an oral or written Operating Instruction to use the English
language, unless agreed to otherwise. An alternate language may be used for internal operations.
Requires the issuer of an oral two party, person‐to‐person Operating Instruction to wait for a
repetition from the receiver and if the repetition is correct confirm the repetition. If the repetition
is incorrect, or if no repetition is received, or if the receiver requests, requires the issuer to reissue
the Operating Instruction.
Requires the receiver of an oral two party, person‐to‐person Operating Instruction to take one of
the following actions:
• Repeat the Operating Instruction and wait for confirmation from the issuer that the repetition
was correct
• Request that the issuer reissue the Operating Instruction.
Requires the issuer of an oral Operating Instruction to verbally or electronically confirm receipt by
at least one receiving party when issuing the Operating Instruction through a one‐way burst
messaging system used to communicate a common message to multiple parties in a short time
period (e.g., an all call system)
Requires the receiver of an oral Operating Instruction to request clarification from the initiator if
the communication is not understood when receiving the Operating Instruction through a one‐way
burst messaging system used to communicate a common message to multiple parties in a short
time period (e.g. an all call system).
(1.2)
(1.3)
(1.4)
(1.5)
(1.6)
(1.7)
Specifies the instances that require time identification when issuing an oral or written Operating
Instruction and the format for that time identification.
(1.8)
Specifies the nomenclature for Transmission interface Elements and Transmission interface
Facilities when issuing an oral or written Operating Instruction.
(1.9)
Specifies the instances where alpha‐numeric clarifiers are required when issuing an oral Operating
Instruction and the format for those clarifiers
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
5
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R2 Supporting Evidence and Documentation
R2. Each Distribution Operator and Distribution Operator shall have documented communications protocols. The
protocols shall, at a minimum:
2.1. Require the receiver of an oral or written Operating Instruction to respond using the English language,
unless agreed to otherwise. An alternate language may be used for internal operations.
2.2. Require the receiver of an oral two‐party, person‐to‐person Operating Instruction to take one of the
following actions:
Repeat the Operating Instruction and wait for confirmation from the issuer that the
repetition was correct.
Request that the issuer reissue the Operating Instruction.
2.3. Require the receiver of an oral Operating Instruction to request clarification from the issuer if the
communication is not understood when receiving the Operating Instruction through a one‐way burst
messaging system used to communicate a common message to multiple parties in a short time period
(e.g., an all call system).
M2. Each Distribution Provider and Generator Operator shall provide its documented communications protocols
developed for Requirement R2.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
Evidence Requested4:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
A copy of the documented communication protocols that cover the Requirements outlined in Requirement R2
Parts 2.1 to 2.3.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
4 Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
6
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM‐002‐4, R2
This section to be completed by the Compliance Enforcement Authority
Review the documented communications protocols provided by entity and ensure they address the sub‐
requirements of R2 as follows:
(2.1) Requires the receiver of an oral or written Operating Instruction to respond using the English
language, unless agreed to otherwise. An alternate language may be used for internal operations.
(2.2) Requires the receiver of an oral two party, person‐to‐person Operating Instruction to take one of
the following actions:
• Repeat the Operating Instruction and wait for confirmation from the issuer that the repetition
was correct
• Request that the issuer reissue the Operating Instruction.
(2.3) Requires the receiver of an oral Operating Instruction to request clarification from the initiator if
the communication is not understood when receiving the Operating Instruction through a one‐way
burst messaging system used to communicate a common message to multiple parties in a short
time period (e.g. an all call system).
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
7
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R3 Supporting Evidence and Documentation
R3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement the
documented communications protocols developed in Requirement R1.
M3. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide evidence that it
implemented the documented communication protocols which may include, but is not limited to, descriptions
of the management practices in place that provide the entity reasonable assurance that protocols established
in Requirement R1 are being followed by personnel responsible for the real‐time generation control and
operation of the interconnected Bulk Electric System, spreadsheets, memos, or logs, evidencing periodic,
independent review of operating personnel’s adherence to the protocols established in Requirement R1 and
the remediation of noted exceptions in fulfillment of Requirement R5.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
Evidence Requested5:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Descriptions of the management practices in place that provide the entity reasonable assurance that protocols
established in Requirement R1 are being followed by personnel responsible for the real‐time generation
control and operation of the interconnected Bulk Electric System.
Spreadsheets, memos, or logs, evidencing periodic, independent review of operating personnel’s adherence to
the protocols established in Requirement R1 and the remediation of noted exceptions.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
5 Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
8
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM‐002‐4, R3
This section to be completed by the Compliance Enforcement Authority
Review the design of the entity’s management practices related to communication protocols to gain
reasonable assurance that they are effective. Design considerations include frequency, volume of
communications reviewed, and independence of the reviewing party. Identify if management practices
proactively identify and correct issues withcommunications protocols.
Review the evidence provided to gain reasonable assurance that the management practices asserted
above are actually occurring, and are reasonably effective.
If above management practices are deemed insufficient to provide reasonable assurance that
communication protocols are being followed, apply other audit procedures as necessary to gain
confidence regarding the implementation of the communication protocols. See ‘Note to Auditor’ section
for additional details.
Note to Auditor:
The nature and extent of audit procedures applied related to this requirement will vary depending on certain
risk factors to the Bulk Electric System and the auditor’s assessment of management practices specific to this
requirement. In general, more extensive audit procedures will be applied where risks to the Bulk Electric
System are higher and management practices are determined to be less effective.
Based on the assessment of risk and internal controls, as described above, specific audit procedures applied
for this requirement may range from exclusion of this requirement from audit scope to the auditor reviewing a
sample of voice recordings to ensure the protocols related to Operating Instructions were followed. Auditors
may also interview entity operating personnel to understand how they comply with the protocols and observe
them performing their duties. In circumstances where voice recordings are reviewed, auditors should consider
requesting recordings commensurate with known events in the entity’s footprint during the audit period, as
Operating Instructions may be more likely to occur during, and related to, such events, although other
sampling methods for selecting voice recordings may also be employed.
An auditor should first examine the internal controls for this Requirement, not the actual communications.
The focus is on understanding the entity’s internal control processes, verifying they are actually performing
the control, and that the control is reasonably designed. Sampling is not a part of the audit process unless the
auditor determines that the internal control is not properly designed or is ineffective. If the auditor cannot
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
9
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rely on the entity’s controls to gain reasonable assurance of compliance, then the auditor can pull a sample of
the entity’s communications from their available voice recordings (limited to the prior 90 calendar days) and if
instances of noncompliance with the protocols are found, they will be turned over to Enforcement, which will
make the determination whether the entity demonstrates a consistent pattern of not using their documented
communications protocols and, if applicable, the severity of the violation.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
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R4 Supporting Evidence and Documentation
R4. Each Distribution Provider and Generator Operator shall implement the documented communications
protocols developed in Requirement R2.
M4. Each Distribution Provider and Generator Operator shall provide evidence that it implemented the
documented communication protocols which may include, but is not limited to, descriptions of the
management practices in place that provide the entity reasonable assurance that protocols established in
Requirement R2 are being followed by personnel responsible for the real‐time generation control and
operation of the interconnected Bulk Electric System, spreadsheets, memos, or logs, evidencing periodic,
independent review of operating personnel’s adherence to the protocols established in Requirement R2.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
Evidence Requested6:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Descriptions of the management practices in place that provide the entity reasonable assurance that protocols
established in Requirement R2 are being followed by personnel responsible for the real‐time generation
control and operation of the interconnected Bulk Electric System.
Spreadsheets, memos, or logs, evidencing periodic, independent review of operating personnel’s adherence to
the protocols established in Requirement R2 and the remediation of noted exceptions.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
6 Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
11
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM‐002‐4, R4
This section to be completed by the Compliance Enforcement Authority
Review the design of the entity’s management practices related to communication protocols to gain
reasonable assurance that they are effective. Design considerations include frequency, volume of
communications reviewed, and independence of the reviewing party. Identify if management practices
proactively identify and correct issues that could lead to failure of communications protocols.
Review the evidence provided to gain reasonable assurance that the management practices asserted
above are actually occurring, and are reasonably effective.
If above management practices are deemed insufficient to provide reasonable assurance that
communication protocols are being followed, apply other audit procedures as necessary to gain
confidence regarding the implementation of the communication protocols. See ‘Note to Auditor’ section
for additional details.
Note to Auditor: The nature and extent of audit procedures applied related to this requirement will vary
depending on certain risk factors to the Bulk Electric System and the auditor’s assessment of management
practices specific to this requirement. In general, more extensive audit procedures will be applied where risks
to the Bulk Electric System are higher and management practices are determined to be less effective.
Based on the assessment of risk and internal controls, as described above, specific audit procedures applied
for this requirement may range from exclusion of this requirement from audit scope to the auditor reviewing a
sample of voice recordings to ensure the protocols related to Operating Instructions were followed. Auditors
may also interview entity operating personnel to understand how they comply with the protocols and observe
them performing their duties. In circumstances where voice recordings are reviewed, auditors should consider
requesting recordings commensurate with known events in the entity’s footprint during the audit period, as
Operating Instructions may be more likely to occur during, and related to, such events, although other
sampling methods for selecting voice recordings may also be employed.
An auditor should first examine the internal controls for this Requirement, not the actual communications.
The focus is on understanding the entity’s internal control processes, verifying they are actually performing
the control, and that the control is reasonably designed. Sampling is not a part of the audit process unless the
auditor determines that the internal control is not properly designed or is ineffective. If the auditor cannot
rely on the entity’s controls to gain reasonable assurance of compliance, then the auditor can pull a sample of
the entity’s communications from their available voice recordings (limited to the prior 90 calendar days) and if
instances of noncompliance with the protocols are found, they will be turned over to Enforcement, which will
make the determination whether the entity demonstrates a consistent pattern of not using their documented
communications protocols and, if applicable, the severity of the violation.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
12
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DRAFT NERC Reliability Standard Audit Worksheet
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
13
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DRAFT NERC Reliability Standard Audit Worksheet
R5 Supporting Evidence and Documentation
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall implement a method to
evaluate the communications protocols developed in Requirement R1 that:
5.1. Assesses adherence to the communication protocols to provide feedback to issuers and receivers of
Operating Instructions.
5.2. Assesses the effectiveness of the communication protocols and modifies those protocols, as
necessary.
M5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide descriptions and
associated evidence of the management practices in place that demonstrate a review of communications with
operating personnel responsible for the real‐time generation control and operation of the interconnected Bulk
Electric System and evidence that the entity evaluates the effectiveness of its documented communications
protocols in fulfillment of Requirement R5.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
Evidence Requested7:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Provide evidence that entity evaluates the effectiveness of the documented protocols.
Provide evidence that entity provides feedback to improve the effectiveness of operator communication.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
7 Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
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DRAFT NERC Reliability Standard Audit Worksheet
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM‐003‐1, R5
This section to be completed by the Compliance Enforcement Authority
Understand the method and review the evidence provided by the entity to gain confidence that the entity
is evaluating its documented communications protocols developed in Requirement R1. Gain confidence
that evaluation addresses sub‐requirements R5.1‐R5.2.
Note to Auditor: Auditor should assess whether evidence related to the management practices providing
reasonable assurance of implementation of communication protocols provided by entity for Requirement R3
also satisfies Requirement R5, in part or in whole.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
15
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DRAFT NERC Reliability Standard Audit Worksheet
Additional Information:
Reliability Standard
The RSAW developer should provide the following information without hyperlinks. Update the information below as
appropriate.
The full text of STD‐0XX‐N may be found on the NERC Web Site (www.nerc.com) under “Program Areas &
Departments”, “Reliability Standards.”
In addition to the Reliability Standard, there is an applicable Implementation Plan available on the NERC Web
Site.
In addition to the Reliability Standard, there is background information available on the NERC Web Site.
Capitalized terms in the Reliability Standard refer to terms in the NERC Glossary, which may be found on the
NERC Web Site.
Sampling Methodology [If developer deems reference applicable]
Sampling is essential for auditing compliance with NERC Reliability Standards since it is not always possible
or practical to test 100% of either the equipment, documentation, or both, associated with the full suite of
enforceable standards. The Sampling Methodology Guidelines and Criteria, or sample guidelines, provided by
the Electric Reliability Organization help to establish a minimum sample set for monitoring and enforcement
uses in audits of NERC Reliability Standards.
Regulatory Language [Developer to ensure RSAW has been provided to NERC Legal for links to appropriate
Regulatory Language – See example below]
E.g. FERC Order No. 742 paragraph 34: “Based on NERC’s…….
E.g. FERC Order No. 742 Paragraph 55, Commission Determination: “We affirm NERC’s…….
Selected Glossary Terms [If developer deems applicable]
The following Glossary terms are provided for convenience only. Please refer to the NERC web site for the
current enforceable terms.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
16
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DRAFT NERC Reliability Standard Audit Worksheet
Revision History
Version
1
Date
10/18/2013
Reviewers
NERC Compliance,
NERC Standards
Revision Description
New Document
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn‐YYYYMMDD
RSAW Version: RSAW_COM‐002‐4_2013_v1 Revision Date: October, 2013
17
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Agenda Item 9
Standards Committee
October 17, 2013
Proposed Waiver on COM-002 and COM-003 Reliability Standards
Action
Approve a waiver to shorten ballot and comment periods during development of a combined
COM-002 and COM-003 standard.
Background
To prepare for potential direction from the Board of Trustees (“Board”) regarding COM-003-1,
the SC took two actions at its meeting on September 19, 2013 enabling the development of a
revised COM-003-1 standard on an expedited timeline. On September 30, 2013, the Board’s
Standards Oversight and Technology Committee (“SOTC”) held a closed conference call to
deliberate on the inputs to the Board’s questions received on the draft COM-003-1 Reliability
Standard from the Independent Expert Review Panel, Reliability Issues Steering Committee,
NERC Management and the Operating Committee. The SOTC approved a recommendation to
the Board directing the SC to work with the relevant standard drafting team (SDT) (i.e. the
Operating Personnel Communications Protocols (OPCP) SDT) to develop a combined COM-002
and COM-003 standard (the “combined standard”) that includes essential elements included in
the SOTC’s resolution.
Prior to Board action, the SOTC further agreed to direct the SC and NERC management to
provide an update to the SOTC at the November 6, 2013 SOTC meeting on the status of the
development of the draft combined standard and the RSAW. The November 2013 Policy Input
to NERC Board of Trustees is attached. Based on the action of the SOTC, the SC is requested to
approve a new waiver that will supersede the SC’s September 19, 2013 waiver on COM-003
that will allow the OPCP SDT to approve development of a revised standard on a shortened
timeline and will enable the SDT to develop a draft combined standard with the input and
direction from the SOTC. The SC is also requested to approve a shorter time period for the
initial posting to develop, post, and ballot the draft combined standard before the November 7,
2013 Board meeting. The proposed waiver on a combined COM-002/COM-003 standard is
included below:
If, prior to or at its November 7, 2013 meeting, the Board or the Standards Oversight
and Technology Committee requests or directs the COM-003-1 standard drafting team
to post for comment and ballot a proposed COM-002 and COM-003 standard (the
“combined standard”), the Standards Committee approves the following waiver:
a. Direct the COM-003-1 standard drafting team to develop a combined standard and
post the revised combined standard for a 15-calendar day comment and concurrent
10-calendar day ballot period.
b. If the revised combined standard passes, the COM-003-1 standard drafting team is
directed to post the revised combined standard for a 5-calendar day final ballot
period.
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Agenda Item 9
Standards Committee
October 17, 2013
c. If the revised combined standard does not pass, the standard drafting team is
directed not to post the revised combined standard for final ballot.
As required in Section 16.0 of the Standard Processes Manual, NERC provided stakeholders with
notice of this waiver request on October 1, 2013. If the waiver is authorized, NERC staff will
post notice of the waiver on the project page and notify the NERC Board of Trustees Standards
Oversight and Technology Committee.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement Reminder
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
An Additional Ballot and Non-binding Poll is now open through November 4, 2013
Now Available
An additional ballot for COM-002-4 Operating Personnel Communications Protocols
and a non-binding poll of the associated Violation Risk Factors and Violation Severity Levels is now
open through 8 p.m. Eastern on Monday, November 4, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
definition by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual,
which requires all negative votes to have an associated comment submitted (or an indication of
support of another entity’s comments). Please see NERC’s announcement regarding the balloting
software updates and the guidance document, which explains how to cast your ballot and note if
you’ve made a comment in the online comment form or support another entity’s comment
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the definition.
If the comments do not show the need for significant revisions, the definition will proceed to a final
ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-02 OPCP COM-002-4 | AB October 2013
2
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Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
Comment Period: October 21 – November 4, 2013
Upcoming
Additional Ballot and Non-binding Poll: October 25 – November 4, 2013
Now Available
A 15‐day comment period for COM‐002‐4 Operating Personnel Communications Protocols
is open through 8 p.m. Eastern on Monday, November 4, 2013.
On October 17, 2013, the NERC Standards Committee authorized a waiver of the standard process, in
accordance with Section 16 of the Standard Processes Manual, to shorten this comment period of the
combined communication standard from 45 days to 15 days with a ballot during the last 10 days of
the comment period.
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES. The seventh posting of Project 2007‐02 combines COM‐002‐3 and
COM‐003‐1 into one standard titled COM‐002‐4 that addresses communications protocols for
operating personnel in emergency, alert, and non‐emergency situations.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and
mutually understood for communicating Operating Instructions.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off‐line, unofficial copy of the comment form is
posted on the project page.
Next Steps
An additional ballot of COM‐002‐4 and non‐binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted from October 25, 2013 through November 4, 2013.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404‐446‐2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404‐446‐2560 | www.nerc.com
Standards Announcement
Project 2007‐02 OPCP COM‐002‐4 | October 2013
2
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Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
Comment Period: October 21 – November 4, 2013
Upcoming
Additional Ballot and Non-binding Poll: October 25 – November 4, 2013
Now Available
A 15‐day comment period for COM‐002‐4 Operating Personnel Communications Protocols
is open through 8 p.m. Eastern on Monday, November 4, 2013.
On October 17, 2013, the NERC Standards Committee authorized a waiver of the standard process, in
accordance with Section 16 of the Standard Processes Manual, to shorten this comment period of the
combined communication standard from 45 days to 15 days with a ballot during the last 10 days of
the comment period.
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES. The seventh posting of Project 2007‐02 combines COM‐002‐3 and
COM‐003‐1 into one standard titled COM‐002‐4 that addresses communications protocols for
operating personnel in emergency, alert, and non‐emergency situations.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and
mutually understood for communicating Operating Instructions.
Background information for this project can be found on the project page.
Instructions for Commenting
Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off‐line, unofficial copy of the comment form is
posted on the project page.
Next Steps
An additional ballot of COM‐002‐4 and non‐binding poll of the associated Violation Risk Factors and
Violation Severity Levels will be conducted from October 25, 2013 through November 4, 2013.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404‐446‐2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404‐446‐2560 | www.nerc.com
Standards Announcement
Project 2007‐02 OPCP COM‐002‐4 | October 2013
2
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Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols COM-002-4
Additional Ballot and Non-Binding Poll Results
Now Available
An additional ballot of COM-002-4 Operating Personnel Communications Protocols and non-binding
poll of the associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern
on Thursday, November 7, 2013.
This standard achieved a quorum but did not receive sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the
additional ballot.
Approval
Non-Binding Poll Results
Quorum: 76.67%
Quorum: 75.52%
Approval: 58.24%
Supportive Opinions: 55.46%
Background information for this project can be found on the project page.
Next Steps
On November 7, 2013 the NERC Board of Trustees (Board) approved a resolution on Operating
Personnel Communications Protocols, which may be found here. In response to this resolution, the
drafting team will meet in Atlanta, GA on November 19, 2013 to consider comments and prepare a new
draft of COM-002-4. Meeting details may be found here, as well as registration information. The
drafting team expects to post this new draft the week of December 2, 2013 so that the standard can be
delivered to the Board at the February 2014 meeting, as directed in the resolution.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-02 OPCP COM-002-4 | November 2013
2
NERC
Standards
20140514-5129
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Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-02 COM-002-4 Additional Ballot October 2013
Password
Ballot Period: 10/25/2013 - 11/7/2013
Ballot Type: Additional Ballot
Log in
Total # Votes: 322
Register
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Total Ballot Pool: 420
Quorum: 76.67 % The Quorum has been reached
Weighted Segment
58.24 %
Vote:
Ballot Results: The Ballot has Closed
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals
1
2
3
4
5
6
7
8
9
108
1
46
0.575
34
0.425
0
7
21
11
0.9
3
0.3
6
0.6
0
1
1
101
1
37
0.578
27
0.422
0
7
30
38
1
13
0.542
11
0.458
0
0
14
89
1
42
0.618
26
0.382
0
9
12
51
1
23
0.622
14
0.378
0
2
12
0
0
0
0
0
0
0
0
0
8
0.4
2
0.2
2
0.2
0
0
4
5
0
0
0
0
0
0
1
4
9
0.8
7
0.7
1
0.1
0
1
0
420
7.1
173
4.135
121
2.965
0
28
98
Individual Ballot Pool Results
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Segment
Organization
Member
1
Ameren Services
Kirit Shah
1
1
1
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Paul B Johnson
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
ATCO Electric
Glen Sutton
Ballot
Negative
Negative
James Armke
Negative
1
1
Avista Corp.
Balancing Authority of Northern California
Scott J Kinney
Kevin Smith
Affirmative
1
Baltimore Gas & Electric Company
Gregory S Miller
1
1
1
1
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Negative
Tony Kroskey
1
Bryan Texas Utilities
John C Fontenot
1
CenterPoint Energy Houston Electric, LLC
John Brockhan
Negative
1
Central Electric Power Cooperative
Michael B Bax
Negative
1
City of Pasadena
Marco A Sustaita
1
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Chang G Choi
1
1
1
1
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
1
1
1
1
1
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Christopher L de
Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
COMMENT
RECEIVED Chris Scanlon
Affirmative
Affirmative
Brazos Electric Power Cooperative, Inc.
1
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Affirmative
1
Paul Morland
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Austin Energy
Colorado Springs Utilities
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Affirmative
Affirmative
Affirmative
1
1
NERC
Notes
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
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1
Gainesville Regional Utilities
Richard Bachmeier
1
1
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Jason Snodgrass
Gordon Pietsch
1
Hydro One Networks, Inc.
Ajay Garg
Negative
1
Hydro-Quebec TransEnergie
Bernard Pelletier
Negative
1
Idaho Power Company
Molly Devine
Negative
1
Affirmative
Affirmative
Bob Solomon
1
International Transmission Company
Holdings Corp
JEA
1
KAMO Electric Cooperative
Walter Kenyon
1
1
Kansas City Power & Light Co.
Keys Energy Services
Michael Gammon
Stanley T Rzad
1
Negative
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Michael Moltane
Affirmative
Ted Hobson
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS ((FMPA)
Florida
Municpal
Power
Agency)
1
Lakeland Electric
Larry E Watt
1
1
1
1
1
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Negative
1
Nebraska Public Power District
Cole C Brodine
Negative
1
New York Power Authority
Bruce Metruck
Negative
1
New York State Electric & Gas Corp.
Raymond P Kinney
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
Northeast Utilities
David Boguslawski
1
1
1
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Kevin M Largura
John Canavan
Robert Mattey
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED National Grid
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
NPCC
submitted
comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
COMMENT
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1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
1
1
1
1
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
1
Platte River Power Authority
John C. Collins
1
1
1
1
1
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
1
1
Negative
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Abstain
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Rod Noteboom
Denise M Lietz
1
Rochester Gas and Electric Corp.
John C. Allen
1
1
1
1
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
1
1
1
1
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
Negative
1
1
Tennessee Valley Authority
Trans Bay Cable LLC
Larry G Akens
Steven Powell
Affirmative
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
Tucson Electric Power Co.
John Tolo
Negative
1
United Illuminating Co.
Jonathan Appelbaum
Westar Energy
Allen Klassen
1
Western Area Power Administration
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
2
BC Hydro
Mark B Thompson
Venkataramakrishnan
Vinnakota
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
1
1
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (Ronald L.
Donahey)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group
comments)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel Energy)
Abstain
Affirmative
SUPPORTS
THIRD PARTY
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COMMENTS (ISO/RTO
Standards
Review
Committee)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (IRC SRC)
SUPPORTS
THIRD PARTY
COMMENTS (IRC/SRC)
2
California ISO
Rich Vine
Negative
2
Electric Reliability Council of Texas, Inc.
Cheryl Moseley
Negative
2
Independent Electricity System Operator
Barbara Constantinescu
Negative
2
ISO New England, Inc.
Kathleen Goodman
Negative
2
Midwest ISO, Inc.
Marie Knox
Negative
2
2
2
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Alden Briggs
Gregory Campoli
stephanie monzon
Affirmative
Affirmative
2
Southwest Power Pool, Inc.
Charles H. Yeung
Negative
COMMENT
RECEIVED
3
3
Alabama Power Company
Alameda Municipal Power
Richard J. Mandes
Douglas Draeger
Negative
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI's)
3
Ameren Services
Mark Peters
3
APS
Steven Norris
3
Associated Electric Cooperative, Inc.
3
3
3
3
3
Atlantic City Electric Company
NICOLE BUCKMAN
Avista Corp.
Robert Lafferty
BC Hydro and Power Authority
Pat G. Harrington
Blachly-Lane Electric Co-op
Bud Tracy
Bonneville Power Administration
Rebecca Berdahl
Central Electric Cooperative, Inc. (Redmond,
Dave Markham
Oregon)
3
Chris W Bolick
Affirmative
Affirmative
Affirmative
3
Central Electric Power Cooperative
Adam M Weber
Negative
3
Central Lincoln PUD
Steve Alexanderson
Negative
3
City of Austin dba Austin Energy
Andrew Gallo
Negative
3
City of Bartow, Florida
Matt Culverhouse
Negative
3
3
3
3
3
City
City
City
City
City
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
of
of
of
of
of
Clewiston
Farmington
Garland
Green Cove Springs
Lodi, California
3
City of Palo Alto
Eric R Scott
3
3
3
3
3
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Small Entity
Comment
Group (to be
submitted))
Affirmative
Abstain
SUPPORTS
THIRD PARTY
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Colorado Springs Utilities
Charles Morgan
Negative
3
ComEd
Bruce Krawczyk
Negative
3
Consolidated Edison Co. of New York
Peter T Yost
3
Consumers Energy
Richard Blumenstock
3
3
3
3
3
3
3
3
3
3
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Joel T Plessinger
Bryan Case
Stephan Kern
3
Florida Municipal Power Agency
Joe McKinney
3
3
3
3
3
3
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Abstain
3
KAMO Electric Cooperative
Theodore J Hilmes
Negative
3
Kansas City Power & Light Co.
Charles Locke
Negative
3
Kissimmee Utility Authority
Gregory D Woessner
Negative
3
Lakeland Electric
Mace D Hunter
Negative
3
3
3
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Affirmative
3
Louisville Gas and Electric Co.
Charles A. Freibert
Negative
3
M & A Electric Power Cooperative
Stephen D Pogue
Negative
3
3
3
3
3
3
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
COMMENTS (Colorado
Springs
Utilities)
SUPPORTS
THIRD PARTY
COMMENTS Chris Scanlon
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (comments
filed under
PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Nebraska Public Power District
Tony Eddleman
Negative
3
New York Power Authority
David R Rivera
Negative
3
3
3
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
3
3
3
3
3
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby
Affirmative
NW Electric Power Cooperative, Inc.
David McDowell
Negative
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Owensboro Municipal Utilities
Thomas T Lyons
3
3
3
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
PacifiCorp
John H Hagen
Rick Paschall
Dan Zollner
Affirmative
3
Platte River Power Authority
Terry L Baker
Negative
3
3
3
3
3
3
3
3
3
3
3
3
3
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Michael Mertz
Thomas G Ward
Robert Reuter
Jeffrey Mueller
Erin Apperson
Heber Carpenter
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
South Carolina Electric & Gas Co.
Hubert C Young
Tacoma Public Utilities
Travis Metcalfe
3
Tampa Electric Co.
Ronald L. Donahey
3
3
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Umatilla Electric Cooperative
Steve Eldrige
3
Westar Energy
Bo Jones
3
3
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
James R Keller
Michael Ibold
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
3
3
SUPPORTS
THIRD PARTY
COMMENTS (Don Schmit
submitted
comments for
Nebraska
Public Power
District)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC
Comments)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Comments)
Abstain
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Affirmative
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
Alliant Energy Corp. Services, Inc.
American Municipal Power
Kenneth Goldsmith
Kevin Koloini
Affirmative
4
Blue Ridge Power Agency
Duane S Dahlquist
Negative
4
Central Lincoln PUD
Shamus J Gamache
Negative
4
City of Austin dba Austin Energy
Reza Ebrahimian
Negative
4
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
Kevin McCarthy
4
4
Tim Beyrle
Nicholas Zettel
Affirmative
4
City Utilities of Springfield, Missouri
John Allen
4
4
4
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
David Frank Ronk
Rick Syring
Daniel Herring
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
Fort Pierce Utilities Authority
Cairo Vanegas
Negative
4
Georgia System Operations Corporation
Guy Andrews
Affirmative
4
Illinois Municipal Electric Agency
Bob C. Thomas
4
Imperial Irrigation District
Diana U Torres
4
Indiana Municipal Power Agency
Jack Alvey
4
4
4
4
4
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
4
Oklahoma Municipal Power Authority
Ashley Stringer
4
4
4
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Mark Ringhausen
Aleka K Scott
Henry E. LuBean
4
SUPPORTS
THIRD PARTY
COMMENTS (Support
comments of
IMPA, FMPA
and Utilities
Services)
SUPPORTS
THIRD PARTY
COMMENTS (Western
Small Entity
Comment
Group)
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
John D Martinsen
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency,
Utility
Services,
Indiana
Municipal
Power Agency,
SERC Review
Group)
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Utility
Services)
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
4
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Richard L Koch
4
Tacoma Public Utilities
Keith Morisette
4
4
4
5
5
West Oregon Electric Cooperative, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
AES Corporation
Marc M Farmer
Anthony Jankowski
Todd Komplin
Brock Ondayko
Leo Bernier
5
Amerenue
Sam Dwyer
5
Arizona Public Service Co.
Edward Cambridge
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
5
5
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
5
5
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Calpine Corporation
Phillip Porter
City and County of San Francisco
Daniel Mason
Negative
5
City of Austin dba Austin Energy
Jeanie Doty
Negative
5
5
5
5
5
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
5
Colorado Springs Utilities
Jennifer Eckels
5
Consolidated Edison Co. of New York
Wilket (Jack) Ng
David C Greyerbiehl
5
5
5
5
5
5
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
5
Dynegy Inc.
Negative
Negative
John R Cashin
Patrick Brown
Abstain
Negative
Michael Korchynsky
5
5
ExxonMobil Research and Engineering
FirstEnergy Solutions
Martin Kaufman
Kenneth Dresner
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Jerry
Farringer)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Exelon Nuclear
COMMENT
RECEIVED
Affirmative
Dana Showalter
5
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Affirmative
Negative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Abstain
Affirmative
Dan Roethemeyer
E.ON Climate & Renewables North America,
LLC
Electric Power Supply Association
Essential Power, LLC
5
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
5
Consumers Energy Company
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
comments)
Affirmative
5
5
COMMENT
RECEIVED
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Committee)
SUPPORTS
THIRD PARTY
COMMENTS Chris Scanlon
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Preston L Walsh
Affirmative
5
Hydro-Québec Production
Roger Dufresne
Negative
5
5
Imperial Irrigation District
JEA
Marcela Y Caballero
John J Babik
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
Kissimmee Utility Authority
Mike Blough
Negative
5
Lakeland Electric
James M Howard
Negative
5
Liberty Electric Power LLC
Daniel Duff
Negative
5
5
5
5
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
David Gordon
Abstain
5
5
5
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
5
Nebraska Public Power District
Don Schmit
Negative
5
New York Power Authority
Wayne Sipperly
Negative
5
NextEra Energy
Allen D Schriver
Affirmative
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
Northern Indiana Public Service Co.
William O. Thompson
Affirmative
5
Occidental Chemical
Michelle R DAntuono
Negative
5
5
5
5
5
5
5
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
5
Steven Grego
Christopher Schneider
Mike Avesing
5
PPL Generation LLC
Annette M Bannon
5
PSEG Fossil LLC
Tim Kucey
5
5
5
5
5
5
5
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Steven Grega
COMMENT
RECEIVED
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Muncipal
Power Pool)
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Affirmative
Negative
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NW small
entity group)
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
5
5
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
5
Tacoma Power
Chris Mattson
Negative
5
Tampa Electric Co.
RJames Rocha
Negative
5
5
5
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
Scott M. Helyer
David Thompson
Melissa Kurtz
5
U.S. Bureau of Reclamation
Martin Bauer
Negative
5
Westar Energy
Bryan Taggart
Negative
5
5
Wisconsin Electric Power Co.
WPPI Energy
Linda Horn
Steven Leovy
Affirmative
Affirmative
5
Xcel Energy, Inc.
Liam Noailles
Negative
6
AEP Marketing
Edward P. Cox
Abstain
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland)
Affirmative
6
Ameren Energy Marketing Co.
Jennifer Richardson
6
APS
Randy A. Young
Affirmative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
Negative
6
Bonneville Power Administration
Brenda S. Anderson
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
6
City of Austin dba Austin Energy
Lisa Martin
6
6
6
6
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
6
Constellation Energy Commodities Group
Donald Schopp
6
6
6
6
6
Discount Power, Inc.
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
David Feldman
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
6
6
6
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
Negative
6
Lakeland Electric
Paul Shipps
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
SUPPORTS
THIRD PARTY
COMMENTS (TEC Ron
Donahey)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS Chris Scanlon
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
(FMPA)
6
6
Lincoln Electric System
Los Angeles Department of Water & Power
Eric Ruskamp
Brad Packer
6
Luminant Energy
Brad Jones
6
6
6
6
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
6
New York Power Authority
Saul Rojas
6
6
6
6
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Affirmative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
6
6
6
6
6
6
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Affirmative
John J. Ciza
Affirmative
6
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Michael C Hill
Negative
6
Tampa Electric Co.
Benjamin F Smith II
Negative
6
Tennessee Valley Authority
Marjorie S. Parsons
Affirmative
6
Westar Energy
Grant L Wilkerson
6
Western Area Power Administration - UGP
Marketing
Peter H Kinney
6
Xcel Energy, Inc.
David F Lemmons
Negative
8
Roger C Zaklukiewicz
Negative
8
8
8
8
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
James A Maenner
Edward C Stein
Frederick R Plett
Margaret Ryan
8
Utility Services, Inc.
Brian Evans-Mongeon
8
8
9
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Robert L Dintelman
Terry Volkmann
William M Chamberlain
9
9
Diane J. Barney
Jerome Murray
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Tacoma Public Utilities
Donald Nelson
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
Affirmative
6
9
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Kieth
Morisette)
SUPPORTS
THIRD PARTY
COMMENTS (support
comments
made by Ron
Donahey)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS Alice Ireland
SUPPORTS
THIRD PARTY
COMMENTS (ISO-NE)
Affirmative
Negative
Affirmative
Abstain
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
9
10
10
10
10
10
10
10
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Emily Pennel
10
Texas Reliability Entity, Inc.
Donald G Jones
10
Western Electricity Coordinating Council
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Steven L. Rueckert
Legal and Privacy
404.446.2560 voice : 404.446.2595 fax
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2012 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=760a4e52-1546-4d84-bbe3-f32a8cc82676[11/12/2013 3:09:58 PM]
COMMENT
RECEIVED
Negative
Affirmative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-Binding Poll Results
Project 2007-02 COM-002-4
Non-Binding Poll Results
Non-Binding Poll Name: Project 2007-02 COM-002-4 Non-Binding Poll October 2013_sc_2
Poll Period: 10/25/2013 - 11/7/2013
Total # Opinions: 290
Total Ballot Pool: 384
75.52% of those who registered to participate provided an opinion or an abstention;
Summary Results: 55.46% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Organization
Member
Opinions
1
Ameren Services
Kirit Shah
Negative
1
American Electric Power
Paul B Johnson
Negative
1
Arizona Public Service Co.
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
ATCO Electric
Glen Sutton
1
Austin Energy
James Armke
1
1
1
1
1
1
Avista Corp.
Balancing Authority of Northern California
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Scott J Kinney
Kevin Smith
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
1
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
1
Bryan Texas Utilities
John C Fontenot
1
CenterPoint Energy Houston Electric, LLC John Brockhan
Comments
COMMENT
RECEIVED SERC OC
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Foltz - AEP)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Abstain
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)
Affirmative
Negative
COMMENT
RECEIVED
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
Central Electric Power Cooperative
Michael B Bax
1
City of Pasadena
Marco A Sustaita
1
City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
1
1
1
1
City Utilities of Springfield, Missouri
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
1
Colorado Springs Utilities
1
Consolidated Edison Co. of New York
1
1
1
1
1
1
1
1
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Empire District Electric Co.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Jeff Knottek
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Ralph F Meyer
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
1
Gainesville Regional Utilities
1
1
Georgia Transmission Corporation
Jason Snodgrass
Great River Energy
Gordon Pietsch
Hoosier Energy Rural Electric Cooperative,
Bob Solomon
Inc.
1
Richard Bachmeier
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Affirmative
Affirmative
1
Hydro One Networks, Inc.
Ajay Garg
Negative
1
Hydro-Quebec TransEnergie
Bernard Pelletier
Negative
1
Idaho Power Company
Molly Devine
Negative
1
International Transmission Company
Holdings Corp
Michael Moltane
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
Abstain
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
JEA
Ted Hobson
1
KAMO Electric Cooperative
Walter Kenyon
1
1
Kansas City Power & Light Co.
Keys Energy Services
Michael Gammon
Stanley T Rzad
1
Lakeland Electric
Larry E Watt
1
1
1
1
1
Lee County Electric Cooperative
John W Delucca
LG&E Energy Transmission Services
Bradley C. Young
Long Island Power Authority
Robert Ganley
Los Angeles Department of Water & Power John Burnett
Lower Colorado River Authority
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Joe D Petaski
Danny Dees
Terry Harbour
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Negative
1
Nebraska Public Power District
Cole C Brodine
Negative
1
New York Power Authority
Bruce Metruck
Negative
1
New York State Electric & Gas Corp.
Raymond P Kinney
1
Northeast Missouri Electric Power
Cooperative
Kevin White
Negative
1
Northeast Utilities
David Boguslawski
Negative
1
1
Northern Indiana Public Service Co.
NorthWestern Energy
Kevin M Largura
John Canavan
1
Ohio Valley Electric Corp.
Robert Mattey
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
SUPPORTS
THIRD PARTY
COMMENTS (Refer to
NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS -
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
1
1
1
1
1
1
1
1
1
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Brad Chase
Bangalore Vijayraghavan
Ryan Millard
Ronald Schloendorn
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
1
1
Negative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Rod Noteboom
Denise M Lietz
1
Rochester Gas and Electric Corp.
John C. Allen
1
1
1
1
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
1
1
1
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Long T Duong
Steven Mavis
Robert A. Schaffeld
William Hutchison
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
1
Southwest Transmission Cooperative, Inc. John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
Negative
1
Tennessee Valley Authority
Larry G Akens
Non-Binding Poll Results
Project 2007-02 | November 2013
(Thomas
Foltz American
Electric
Power)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (Ronald L.
Donahey)
Affirmative
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
Trans Bay Cable LLC
Steven Powell
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
1
Tucson Electric Power Co.
United Illuminating Co.
John Tolo
Jonathan Appelbaum
1
Westar Energy
Allen Klassen
1
1
2
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator
2
BC Hydro
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Abstain
Affirmative
Negative
California ISO
Rich Vine
Negative
2
Electric Reliability Council of Texas, Inc.
Cheryl Moseley
Negative
2
Independent Electricity System Operator
Barbara Constantinescu
Negative
2
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
2
New Brunswick System Operator
Alden Briggs
2
New York Independent System Operator
Gregory Campoli
2
2
3
3
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alabama Power Company
Alameda Municipal Power
stephanie monzon
Charles H. Yeung
Richard J. Mandes
Douglas Draeger
3
Ameren Services
Mark Peters
3
APS
Steven Norris
3
Associated Electric Cooperative, Inc.
Chris W Bolick
3
3
3
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group
comments)
Abstain
2
2
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ISO/RTO
Standards
Review
Committee)
COMMENT
RECEIVED
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (IRC/SRC)
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI's)
Abstain
Affirmative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Central Electric Power Cooperative
Adam M Weber
Negative
3
Central Lincoln PUD
Steve Alexanderson
3
City of Austin dba Austin Energy
Andrew Gallo
Negative
3
City of Bartow, Florida
Matt Culverhouse
Negative
3
3
3
3
3
3
3
3
3
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
Cleco Corporation
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Michelle A Corley
Abstain
Abstain
Affirmative
Colorado Springs Utilities
Charles Morgan
Negative
3
ComEd
Bruce Krawczyk
Negative
3
Consolidated Edison Co. of New York
Peter T Yost
3
Consumers Energy
Richard Blumenstock
3
3
3
3
3
Cowlitz County PUD
CPS Energy
Detroit Edison Company
Entergy
FirstEnergy Energy Delivery
Russell A Noble
Jose Escamilla
Kent Kujala
Joel T Plessinger
Stephan Kern
3
Florida Municipal Power Agency
Joe McKinney
3
3
3
3
3
3
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
KAMO Electric Cooperative
Non-Binding Poll Results
Project 2007-02 | November 2013
Theodore J Hilmes
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Abstain
Abstain
3
3
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (associated
electric
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Kansas City Power & Light Co.
Charles Locke
Negative
3
Kissimmee Utility Authority
Gregory D Woessner
Negative
3
3
3
3
Lakeland Electric
Mace D Hunter
Lincoln Electric System
Jason Fortik
Los Angeles Department of Water & Power Daniel D Kurowski
Louisville Gas and Electric Co.
Charles A. Freibert
3
M & A Electric Power Cooperative
Stephen D Pogue
3
3
3
3
3
3
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Affirmative
Negative
Affirmative
Affirmative
Nebraska Public Power District
Tony Eddleman
Negative
3
New York Power Authority
David R Rivera
Negative
3
Niagara Mohawk (National Grid Company) Michael Schiavone
Northeast Missouri Electric Power
Skyler Wiegmann
Cooperative
Northern Indiana Public Service Co.
William SeDoris
3
3
NW Electric Power Cooperative, Inc.
David McDowell
3
Orange and Rockland Utilities, Inc.
David Burke
3
Owensboro Municipal Utilities
Thomas T Lyons
3
3
Pacific Gas and Electric Company
PacifiCorp
John H Hagen
Dan Zollner
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
Affirmative
Affirmative
Affirmative
3
3
cooperative)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (Don Schmit
submitted
comments
for Nebraska
Public Power
District)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC
Comments)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Comments)
Affirmative
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Platte River Power Authority
Terry L Baker
3
3
3
3
3
3
3
3
3
3
3
3
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Michael Mertz
Thomas G Ward
Robert Reuter
Jeffrey Mueller
Erin Apperson
Thomas M Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
South Carolina Electric & Gas Co.
Hubert C Young
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
3
Tacoma Public Utilities
Travis Metcalfe
Negative
3
Tampa Electric Co.
Ronald L. Donahey
Negative
3
3
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Ian S Grant
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
Negative
3
Westar Energy
Bo Jones
Negative
3
3
4
4
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
COMMENT
RECEIVED
Abstain
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)
Abstain
Affirmative
4
Blue Ridge Power Agency
Duane S Dahlquist
Negative
4
Central Lincoln PUD
Shamus J Gamache
Abstain
4
City of Austin dba Austin Energy
Reza Ebrahimian
Non-Binding Poll Results
Project 2007-02 | November 2013
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Support
comments of
IMPA, FMPA
and Utilities
Services)
SUPPORTS
THIRD PARTY
COMMENTS -
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
(Andrew
Gallo)
4
4
4
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
Affirmative
4
City Utilities of Springfield, Missouri
John Allen
4
4
4
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
David Frank Ronk
Rick Syring
Daniel Herring
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
Florida Municipal Power Agency
Frank Gaffney
Negative
4
4
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Cairo Vanegas
Guy Andrews
Abstain
Affirmative
4
Illinois Municipal Electric Agency
Bob C. Thomas
4
Imperial Irrigation District
Diana U Torres
4
Indiana Municipal Power Agency
Jack Alvey
4
4
4
4
4
4
4
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
4
4
4
4
4
4
Non-Binding Poll Results
Project 2007-02 | November 2013
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency,
Utility
Services,
Indiana
Municipal
Power
Agency,
SERC Review
Group)
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Abstain
Henry E. LuBean
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Abstain
Affirmative
9
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Association
4
Tacoma Public Utilities
Keith Morisette
4
4
Wisconsin Energy Corp.
WPPI Energy
Anthony Jankowski
Todd Komplin
Negative
Affirmative
Affirmative
5
AEP Service Corp.
Brock Ondayko
Negative
5
AES Corporation
Leo Bernier
Negative
5
Amerenue
Sam Dwyer
Negative
5
Arizona Public Service Co.
Edward Cambridge
Associated Electric Cooperative, Inc.
Matthew Pacobit
Negative
5
5
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration
Edward F. Groce
Clement Ma
Abstain
5
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Mike D Kukla
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
Calpine Corporation
City and County of San Francisco
Phillip Porter
Daniel Mason
5
City of Austin dba Austin Energy
Jeanie Doty
5
5
5
5
5
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
5
Colorado Springs Utilities
Jennifer Eckels
5
5
Consolidated Edison Co. of New York
Consumers Energy Company
Wilket (Jack) Ng
David C Greyerbiehl
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (Thomas
Foltz –
American
Electric
Power)
SUPPORTS
THIRD PARTY
COMMENTS (reliability
First)
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
comments)
Affirmative
5
5
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
THIRD PARTY
COMMENTS (Jerry
Farringer)
5
5
5
5
5
5
5
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
5
5
E.ON Climate & Renewables North
America, LLC
Electric Power Supply Association
Essential Power, LLC
5
Exelon Nuclear
Michael Korchynsky
5
5
ExxonMobil Research and Engineering
FirstEnergy Solutions
Martin Kaufman
Kenneth Dresner
Affirmative
5
Florida Municipal Power Agency
David Schumann
Negative
5
Great River Energy
Preston L Walsh
Affirmative
5
Hydro-Québec Production
Roger Dufresne
Negative
5
5
Imperial Irrigation District
JEA
Marcela Y Caballero
John J Babik
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
Kissimmee Utility Authority
Mike Blough
Negative
5
5
5
5
5
5
Lakeland Electric
James M Howard
Liberty Electric Power LLC
Daniel Duff
Lincoln Electric System
Dennis Florom
Los Angeles Department of Water & Power Kenneth Silver
Luminant Generation Company LLC
Mike Laney
Manitoba Hydro
S N Fernando
Massachusetts Municipal Wholesale
David Gordon
Electric Company
MEAG Power
Steven Grego
MidAmerican Energy Co.
Christopher Schneider
Muscatine Power & Water
Mike Avesing
Nebraska Public Power District
Don Schmit
5
5
5
5
5
5
Non-Binding Poll Results
Project 2007-02 | November 2013
Dana Showalter
Abstain
John R Cashin
Patrick Brown
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Committee)
COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power
Agency)
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
COMMENT
11
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
New York Power Authority
Wayne Sipperly
Negative
5
NextEra Energy
Allen D Schriver
Affirmative
5
North Carolina Electric Membership Corp. Jeffrey S Brame
5
5
5
5
5
5
5
5
5
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Tim Hattaway
5
PPL Generation LLC
Annette M Bannon
5
PSEG Fossil LLC
Tim Kucey
5
5
5
5
5
5
5
5
5
5
5
5
5
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Steven Grega
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
Abstain
Negative
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (NW small
entity group)
Affirmative
Affirmative
5
Tacoma Power
Chris Mattson
Negative
5
Tampa Electric Co.
RJames Rocha
Negative
Non-Binding Poll Results
Project 2007-02 | November 2013
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (Keith
Morisette)
SUPPORTS
THIRD PARTY
COMMENTS -
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
(TEC Ron
Donahey)
5
5
5
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
Scott M. Helyer
David Thompson
Melissa Kurtz
Abstain
Affirmative
Affirmative
5
U.S. Bureau of Reclamation
Martin Bauer
Negative
5
5
5
Wisconsin Electric Power Co.
WPPI Energy
Xcel Energy, Inc.
Linda Horn
Steven Leovy
Liam Noailles
Affirmative
6
AEP Marketing
Edward P. Cox
Negative
6
Ameren Energy Marketing Co.
Jennifer Richardson
Negative
6
6
APS
Bonneville Power Administration
Randy A. Young
Brenda S. Anderson
Affirmative
Affirmative
6
City of Austin dba Austin Energy
Lisa Martin
6
6
6
6
6
6
6
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Greg Cecil
Terri F Benoit
Kevin Querry
6
Florida Municipal Power Agency
Richard L. Montgomery
6
6
6
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
Negative
6
Lakeland Electric
Paul Shipps
Negative
6
6
Lincoln Electric System
Eric Ruskamp
Los Angeles Department of Water & Power Brad Packer
6
Luminant Energy
Brad Jones
6
6
Manitoba Hydro
MidAmerican Energy Co.
Daniel Prowse
Dennis Kimm
Non-Binding Poll Results
Project 2007-02 | November 2013
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
AEP)
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Andrew
Gallo)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMAP)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
Modesto Irrigation District
Muscatine Power & Water
James McFall
John Stolley
Affirmative
6
New York Power Authority
Saul Rojas
6
6
6
6
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Affirmative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
6
6
6
6
6
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and
Energy Marketing
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Abstain
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
John J. Ciza
Affirmative
6
Negative
Affirmative
6
Tacoma Public Utilities
Michael C Hill
Negative
6
Tampa Electric Co.
Benjamin F Smith II
Negative
6
Tennessee Valley Authority
Marjorie S. Parsons
Abstain
6
6
8
8
Westar Energy
Grant L Wilkerson
Western Area Power Administration - UGP
Peter H Kinney
Marketing
Edward C Stein
James A Maenner
8
Roger C Zaklukiewicz
8
Massachusetts Attorney General
Frederick R Plett
8
Utility Services, Inc.
Brian Evans-Mongeon
Non-Binding Poll Results
Project 2007-02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Kieith
Morisette)
SUPPORTS
THIRD PARTY
COMMENTS (support
comments
made by Ron
Donahey)
SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standard
Group)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ISO-NE)
Affirmative
Negative
COMMENT
RECEIVED
14
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
8
8
9
Robert L Dintelman
Terry Volkmann
William M Chamberlain
9
10
10
10
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts
Department of Public Utilities
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
10
Northeast Power Coordinating Council
Guy V. Zito
10
10
10
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Anthony E Jablonski
Carter B Edge
Emily Pennel
10
Texas Reliability Entity, Inc.
Donald G Jones
10
Western Electricity Coordinating Council
Steven L. Rueckert
9
Non-Binding Poll Results
Project 2007-02 | November 2013
Donald Nelson
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Abstain
15
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (77 Responses)
Name (51 Responses)
Organization (51 Responses)
Group Name (26 Responses)
Lead Contact (26 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING
ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (11 Responses)
Comments (77 Responses)
Question 1 (50 Responses)
Question 1 Comments (66 Responses)
Question 2 (50 Responses)
Question 2 Comments (66 Responses)
Question 3 (64 Responses)
Question 3 Comments (66 Responses)
Individual
William H. Chambliss, Operating Committee
Virginia State Corporation Commission
Yes
Requirement R.1.5 obligates issuers of burst messages using "a one-way burst messaging
system" to confirm receipt of that message "by at least one receiver." However, nothing in the
requirements that I can find explains how such confirmation is to occur. Requirement R.1.6
obligates a receiver of a burst message to respond only "to request clarification from this issuer
if the communication is not understood." There is no Requirement on any receiver to confirm
receipt of an understood communication.
Group
Northeast Power Coordinating Council
Guy Zito
No
Neither Recommendation 26 in the Final Report on the August 14, 2003 Blackout In The United
States and Canada or FERC Order 693 require 3-part communications protocol, or any
established communication protocol for day to day operations. Both the Blackout Report
Recommendation 26 and the Order 693 sections related to inter-Area communications
identified one of the key factors in the Blackout being related to communications between and
to RC entities as not being effective. It is not apparent if 3-part communications or the content
of the other requirements in the proposed standard were in effect August 13, 2003 the
problems would not have occurred. From the North American Electric Reliability Council Status
of August 2003 Blackout Recommendations July 14, 2005: Recommendation 26. Tighten
communications protocols, especially for communications during alerts and emergencies.
Upgrade communication system hardware where appropriate. Status: Ongoing initiative. In
response to this recommendation, NERC installed a new conference bridge and approved a
new set of hotline procedures and protocols for reliability coordinator hotline calls. NERC is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
working on an upgrade of the Reliability Coordinator Information System (RCIS) — an on-line,
real-time, messaging system that connects all Reliability Coordinators and many control areas,
which permits Reliability Coordinators to share emergency alerts. RCIS also displays
information related to Area Control Error (ACE), frequency, and selected outages. Work in this
area will be an ongoing activity as technologies and techniques improve. Note that NERC’s own
report does not mention any operator-to-operator communications. Also, from the Report to
the U.S.-Canada Power System Outage Task Force The August 14, 2003 Blackout One Year
Later: Actions Taken in the United States and Canada To Reduce Blackout Risk from the Natural
Resources Canada, and the U.S. Department of Energy, the section Key Accomplishments—and
Major Challenges Still Ahead section, there is no mention of communications issues. In light of
the above, some of NPCC’s participating members do not believe that the Standard is
necessary and any perceived gap in communications has already been addressed through other
means. We are not aware of any evidence that exists of a reliability issue existing for normal
communications that needs to be addressed.
No
Not following a communications protocol when the Operating Instruction is identified as a
Reliability Directive is an instance of zero tolerance. So even if a Reliability Directive is
addressed and action is taken but the protocol was “missed” and a BES situation is mitigated, it
is still a Severe Violation. This is extreme, and the VSLs for R4 should be reduced to address
this. Regarding Requirement R4, more clarity needs to be provided on how a “consistent
pattern” will be established and a set of uniform criteria needs to exist, without it there will be
disparity in assessing compliance. Some of the applicable entities do not record phone
conversations. The RSAW states that any instances of non-compliance will be turned over to
Enforcement to determine a “consistent pattern.” Again this is zero-tolerance language as each
instance will be considered a potential violation. The standard implies that a zero defect
assessment for Reliability Directives will be assessed in reviewing the VSL’s. This does not meet
the tenets of a results based standards development or any intention of the RAI process. The
requirement needs to stand on its own. Only requirements that are approved by FERC are
therefore enforceable. Requirement language should be provided that clearly states the intent
to have a zero defect requirement for completing three part communication when Reliability
Directives are issued. This is not an endorsement of this approach, simply a correct application
of the SDT intent. The VSL wording is incorrect. For example, in R1, the Low VSL states the
following: “The responsible entity did not specify the instances that require time
identification…” when it should read “The responsible entity’s protocol did not specify the
instances that require time identification…” The Requirement is about specification in the
protocol document explicitly. There are other places in the VSLs that similar errors occur.
Suggest adding for R4 VSL Lower - The Reliability Directive was performed correctly by the
receiver, but the responsible entity did not use the documented communications protocols
developed in Requirement R2 when receiving a Reliability Directive. Suggest revising R4 VSL
Severe - The Reliability Directive was performed incorrectly by the receiver, because the
responsible entity did not use the documented communications protocols developed in
Requirement R2 when receiving a Reliability Directive. The VSL should not add an additional
layer of compliance to the proposed requirement. The requirements are structured to include:
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1) document, 2) implement and 3) evaluate. The VSL should be developed from these three
components of the standard and not introduce a ‘zero defect’ enforcement approach. NERC’s
recent direction was to move away from ‘zero defect’ standards and approach compliance
from an ‘ identify, assess and correct’ approach for controls type standards that have high
frequency activity that do not immediately pose a reliability risk. The proposed requirements
follow that approach. The proposed VRFs incorrectly introduce a ‘zero defect’ approach
through a ‘back door’. An entity may ‘implement’ a protocol, but one occurrence of not
following that protocol does not warrant an entity to be non-compliant, as proposed in the
standard. If the drafting team is looking for a ‘zero defect’ standard then the appropriate
wording needs to be in the requirement. It is unnecessary as the ‘zero defect’ requirements for
poor communication already exist in current IRO/TOP Standards.
Yes
The Requirements of COM-002-4 as written make it a zero tolerance standard. Non-emergency
communications should not be zero tolerance. It can be argued that Reliability Directives be
subject to zero tolerance, but even then there are realistic operational situations where having
to identify a communication as a Reliability Directive, and having to repeat it back can further
exacerbate a tenuous operating condition. Burst messaging should not be considered in the
standard. Part 1.5 requires confirmation by at least one receiver for burst messaging. A burst
message can include the issuance of multiple Reliability Directives. Getting one receipt does
not guarantee that all Reliability Directives were received. There is no value in getting one
back. In an emergency situation waiting for all recipients of a burst message to respond can
have catastrophic reliability consequences. When a burst message is sent, the initiator can see
from the system response if the message was received. FERC approved Standard TOP-001-1a
Requirement R3 states that “Each Transmission Operator, Balancing Authority, and Generator
Operator shall comply with reliability directives issued by the Reliability Coordinator, and each
Balancing Authority and Generator Operator shall comply with reliability directives issued by
the Transmission Operator, unless such actions would violate safety, equipment, regulatory or
statutory requirements…” (This TOP-001 is deficient in itself as it doesn’t address Transmission
Operator to Transmission Operator directives). The Requirement goes on to further state that a
response is only required if there is an inability to perform the directive. This introduces a
double jeopardy situation with COM-002-4. If an entity does not comply with a directive and
has not repeated it back to the issuer there is a violation of TOP-001-1a, and COM-002-4. TOP001-1a Requirement R4, IRO-001-1.1 Requirement R8, and IRO-004-2 Requirement R1 also
address communications. There is questionable value in having a documented communications
protocol if the entity does not intend to implement it, make sure it is followed, maintained and
personnel are trained in it. Suggest that requirements R3 and R4 either be added into the body
of R1 and R2 respectively, or as Parts of R1 and R2 respectively. The VSLs should be modified
accordingly. There was concern in the expressed in the Northeast that if no proper
documented protocol is available, it also can’t be implemented thus resulting in double
jeopardy concerns. Combining these and requiring the protocol and also implementing it in the
same requirement is preferable. In addition a problem was expressed with the term
“implement”. NPCC’s participating members believe that implement, in the context written,
could result in an auditor taking a “zero” defect approach. In this context, implement means to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
have a current in effect document that is part of the mandatory policy of the entity that
employees must follow if applicable to their job function. Part 1.4 reads: “Require the issuer of
an oral Operating Instruction to verbally or electronically confirm receipt by at least one
receiver when issuing the Operating Instruction through a one-way burst messaging system
used to communicate a common message to multiple parties in a short time period (e.g., an all
call system).” This removes the efficiency gains obtained through such communication. It is
unrealistic and an impediment to reliability if, during an emergency situation for example, the
issuer of an oral Operating Instruction has to take the time to confirm receipt, and have the
receiver of the Operating Instruction interrupt the implementation of actions to mitigate the
emergency to confirm receipt. In all cases the issuer of the instruction would observe changes
to the system thus providing “confirmation” of receipt. Furthermore, there is no requirement
for the receiver to confirm receipt. Suggest adding a bullet stating that the receiver has to
acknowledge receipt of the initial message. NPCC’s participating members maintain that a
Reliability Directive is a communication requiring immediate or emergency action, it should not
be included in the definition of Operating Instruction, and the definition of Operating
Instruction revised accordingly. R5 reads: “Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall implement a method to evaluate the communications
protocols developed in Requirement R1 that:…” This does not require any evaluation by the DP
or GOP. We would like the Standard Drafting Team to explain why a similar requirement was
not considered for the DP or GOP? There is a disparity between the RSAW and VSLs as to what
is considered noncompliant. The VSL states you are non-compliant for not using 3-way
communications for Operating Instructions only if you show a “consistent pattern” of not
following your protocols. The RSAW states that events should be sampled, and if instances of
noncompliance with the protocols are found, the issue should be turned over to the
Compliance Enforcement Authority who will then make a determination whether there was a
pattern. First, the focus should not be on just sampling events. The entity should provide the
samples that they tested internally to do their periodic reviews of the effectiveness and
adherence to the protocols in place. Is Requirement R1.1 necessary? As per NERC
Management’s response in the document "NERC Management Response to the Questions of
the NERC BOT on Reliability Standard COM-003-1" (page 4/5), it was suggested that
distinguishing between "operating instructions" and "reliability directives" would not be
practical during real-time situations and that it was as important, if not more important that
common protocols be used for emergency communications. Any instruction given should be
treated as a reliability directive and therefore there is no need for R1.1. Furthermore, the
proposed definition of Operating Instruction on page 2 of the draft standard states that a
reliability directive is one type of operating instruction. This further demonstrates the
redundancy of having R1.1 in the standard. The applicability of the standard should be written
to exclude DPs that do not own or operate BES equipment. As per the definition of Operating
Instruction “A command … to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System...” Entities that do not
have real-time control of Elements or Facilities of the BES should be removed from the
applicability of the standard. Suggest adding the following to Section 4: 4.1.2 Distribution
Provider with control of Elements or Facilities of the Bulk Electric System. M3 and M4 are
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
difficult to understand and suggest edits to clarify: Each Distribution Provider and Generator
Operator shall provide evidence that it implemented the documented communication
protocols such that the entity has reasonable assurance that protocols established in
Requirement R2 are being followed by personnel responsible for the real-time generation
control and operation of the interconnected Bulk Electric System. Evidence should show
periodic, independent review of the operating personnel’s adherence to protocols established
in R2. Evidence may include, but is not limited to • Descriptions of the management practices
in place, • spreadsheets, • memos, or • logs, R5.1 is redundant with R3 as both require
assessment of adherence to protocols established in R1. If part of “Implementation” (covered
in R3) includes an assessment of the communication protocols, R5 should be limited to only
correcting deficiencies with the protocols and the implementation of those protocols. If not
removed as redundant, Requirement 5.1 should specify that the assessment will be limited to
the operating personnel of the individual entity for both issuing and receiving Operating
Instructions. As it is written now it would be the responsibility of the BA, RC and TOP to assess
compliance with communication protocols to all entities involved in every communication,
including the receiving GOPs and DPs, and other BAs, RCs and TOPs based on the Operating
Instruction as “issuer and receiver” are not defined. Suggested Rewording of R5.1: “Assesses
adherence to the communications protocols to provide feedback to entity personnel”. In
several places, including the Implementation Plan, there is mention of retiring COM-002-3. This
standard was never FERC approved, therefore suggest changing this from retiring COM-002-3
to withdrawing COM-002-3. Implementation plan period – it is in the best interest of reliability
for operating and other control room personnel to be thoroughly trained on the new
communications protocols proposed in COM‐002‐4 before the standard goes into effect for
compliance. To thoroughly train the more than 6000 certified operators in North America will
likely take more than a year and an implementation plan period of one year is therefore
inadequate. It is recommended that the SDT consider a two year period to assure successful
implementation. If the SDT decides to retain the proposed one year implementation plan, we
recommend that the SDT consider adding an option for the Registered Entity to elect an
additional one year implementation period, to be vetted and pre‐approved on a case by case
basis upon mutual agreement between the Regional Entity and the Registered Entity.
Addressing preferred communication methods and procedures could be addressed in training
programs that would be reviewed for universal consistency. The requirements contained
within COM-002-4 and its previous versions have concepts that more appropriately belong in a
procedure or guideline. One example is COM-002-4, R1.3: "Require the issuer of an oral twoparty, person-to-person Operating Instruction to wait for a response from the receiver ...". If
the NERC Board of Trustees decides that a standard is needed: 1) Industry must accept that
there needs to be a NERC Standard that addresses both Normal and Emergency
communications. 2) The standard needs to be simplified. 3) Regulators acknowledge and
understand that the "zero-defect" regulatory approach is already (appropriately) applied to the
result (e.g. was a Reliability Directive implemented properly), and therefore does not need to
be applied to the supporting means (communications). 4) Related to 3), there are already
"zero-defect" requirements associated with Reliability Directive compliance as contained in
IRO-001, R8, IRO-004-2, R1, TOP-001-1a, R3 and R4. 5) Acknowledge that each entity is going to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
have to ensure their communication protocols are appropriately coordinated w/ neighboring
entities. 6. Burst messaging should not be included in this standard. The preceding will require
compromise between the Industry and Regulatory bodies. RSAW Comments: The “Note to
Auditor” related to R3 and R4 is outside of the scope of the standard. Placing the examination
of Internal Control within the RSAW effectively requires entities to have Internal Controls,
which expands the scope of the standard significantly.
Individual
Thomas Foltz
American Electric Power
Yes
No
R3 & R4: While there *is* the potential of risk if documented communications protocols are
not followed, this should not somehow imply that incorrect operations were performed as a
result. The severe category should be reserved only for those instances in which documented
communications protocols were not followed *and* which resulted in an emergency operation
or reliability issue. As a result, we suggest “demoting” each existing VSL to a lower level, and
editing the Severe VSL and limit it to only those instances that resulted in an emergency
operation or reliability issue (suggestions provided below). Low - The responsible entity
demonstrates a consistent pattern of not using the documented communications protocols
developed in Requirement R1 for Operating Instructions that are not Reliability Directives.
Moderate – The responsible entity did not use the documented communications protocols
developed in Requirement R1 when issuing or receiving a Reliability Directive. High – The
responsible entity did not use the documented communications protocols developed in
Requirement R1 when issuing or receiving an Operating Instruction *and* resulting in an
emergency operation or reliability issue. Severe - The responsible entity did not use the
documented communications protocols developed in Requirement R1 when issuing or
receiving a Reliability Directive *and* resulting in an emergency operation or reliability issue.
Yes
R5.1: Read on its own, one might think an issuer of an operating instruction may be required to
provide feedback to the receiver. We don’t believe this is the intent. We suggest removing R5.1
in its entirety, or at a minimum, change the wording to the following: “Assesses adherence to
communications protocols.”
Individual
Gerald G Farringer
Consumers Energy
Yes
The addition of “Operating Instruction” is less clear than in previous versions. In the distinction
of “Operating Instruction “is needed at all it needs to be distinct and separate from a
“Reliability Directive”. There needs to be a distinction of requests and instruction. Typical
generation dispatch could be a request and does not have the weight of a direct reliability risk
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for example. Keeping a clear distinction of “Reliability Directive” lends an air of urgency to the
direction. There needs to be this clear distinction to communicate the difference between
routine economic dispatches and true reliability needs. Creating “Operating Instruction” will
only cause this category to be used when a “Reliability Directive” would be appropriate.
Individual
Chantal Mazza
Hydro Québec TransÉnergie
Agree
NPCC
Group
Southwest Power Pool Regional Entity
Emily Pennel
Yes
R3, R4, and R5 as addressed in the draft RSAW focuses on compliance related to internal
controls. Disagree that compliance assessment is primarily based on internal controls and
limiting audit scope and review of evidence as reflected in the Notes to Auditor section. Also
limiting review of voice recordings to last 90 days negates the value of sampling for 3 way
communication during events during the entire audit period. I don’t think notes to auditor
section should include audit scoping and dedicated to internal controls review for which
compliance assessment findings of violations cannot be determined. R1 and R2 are focused on
documentation of communication protocols, R3 and R4 the implementation of said protocols.
R5 a method to evaluate protocols for R1. Unclear as to why R3 implementation cannot include
the components of R5 as for same entities and both involve implementation of protocols. R5 is
review.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
Yes
No
Individual
Christopher Wood
Platte River Power Authority
Yes
We believe that requirement 1.9 should be removed or rewritten. If each utility is allowed to
define this differently it would make communication more difficult, especially in emergency
conditions.
Individual
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Andrew Gallo
City of Austin dba Austin Energy
No
Neither the August 2003 Blackout Report Recommendation number 26 nor Order 693 requires
three-part communications or any established communication protocol for normal operations.
Additionally, EOP-001-2, R3.1 and COM-002-2, R2 already address the requirements of the
Blackout Report and FERC Order 693.
No
Regarding R3 and R4: These VSLs create a “zero tolerance” situation. If an entity fails to follow
the communication protocol when issuing or receiving a Reliability Directive one time, even if
there is no adverse impact to the BES, it is a violation. While there is the potential of risk if
documented communications protocols are not followed, this should not somehow imply that
incorrect operations occurred as a result. The severe category should be reserved for only
those instances in which documented communications protocols were not followed and the
failure resulted in an emergency operation or reliability issue. As a result, we suggest
“demoting” each existing VSL to a lower level and limiting the Severe VSL to only those
instances that resulted in an adverse impact on the BES (suggestions provided below). Low The responsible entity demonstrates a consistent pattern of not using the documented
communications protocols developed in Requirement R1 for Operating Instructions that are
not Reliability Directives. Moderate – The responsible entity did not use the documented
communications protocols developed in Requirement R1 when issuing or receiving a Reliability
Directive. High – The responsible entity did not use the documented communications protocols
developed in Requirement R1 when issuing or receiving an Operating Instruction and that
failure resulted in an emergency operation or reliability issue. Severe - The responsible entity
did not use the documented communications protocols developed in Requirement R1 when
issuing or receiving a Reliability Directive and that failure resulted in an emergency operation
or reliability issue. Regarding the VSL for R3 and R4: Use of the term “consistent pattern” is
vague and will be difficult to determine and analyze.
Yes
R2.1 currently requires, “the receiver of an oral or written Operating Instruction to respond
using the English language.” We recommend re-writing the requirement to require, “the
receiver of an oral or written Operating Instruction to use the English language.” (similar to
R1.2) “Written Operating Instructions” must be defined (e.g. in the ERCOT Region, would an
electronic, computer-generated dispatch instruction constitute a “written Operating
Instruction?”) Measure 3 requires “reasonable assurance” without defining that term.
Additionally, M3 also requires an “independent review.” Does that require hiring a third-party?
Can a company’s compliance office serve as the “independent” reviewer? Can an operator
“independently review” another operator? In several places, including the implementation
plan, there is mention of retiring COM-002-3. FERC never approved that standard. The
standard should not apply to DPs who do not own or operate BES equipment. As per the
definition of Operating Instruction “A command … to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
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System...” The Standard should not apply to entities that do not have real-time control of BES
Elements or Facilities. We suggest adding the following to Section 4: 4.1.2 Distribution
Providers who control BES Elements or Facilities. In the definition of “Operating Instruction,”
the word “and” in the second line and the fourth line should be “or.”
Individual
Steven Wallace
Seminole Electric Cooperative, Inc.
Yes
Yes
Yes
The RSAW for COM-002-4 seems dependent on the implementation of the Reliability
Assurance Initiative (RAI) which is not expected to be implemented until 2016. It is not
reasonable to utilize an internal controls approach to auditing until the criteria for such
evaluation has been clearly explained to the stakeholders. Therefore, the Implementation Plan
and the EFFECTIVE DATE for this standard needs to be delayed accordingly.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
Modify Requirement 1 Part 1.1 to say: “Require the issuer of a Reliability Directive to identify
the action as a Reliability Directive to the receiver where time permitting.” Time permitting
would be defined as when taking proactive actions to mitigate or prevent an Adverse Reliability
impact pre-contingency. Stating “This is a Reliability Directive” would not be required postcontingency, and at the discretion of the sender would only be used if time were permitting.
Add a new sub-requirement requiring that senders (RC, BA, TOP) and receivers (GOP, DP) of
Operating Instructions, including Reliability Directives, have direct communication facilities.
This requirement would remove the inherent time delay and introduction of garbled messages
caused by the use of communications intermediaries. The following wording is suggested: New
Requirement 1.2 - Require the issuer and receiver of an oral or written Operating Instruction
have direct communications facilities. The use of communications intermediaries is not
acceptable. Append the following words to the end of Requirement 5.1: “to ensure there that
there is a consistent pattern in the use of communications protocols.” The sub-requirement
would then read as follows: 5.1. Assesses adherence to the communications protocols to
provide feedback to issuers and receivers of Operating Instructions to ensure there that there
is a consistent pattern in the use of communications protocols.
No
Background - The ultimate purpose of any communications standard should be to see that the
correct actions affecting the BES are taken. Greater emphasis should be placed on Reliability
Directives, than on non-RD Operating Instructions. Therefore, the ultimate measure of whether
such communications were successful should be whether the required action was taken (and
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the real-time risk to the BES reduced) or not. It should not be based on whether some
documentation requirement was met or some communications protocol was followed to the
letter. Recommendations - We recommend different VSL ratings for a failure to repeat-back,
depending upon whether the Operating Instruction was a Reliability Directive or a non-RD
Operating Instruction, and whether the action taken reduced or potentially increased the realtime risk to the BES. If the action taken by the receiver (who failed to repeat back) was still
correct and in accordance with the Sender’s instructions, then only an administrative
requirement was violated. There was no actual risk to the BES. This fact should be recognized
and the documentation failure rated lower. However, if following a failure to repeat-back a
receiver takes an incorrect or inappropriate action, which potentially introduces increased risk
to the reliable operation of the BES, then this failure and should receive a higher rating. As
such, we recommend the following replacements for the Requirement R4 VSL’s: Add R4 VSL
Lower - The Reliability Directive was performed correctly by the receiver, but the responsible
entity did not use the documented communications protocols developed in Requirement R2
when receiving a Reliability Directive. Revise R4 VSL Severe - The Reliability Directive was
performed incorrectly by the receiver, because the responsible entity did not use the
documented communications protocols developed in Requirement R2 when receiving a
Reliability Directive.
No
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC Review Group
Individual
David Burke
Orange and Rockland Utilities, Inc.
Agree
Consolidated Edison Co. of NY, Inc.
Individual
Shirley Mayadewi
Manitoba Hydro
Yes
No comment.
Yes
Although Manitoba Hydro is in general agreement with the standard, we have the following
clarifying comments: (a) VSLs, R1 and R2, Moderate – the statement ‘an alternate language
may be used for internal operations’ is not necessary. (b) VSLs, R1 and R2, High and Severe –
these are not written in the same form as the lower and moderate VSLs. The latter paraphrase
the requirement part that is being violated while the former only refer to the requirement part
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number. (c) VSLs R3, R4 – the term ‘consistent pattern’ is subjective; unclear how this would be
interpreted. (d) VSLs R5 – doesn’t address requirements in 5.1 and 5.2
Yes
Although Manitoba Hydro is in general agreement with the standard, we have the following
clarifying comments: (a) M3, M4, M5 – replace Bulk Electric System with BES. (b) Purpose –
consider using the word ‘improve’ or ‘strengthen’ instead of ‘tighten’ in this statement. (c) R1 –
Reliability Directive is not yet a FERC approved definition. What is the protocol if the definition
of Reliability Direction is not approved? (d) R1 – the bulleted statements in R1, 1.3 make more
sense if they came after the statements in 1.4. 1.4 discusses the requirement on the receiver to
repeat information, a reference in 1.3 to ‘repeated information’ is premature. (e) R5 – 5.2
buries an additional requirement with the last few words ‘to modify the protocols as
necessary’. If such a requirement is to be in place, it should be a separate requirement not
tagged on to the R5 requirement to evaluate and assess. (f) There seems to be missing a
further requirement that would require the Distribution Provider and Generator Operator to
evaluate their communication protocols similar to that in R5. (g) M3 and M4 – the language
‘that provide the entity reasonable assurance that protocols……Bulk Electric System’ seems
unnecessary here. This language does not appear anywhere else in the requirement or the
standard. Wouldn’t it be sufficient to require evidence of management practices in place
without going into further description? (h) M4 – the language ‘and the remediation of noted
exceptions in fulfillment of Requirement R5’ doesn’t seem to belong here. R3 simply requires
implementation, not remediation. (i) M5 – the language in M5 does not match the language in
R5, and doesn’t address 5.1 or 5.2.
Individual
Michael Falvo
Independent Electricity System Operator
No
a. As indicated in all of our comments on the previous COM-003 postings, we believe that the
COM-002-3 standard that is supported by the industry and approved by NERC Board of
Trustees adequately addressed the Blackout Report recommendation. Furthermore,
communication protocols are in place to require functional entities that receive Reliability
Directives to perform the directive issues by the RC, BA and TOP. While we generally supports
exercising tightened communication protocols for routine operating instructions, we continue
to disagree with the need to develop a standard that mandate three-part communication for
issuance of Operating Instructions for normal operating system conditions. Any and all
instructions will either change or preserve the state, status, output, or input of an Element of
the Bulk Electric System or Facility of the Bulk Electric System. Unlike its COM-003-1 Draft 5
predecessor, this draft no longer allows the Responsible Entity to specify the instances where
the issuer of an oral two party, person-to-person Operating Instruction is required to exercise
3-part communication. Without this provision, the standard now requires 3-part
communication whenever a Responsible Entity issues an Operating Instruction. This is overly
burdensome, and may in fact hurt reliability as System Operators will now place focus on
implementing and completing the 3-part communication process rather than concentrating on
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the actions needed to achieve a reliability outcome. Notwithstanding the above, we have the
following comments on the proposed standard. b. Part 1.3 is unclear in two aspect: • To “wait”
is not a 2-part action, and is not measurable. How is an entity assessed whether or not it
waited or not waited? We suggest to make it more proactive by replacing it with “obtain” or
“collect” a response. • In the second sentence, the phrase “or if no response is received” is
open-ended. When should the issuing entity take one of the actions listed in the bullets below?
We suggest the SDT to add a time frame in this sentence such as: “or if no response is received
in X minutes”. Without the time frame, it will not be possible for the issuing entity to know
when it is supposed to follow up, and for the Compliance Enforcement Authority to assess if
Part 1.3 was complied with. • The above comment also applies to Part 2.2. c. Part 1.4 places
the obligation on the receivers of the Operating Instruction; it is not appropriate for inclusion in
the issuer’s communication protocol unless the protocol document is distributed to all
potential recipients of the Operating Instructions. However, there does not exist a requirement
for the BA, RC or TOP to distribute their communication protocol document hence the
inclusion of Part 1.4 in their communication protocol document is inappropriate and serves no
purpose. d. Part 1.5: The intent of this part is unclear or the requirement is incomplete, leading
to an unnecessary or missing action mandated by the requirement, or the potential for noncompliance despite best effort. Part 1.5 requires the issuer (say, a BA) of an Operating
Instruction that uses a one-way burst messaging system for communicating common messages
to multiple parties to obtain confirmation from at least one recipient (say, a GOP). The intent of
using the burst messaging system is to achieve efficiency by eliminating the need for one-onone communication of the same message and the need for confirming receipt of the message.
The requirement for the issuer to confirm receipt by at least one receiver of the message is not
consistent with the intent of using the burst messaging system. Further, we believe that the
combined standard should focus on oral two-party, person-to-person communication. The oneway burst messaging system requirement is thus not necessary (e.g., confirmation of receipt)
and should be removed because this is more of an electronic verification that is a function of
the operability of the one-way burst messaging system If the SDT should insist that
requirement be retained, then to confirm at least one recipient receives the message, there
needs to be an obligation on the receiving entities to acknowledge receipt of the Operating
Instruction. However, there is no requirement in the standard to require the receiving entities
(say, a GOP or a DP) to provide that confirmation. The only requirement for responding to
Operating Instruction transmitted through the burst messaging system is when the
communication is not understood by the recipient as stipulated in Part 1.6 and Part 2.3. If all
recipients understand (or think they understand) the Operating Instruction so transmitted, the
issuing party (e.g. a BA) will not receive any confirmation at all. In this case, the issuing part
(e.g. the BA) will not be able to comply with Part 1.5. We suggest the SDT to review the intent
of Part 1.5, and to remove this part or strengthen the other parts in this and other requirement
to close the loop for confirming receipt of Operating Instructions transmitted through the burst
messaging system. e. Requirement R5 requires the BA, RC and TOP to implement a method to
evaluate the communications protocols developed in Requirement R1, assess adherence to the
protocol, provide feedback and make adjustments as necessary. There is no such requirement
for the GOP and DP who are also required to develop their communication protocol per
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Requirement R2. The reason for not having such a requirement is not presented in the posted
Rationale and Technical Justification document. We suggest the SDT to provide the reason for
not having this requirement, or to add this requirement to close the gap.
No
Requirements R3 and R4 were mapped from Requirements R1 and R2 of in Draft 5 of the COM003-1 standard. In that draft, both of these requirements were assigned a LOW VRF, which we
concurred. In the proposed COM-002-4, the SDT proposes that these two requirements (now
R3 and R4) be assigned a HIGH VRF “… because failure to use the communications protocols
during an emergency could directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures.” We do not agree with the
HIGH VRF since miscommunication alone does not and cannot cause instability. It needs to
have another action or inaction combined by an event on the BES to result in any disturbance
that results in instability. Even if we agree to some extent that failure to use the
communication protocol during an emergency could contribute to bulk electric system
instability, these two requirements also cover non-emergency situations. Under the latter
conditions, we are unable to support the argument that failure to use the communications
protocols could cause or contribute to bulk electric system instability. At most, we can accept a
MEDIUM VRF assigned to these two requirements, but not a HIGH. We suggest the SDT to
revise these VRF accordingly.
Individual
David Thorne
Pepco Holdings Inc
Yes
Take the case of a TO communicating with a TOP regarding the TOs prescheduled request to
perform a BES switching activity. When field personnel are ready to begin work, the TO would
contact the TOP requesting that the switching activity begin. The TOP would then authorize the
TO perform the prescheduled BES switching. Technically the TOP did not “command” that the
TO change the state of the BES system as described in the definition of Operating Instruction. Is
“three part” communication required in this instance? If so please explain/describe how the
draft standard is applied in this instance, since TOs are not included as Applicable and that no
Operating Instructions were issued. In R3 and R4 in the RSAW it states under Evidence
Required: “Spreadsheets, memos, or logs, evidencing periodic, independent review of
operating personnel’s adherence to the protocols…” What is meant by “independent review”?
Is that meant to onlyexclude the personnel involved directly in the communication from “selfcertifying” their adherence or does that exclude the Operations supervisor in charge of the
Operating personnel and other operations personnel from review? That would imply then that
review would require someone from outside operations like internal audit or a consultant.
Group
Tennessee Valley Authority
Brandy Spraker
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Yes
Yes
Yes
TVA supports the SERC OC Review Group comments. We would respectfully add the comment
below: As currently written, Measurements M3 and M4 establish the additional requirement of
“periodic, independent review . . . of adherence to the [documented communication]
protocols.” This is essentially duplication of activity without additional reliability benefit over
assessments performed by issuers required in R5. As such, this will create unnecessary
administrative burden on applicable entities. The SDT is respectfully requested to remove this
language from M3 and M4 and to add as an alternative, a requirement for documented
response to feedback from the issuers’ assessments that would include evidence of corrective
actions taken. Suggested wording would be, “ . . . reasonable assurance that protocols
established in Requirement R2 are being followed by personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System, and documented
responses to feedback received from assessments performed as required in R5, consisting of
dated reports, or copies of electronic messages, or other evidence of appropriate corrective
actions taken or technically justified explanations as to why no action is required.
Individual
John Seelke
Public Service Enterprise Group
Yes
Yes
1. Make a common NERC-wide communications protocol a separate standard attachment. We
believe a single protocol that would apply across all of NERC is desirable. That protocol could
be incorporated in a separate attachment with these items defining the “protocol:” a. The
issuer of a Reliability Directive shall identify the action as a Reliability Directive to the receiver.
b. When an oral person-to-person Operating Instruction command is issued, the command
shall be repeated by the recipient and either confirmed by the issuer or reissued to resolve
misunderstandings. c. For an oral Operating Instruction that uses a one-way burst messaging
system to communicate a common message to multiple parties in a short time period (e.g., an
all call system): i. The issuer shall electronically or verbally confirm the receipt by at least
recipient. ii. The receiver shall request clarification from the issuer when the Operating
Instruction is not understood. We have not included certain provisions in R1 in the COM-002-4
draft in the protocol items: • We would not require each RC, BA, and TOP to develop its own
protocol to address such items as time identifiers and the use of alpha-numeric clarifiers. We
believe that three-part communications will correct any misunderstandings. • We would not
address written communications, which are included in subparts 1.2 and 1.8. Although
addressed in COM-002-4 draft, written communications requirements are only placed the
issuer and therefore should not be included. • While not impacted by 1.2 for oral Operating
Instructions, we did not require the receiver of an oral Operating Instruction to reply in English,
unless agreed to otherwise. We believe the language used for communicating does not need to
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be addressed in a standard because it is automatically handled by the use of three-part
communications. 2. Include a requirement that requires the protocol be implemented. With a
protocol defined in an attachment, a requirement should simply require Operating Instruction
issuers (RC, BA, and TOP) and receivers (BA, TOP, DP, and GOP) to implement the
communications protocol as defined in the attachment. This requirement would replace R1
through R4 in the current COM-002-4 draft.
Individual
Roger Dufresne
Hydro-québec Production
Yes
No
VRF, VSL The violation severity level and the VRF level seems not to be at the proper level
compare to the requirement.
Yes
R1 - The issuer of a reliability directive should not have to identify the action as a reliability
directive to a receiver. There should be only one level of communication protocol. The
operating instruction should be included in the Reliability Directive to create only one level of
communication protocol. This communication protocol would then be considered the highest
level in all communication situation. A single communication protocol would minimise the risk
of unwanted communication delay in emergency situation. Requiring the issuer of an oral twoparty, person-to-person Operating Instruction to wait for a response from the receiver and
having the receiver to repeat the Operating instruction would induce unwanted
communication delay in emergency situation.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
No
FERC Order 693 P 512 may have intended Distribution Provider (DP) be made applicable, but
also stipulates not all DP entities will be required to comply with the communication and
coordination standard. For an entity registered as a DP to provide BES support as intended by
the Standard, there must be means and trained personnel available 24/7 to control facilities in
a timely fashion which will have a significant operational impact on the BES and staff available
to receive Operational Instructions. Many small entities do not maintain a 24/7 distribution
dispath operation, precisely because their TOP is the one with control of the BES and lower
level communications are generally related to impacts of the TOP's operational decisions. If
DPs are included in the applicability section, there needs to be some qualifier on DPs with BES
control of assets deemed essential by the the RC or PA/PC or something similar.
No
Not with the current unqualified applicability for DPs.
No
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Previous comments by other small entities on the impacts of this standard appear to remain
unaddressed in the current draft. This may be an oversight by the drafting team, but it does
remain a defect in the current draft. The standard as drafted will require small entities to have
and implement protocols to deal with Operating Instructions that they currently don't get or
may never get from their TOP or BA, because of their lower voltage and impact position on the
outskirts of the BES. Additional staffing will be required to deal with one-way bursts that might
occur after hours, even though none of the possible issuers of these have indicated any plans
to implement such a system, or have suggested that these entities must be available around
the clock for reliability. DPs not designated by the RC or PA/PC be excluded.
Individual
Keith Morisette
Tacoma Power
No
Tacoma Power does not agree with the result, COM-002-4 standard. Reason One: -R1 and R2 of
the proposed standard both address the issuance and receipt of an “oral, two-party, person-toperson Operating Instruction.” -R1 applies to BA, TC, and TO -R2 applies to DP and GO -The
requirements in R1 are different from R2, in that R1 contains several sub-requirements that R2
does not. One of these additional requirements is confirming the accuracy of the repeat-back
of the Operating Instruction. This is a cornerstone of three-part communication, and its
omission from R2 is a move in the wrong direction. -This sets a “compliance trap” for the
System Operator and could delay critical communications. Alternately, it would require utilities
that perform TO, BA, GO, and DP functions out of the same control room, often from the same
Operator, to over-apply R1 to ensure compliance. Reason Two: -R5 (R5.1) will require
implementation of a method to evaluate the communication protocols developed in R1 that
assesses the adherence to the communication protocols and provide feedback to the issuers
and receivers of Operating Instructions. -R5.1 does not specify a periodicity for this evaluation:
annually, semi-annually, monthly? The data retention period is 90 days, so arguably we would
need to perform these evaluations every 90 days on all operators. -This has the potential to
create a large burden to administer this program.
No
Tacoma Power does not agree to the standard as proposed, for the reasons stated above.
Therefore applications of VRFs and VSLs cannot be determined and supported for the proposed
standard.
No
Group
Western Small Entity Comment Group
Steve Alexanderson
No
FERC Order 693 P 512 mandates Distribution Providers (DP) be made applicable, but also
stipulates that DP entities that do not use, own, or operate BES facilities need not be required
to comply with the communication and coordination standard. This implies there is room for
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exclusion language in the Standard to remove compliance obligations for DP entities that are
unable to provide any BES reliability support the Standard is designed to cover. However, the
current draft has no such language. This standard assumes each applicable entity has the
means to control BES facilities in a timely fashion, and has staff continuously available to
receive Operational Instructions (OIs). Many DP entities do not have continuously staffed
dispatch, nor own supervisory control and data acquisition (SCADA) equipment enabling
remote control from a central location and may own limited BES facilities, if any at all.
Therefore, the applicability section should allow exclusion for such entities. We suggest the
applicability for Distribution Providers be further focused: Distribution Providers having a
continuously staffed (24-7) dispatch desk with the ability to remotely control BES facilities with
an aggregate impact of 75 MW or greater; or as identified in written agreement by the RC, BA,
or TOP as required for specific prearranged operational actions. We also urge consideration be
given to small non-24/7 GOPs. Small generation projects often are only manned for a single 8hour shift each day.
No
In light of the comments submitted for questions one and three, the VRFs and VSLs cannot be
aligned until the Standard is modified to remove applicability on entities that cannot provide
the Reliability support it is designed to cover. Further, the high VRF for Requirement R4 is
obviously inappropriate for small DPs and GOPs.
Yes
The comment group emphasizes its past comments submitted during COM-003-1 development
and believes that smaller entities and non-24/7 staffed-entities, including small GOPs, were not
considered during the drafting of this standard. The standard as drafted will require these
entities to have and implement protocols to deal with OIs that have never occurred in the
memories of numerous 30 year employees. Additional staffing will be required to deal with
one-way burst OIs that might occur after hours, even though none of the possible issuers of
these OIs have indicated any plans to implement such a system, or have suggested that these
entities must be available around the clock for reliability. We suggest that non-24/7 DPs/GOPs
and/or those not designated by the RC or PA/PC be excluded from the Applicability section of
COM-002-4. The comment group also believes that the abbreviated 15-day comment period is
an unreasonably short period for stakeholders to analyze and reach consensus on
modifications to the standard that would address our concerns.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
No
AECI firmly believes COM-002-3 adequately addressed SWBO recommendation 26 and FERC
Order 693, with a reasonable balance of BES benefit, risk, and scope of governance, and should
have been submitted to FERC upon NERC BOT approval per standard development procedure.
No
The scope of Operating Instructions is too broad for the assessed Severity, due to capturing
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within its scope communications that would not significantly affect BES reliability, based solely
upon mild possibilities.
Yes
AECI does not approve of this draft for the following reasons: 1) Expectations that once a
Directive or even Instruction is issued then the issuer is legally obligated to wait upon a
response, although adverse conditions could make such response impossible. 2) Including
Distribution Providers, where redundant communication lines are not and in most all cases
should not be required, by failing to reduce their Applicability scope to only communications
affecting load reduction or shedding to protect the BES. 3) This draft introduces a hidden
compliance-risk to responsible entities who improperly categorize Directives. 4) COM-002-3
addressed the risks to the industry.
Individual
Tracy Goble
Consumer Energy Co
Agree
Jerry Farringer - Consumers Energy Company
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
1. However, ATC does not believe that the following text taken from the SAR was adequately
addressed: “Requirements will ensure that communications include essential elements such
that information is efficiently conveyed and mutually understood for communicating changes
to real-time operating conditions and responding to operating directives.” NERC Glossary of
Terms Definition of a “Reliability Directive”: (Approved by FERC) A communication initiated by
a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by the
recipient is necessary to address an Emergency or Adverse Reliability Impact. The draft COM002-4 Standard in R1.1 requires the “issuer” to identify a “Reliability Directive”, however, does
not specifically call out the requirement that the “receiver” repeat back that it is considered a
“Reliability Directive”. ATC recommends this be added to R1.1. The Standard should close the
loop on this subject as it is considered an Emergency or Adverse Reliability Impact. 2. Draft
COM-002-4 Standard R1.4 requires the receiver to wait for “confirmation” from the issuer that
the repeat back was correct. ATC recommends that the SDT include language which states
confirmation consists of stating “that is correct” or “that is incorrect” followed by a re-issuing
of the instruction.
No
ATC believes there should be more than just a “Severe VSL” for R5. Implementing a method of
evaluating communication protocols could be accomplished at various levels of adequacy. With
that said, additional levels should be considered.
Yes
The following are recommendations to improve the quality of the draft Standard: 1. After
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reviewing the Measures in this draft Standard , ATC has the following comments: • M3, as
written, is awkward and not grammatically correct and should be revised to clearly state the
intent of the Measure. • Also, M3 and M5 may be duplicative when referring to R5.
Furthermore, ATC recommends that in the last sentence in M3 be shortened by deleting the
phase “….. and the remediation of noted exceptions in fulfillment of Requirement 5.” Finally,
this phrase uses the term “remediation” that does not make sense after researching the
definition of the term to meet the intent of R5. 2. After reviewing Section D 1.2 Data Retention
of the draft Standard, ATC is concerned that the guidance provided to the CEA is confusing and
contradictory. In the first paragraph, the Standard states ” where the evidence retention period
(for the Standard) is shorter than the time since the last audit, the CEA may ask an entity to
provide other evidence to show that it was compliant for the full time period since the last
audit.” (What does this mean?) In the second paragraph, the Standard requires the entity to
“keep data or evidence for each applicable Requirement for the current year and one previous
calendar year, with the exception of voice recordings which shall be retained for 90 calendar
days…..” Bottom line is the required retention period in the second paragraph is much shorter
than the 3-year audit period that would apply to Transmission Operators and it is not
reasonable to meet the expectations of both time periods and comply. 3. ATC suggests R5.2 be
re-worded as follows: R5.2 Provides for a periodic review of the communication protocols and
modifies them based on lessons-learned during the adherence of the communication
protocols. Evidence would be documenting this periodic review, whether changes were
warranted, and subsequently implemented.
Individual
Scott Berry
Indiana Municipal Power Agency
No
For requirement R3 (and other requirements) VSL, how many non-conforming communications
or types of non-conforming communications demonstrate a consistent pattern of not using the
documented communications protocols? Would it be two or three or does it just depend on
the volume of communications the entity performs? This VSL is very open to interpretation and
may lead to much inconsistency in the Enforcement area.
Yes
The definition of an Operating Instruction has changed since the last posting of COM-003-1. In
COM-003-1, an Operating Instruction was “a command by a System Operator of a Reliability
Coordinator, or of a Transmission Operator, or of a Balancing Authority, where…” and now it
has changed to “a command by operating personnel responsible for the Real-time generation
control and operation of the interconnected Bulk Electric System to change…”. The current
definition in COM-002-4 of Operating Instruction seems to now include communications
between an entity’s Market Operations Center (not a control center) and its generation facility.
Previously, this did not seem to be the intent of the SDT and IMPA would recommend that the
SDT uses the words “a command by a System Operator of a Reliability Coordinator, or of a
Transmission Operator, or of a Balancing Authority, where…” so as not to include
communications between the entity’s Market Operations and its generation facilities. IMPA has
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concerns with the RSAW. First, the GOP requirements do not say or require the GOP to have
management practices in place. The RSAW should be written to audit an entity to what is in the
requirements and nothing more. Second, the RSAW is written in a way that makes an entity’s
management practices fall under the audit, and it allows the auditor great latitude in
determining if an entity’s management practice designs are effective. IMPA does not believe
that management practices should be reviewed by an auditor during an audit. Even the RAI is
looking at reviewing management practices outside of an audit in an assessment style only
before an audit is performed. If a management practice must be included in the audit, there
must be consistency among the auditors and not so much discretion of the auditor allowed
which may lead to inconsistent audits. Maybe benchmarking or a model of internal controls
can be used by both the entities and auditors (one that also allows for different sizes of entities
- scalability and tailor-able). Third, an entity may believe that its internal controls are effective
but if the auditor deems they are not effective then the auditor can pull samples of
communications which may be ones that were not reviewed by the entity during its review
check. So, does this mean the entity will have to review every communication just in case the
auditor pulls a sample of communications? Under this scenario, if the auditor finds instances of
noncompliance they are to turn them over to Enforcement. This is very problematic and does
not remove the “zero defects” issue.
Individual
asd
asdf
Agree
Individual
Brett Holland
Kansas City Power & Light
Agree
Southwest Power Pool - Robert Rhodes
Group
ISO / RTO Standards Review Committee
Greg Campoli
No
General a. The SRC disagrees with the need for standards to repeat and confirm Operating
Instructions for normal operating system conditions. Any and all instructions will either change
or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System. Unlike its COM-003-1 Draft 5 predecessor, this draft no
longer allows the Responsible Entity to specify the instances where the issuer of an oral two
party, person-to-person Operating Instruction is required to exercise 3-part communication.
Without this provision, the standard now requires 3-part communication whenever a
Responsible Entity issues an Operating Instruction. To track every Operating instruction is
overly burdensome, and may in fact hurt reliability as System Operators will now place focus
on implementing and completing the 3-part communication process rather than concentrating
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on the actions needed to achieve a reliability outcome. The SRC supports relying on the OC’s
Reliability Guidance that supports 3-part communication for all oral two party, person-toperson communications. The SRC proposes that this approach be used for a two year trial
period. During that trial period NERC should collect information on the number of reliability
events caused by communications errors. The ERO could then use the data to justify added
requirements if the data justified the need. b. R3 in conjunction with R1 is a zero tolerance
standard. All parties (Industry as well as the SDT) have stated that a zero tolerance standard for
Operating Instructions during normal conditions is inappropriate. The SRC recommends that R3
be deleted. c. There is no rationale given for the omission of Load-Serving Entity (LSE) as an
Applicable entity. The TOP-001-2 standard, as referenced in the Rationale and Technical
Justification document, holds the LSE responsible for complying with Reliability Directives from
its TOP. If, as the standard implies, tightened communication is required for any and all
Reliability Directives and Operating Instructions, then there is no reason that LSE is not
included in this standard. We would like to understand the rationale/technical basis for
excluding the LSE and determine whether that same rationale should be applied to other parts
or to the entire standard. Absent a rationale/technical reason for omission of LSE, we ask that
this entity also be subject to the requirement. The SRC recommends that LSE be added to the
standard Requirements d. R1.3 is unclear in two aspects: • To “wait” is not a 2-part action, and
is not measurable. The SRC questions how an entity would be assessed regarding whether or
not it waited or not waited? The SRC recommends that the word “wait” be replaced with
“obtain” or “collect” a response. • In the second sentence, the phrase “or if no response is
received” is open-ended. The SRC asks “When should the issuing entity take one of the
bulleted actions listed? The SC proposes that the SDT to add a time frame in this sentence such
as: “or if no response is received in X minutes”. Without the time frame, it will not be possible
for the issuing entity to know when it is supposed to follow up, and for the Compliance
Enforcement Authority to assess if Part 1.3 was complied with. The above comment also
applies to Part 2.2. e. Requirement 1 is a mandate to document the applicable (issuing) entity’s
protocols for communications. And lists the requirements that must be in those protocols. Part
1.4 however, is an obligation on the receivers of the Operating Instruction. Such an obligation
on the receiver is not appropriate for inclusion in the issuer’s communication protocol unless of
course the issuer’s protocol document is distributed to all potential recipients of the Operating
Instructions. However, there is no requirement for the BA, RC or TOP to distribute their
communication protocol document hence the inclusion of Part 1.4 in their communication
protocol document is inappropriate and serves no purpose. f. Part 1.5: The intent of this part is
unclear or the requirement is incomplete, leading to an unnecessary or missing action
mandated by the requirement, or the potential for non-compliance despite best effort. Part 1.5
requires the issuer (e.g. a BA) of an Operating Instruction that uses a one-way burst messaging
system for communicating common messages to multiple parties to obtain confirmation from
at least one recipient (e.g. a GOP). The intent of using the burst messaging system is to achieve
efficiency by eliminating the need for one-on-one communication of the same message and
the need for confirming receipt of the message. The requirement for the issuer to confirm
receipt by at least one receiver of the message thus mitigating the reason for using the burst
messaging system. On the other hand, to be effective, a requirement to confirm at least one
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recipient receives the message requires a complementary obligation on the receiving entities
to acknowledge receipt of the Operating Instruction. However, there is no requirement in the
standard to require the receiving entities (say, a GOP or a DP) to provide that confirmation. The
only requirement for responding to Operating Instruction transmitted through the burst
messaging system is when the communication is not understood by the recipient as stipulated
in Part 1.6 and Part 2.3. If all recipients understand (or think they understand) the Operating
Instruction so transmitted, the issuing party (e.g. a BA) will not receive any confirmation at all.
In this case, the issuing party (e.g. the BA) will not be able to comply with Part 1.5. We suggest
the SDT to delete requirement 1.5. g. Requirement R5 requires the BA, RC and TOP to
implement a method to: evaluate the communications protocols developed in Requirement
R1; assess adherence to the protocol; provide feedback; and make adjustments as necessary.
There is no such requirement for the GOP and DP who are also required to develop their
communication protocol per Requirement R2. The reason for not having such a requirement is
not presented in the posted Rationale and Technical Justification document. The SRC
recommends the SDT add this requirement to close the gap. h. The Industry-approved COM002 states “When a Reliability Coordinator, Transmission Operator, or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator, or Balancing Authority shall identify the action as a Reliability Directive
to the recipient.” However, the current draft reads “Require the issuer of a Reliability Directive
to identify the action as a Reliability Directive to the receiver.” The previous version allowed
the RC, TOP or BA to pre-define what system conditions constitute a Reliability Directive in an
operating procedure instead of during pressing oral communications, in effect, developing a
standing definition, the new draft appears to eliminate that needed flexibility The SRC
recommends the SDT to retain the previously approved text.
No
Requirements R3 and R4 were mapped from Requirements R1 and R2 of in Draft 5 of the COM003-1 standard. In that draft, both of these requirements were assigned a LOW VRF, with
which we concurred. In the proposed COM-002-4, the SDT proposes that these two
requirements (now R3 and R4) be assigned a HIGH VRF “… because failure to use the
communications protocols during an emergency could directly cause or contribute to bulk
electric system instability, separation, or a cascading sequence of failures, or could place the
bulk electric system at an unacceptable risk of instability, separation, or cascading failures.” We
do not agree with the HIGH VRF since miscommunication alone does not and cannot cause
instability. There needs to be another action or inaction combined with an event on the BES to
result in any disturbance that results in instability. Even if we agree to some extent that failure
to use the communication protocol during an emergency could contribute to bulk electric
system instability, these two requirements also cover non-emergency situations. Under the
latter conditions, we are unable to support the argument that failure to use the
communications protocols could cause or contribute to bulk electric system instability. At
most, we can accept a MEDIUM VRF assigned to these two requirements, but not a HIGH. The
SRC recommends the SDT to revise these VRFs accordingly.
Yes
The SDT tries to avoid making this standard a zero tolerance by using explanations in the
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Measures, VSLs and RSAWs. However it is our understanding that the words of the
requirement form the basis for compliance (the other venues are not part of the standard they
are part of the compliance program that is not subject to Industry or regulatory approval). The
SRC recommends all text that is meant to mitigate the impact of the words in the requirement
be placed in that requirement. Please note that CAISO and PJM abstained from these
comments and will submit their own comments independently.
Individual
Matthew Beilfuss
Wisconsin Electric (WEPCO)
Yes
Yes
Yes
R1.4 / R2: It should be clear that it is the issuer’s responsibility to ensure three-way
conversation occurs. Situations where an issuer fails to prompt the receiver to partake in a 3way conversation during issuance of an Operating Instruction should not be a violation on the
part of the receiver. R1.7: The protocol should include a format for time identification,
identifying specific instances for using the protocol becomes more problematic. An instance
could mean a number of things, including: (1) when issuing Operating Instructions to a receiver
in a different time zone; (2) when issuing specific types of Operating Instructions, or when a
time component would materially impact an Operating Instruction. Alternate language for
R1.7, “Specify the time format to use when issuing an oral or written Operating Instruction.”
The R5 requirement to implement a method to evaluate the communications protocols
provides a more flexible method for evaluating “instances.” R1.9: Comments similar to R1.7,
alternate language for R1.9, “Specify the alpha-numeric clarifiers to use when issuing an oral
Operating Instruction.” The R5 requirement to implement a method to evaluate the
communications protocols provides a more flexible method for evaluating “instances.” R2 / R4:
These requirements should also be made applicable to Load Serving Entities, Balancing
Authorities, and Transmission Operators. All are potential “receivers” of Operating Instructions.
The following Standards (mandatory or in process) establish RC and TOP authority for issuing
Operating Instructions. • Mandatory Standards Subject to Enforcement: o IRO-001-1.1 R3. The
Reliability Coordinator shall have clear decision-making authority to act and to direct actions to
be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission
Service Providers, Load-Serving Entities, and Purchasing-Selling Entities within its Reliability
Coordinator Area to preserve the integrity and reliability of the Bulk Electric System. These
actions shall be taken without delay, but no longer than 30 minutes. o TOP-001-1a R3. Each
Transmission Operator, Balancing Authority, and Generator Operator shall comply with
reliability directives issued by the Reliability Coordinator, and each Balancing Authority and
Generator Operator shall comply with reliability directives issued by the Transmission
Operator, unless such actions would violate safety, equipment, regulatory or statutory
requirements. Under these circumstances the Transmission Operator, Balancing Authority or
Generator Operator shall immediately inform the Reliability Coordinator or Transmission
Operator of the inability to perform the directive so that the Reliability Coordinator or
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Transmission Operator can implement alternate remedial actions. • Filed and Pending
Regulatory Approval o IRO-001-3 R2: Each Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider shall comply with its Reliability Coordinator’s
direction unless compliance with the direction cannot be physically implemented or unless
such actions would violate safety, equipment, regulatory, or statutory requirements. o TOP001-2 R1. Each Balancing Authority, Generator Operator, Distribution Provider, and LoadServing Entity shall comply with each Reliability Directive issued and identified as such by its
Transmission Operator(s), unless such action would violate safety, equipment, regulatory, or
statutory requirements. R2 / R4 / R5: The standard as drafted requires the DP and GOP to
document and implement their protocols in the role as a receiver. However, R5 or similar
language establishing an evaluation program is identified only for the Balancing Authority,
Reliability Coordinator, and Transmission Operator. As a result, compliance for the DP and GOP
will be in a zero defect environment with no opportunity to internally set-up a program to
evaluate and assess effectiveness. We highly recommend making R5 applicable to all receivers
of Operating Instructions. Alternate language for R5, “Each Balancing Authority, Reliability
Coordinator, Transmission Operator, Generation Operator, and Distribution Provider shall
implement a method to evaluate the communication protocols developed in Requirements R1
or R2”
Individual
Michelle D'Antuono
Ingleside Cogeneration LP (Occidental Chemical Corporation)
No
Ingleside Cogeneration agrees in general with the Operating Instruction concept proposed by
the project team. It correctly distinguishes between entities who issue and receive Operating
Instructions and those who only receive them. In addition, protocols can be developed which
vary by the criticality of the communication – allowing much more flexibility in the delivery of a
routine Operating Instruction as compared to a Reliability Directive. However, we do not
believe that Requirements R3 and R4, which state that entities “shall implement the
documented communications protocols”, can be consistently enforced. Although we
understand the intent to leverage the Measures, VSLs, and auditor guidance in the RSAW to
determine when a violation takes place, is not clear that they would prevail in a finding of
violation. In addition, the intent which seems to be reasonable now, could change over time to
be more restrictive if an RE, NERC, or FERC should so choose. FERC has consistently ruled that
reliability violation outcomes must be consistent, deterministic, and repeatable. Ingleside
believes that mandatory bright-line criteria can be developed to assure such an outcome – but
COM-002-4 as written relies too heavily on CEA opinion. There is a place for subjectivity in any
risk-based evaluation, but that balance has not been struck in our view.
No
The enforcement of COM-002-4 relies heavily on the “High” VSL for requirements R3 and R4
which call for a violation to be assessed on a responsible entity who “demonstrates a
consistent pattern of not using the documented communications protocols” for routine
Operating Instructions. There is no definition of “pattern” given in the standard or NERC
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glossary. It is possible that some CEAs would consider a pattern to be 10% or more of all
Operating Instructions – others could assess a violation when two or more errors occur. Also,
there is no differentiation between situations where documentation is inadequate as
compared to those where Operating Instructions are inadequately performed. If
“undocumented” equates to a “miss”, Ingleside Cogeneration believes the chances of a
“pattern” being detected go up significantly. In our view, the criteria that Enforcement will use
to determine a violation must be vetted as part of this project. In addition; we would like to see
language added to the VSL allowing to consideration of the outcomes of miss-executed
Operating Instructions. Those that led to a BES threat or even an outage must weigh heavily in
an assessment – those that do not should be less of a factor. This was the primary criteria in
COM-003-1 Draft 6, but has disappeared completely in COM-002-4. Even though there were
concerns that a causal tie cannot be made under every circumstance, we believe that a
reasonable solution can be found through the development of specific Compliance criteria. The
VSLs for R3 and R4 seem to determine what constitutes a violation, which is not the purview of
the VSLs. The language “demonstrates a consistent pattern of not using the documented
communications protocols” is determinative of a violation. Perhaps some modified form of this
wording could be included in the Requirements themselves. The VSLs for R3 and R4 are also
“stacked” on the High and Severe level. Obviously, the communications are important, but
without the emphasis on outcomes, there can’t be High and Severe VSLs. See AEP’s comments.
Yes
1. The SDT should consider having the issuer of an oral, two-party, person-to-person Operating
Instruction identify the communication as such much like a Reliability Directive. Since the issuer
will have to use three part communications in both cases, this will avoid any confusion on the
receiver’s part concerning whether the communication is a Reliability Directive, Operating
Instruction, or other type of communication. 2. In M3 and M4, there needs to be clarity on
what constitutes an “independent review.” The same comment is applicable to “degree of
independence” in the proposed RSAW. 3. Clarification is also needed for R5.1 “feedback to
issuers and receivers.” We understand this to mean internal feedback from the internal review
to the issuers and receivers. However, it could be construed as BA to GOP, etc. 4. In R1.2, the
words “or written” should be deleted. This standard doesn’t seem to pertain to written or
electronic communications. The term “written” could be construed as an electronic dispatch
instruction.
Individual
Kathleen Goodman
ISO New England, Inc.
Agree
IRC SRC
Individual
Denise M. Lietz
Puget Sound Energy
Yes
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No
The severe VSLs for requirements R3 and R4 effectively add a requirement to the standard by
requiring a responsible entity to use its communications protocols when issuing or receiving a
Reliability Directive. This is inconsistent with the measurements for those requirements, which
address only management controls for the implementation of the protocols. It is also
inconsistent with the draft RSAW language for these requirements, which do not address this
issue either. For clarity, this additional requirement should be included in the standard's
requirement and measurement language, not just in the VSL language. It is preferable to
include it as a separate requirement, since the related measure will be much different that
those addressing the implementation of the communciations protocols.
No
Individual
Molly Devine
Idaho Power Co.
Yes
Yes
Yes
I don't believe the terms "Transmission interface Elements" and "Transmission Interface
Facilities" in Requirement 1.8 the terms are defined anywhere. In discussions internally, there
have been differeing opinions on what the scope of these.
Individual
Oliver Burke
Entergy Services, Inc.
Agree
Entergy support comments provided by SERC OC Review Group.
Group
Duke Energy
Michael Lowman
Yes
Duke Energy would like to commend the SDT’s efforts on developing a Communications
Standard that is on the right path. We agree, in general, that this standard is intended to be a
risk/process based standard and not a zero defect standard. Duke Energy’s balloting position is
predicated on the assurances from the ERO and RRO that the standard’s enforcement will be
from a process/risk based approach as opposed to a zero defect approach.
No
Duke Energy would like for the SDT to clarify the meaning of “consistent pattern” in the VSLs
for R3 and R4. We are concerned with how an auditor determines what constitutes a
“consistent pattern” of non-compliance. Once the SDT has clarified the meaning of “consistent
pattern”, Duke Energy recommends adding similar language to the Severe VSLs for
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Requirements 3 and 4 for a Reliability Directive. If the industry is going to be measured on the
effectiveness of their internal controls process, as outlined in the Measures and in the RSAW, a
zero-defect VSL should not be the answer.
Yes
Duke Energy suggests rewording, for clarity, the definition of Operating Instruction as follows:
“Operating Instruction — A command by operating personnel responsible for the Real-time
generation control and operation of the interconnected Bulk Electric System to change or
preserve the state, status, output, or input of an Element or Facility of the Bulk Electric System.
A Reliability Directive is one type of an Operating Instruction. A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System operating
concerns is not a command and is not considered an Operating Instruction.” Duke Energy seeks
clarification on the absence of a provision requiring the GOP and DP from implementing a
method to evaluate the communications protocols developed in R2. Also, FERC has not
approved Reliability Directive as an official definition in the NERC Glossary of Terms. Duke
Energy recommends adding this definition to the new COM-002-4 standard for consistency and
to provide clarification to this standard.
Group
Midwest Reliability Organization NERC Standards Review Forum (MRO NSRF)
Russ Mountjoy
No
The MRO NSRF agrees with the Independent Expert Review Panel and NERC Management on
the recommendation of combining COM-002-3 and COM-003-1 into one Operating Personnel
Communications Reliability Standard. The NSRF disagrees with the decision to waive the
standards development procedures. For such a substantial change, a 15 day review and
comment period does not allow sufficient time for consideration of the proposed changes and
comment coordination Recommendation 26 states, “…ensure that all key parties, including
state and local officials, receive timely and accurate information.” This draft does not address
communicating to entities outside of the identified functional entities. Each of the cited
scenarios for Recommendation 26 (p. 56, 65 & 67) were categorized under “Cause 2 –
Inadequate Situational Awareness” this draft standard does not address System Operator
situational awareness, only how to communicate instructions.
No
The MRO NSRF recommends that the drafting team should clarify what is a “consistent pattern
of not using the documented communication protocols.” The NSRF also believes that R3 and R4
should include lower and moderate VSLs for errors in the use of communication protocols that
do not rise to the level of a “consistent pattern of not using the documented communication
protocols.” The Violation Severity Levels imply you are only non-compliant for operating
instructions if you show a pattern of not following your protocols. The problem is the RSAW
states that system events should be sampled, and if instances of nonconformance with the
protocols are found, the issue should be turned over to the Compliance Enforcement
Authority, who will then make a determination whether there was a pattern. Are two data
points a pattern? Is this considered a trend, too? The NSRF recommends the development of
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clear numerical thresholds for the VSLs. “In circumstances where voice recordings are
reviewed, auditors should consider requesting recordings commensurate with known events in
the entity’s footprint during the audit period, as Operating Instructions may be more likely to
occur during, and related to, such events…”. This goes against the NERC process of random
sampling. Auditors are trained and should be industry experts. They do not need auditor notes
that explicitly guide them on how to audit a requirement. Auditors need to read each
Requirement and understand what the intent is, just like every applicable entity is required to
do. Recommend that if “Note to Auditors” needs to be present within the RSAW that R3 and R4
wording be deleted and replaced with R5’s Note to Auditor wording; “Auditor should assess
whether evidence related to the management practices providing reasonable assurance of
implementation of communication protocols provided by entity for Requirement…”. If the
RSAW SDT will not provide this change then a foot note with a disclaimer needs to be added.
Yes
1. The Purpose seems to be wordy and loosely written. Recommend the Purpose to read, “To
reduce the possibility of miscommunications that could lead to action or inaction harmful to
the reliability of the Bulk Electric System (BES) by establishing Operating Instructions with
predefined communication protocols”. 2. R1.2 and R2.1, remove “An alternate language may
be used for internal operations” as this will not be used between two different operating
personal and the first sentence already allows for other languages to be used, if agreed upon.
3. The proposed definition of Operating Instruction defines a Reliability Directive as a subset or
one type of Operating Instruction. However, the current definition of Reliability Directive refers
to a broader set of “communications” than “commands” referred to in the proposed definition
of Operating Instruction. The drafting team should reconcile the use of the broader term
“communication” with the narrower term “command,” 4. R1.7, R1.8 and R1.9, all speak of
“specifying” time identification, nomenclature and instances of alpha-numeric clarifiers,
respectfully. Recommend that a statement similar to CIP-002-5.1, R3.1 be added that reads “a
discrete list of all Operating Instructions is not required”. This statement has been vetted
within the CIP version 5 Standard, CIP-002 and would allow entities to determine (specify) what
R1.7, R1.8 and R1.9 need to refer too. 5. R3. Add at the end of Requirement 3 (after the words
Requirement 1) “and remediate noted exceptions identified as provided in R5”. (This aligns
with Measurement 3 (M3).) M4 (Measurement 4) calls for an “…independent review of
operating personnel’s adherence to the protocols established in Requirement 2”. M4 in effect
is expanding R4. This independent review should be removed from M4 and we suggests the
following for M4: after the words “Bulk Electric System, spreadsheets, memos or logs[.}” place
a period. 6. R5.2, please change “modifies” to “modify”. 7. The NSRF recommends that the
drafting team update R1 and R2 to allow entities to inform the RC, BA, or TOP of the inability to
comply with an Operating Instruction or Reliability Directive if doing so would violate safety,
equipment, regulatory, or statutory requirements. 8. The NSRF suggests that the
Implementation Plan be updated to reflect necessary conforming changes to other standards.
The NSRF notes that proposed revisions to IRO-001-3 and TOP-001-2 would refer to “Reliability
Directives.” The NSRF believes that other standards that incorporate terms with a meaning
similar to Operating Instruction or Reliability Directive should be updated to include defined
terms. BAL-STD-002-0 refers to “any instruction, directive, order or suggested action.” CIP-002-
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5 refers to “operational directives.” INT-010-1 refers to Interchange schedules “directed” by
the Reliability Coordinator. IRO-004-2 R1 refers to “directives.” VAR-001-2 R6 refers to
“direct[ing] the Generator Operator to maintain or change its voltage schedule or its Reactive
Power schedule.” VAR-001-3 M3 refers to evidence of “issued directives.” VAR-002-1.1.B R2.1
refers to actions “directed by the Transmission Operator,” and M3 refers to responses to
“Transmission Operator’s directives.” The NSRF recommends that these standards be updated
to incorporate the term Operating Instruction or Reliability Directive to avoid industry
confusion about which types of communications these standards are intended to describe.
COM-002-4 Proposed RSAW, comments: The MRO NSRF does not agree with the contents of
the COM-002-4 RSAW. Per the SPM, footnote 19 of the SPM says “While RSAWs are not part of
the Reliability Standard; they are developed through collaboration of the SDT and NERC
Compliance Staff. A non-binding poll, similar to what is done for VRFs and VSLs may be
conducted for the RSAW developed through this process to gauge industry support for the
companion RSAW to be provided for informational purposes to the NERC Board of Trustees.”
(Emphasis added). Please note the following items expand the scope of the applicable
Requirement(s). Under Note to Auditor; The RSAW drafting team starts to add additional
compliance actions and there are no foot notes associated, either. Note that footnote 1 states,
“While the information included in this RSAW provides some of the methodology that NERC
has elected to use to assess compliance with the requirements of the Reliability Standard, this
document should not be treated as a substitute for the Reliability Standard or viewed as
additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the
language contained in the Reliability Standard itself, and not on the language contained in this
RSAW, to determine compliance with the Reliability Standard.” And foot notes 3, 4 and 5 all
state that “These items are not mandatory and other forms and types of evidence may be
submitted at the entity’s discretion”. R1, well written and no additional wording was
interjected that expands the Requirement. R2, well written and no additional wording was
interjected that expands the Requirement. Per the RSAW; R3 and R4, do not relate to the
actionable words of the Requirement. As stated in R3, protocols are to be “implemented” per
R1. But under Compliance assessment Approach for R3 the first sentence states for the auditor
to review management practices to assure that R3 is “effective”. This statement needs to be
deleted as it does not support Requirement 3. For both R3 and R4 these types of statements
should be deleted.
Group
SERC OC Review Group
Stuart Goza
Yes
Yes
Yes
The SDT is respectfully requested to rearrange the sentences in the Operating Instruction
definition to differentiate between what the command is and what it is not. The
recommendation follows: A command by operating personnel responsible for the Real-time
generation control and operation of the interconnected Bulk Electric System to change or
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preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System. A Reliability Directive is one type of an Operating Instruction. A
discussion of general information and of potential options or alternatives to resolve Bulk
Electric System operating concerns is not a command and is not considered an Operating
Instruction. The SDT is requested to clarify the applicability of COM-002-4 for the Distribution
Provider (DP) with language that limits DP applicability to load reduction or load shedding. The
Violation Severity Levels imply you are only non-compliant for operating instructions if you
show a pattern of not following your protocols. The problem is the RSAW says that system
events should be reviewed, and if instances of nonconformance with the protocols are found,
the issue will be turned over to the Compliance Enforcement Authority, who will then make a
determination whether there was a pattern. Are two data points a pattern? The standard
should not focus on sampling events. The standard should let the entity provide the samples
used as part of the periodic reviews of their operators’ communications. The RSAW should be
changed and the standard should be clear that if the entity has a protocol document that lays
out its expectations of its operators, periodically checks for conformance with the protocols,
and implements corrective actions when deficiencies are found, the entity is compliant. In
several places, including the implementation plan, there is mention of retiring COM-002-3. This
standard was approved by the NERC BoT but not submitted to FERC. Therefore, we suggest
that the SDT review the language and modify as necessary to capture the anticipated NERC BoT
future action regarding COM-002-3. The comments expressed herein represent a consensus of
the views of the above named members of the SERC OC Review Group only and should not be
construed as the position of the SERC Reliability Corporation, or its board or its officers.
Group
Florida Municipal Power Agency
Frank Gaffney
No
In regards to Order 693, P 532: “… We also believe an integral component in tightening the
protocols is to establish communication uniformity as much as practical on a continent-wide
basis. This will eliminate possible ambiguities in communications during normal, alert and
emergency conditions …” FMPA believes that only the RC needs to have protocols that
everyone else follows. Everyone within an RC talks with each other; therefore, everyone’s
protocols ought to be similar if not the same within an RC area, e.g., entities within an RC ought
to use similar time stamps, similar nomenclature, etc. There are a couple of ways that this
could be done: i) the RC could be the only one to develop protocols that everyone else follows
within their area; or ii) the RC develops “pro forma” protocols that everyone else uses to
develop their protocols (similar to FERC developing the Pro Forma OATT and each TSP using
that Pro Forma to develop their OATTs, with the associated need to justify deviations).
Yes
Yes
FMPA appreciates the efforts of the SDT. We believe it is the best effort to date in developing
the standard. However, FMPA is voting “Negative” primarily due to regulatory uncertainty
concerning monitoring and enforcement, and we also have concerns regarding the standard
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itself. OTHER ISSUES WITH THE STANDARD The SDT incorporated two approaches to the
standard: 1. Performance Measurement: Zero defect requirements with RAI type enforcement
in R3 and R4 2. Internal Controls Measurement where we measure the internal controls
themselves in R1, R2 and R5 The standard should not include both of these types of
measurements, and it would be better if only one of these two methods were contained in the
standard. R3 and R4 as written are “zero defect” requirements for all Operating Instructions.
The SDT tries to mitigate the “zero defect” problem through the VSLs and the RSAW, which
depend on internal controls. This creates a double jeopardy with R5. There are two ways to
resolve this: a) Measure performance for only Reliability Directives by replacing “Operating
Instruction” within R3 and R4 with “Reliability Directives” (FMPA’s preferred alternative as
further described below). b) Remove R5. If R3 and R4 are retained as is, R5 is not necessary and
should be deleted. With the audit methodology proposed for R3 and R4 of evaluating
management practices / internal controls, which would include the protocols themselves, the
assessment described in R5 would happen naturally to avoid a “pattern” of failure to follow the
protocols. DPs are a special case within the standard. FMPA believes that DPs will not receive
any Operating Instructions with the exception of Reliability Directives to shed load, or
Operating Instructions associated with a cranking path, since they do not own or operate “an
Element of the Bulk Electric System or Facility of the Bulk Electric System. As such, DPs should
only be measured against performance and not internal controls, e.g., R3 and R4, not R5, due
to the very rare occurrence of an Operating Instruction being given to a DP. As such, the
expectation for audit is that DPs will not have the same level of internal controls as other
registered functions since there will be no statistical significance to rely on in sampling. As
such, if R5 is retained, DPs should not be included as an applicable entity to that requirement.
ISSUES WITH THE RSAW The RSAW gives the auditor complete subjective discretion and
decision making as to what constitutes an effective management practice / internal control.
Such unfettered discretion is a recipe for: i) inconsistent treatment, not only between regions,
but between different auditors within a region; and ii) conflict between entities and auditors as
to what is and is not an effective internal control. FMPA supports moving towards RAI; but in
order to do so, expectations must be set to avoid unnecessary conflict and inconsistency. As
such, the SDT ought to develop benchmarks or criteria for what would constitute effective
management practices/internal controls in the next version of the RSAW if R3 and R4 are
retained as written. In addition, FMPA is especially concerned about the auditor having the
experience and wisdom necessary to properly scale their subjective judgments to the entity.
For instance, as discussed above concerning a DP that will receive very, very few Operating
Instructions, internal controls that require statistical sampling of voice recordings makes no
sense. As such, we suggest that the next draft of the RSAW include “benchmark” internal
controls or other criteria for at least three different size entities(large, medium and small) so
that the auditor has guidance as to how to scale their expectations. Another source of
ambiguity that will give rise to unnecessary inconsistency and conflict is the ambiguous phrase
“consistent pattern”. The SDT is also encouraged to set expectations regarding what
“consistent pattern” is intended to mean. The standard, as written, depends on the successful
implementation of RAI; yet, we are not confident in that successful implementation. So far, we
have heard a great short story; but, the story does not have nearly enough depth to make for a
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good novel. And, we have a lot of concern over the details around RAI. If not implemented
correctly, RAI could make our lives much worse than they already are, not better. As such, if we
are going to depend on RAI to audit R3 and R4, we need more meat on the bone of what that
RAI process would look like for this standard. WHEN SHOULD AN ENTITY SELF REPORT? R3 and
R4 are written as zero-defect requirements. However, the expectation is that there would not
be a violation as long as the entity has effective internal controls. Such internal controls may
reveal instances where the communication protocols were not followed. Is an entity expected
to self-report those instances, or only self-report if the entity identifies a pattern of failing to
follow those protocols? CONCLUSION FMPA recommends that either: 1) The SDT made R3 and
R4 only applicable to Reliability Directives and retain R5 for other Operating Instructions
(FMPA’s preferred method since it does not depend on successful implementation of RAI while
allowing RAI to mature, and addresses the “self-report” issue). 2) The SDT put much more meat
on the bone of how RAI would be used for COM-002-4 by setting expectations of both the
auditors and the entities concerning mutual agreement about what constitutes effective
internal controls for various size entities and various registrations.
Individual
Silvia Parada Mitchell
NextEra Energy
Yes
NextEra Energy (NextEra) appreciates the work of the SDT. NextEra has a number of
recommended changes based on its experience as RC agent, large DP, TOP and BA and GOP, as
well as TOP and GOP in multiple regions. Definition of Operating Instruction. NextEra is
concerned that the definition of Operating Instruction is overly board, subject to multiple
interpretations and goes well beyond communications that could impact the reliability of the
Bulk Electric System. To clarify Operating Instruction and have it pertain to communications
that can impact reliability, NextEra recommends that Operating Instruction be amended to
read as follows: “A Reliability Directive; or, a non-emergency command by operating personnel
responsible for the real-time generation control and operation of the interconnected Bulk
Electric System to: (i) switch in or out a Bulk Electric System Element or Facility or (ii) mitigate a
SOL or IROL. Any discussion of general information and of potential options or alternatives to
resolve Bulk Electric System operating concerns is not a command and is not considered an
Operating Instruction. A Reliability Directive is a type of an Operating Instruction.” Applicability
of DPs and GOPs. NextEra is concerned that without qualification on the applicability of DPs
and GOPs the Standard is vague and will have unintended consequences. Thus, NextEra
recommends that GOPs be qualified in the same manner that the PER-005 SDT is qualifying
GOPs. To NextEra, such a qualification and syncing up of PER-005’s section “4.1.5 Generator
Operators” is needed because PER-005 is related to the training associated with
communications, and, thus, is targeting the personnel who need to be trained to effectively
communicate and receive Operating Instructions and Reliability Directives. Hence, the
population of applicable GOPs should be the same in both Standards. With respect to DPs,
NextEra only sees DPs being applicable when they are required to curtail load via a Reliability
Directive or conduct switching of BES facility – both of which rarely occur. To fail to limit the
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applicability to DPs to personnel who receive Reliability Directives to curtail load or Operating
Instructions/Reliability Directives to switch a BES facility will lead to confusion and over
application of the Standard to DPs for no reliability reason. Thus, NextEra recommends that
both GOPs and DPs applicability sections be revised pursuant to these comments. R1. NextEra
is concerned with the lack of coordination between an RC, TOP and BA in one RC region as well
as across the Interconnections. Reliability will not likely be served by having multiple protocols
in one RC region and across RC regions. One approach that NextEra supports is to recommend
in the implementation plan that RCs, TOPs and BAs coordinate their protocols, and that NERC
facilitate the coordination of these protocols. R1.1 NextEra favors retaining R1.1 so that the RC,
TOP or BA must state it is issuing a Reliability Directive. Without this requirement, receiving
parties will not understand the importance of a Reliability Directive during an Emergency or
leading up to a possible Emergency versus an Operating Instruction issued during a nonEmergency state. At the same time that NextEra favors retaining, R1.1, it is concerned that
application of a strict zero tolerance approach will not consider the facts and circumstances of
the situation. For example, during an emergency, an operating person may forget to state
“Reliability Directive” but otherwise indicate that the situation is an Emergency, and he or she
requires action from the receiver. Thus, for purposes of self-reporting, during an audit or spot
check, there should be discretion not to find a violation simply because the word Reliability
Directive was not used. NextEra will address this issue below in the context of the draft RSAW.
R2 and subrequirements. NextEra does not see the value of documented protocols for
receivers only – i.e., DPs and GOPs. DPs and GOPs need to use three-way communication when
provided a Reliability Directive or Operating Instruction; this is performance of a task, a
documented protocol for this task is unnecessary, administrative in nature and problematic.
For example, what if a GOP or DP implemented a different written protocol than a RC, TOP or
BA – the issuer; such a situation will not help reliability, but only add to confusion and possible
mistakes. As NERC Standards are to be drafted to be results-based, this is a perfect situation in
which the DPs and GOPs are more appropriately required to perform, than to have a
documented protocol. Therefore, NextEra, recommends that R2 and its subrequirements read
as follows: “R2. Each Distribution Provider and Generator Operator that receives an Operating
Instruction shall: [Violation Risk Factor: Low][Time Horizon: Long-term Planning] 2.1. Respond
using the English language, unless agreed to otherwise. An alternate language may be used for
internal operations. 2.2. Take one of the following actions for an oral two-party, person-toperson Operating Instruction: • Repeat the Operating Instruction and wait for confirmation
from the issuer that the repetition was correct. • Request that the issuer reissue the Operating
Instruction. 2.3. Request clarification from the issuer if the communication is not understood
when receiving the Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g., an all call
system).” This performance-based approach also nullifies the need for R4, thus, that
requirement should be deleted. R5. NextEra supports R5; however, it is not clear how R5 is or is
not connected to moving away from a zero tolerance environment. To clarify this connection,
NextEra will recommend, below, specific changes to the RSAW. Implementation Plan. Moving
the implementation plan to 18 months would facilitate the industry considering that operators
work on multiple shifts and multiple training will be required as well as provide time to conduct
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the recommendation coordination of protocols among RCs, TOPs and BAs. Also, the 18 month
implementation would provide time for a robust pilot program, as offered by some regions,
along with an assessment and the follow-up to ensure success of the implementation of nonzero defect compliance and enforcement program. Measures and RSAW overall. NextEra
thanks NERC for providing a draft RSAW. The RSAW, however, needs to be significantly rewritten in order to sync up with COM-004-2 and set forth a reasonably understood and
predictable compliance and enforcement approach. For example, the measures and RSAW
both introduce management practices, which are not required by the Standard’s requirements.
The term “management practices” should be deleted from both the Measures and RSAW, and
replaced with more directly applicable language, such as “implemented the communication
protocols.” To facilitate the re-writing of the RSAW, NextEra recommends that the following
language be used in R3. RSAW R3. Evidence Requested. That the communication protocols set
for in R1 and its subrequirements have been implemented and are followed by the applicable
operating personnel, with the understanding that zero tolerance implementation is not
required, given that under certain circumstances an operating personnel may not have
followed the communication protocols, yet sufficiently communicated the need for the
receiver to follow the Operating Instruction, and, thus the reliability of the Bulk Electric System
was served. For example, the operating personnel may not have identified a Reliability
Directive, as required by R1.1, but did communicated that there was an Emergency and that
the receiver needed to follow the instructions. In these instances, the auditor shall work with
the entity to understand the circumstances and determine whether a violation is warranted.
Evidence may include spreadsheets, memos, or logs and any noted exceptions to following the
communication protocols set forth in R1 and its subrequirements. RSAW Compliance
Assessment Approach Specific to COM‐002‐4, R3. Review the evidence provided to gain
reasonable assurance that R1 and its subrequirements have been implemented, with the
understanding that zero tolerance implementation is not required, given that under certain
circumstances an operating personnel may not have followed the communication protocols yet
sufficiently communicated the need for the receiver to follow the Operating Instruction, and,
thus the reliability of the Bulk Electric System was served. Only if above implementation of R1
and its subrequirements are deemed insufficient to provide reasonable assurance, apply other
audit procedures as necessary to gain confidence regarding the implementation of the
communication protocols. See ‘Note to Auditor’ section for additional details. RSAW Auditors
Note R3. The auditor may interview SMEs and pull a statistically randomly valid sample of the
entity’s communications from their available voice recordings (limited to the prior 90 calendar
days) and if instances of noncompliance with the protocols are found (without a reasonable
exception due to the facts and circumstances), the possible non-compliance will be submitted
to Enforcement, which will make the determination whether the entity demonstrates a
consistent pattern of not using their documented communications protocols and, if applicable,
the severity of the violation. For purposes of a statistcally random sample, auditors may not
request more than 15 days of recordings. Also, findings of possible non-compliance during the
review of the statistically random sample, may not lead to additional review of voice
recordings, unless necessary by Enforcement to determine the severity of the violation, and
even in those cases the review of voice recordings shall be limited to sampling of additional
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days (no more than 15 days) to determine a pattern. RSAW existing R4 (if not deleted as
recommended above). Evidence Requested. That the communication protocols set for in R2
and its subrequirements have been implemented and are followed by the applicable operating
personnel receiving an Operating Instruction, with the understanding that zero tolerance
implementation is not required, given that under certain circumstances an operating personnel
may not have followed the communication protocols, yet sufficiently received and
communicated back the Operating Instruction, and, thus, the reliability of the Bulk Electric
System was served. For example, the operating personnel receiving a Reliability Directive may
not repeat that it heard the term Reliability Directive used, but sufficiently communicated that
it would implement the instruction given. In these instances, the auditor shall work with the
entity to understand the circumstances and determine whether a violation is warranted.
Evidence may include spreadsheets, memos, or logs and any noted exceptions to following the
communication protocols set forth in R2 and its subrequirements. RSAW Compliance
Assessment Approach Specific to COM‐002‐4, R4. Review the evidence provided to gain
reasonable assurance that R2 and its subrequirements have been implemented, with the
understanding that zero tolerance implementation is not required, given that under certain
circumstances an operating personnel may not have followed the communication protocols,
yet sufficiently communicated that it would follow the Operating Instruction, and, thus, the
reliability of the Bulk Electric System was served. Only if above implementation of R2 and its
subrequirements are deemed insufficient to provide reasonable assurance, apply other audit
procedures as necessary to gain confidence regarding the implementation of the
communication protocols. See ‘Note to Auditor’ section for additional details. RSAW Auditors
Note R4. The auditor may interview SMEs and pull a statistically randomly valid sample of the
entity’s communications from their available voice recordings (limited to the prior 90 calendar
days) – provided the DP or GOP have voice recordings. If instances of noncompliance with the
protocols are found (without a reasonable exception due to the facts and circumstances), the
possible non-compliance will be submitted to Enforcement, which will make the determination
whether the entity demonstrates a consistent pattern of not using their documented
communications protocols, and, if applicable, the severity of the violation. For purposes of a
statistcally random sample, auditors may not request more than 15 days of recordings,
provided the DP or GOP have voice recordings. Also, findings of possible non-compliance
during the review of the statistically random sample may not lead to additional review of voice
recordings, unless deemed necessary by Enforcement to determine the severity of the
violation, and even in those cases the review of voice recordings shall be limited to sampling of
additional days (no more than 15 days) to determine a pattern. NextEra also recommends that
the following language be used in the RSAW if the newly NextEra drafted R2 and its
subrequirements, above is adopted: RSAW new NextEra R2 set forth above. Evidence
Requested. That R2 and its subrequirements have been executed by the applicable operating
personnel receiving an Operating Instruction, with the understanding that zero tolerance
execution is not required, given that under certain circumstances an operating personnel may
not have strictly executed R2, yet sufficiently received and communicated back the Operating
Instruction, and, thus, the reliability of the Bulk Electric System was served. For example, the
operating personnel receiving a Reliability Directive may not repeat that it heard the term
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Reliability Directive used, but sufficiently communicated that it would execute the instruction
given. In these instances, the auditor shall work with the entity to understand the
circumstances and determine whether a violation is warranted. Evidence may include
spreadsheets, memos, or logs and any noted exceptions to following the communication
protocols set forth in R2 and its subrequirements. RSAW Compliance Assessment Approach
Specific to COM‐002‐4, new NextEra R2. Review the evidence provided to gain reasonable
assurance that R2 and its subrequirements have been executed, with the understanding that
zero tolerance execution is not required, given that under certain circumstances an operating
personnel may not have followed the communication protocols, yet sufficiently communicated
that it would follow the Operating Instruction, and, thus, the reliability of the Bulk Electric
System was served. Only if above execution of R2 and its subrequirements are deemed
insufficient to provide reasonable assurance, apply other audit procedures as necessary to gain
confidence regarding the execution R2. See ‘Note to Auditor’ section for additional details.
RSAW Auditors Note new NextEra R2. The auditor may interview SMEs and pull a statistically
randomly valid sample of the entity’s communications from their available voice recordings
(limited to the prior 90 calendar days) – provided the DP or GOP has voice recordings. If
instances of noncompliance with R2 are found (without a reasonable exception due to the facts
and circumstances), the possible non-compliance will be submitted to Enforcement, which will
make the determination whether the entity demonstrates a consistent pattern of not using
their documented communications protocols and, if applicable, the severity of the violation.
For purposes of a statistcally random sample, auditors may not request more than 15 days of
recordings, provided the DP or GOP has voice recordings. Also, findings of possible noncompliance during the review of the statistically random sample, may not lead to additional
review of voice recordings, unless deemed necessary by Enforcement to determine the severity
of the violation, and even in those cases the review of voice recordings shall be limited to
sampling of additional days (no more than 15 days) to determine a pattern.
Group
DTE Electric
Kathleen Black
Yes
Yes
Yes
R2 Section 2.1 requires a response in English to an oral or written Operating Instruction.
Section 2.3 only requires the receiver to respond if the Operating Instruction is not understood
implying a response may not be required. Suggest adding "When a response is required" to R2
Section 2.1: 2.1 When a response is required, require the receiver of an oral or written
Operating Instruction respond using the English language, unless agreed to otherwise. An
alternative language may be used for internal operations.
Group
Exelon Registerd Entities
Chris Scanlon
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Segment 1 BGE,Segment 3 ComEd, Segment 4 CECD, Segment 5 Exelon Nuclear, Segment 6
CEG; all submit the following comments in support of their negative vote.
No
2003 Blackout Report Recommendation No. 26 reads: “Tighten communications protocols,
especially for communications during alerts and emergencies. Upgrade communication system
hardware where appropriate. (footnote omitted) NERC should work with reliability
coordinators and control area operators to improve the effectiveness of internal and external
communications during alerts, emergencies, or other critical situations, and ensure that all key
parties, including state and local officials, receive timely and accurate information. NERC
should task the regional councils to work together to develop communications protocols by
December 31, 2004, and to assess and report on the adequacy of emergency communications
systems within their regions against the protocols by that date.” • While Exelon believes that
COM-002-4 goes beyond the Recommendation and includes the requirement to implement
communication protocols for operating BES elements in non-emergency and other non-critical
situations, Exelon also recognizes that the NERC Board believes that the words “especially for”
in the recommendation are the reason to include a standard for normal communications. We
also understand that in paragraph 540 of Order No. 693, FERC directed the ERO to expand the
applicability of the communication standard to distribution providers (DP’s) but that directive
tied back to communications protocols “especially for communications during alerts and
emergencies.” However, although Recommendation 26 addresses “key parties” and FERC
directive addresses DP’s in the context of Blackout Recommendation No. 26, we don’t believe
that either was intended to include DP’s and GOP’s for non-emergency /Operating Instructions
communications. There is no evidence that failure by DP’s and GOP’s to follow Operating
Instructions has caused a reliability gap in the BES.
No
• VSL for R4 introduces the concept of “consistent pattern” of behavior. This is undefined and
subjective. Entities operating in multiple regions may be subject to varying interpretations of
this language.
No
The Exelon companies have voted affirmatively for previous versions of the COM standards
including COM-002-3 (pending filing) and COM-003-1 (predecessor to COM-002-4 recently
defeated at ballot). We do however have concerns with the process used to arrive at COM-0024 and some of the content of the standard and have therfore cast a negative ballot for this rev.
• COM-002-4 represents more than a revision in response to comments of the previously
balloted standard. Several other approved standards are proposed to be modified as part of
this Project. Additionally, the change from COM-003-1 to COM-002-4 regarding Operating
Instructions is significant. In the time allotted, Exelon has not been able to conduct a sufficient
review of the impacts to all of its business units. • M4 says that“independent review” of the
entity’s evidence should be done to demonstrate adherence to the protocols. What is an
“independent review”? Is it a second operator, an operations supervisor, a management
person from a separate business area, a contractor? More clarity on this issue is required. • M4
and the RSAW “Notes to Auditor” for R4 and Data Retention make it clear that an entity (DP
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and GOP) will need to be able to produce two years of evidence and 90 days of voice
recordings. As noted above, this is a significant change from COM-003-1 and Exelon has not
had sufficient time to assess the potential impact of the increased compliance burden to the
DP and GOP because of the changes requiring these entities to have evidence of compliance
for all Operating Instructions, not just Operating Instructions that were not followed and led to
a Directive. (COM-003-1 R3) In the technical document, the SDT points to a potential “reliability
gap” if DPs and GOPs are not included. More information is needed on the nature of this
potential gap in order to determine whether this extension is technically supported. • Several
Regions are currently conducting pilots to develop the RAI/Internal Control initiative. Repeated
references to and instructions to the auditors in the RSAW to review internal controls are
premature. • Exelon agrees with the recommendation made by EEI and others that COM-002-3
be filed with FERC. Exelon feels that other COM Projects have been responsive to the Order No.
693 directives. Related Projects already approved by FERC and/or the NERC BOT include: COM001-1.1 (FERC effective date 5/13/2009), COM-001-2, (NERC BOT approved, 11/7/2012), COM002-2 (FERC effective date 6/18/2007), COM-002-3 (NERC BOT approved 11/7/2012). • The
definition of Operating Instruction may be misinterpreted to mean that an OI is a command
applicable to personnel responsible for “Real-time generation control and operation of the
interconnected Bulk Electric System” as opposed to “Real-time generation control and/or
operation of the interconnected Bulk Electric System”. Please consider this clarification.
Individual
Terri Pyle
Oklahoma Gas & Electric Company
No
Recommendation 26 says “Tighten communications protocols, especially for communications
during alerts and emergencies. Upgrade communication system hardware where appropriate.”
It is difficult to see how including or forcing a communications protocol for non-emergency
operations fulfills this recommendation. Furthermore, the 2003 Blackout report suggested a
lack of situational awareness was a key causal component and yet no link between three part
communication and identified lack of situational awareness has been made. We therefore
believe that the significant and unreasonably burdensome compliance obligations associated
with this broad expanse is unjustified.
No
Given our belief that establishing a communications protocol for non-emergency
communications is overly burdensome, we fail to see the need for VRFs any greater than low.
Yes
• The use of terms such as “reasonable assurance” in the measures and “reasonably designed”
in the RSAW leaves us little guidance on how an auditor might interpret those terms. • OG&E
finds significant parallels in the proposed revision to the COM-002-3 standard and those
standards called out for retirement in the Paragraph 81 project. OG&E believes that requiring a
standard for three-part communication for non-emergency communication fits several of the
criteria in Paragraph 81 such as: o Criterion A: Little, if any benefit or protection to the reliable
operation of the BES Because there are no instances of any significance in which the lack of
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three-part communication contributed to a reduction in reliable operation of the BES, requiring
three-part communication for non-emergency conditions, complete with
implementation/documentation/assessment/remediation requirements seems unwarranted,
especially given the significant effort required to demonstrate compliance. In the “NERC
Management Response to the Questions of the NERC Board of Trustees on Reliability Standard
COM-003-1” dated September 6, 2013, an attempt is made to tie the lack of three-part
communication during non-emergency conditions to a lack of situational awareness, thus
implicating it in FERC’s Recommendation 26 of the 2003 Blackout Report. There is little, if any
evidence to suggest that the lack of the use of three-part communication had any impact on
the 2003 blackout, or any other significant reliability failure in North America. In its response,
NERC Management uses the term “could” several times. For example, on page 1, they state, “…
miscommunication by operating personnel could result in switching errors during routine
switching of Bulk Electric System Elements, which could jeopardize the reliable operation of the
Bulk Electric System” (emphasis added). We believe that the amount of additional compliance
and operational burdens that will be imposed by this standard should be due to a situation that
would jeopardize the reliable operation of the BES, rather than anything that could do so. o
Criteria B: B1: Administrative –B2: Data Collection/Data Retention – The activities required in
the proposed standard would involve a significant amount of data collection and data retention
to prove compliance. In its response to the NERC BOT, NERC Management states (on page 7),
“Second, concerns over creating an operational and compliance environment that requires
mining of hundreds, thousands or millions of routine/normal communications to prove
compliance or make a finding of reasonable assurance of compliance was consistently cited in
comments to all drafts of COM-003-1. NERC plans to address this issue in the compliance
section of the standard and in development of the RSAW concurrently with development of
the standard.” Nowhere in the proposed standard can we find any meaningful attempt to
address this issue. That leaves entities to the interpretations of various auditors to find
“reasonable assurance of compliance”, which would increase their compliance risk, and
therefore their compliance effort, beyond what we believe to be reasonable, especially given
the minimal benefit to the reliable operation of the BES. B3. Documentation – As stated our
comments above, the amount of documentation that will be required to prove compliance
with COM-002-4 will be significant. In order to demonstrate compliance with the proposed
standard, entities will be required to create additional documentation, audit period to audit
period, in order to demonstrate compliance. Protocols will have to be developed, maintained,
and distributed, on a regular basis. They will have to be reviewed, and that review
documented. For a single standard, this may not seem like much, but when combined with the
significant efforts already required of us today for standards that we do believe have a positive
impact on reliability, we find the continual additions to our workload unsustainable, especially
given the lack of empirical data to support such an increase. • Finally, every Transmission
Operator that OG&E is aware of uses three-part communication, in some form, when
performing routine switching and as well as some other operations. We train our operators in
three-part communication and we assess their performance. In fact, the use of three-part
communication is a part of their performance assessments throughout the year and their
annual performance appraisals reflect their performance in that regard. In short, OG&E finds
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little value in an additional NERC Reliability Standard that addresses a “best practice” that has
never been implicated in any significant reliability failure; at least as far as has been published
in North America and we believe that our collective effort should be spent focusing on those
issues that have been a problem and that continue to be a challenge for the industry. Threepart communication for non-emergency conditions is not one of those.
Individual
Daniel Duff
Liberty Electric Power, LLC
No
The blackout report, in Recommendation 26, states "NERC should work with reliability
coordinators and control area operators to improve the effectiveness of internal and external
communications during alerts, emergencies, or other critical situations, and ensure that all key
parties, including state and local officials, receive timely and accurate information." Operating
instructions in non-emergency situations are, by definition, not "communications during alerts,
emergencies, or other critical situations". Order 693 similarly states "(4) requires tightened
communications protocols, especially for communications during alerts and emergencies. With
respect to this final issue, the Commission proposed alternatively to direct NERC to develop a
new Reliability Standard that responds to Blackout Report Recommendation No. 26, which
deals with the need for tightened communications protocols." Again, the focus of the order is
on "alerts and emergencies". The error of stating 693 requires non-emergency communications
protocols is repeated in the SAR, which was developed prior to the enforcement date of the
standards. Not surprisingly, there was little attention paid to the error by industry, as most
were scrambling to confirm their programs were in compliance prior to June 8th 2007. As there
is not a specific directive from FERC or the Blackout Report mandating the development of
communications protocols for routine interactions between RE's, the SAR should be remanded.
No
VRF/VSL for R4 penalizes a "consistent pattern of not using the protocols". This would trigger a
violation even if the pattern was discovered by implementing a review of evidence under M4.
The VRF/VSL should be for not implementing the review, instead of for discovery of the issue.
Yes
M4 requires an "independent review of operating personnel’s adherence to the protocols
established in Requirement R2.". The word "independent" should be removed, as small entities
may only have staff in the supervisory chain trained and capable of performing an accurate
review of the implementation of the communications program.
Individual
Jen Fiegel
Oncor Electric Delivery Company LLC
No
COM-002-4 goes beyond the August 2003 Blackout Report Recommendation number 26, FERC
Order 693 for neither identify requirements for normal operations. Oncor concurs with Austin
Energy’s comment that EOP-001-2, R3.1 and COM-002-2, R2 already address the requirements
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of the Blackout Report and FERC Order 693. In addition, the COM Standards were evaluated by
the NERC Operating Committee (OC) who recommended guidelines on normal operations
protocols not mandatory standards.
No
The VSLs proposed for all Requirements are designed as prescriptive zero-tolerance and appear
to step backward from the global objective of transitioning to results, risk based standards
which support the reliability of the BES. Oncor recommends the requirements be defined and
the VRF/VSL be developed based on the risk to the reliability of the BES. For example, in normal
or emergency operations, not following the letter of the law is not indicative of a severe
reliability risk to the BES. Additionally, Oncor concurs with Austin Energy’s comments:
Regarding R3 and R4: These VSLs create a “zero tolerance” situation. If an entity fails to follow
the communication protocol when issuing or receiving a Reliability Directive one time, even if
there is no adverse impact to the BES, it is a violation. While there is the potential of risk if
documented communications protocols are not followed, this should not somehow imply that
incorrect operations occurred as a result. The severe category should be reserved for only
those instances in which documented communications protocols were not followed and the
failure resulted in an emergency operation or reliability issue. As a result, we suggest
“demoting” each existing VSL to a lower level and limiting the Severe VSL to only those
instances that resulted in an adverse impact on the BES (suggestions provided below). Low The responsible entity demonstrates a consistent pattern of not using the documented
communications protocols developed in Requirement R1 for Operating Instructions that are
not Reliability Directives. Moderate – The responsible entity did not use the documented
communications protocols developed in Requirement R1 when issuing or receiving a Reliability
Directive. High – The responsible entity did not use the documented communications protocols
developed in Requirement R1 when issuing or receiving an Operating Instruction and that
failure resulted in an emergency operation or reliability issue. Severe - The responsible entity
did not use the documented communications protocols developed in Requirement R1 when
issuing or receiving a Reliability Directive and that failure resulted in an emergency operation
or reliability issue. Regarding the VSL for R3 and R4: Use of the term “consistent pattern” is
vague and will be difficult to determine and analyze.
Yes
Oncor recommends Requirement 5 be removed and the Measurements be re-evaluated to
remove the internal controls additives. Reliability Standards must be revised to focus on
strategic and critical reliability objectives incorporating requirements for meeting and
sustaining reliability of the BES. The current state of Standards must transition from a
prescriptive zero tolerance approach to results-based requirements which assure the reliability
and security of the critical infrastructure. A reliability results-based approach should not be an
additive to the Reliability Standards; hence, controls requirements should not be incorporated
within the Standards, rather controls should be considered at the Program level. Reliability
Standards should define the results (“what”) Entities are mandated to meet and maintain and
the “how” should be handled by each Entity for there is not a “one size fits all”. Incorporating
internal controls as requirements and prescriptive measurements can lead to unintended
consequences and again, an additive versus a process that helps provide a registered entity
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with reasonable assurance they comply with the Standard(s) or the operating function(s) and
processes that the Standard(s) require.
Individual
David Jendras
Ameren
Agree
We generally support the SERC OC comments. We believe that combining the two standards is
the right approach.
Group
US Bureau of Reclamation
Erika Doot
Yes
The Bureau of Reclamation (Reclamation) agrees with NERC’s decision to combine COM-002
and COM-003 into one standard. However, Reclamation disagrees with the decision to waive
the standards development procedures. For such a substantial change, a 15 day review and
comment period does not allow sufficient time for consideration of the proposed changes and
comment coordination.
No
Reclamation recommends that the drafting team clarify what is a “consistent pattern of not
using the documented communication protocols.” Reclamation also believes that R3 and R4
should include lower and moderate VSLs for errors in the use of communication protocols that
do not rise to the level of a “consistent pattern of not using the documented communication
protocols.” Reclamation recommends the development of clear numerical thresholds for the
VSLs.
1. Reclamation recommends that the drafting team revise the definitions of Operating
Instruction and Reliability Directives to make sure they are clear and consistent. First,
Reclamation suggests that the drafting clarify the term “command” because most day-to-day
communications between Transmission Operators or Balancing Authorities are phrased as
requests rather than commands. The definition of Operating Instruction exempts “discussions
of general information and of potential options or alternatives,” without recognizing that these
discussions generally result in mutually agreed upon decisions of how to operate the Bulk
Electric System (rather than resulting in commands). Reclamation suggests that the drafting
team choose another term or define the term command to reflect this operational reality.
Second, the proposed definition of Operating Instruction defines a Reliability Directive as a
subset or one type of Operating Instruction. However, the current definition of Reliability
Directive refers to a broader set of “communications” than “commands” referred to in the
proposed definition of Operating Instruction. The drafting team should reconcile the use of the
broader term “communication” with the narrower term “command,” and preferably revise the
term command as explained above. Third, under the proposed definition, Operating
Instructions that can be issued by a seemingly broader array of “operating personnel” than
Reliability Directives, which can only be issued by Reliability Coordinators, Balancing
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Authorities, and Transmission Operators. Reclamation suggests that the definition of Operating
Instruction should be updated to refer to instructions “from a Reliability Coordinator,
Transmission Operator, or Balancing Authority” to clarify that Generator Operators and
Distribution Providers do not issue internal Operating Instructions. 2. Reclamation
recommends that the drafting team update R1 and R2 to allow entities to inform the RC, BA, or
TOP of the inability to comply with an Operating Instruction or Reliability Directive if doing so
would violate safety, equipment, regulatory, or statutory requirements. Reclamation
recommends that the drafting team incorporate language similar to IRO-001.1a and TOP-0011a, for example the drafting team could add an R2.4 which states “Each Transmission Operator,
Balancing Authority, and Generator Operator shall comply with Operating Instructions issued
by the Reliability Coordinator, and each Balancing Authority and Generator Operator shall
comply with Operating Instructions issued by the Transmission Operator, unless such actions
would violate safety, equipment, regulatory or statutory requirements. Under these
circumstances the Transmission Operator, Balancing Authority or Generator Operator shall
immediately inform the Reliability Coordinator or Transmission Operator of the inability to
perform the Operating Instruction so that the Reliability Coordinator or Transmission Operator
can implement alternate remedial actions.” 3. Finally, Reclamation suggests that the
Implementation Plan be updated to reflect necessary conforming changes to other standards.
Reclamation notes that proposed revisions to IRO-001-3 and TOP-001-2 would refer to
“Reliability Directives.” Reclamation believes that other standards that incorporate terms with
a meaning similar to Operating Instruction or Reliability Directive should be updated to include
defined terms. BAL-STD-002-0 refers to “any instruction, directive, order or suggested action.”
CIP-002-5 refers to “operational directives.” INT-010-1 refers to Interchange schedules
“directed” by the Reliability Coordinator. IRO-004-2 R1 refers to “directives.” VAR-001-2 R6
refers to “direct[ing] the Generator Operator to maintain or change its voltage schedule or its
Reactive Power schedule.” VAR-001-3 M3 refers to evidence of “issued directives.” VAR-0021.1.B R2.1 refers to actions “directed by the Transmission Operator,” and M3 refers to
responses to “Transmission Operator’s directives.” Reclamation recommends that these
standards be updated to incorporate the term Operating Instruction or Reliability Directive to
avoid industry confusion about which types of communications these standards are intended
to describe.
Individual
Texas Reliability Entity
Texas Reliability Entity
Yes
Texas RE generally supports the approach taken in this draft: combining COM-002 and COM003 into one comprehensive communications standard. However, we feel that the current
draft is seriously defective because the REQUIREMENTS do not clearly and completely set forth
criteria by which compliance can be assessed (R3 and R4).
No
See comments below under Question 3.
Yes
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1. Texas RE generally supports the approach taken in this draft: combining COM-002 and COM003 into one comprehensive communications standard. However, we feel that the current
draft is seriously defective because the REQUIREMENTS do not clearly and completely set forth
criteria by which compliance can be assessed (R3 and R4). 2. The existence of a violation should
be determinable by applying the REQUIREMENTS to the evidence, without reference to the
VSLs. However, in this draft, the VSLs for R3 and R4 appear to be intended to define what
constitutes a violation, rather than the Requirements. Texas RE urges the drafting team to
clearly state what is required for compliance in the REQUIREMENTS only. VSLs are intended to
indicate the severity of a violation, not the existence of a violation. 3. The apparent intent of
this draft is that an entity is to be deemed compliant in a non-emergency situation unless there
is a “consistent pattern of not using the documented communications protocols.” That is an
extremely vague threshold that will be very difficult to enforce. How are we supposed to
consistently determine whether a “consistent pattern” exists? What if an entity fails to follow
its protocols 25% of the time, but there is no “consistent pattern” to the failures? 4. Texas RE
opposes the zero-defect application of this standard in connection with Reliability Directives.
The circumstances of a violation, including system impact, are taken into account in the
enforcement process when determining a penalty. The standard requirements should focus on
an entity’s conduct and performance, which are under its control, not on system occurrences,
which may be out of the entity’s control. Furthermore, having different requirements for
different situations will be disruptive in the control room and can adversely affect reliability. 5.
Consider whether this standard should apply to Load Serving Entities (LSE) as recipients of
Operating Instructions. Note that TOP-001-01a Requirement R4 contemplates that LSEs will
receive “reliability directives” from TOPs. TOP-001-2 (pending regulatory approval) also
includes LSEs as recipients of “Reliability Directives.” 6. RSAW: On page 9 and page 12, the draft
RSAW states “Sampling is not a part of the audit process unless the auditor determines that the
internal control is not properly designed or is ineffective. If the auditor cannot rely on the
entity’s controls to gain reasonable assurance of compliance, then the auditor can pull a
sample of the entity’s communications from their available voice recordings (limited to the
prior 90 calendar days) . . ..” (6A) This is written in a manner that leads a reader (e.g. Auditor or
Registered Entity) to believe the CEA cannot review actual performance (e.g. voice recordings)
unless the CEA first finds that the entity’s controls are deficient or defective. In order to assess
the internal controls by listening to a voice recording the Regional Entity will have to put the
Registered Entity in a defensive posture. Is that the expectation of the RSAW drafters? We
hope not, as Texas RE would expect to be able to review voice recordings as part of any
assessment engagement, even if the controls appear to be in order. [The NERC Sampling
Methodology specifically lists voice recordings in the discussion of statistical sampling:
“Statistical sampling helps ensure a high confidence level of compliance for the larger
population of documents when a smaller population is statistically sampled. The confidence
level for the Sampling Methodology is set at 95%. Statistical sampling should be employed
when auditing all processes, procedures and any documentation-related evidence (documents,
logs, voice recordings, etc.) when a sample is required because the entire population cannot be
audited. The use of RAT-STATS in tandem with the Sampling Methodology lends itself nicely to
support this approach.”] (6B) The 90-day retention period is too short. The CEA could easily
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need to review recordings for a longer period, particularly if it becomes concerned about the
entity’s performance or needs to determine whether a “consistent pattern” exists. Advancing
technology has mitigated many earlier limitations with respect to retention of data, including
voice recordings. (6C) Recordings associated with Reliability Directives should be retained until
the next audit, or else the CEA will need to conduct spot checks after each “Emergency or
Adverse Reliability Impact” occurs. 7. RSAW: On page 10 and page 12, the draft RSAW states: “.
. . if instances of noncompliance with the protocols are found, they will be turned over to
Enforcement, which will make the determination whether the entity demonstrates a consistent
pattern of not using their documented communications protocols and, if applicable, the
severity of the violation.” (7A) This provision reflects the inappropriate failure to clearly state
what constitutes compliance in the REQUIREMENTS. If a “consistent pattern” of errors is
required to constitute a violation, that needs to be stated in the REQUIREMENT, not in the VSL,
and it should be addressed by Compliance, not by Enforcement, in the first instance. (7B) This
language should not even be in the RSAW – it appears to forbid the auditor from making a
compliance determination and it turns the auditor into a mere collector of evidence for
Enforcement. We are not aware of any justification or precedent for this allocation of
responsibility.
Group
EPSA
Jack Cashin
Yes
Companies have strongly responded to the 2003 Blackout Report with strengthened
communications protocols. Since 2003 companies have responded by reinforcing their
reliability regimes with a host of management, training, communications, and technology tools.
Therefore, much of what addresses the substance of the standard has taken place in the
intervening 10 years since the event. EPSA believes that NERC management and staff have not
clearly described the reliability gap that takes place between what the Board has already
approved, and the Order No. 693 directive. Reliability would be better served if questions
around the perceptions of a reliability gap were responded to in detail. The seven year old
directive is both dated and vague in light of the steps taken by registered entities since the
Blackout.
No
Comments: It is not clear from the draft standard what language would prevail in a finding of
violation – the Requirement, Measure, VSL, or RSAW. Without better definition in the Standard
over which language prevails makes consensus agreement with the measures difficult. While
some requirements would seem eligible for Find, Fix and Track (FFT) treatment due to a high
measurement designation would not qualify for FFT . In addition, while the intent seems
reasonable at this time, this could change over time should an RE, NERC or FERC choose to
make it more restrictive.
Yes
EPSA supports the development and approval of a single, combined communication protocols
Reliability Standard that covers emergency, alert and normal operating conditions for the BES,
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while recognizing that performance expectations for applicable registered entities and NERC’s
approach to compliance and enforcement should differentiate between emergency and
nonemergency conditions. The proposed draft standard COM-002-4 strikes an appropriate
balance between these considerations, and responds to the NERC Board’s and Standards
Oversight and Technology Committee’s Resolutions. Competitive suppliers however are
concerned that the severely shortened, 15-day comment and ballot period directed by the
Standards Committee for COM-002-4 will foreclose resolution of major technical objections to
the proposed standard. The proposed draft relies heavily on the as-yet untested application of
the NERC Reliability Assurance Initiative (RAI). Small changes to the Compliance Elements of
the proposed standard – the Measures, Violation Risk Factors, Violation Severity Levels and
Reliability Standard Audit Worksheets – would undermine the balance of what EPSA supports.
Consequently, delays in the development and implementation of RAI will certainly jeopardize
successful implementation of COM-002-4. Control Room operators will find it difficult to
capture every oral Operating Instruction that must be transacted using the proper protocol.
COM‐002‐4 offers a solution where the Compliance Enforcement Authorities (CEAs) look for a
situation where a “pattern” of lapses occurs in the transaction of routine Operating
Instructions. However, there is no definition of “pattern” given in the standard or NERC
glossary. It is possible that some CEAs would consider a pattern to be 10 percent or more of all
Operating Instructions – others could assess a violation when two or more errors occur. Also,
there is no differentiation between situations where documentation is inadequate as
compared to those where Operating Instructions are inadequately performed. If
“undocumented” equates to a “miss,” your chances of a “pattern” being detected go up
significantly.
Individual
Don Schmit
Nebraska Public Power District
No
NPPD agrees with combining COM-002-3 and COM-003-1 into one Standard. We do not agree
that COM-002-4 addresses the August 2003 Blackout Report Recommendation number 26. The
recommendation addressed effectiveness of alerts, emergencies, or other critical situations
and not normal operating communications.
No
Suggest the following changes: For R1; Severe- No documented communication protocols,
High- documented protocols missing from 5 to 8 sub-requirements in R1. Medium-missing 3 or
4 sub-requirements, Low-missing one or two sub-requirements. R2; Severe- no communication
protocols, High- missing 2 of 3 sub-requirements of R2, Moderate: missing 1 of 3 subrequirements of R2. R3 and R4; See changes in Question 3 below. R5: as is, but re-classify to
Moderate or High.
Yes
Revise the Purpose Statement to read: “Minimum communication protocols for the issuance of
Operating Instructions with the intended affect to reduce the possibility of miscommunication
that could lead to action or inaction harmful to the reliability of the BES”. The former purpose
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statement says to “tighten communications” which makes it sound as though communications
need to be prescriptive. Within the definition of “Operating Instruction” provided it states “...A
discussion of general information and of potential options or alternatives to resolve BES
operating concerns…”. NPPD believes that it is imperative to BES reliability for operators to be
able to discuss possible options or actions to help system reliability. A Reliability Directive or
Operating Instruction may result from that discussion or may change the Reliability Directive or
Operating Instruction based upon the discussion. The purpose should not be to “tighten”
communicatons, but to broaden and provide for “effective” communications. The purpose of
the Standard appears to be to provide “minimum communication” protocols for the industry.
R3. Add at the end (after the words Requirement 1) “and remediate noted exceptions
identified in R5”. This aligns with the Measurement 3 (M3). The VSL for R3 needs to change to
correlate to R3: for the High VSL after “Requirement R1” add “or remediating noted exceptions
identified in R5” for Operating Instructions that are not Reliability Directives. The Severe VSL
should read read the same way as the High VSL, except for the issuing or receiving of a
Reliability Directive. R4. Add at the end (after the words Requirement 2) “and remediate noted
exceptions identified in R5”. This aligns with the Measurement 4 (M4); however M4 does need
to change to reference back to Requirement R5 in a similar way that M3 does. The VSL for R4
needs to change to correlate to R4: for the High VSL after “Requirement R2” add “or
remediating noted exceptions identified in R5” for Operating Instructions that are not
Reliability Directives. The Severe VSL should read read the same way as the High VSL, except
for the receiving of a Reliability Directive. R5. NPPD suggests that that sub-requirement 5.1 and
5.2 be removed. R5 adequatly covers the requirement to evaluate communications protocols.
Sub-requirements 5.1 and 5.2 are ambiguous and lead to auditors to interject their own
“standards” for adherence and effectiveness. NPPD appreciates the considerations and
changes made by the drafting team and with the additional changes identified above we will
change our vote in support of this proposed Standard.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
Yes
These comments are submitted on behalf of the following PPL NERC Registered Affiliates:
Louisville Gas and Electric Company and Kentucky Utilities Company; PPL EnergyPlus, LLC; and
PPL Generation, LLC, on behalf of its NERC registered entities. The PPL NERC Registered
Affiliates are registered in six regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more
of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
PPL NERC Registered Affiliates recognize the need for industry standards applicable to certain
communications. However, the current draft version of COM-002-4 requires change. We have
the following questions that we would like the SDT to consider and respond to as part of the
next draft: 1) There is no lesser VSL for R3 and R4 other than for a “consistent pattern of not
using the communication protocols” developed in accordance with R1 or R2 for Operating
Instructions that are not Reliability Directives. Does this mean that the SDT intends that there
would be no violation unless there is a “consistent pattern” of not using such documented
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protocols? 2) What would constitute a “consistent pattern” of not following the
communication protocols? 3) If, for example, a BA, RC or TOP develops and implements a
communications protocol which addresses the requirements and performs periodic sampling
of communications among the issuers and recipients of the Operating Instructions to
determine adherence to the protocols (e.g., 95% confidence), would identification of any issues
with appropriate corrective action by the affected parties meet the compliance requirement?
Along with a significant majority of the industry, we supported COM-002-3 (Version 3)
developed under NERC project 2006-06 and approved by the NERC Board of Trustees. We
support NERC filing COM-002-3 with the Applicable Governmental Authorities for approval and
ending Project 2007-02. In the event that NERC moves the current draft of COM-002-4 forward
the draft should be revised as follows. This current draft does not include the “Reliability
Directive” definition that industry and the NERC BOT approved in COM-002-3. Likewise, the
implementation plan that is posted with this first draft of COM-002-4 indicates that there are
“Prerequisite Approvals” needed “of the definition of ‘Reliability Directive’”. The current
definition of Reliability Directive is now unclear as the term had been defined in the Board
approved COM-002-3 but is not included in this draft. Therefore, we suggest adding the
definition of Reliability Directive into Definitions of Terms Used in Standard as follows:
Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission
Operator, or Balancing Authority where action by the recipient is necessary to address an
Emergency or Adverse Reliability Impact. Similarly, we had previously proposed in comments
to COM-003-1 drafts a clear definition of Operating Instruction and suggests the following:
Operating Instruction: A Real-time Operations command, other than a Reliability Directive, by a
System Operator of a Reliability Coordinator, or of a Transmission Operator, or of a Balancing
Authority, where the recipient of the Real-time Operations command is expected to act to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System
or Facility of the Bulk Electric System. A discussion of general information, potential options
and/or alternatives to resolve Bulk Electric System operating concerns is not a command and is
not an Operating Instruction. An Operating Instruction is exclusive and distinct from a
Reliability Directive. There is no overlap between an Operating Instruction and Reliability
Directive. Only in concert with these two definitions, we propose only the following
Requirements as part of COM-002-4: [R1 through R3 are for Reliability Directives and are
identical to those in approved COM-002-3 with clarification for burst messages in R2.1 through
R2.2] R1.When a Reliability Coordinator, Transmission Operator, or Balancing Authority
requires actions to be executed as a Reliability Directive, the Reliability Coordinator,
Transmission Operator, or Balancing Authority shall identify the action as a Reliability Directive
to the recipient. [Violation Risk Factor: High][Time Horizon: Real-Time] R2. Each Balancing
Authority, Transmission Operator, Generator Operator, and Distribution Provider that is the
recipient of a Reliability Directive shall repeat, restate, rephrase, or recapitulate the Reliability
Directive. [Violation Risk Factor: High][Time Horizon: Real-Time] R2.1 The issuer of an oral
Reliability Directive using a one-way burst messaging system to communicate a common
message to multiple parties in a short time period (e.g. an All Call system) is required to
verbally or electronically confirm receipt from at least one receiving party. R2.2 The receiver of
an oral Reliability Directive receiving a one-way burst messaging system to communicate a
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common message to multiple parties in a short time period (e.g. an All Call system) shall
request clarification from the issuer if the communication is not understood. R3.Each Reliability
Coordinator, Transmission Operator, and Balancing Authority that issues a Reliability Directive
shall either: [Violation Risk Factor: High][Time Horizon: Real-Time] Confirm that the response
from the recipient of the Reliability Directive (in accordance with Requirement R2) was
accurate, or Reissue the Reliability Directive to resolve a misunderstanding. [R4 through R7 are
for those instances where an entity determines Operating Instructions are necessary in their
protocol and are based upon the comments provided by PPL NERC Registered Affiliates in
COM-003-1 draft 5] R4. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall develop and implement documented communication protocols that outline the
communications expectations of its System Operators. The documented communication
protocols will address, where applicable, the following:[Violation Risk Factor: Low] [Time
Horizon: Long-term Planning ] 4.1. Use of the English language when issuing or responding to
an oral or written Operating Instruction, unless another language is mandated by law or
regulation. 4.2. Instances that require time identification when issuing an oral or written
Operating Instruction, and the format for that time identification. 4.3. Nomenclature for
Transmission interface Elements and Transmission interface Facilities when issuing an oral or
written Operating Instruction. 4.4. Instances where alpha-numeric clarifiers are necessary
when issuing an oral Operating Instruction, and the format for those clarifiers. 4.5. Instances
where the issuer of an oral two party, person-to-person Operating Instruction is required to:
Confirm that the response from the recipient of the Operating Instruction was accurate, or
Reissue the Operating Instruction to resolve a misunderstanding. 4.6. Require the recipient of
an oral two party, person-to-person Operating Instruction to repeat, restate, rephrase, or
recapitulate the Operating Instruction, if requested by the issuer. 4.7. Instances where the
issuer of an oral Operating Instruction using a one-way burst messaging system to
communicate a common message to multiple parties in a short time period (e.g. an All Call
system) is required to verbally or electronically confirm receipt from at least one receiving
party. 4.8. Require the receiver of an oral Operating Instruction using a one-way burst
messaging system to communicate a common message to multiple parties in a short time
period (e.g. an All Call system) to request clarification from the issuer if the communication is
not understood. 4.9. Coordination with affected Reliability Coordinators’, Balancing
Authorities’, Transmission Operators’, Distribution Providers’, and Generator Operators’
communication protocols. R5. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop method(s) to assess System Operators’ communication
practices and implement corrective actions necessary to meet the expectations in its
documented communication protocols developed for Requirement R4. [Violation Risk Factor:
Medium] [Time Horizon: Operations Planning, Operations Assessment ] R6. Each Distribution
Provider and Generator Operator shall develop and implement documented communication
protocols that outline the communications expectations of its operators. The documented
communication protocols will address, where applicable, the following: [Violation Risk Factor:
Low] [Time Horizon: Long-term Planning ] 6.1. Use of the English language when responding to
an oral or written Operating Instruction, unless another language is mandated by law or
regulation. 6.2. Require the recipient of an oral two party, person-to-person Operating
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Instruction to repeat, restate, rephrase, or recapitulate the Operating Instruction, if requested
by the issuer. 6.3. Require the receiver of an oral Operating Instruction using a one-way burst
messaging system to communicate a common message to multiple parties in a short time
period (e.g. an All Call system) to request clarification from the issuer if the communication is
not understood. R7. Each Distribution Provider and Generator Operator shall develop
method(s) to assess operators’ communication practices and implement corrective actions
necessary to meet the expectations in its documented communication protocols developed for
Requirement R6. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning
/Operations Assessment ] In summary, we do not agree with imposing three-part
communications on the industry for all normal / routine operating instructions.
Group
Hydro One Networks inc.
Sasa Maljukan
Yes
Hydro One fully supports combining two standards into one. From the early drafts we believed
that in order to make it easier for entities to comply single communication standard is the right
way to go. However, on one occasion, drafting team rejected requests for combining two
standards on the ground that COM-002 SAR doesn’t give enough room for this to be done and
that brand new standard must be developed. How is the SDT planning to address possible
challenges from the industry? Would margining two standards into COM-003 which has
broader scope relieve this notion?
Yes
Yes
Hydro One agrees with the comments submitted by the NPCC RSC and would like to offer
following additional comments: Hydro One believes that the issue of three part communication
is major stumbling block in passing this standard. Hydro One understands the reasons behind it
and generally is not opposed to tightened communication for both Operating and Reliability
directives. However, our issue and consequently the negative vote on this draft is primarily due
to lack of coordination between the entities. Additionally, we don’t agree with the general
direction this standard is taking when it comes to compliance with this standard. We feel that
violation of three part communication should constitute non-compliance with the standard
ONLY if it played a part in the event. Otherwise it should be treated as non-violation and be
handled through identify, asses and correct approach. We see these two issues as important
enough to cast a negative vote. If corrected, we’d be open to supporting this standard in the
future. In addition to above we’d like to offer following comments: 1. General Comment: We
feel that the current draft is lacking coordination of communication protocols. We recommend
that the SDT reassesses the need and assigns clear accountabilities to RC or others as
appropriate. We believe that this component is essential in ensuring clear and reliable
communication between entities. 2. In R1.2 the alternate language can be used for internal
operation and if agree otherwise. For clarity purposes we’d like to see the standard address
following questions: - Who can agree otherwise? - What is the meaning of internal operation?
Is this operation internal to one entity? What if this is a vertically integrated utility? We believe
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that these two instances are vague and must be further defined to avoid future interpretations.
3. R2.2 – see the comment above Section 1.2 Data Retention states “…the Compliance
Enforcement Authority may ask an entity to provide other evidence to show that it was
compliant for the full time period since the last audit.” This statement is vague and
unenforceable. Hydro One recommends the SDT removes this sentence and provide clear,
measurable direction regarding the retention period. 4. We understand that due to the rush for
this standard to be developed SDT and NERC staff didn’t have time to develop the RSAW and
post it together with the standard (RSAW was posted sometimes at a later date). We hope that
this is exception rather than the rule and that in the future RSAWs are going to be developed in
time to be posted together with the standard.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
Yes
While we think this draft standard is superior to the previous drafts, we have some issues that
should be addressed first. Suggest changing language in the purpose section from “to tighten
communications” to “to strengthen communications” The “Real-time generation control and
operation” language in the definition for Operating Instruction is confusing. As written the
definition seems to limit Operating Instructions being issued only by personnel that control and
operate generation. Suggest changing the language to “A command by operating personnel
responsible for the Real-time generation control or operation of the interconnected Bulk
Electric System…” In R1.8, what is the definition for “Transmission interface”? This seems to be
alluding to interconnection facilities, but is not definitive. If the intent was for Transmission
interconnections, suggest the language be “Specify the nomenclature for Transmission
interconnecting Elements and Transmission interconnecting Facilities between two parties
when issuing an oral or written Operating Instruction.”
Individual
Gregory Campoli
New York Independent System Operator
No
It remains unclear that additional work is needed to address recommendations from the
August 2003 Black out Report or to address concerns raised in FERC Order 693. Much work has
been completed to date that should address issues raised in those comments. We agree with
the SRC in relying on the OC’s Reliability Guidance that supports 3-part communication for all
oral two party, person-to-person communications. The SRC proposes that this approach be
used for a two year trial period. During that trial period NERC should collect information on the
number of reliability events caused by communications errors. The ERO could then use the
data to justify added requirements if the data justified the need. To date it does not appear
that data exists to support that need for and additional communication standards.
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No
The NERC Compliance Monitoring and Enforcement Program is based on FERC approved
requirements and registered entities are obligated to demonstrate compliance with Reliability
Standard requirements. The proposed VSL introduce an additional layer of compliance without
being clearly defined in the proposed requirement. The proposed requirements are structured
to include: 1) document, 2) implement and 3) evaluate communication protocols. The VSL
should be developed from these three components of the standard and not introduce a ‘zero
defect’ enforcement approach as is proposed in VSL R3 and others. NERC’s recent direction
was to move away from ‘zero defect’ standards and approach compliance from an ‘ identify,
assess and correct’ approach for controls type standards that have high frequency activity that
do not immediately pose a reliability risk. The proposed requirements follow that approach.
The proposed VRF’s incorrectly introduce a ‘zero defect’ approach through a ‘back door’. An
entity may ‘implement’ a protocol, but one occurrence of not following that protocol does not
warrant an entity to be non compliant, as proposed in the standard. If the drafting team is
looking for a ‘zero defect’ standard, then the words need to be in the requirement. However
we continue to believe that this is unnecessary, since a ‘zero defect’ requirement for poor
communication already exist in current IRO/TOP Standards for not following directives.
Yes
We have specific questions to individual requirements below: R1.1 Require the issuer of a
Reliability Directive to identify the action as a Reliability Directive to the receiver. The NYISO
request confirmation from the SDT that identification of Reliability Directives can be made in
policies or procedures agreed to by all parties. This will allow an entity to ensure consistent
communications for all conditions without having to add additional information into the
dialogue for emergency conditions that could complicate the interaction. 1.5. Require the
issuer of an oral Operating Instruction to verbally or electronically confirm receipt by at least
one receiver when issuing the Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time period
(e.g., an all call system). This requirement appears to require a confirmation that the all call
was completed. The NYISO is requesting confirmation from the SDT that an electronic
confirmation that the one-way communication was completed to the intended parties. For the
following: 1.7. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification. 1.8. Specify the
nomenclature for Transmission interface Elements and Transmission interface Facilities when
issuing an oral or written Operating Instruction. 1.9. Specify the instances where alpha-numeric
clarifiers are required when issuing an oral Operating Instruction and the format for those
clarifiers. The NYISO is requesting confirmation from the SDT that in some cases an entity may
have no instances where time identification, nomenclature or alpha-numeric’s will be required
and that the SDT did not intend this to be a case of non-compliance. The NYISO would also like
to ask the drafting team what jurisdiction or authority the initiator of the communication has
over the receiver of the communication. Some requirements require the entities
communication protocol to have an obligation on the receiver to take action with no apparent
authority to enforce that requirement. The NYISO would also like the SDT to consider the
relationship between R1, ‘have a protocol’ and R3 ‘implement a protocol’. We believe that to
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have a protocol is simply an administrative requirement that could be incorporated into a
single requirement. One requirement could exist to ‘implement a protocol that shall at a
minimum…’. To have a protocol has no impact on reliability. We believe this would be a
recommendation based on the paragraph 81 work.
Individual
Lee Layton
Blue Ridge Electric
Yes
The draft expands the scope of COM-002 to include DP's, however, I don't see any rational
offered for including DP's who have no impact to the BES.
Individual
Brian Evans-Mongeon
Utility Services, Inc
No
Not following a communications protocol when the Operating Instruction is a Reliability
Directive is a zero tolerance instance. So even if directive is followed and any BES situation is
mitigated, it is still a Severe Violation. This is extreme, and the VSLs for R4 should be reduced. If
a Reliability Directive is not followed there are violations of other standards, which are severe,
so a lowering of this VSL will not affect the reliability of the BES. VSLs for all Operating
Instructions should be graduated within the VSL table as opposed to being passed onto
Enforcement to make a determination of a “Consistent Pattern.” This will provide clearer
guidance to industry on Violation Severities. For example, they could range from Low to High,
with failures in less than 1/3 as Low VSL, less than 2/3 as Medium, and failure in more than 2/3
as High. R4: More clarity needs to be provided on how a “consistent pattern” will be
established. Most of the applicable entities do not record phone conversations. The RSAW
states that any instances of non-compliance will be turned over to Enforcement to determine a
“consistent pattern.” This is zero-defect language as each instance will be considered a PV.
No
The applicability of the standard should be written to exclude DPs that do not own or operate
BES equipment. As per the definition of Operating Instruction “A command … to change or
preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System...” Entities that do not have real-time control of Elements or
Facilities of the BES should be removed from the applicability of the standard. It is excessive to
mandate that DPs in this situation, that never receive Operating Instructions, have a
Communications Protocol, and implement that protocol. Suggest adding the following to
Section 4: 4.1.2 Distribution Provider with control of Elements or Facilities of the Bulk Electric
System. M3 and M4 are difficult to understand and suggest edits to clarify: Each Distribution
Provider and Generator Operator shall provide evidence that it implemented the documented
communication protocols such that the entity has reasonable assurance that protocols
established in Requirement R2 are being followed by personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System. Evidence should
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show periodic, independent review of the operating personnel’s adherence to protocols
established in R2. Evidence may include, but is not limited to • Descriptions of the
management practices in place, • spreadsheets, • memos, or • logs, R5.1 is redundant with R3
as both require assessment of adherence to protocols established in R1. If part of
“Implementation” (covered in R3) includes an assessment of the communication protocols, R5
should be limited to only correcting discovered and correcting deficiencies with the protocols
and the implementation of those protocols. If not removed as redundant, Requirement 5.1
should specify that the assessment will be limited to the operating personnel of the individual
entity for both issuing and receiving Operating Instructions. As it is written now it would be the
responsibility of the BA, RC and TOP to assess compliance with communication protocols to all
entities involved in every communication, including the receiving GOPs and DPs, and other BAs,
RCs and TOPs based on the Operating Instruction as “issuer and receiver” are not defined.
Suggested Rewording of R5.1: “Assesses adherence to the communications protocols to
provide feedback to entity personnel” R2 requires DPs and GOPs to call the issuer in an all call
situation if the Operating Instruction is not understood. If the Operating Instruction is
misunderstood, and the entity believes it has taken the appropriate action, but was incorrect
creates a potential violation scenario. This needs to be clearly addressed as a Potential
Violation in this instance could be severe (if the OI is a Reliability Directive) and could be a
Potential Violation of several other standards as well (not following a Reliability Directive).
RSAW Comments: The “Note to Auditor” related to R3 and R4 is outside of the scope of the
standard. Placing the examination of Internal Control within the RSAW effectively requires
entities to have Internal Controls, which expands the scope of the standard significantly.
Group
Dominion
Connie Lowe
Yes
Yes
Yes
It does not appear that there are any requirements to coordinate communication protocols
established in R1 with those established in R2. For instance, R1 contains 9 sub-requirements
whereas R2 only contains 3 sub-requirements. Does the SDT maintain that coordination is not
necessary expecting that the recipient will be instructed by the issuer to either repeat or
confirm any information that is included in parts 1.5, 1.6, 1.7, 1.8, or 1.9 that is vital to
understanding the Reliability Directive or Operating Instruction? There is no value in having a
documented communications protocol if the entity does not intend to implement it. We
therefore suggest that requirements 3 & 4 either be added into the body of R1 and R2
respectively, or as sub-requirements of R1 and R2 respectively. The VSLs and RSAW should be
modified accordingly. The Violation Severity Levels imply an entity is non-compliant for
operating instructions only if a pattern of not following its protocols is demonstrated. However,
the RSAW says that system events should be reviewed, and if instances of nonconformance
with the protocols are found, the issue will be turned over to the Compliance Enforcement
Authority, who will then make a determination whether there was a pattern. We suggest that
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the RSAW be changed to explicitly indicate that if the entity has a documented protocol that
defines the expectations of its operators, requires periodic checks to validate conformance
with the protocols, and implements corrective actions when deficiencies are found, the entity
will be determined to be compliant In several places, including the implementation plan, there
is mention of retiring COM-002-3. This standard was never FERC approved, therefore Dominion
suggests changing this from retiring COM-002-3 to withdrawing COM-002-3.
Group
Southern Company: Southern CompanyServices, Inc.; Alabama Power Company; Georgia
Power Company; Gulf Power Company; Mississippi Power Company; Southern Company
Generation; Southern Company Generation and Energy Marketing
Marcus Pelt
Yes
No
R3 & R4 - While there is the potential of risk if documented communications protocols are not
followed, this should not somehow imply that incorrect operations were performed as a result.
The severe category should be reserved only for those instances in which documented
communications protocols were not followed *and* which resulted in an emergency operation
or reliability issue. As a result, we suggest “demoting” each existing VSL to a lower level, and
editing the Severe VSL and limit it to only those instances that resulted in an emergency
operation or reliability issue (suggestions provided below). Low - The responsible entity
demonstrates a consistent pattern of not using the documented communications protocols
developed in Requirement R1 for Operating Instructions that are not Reliability Directives.
Moderate – The responsible entity did not use the documented communications protocols
developed in Requirement R1 when issuing or receiving a Reliability Directive. High – The
responsible entity did not use the documented communications protocols developed in
Requirement R1 when issuing or receiving an Operating Instruction *and* resulting in an
emergency operation or reliability issue. Severe - The responsible entity did not use the
documented communications protocols developed in Requirement R1 when issuing or
receiving a Reliability Directive *and* resulting in an emergency operation or reliability issue.
Southern also suggests (per comments below in section 3 on R5) that the VRF’s and VSL’s
should be deleted for R5.
Yes
Standard Comments: R2 - We disagree with the DP and GOP being required to have a
documented communications protocol. The requirement should simply require these two
entities to use 3-part communication (i.e. repeat back) for Operating Instructions. Requiring a
document is a purely administrative requirement and certainly meets the Paragraph 81 criteria.
R5 - In NERC’s own Q&A document for RAI prepared by the Risk-Based Reliability Compliance
Working Group (RBRCWG), the following statements are made: “An entity can voluntarily
establish internal controls designed to reduce its control risk, which could have a positive
influence on the scoping of compliance monitoring by the Regional Entity. Conversely, the
entity can voluntarily elect to not establish internal controls or share them with the Regional
Entity.” This is inconsistent with the direction of the proposed Standard COM-002-4, R5. This
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not only requires an internal control, but also requires that the control be shared with the
Regional Entity (during audits). Also, consider that an entity can develop and implement a
robust communication protocol consistent with COM-002-4 requirements and flawlessly follow
its communication protocol, yet be found in violation of COM-002-4 by failing to demonstrate
that it has adequate (subjective) management (internal) controls in place. This is inconsistent
with the RAI guidance provided by NERC regarding the voluntary nature of internal controls.
So, in principle, internal controls should not be dictated in a reliability standard. This goes
against the principle of “Results-Based” standards. The intended result is effective
communications. This can be attained with Requirements 1 through 4. No one will argue that
internal controls won’t help ensure that the desired results are achieved. However,
Requirement 5 is not absolutely necessary for the results to be achieved, and therefore, should
not be included in the standard and should be removed. R5.1 – We understand the thought
that the BA, RC, and TOP will be assessing both the issuer’s and receiver’s adherence to the
communications protocols; however, there needs to be some obligation on the receiver’s end
to incorporate the feedback in their management practices. M3 and M4 – It is not clear what is
meant by “independent review of operating personnel’s adherence to the protocols”. We
recommend clarifying that this independent review only implies that the operator cannot
assess their own communications. This assessment can be conducted by the operator’s
management that is responsible for developing and training on the protocols or other groups
within the entity’s organization that the operator’s management deems appropriate to provide
an independent assessment. This same comment applies to the RSAW for R3 and R4. RSAW
Comments: It appears that the intent of the revised COM-002-4 standard and the RSAW is to
eliminate the “zero defect” concern expressed by the industry. Southern appreciates the SDT
and NERC’s move in this direction; however we recommend modifying the RSAW to make it
clear that as long as registered entities have a protocol document that lays out its expectations
of its operators, periodically checks for conformance with the protocols, and implements
corrective actions when deficiencies are found, the entities are compliant. Specifically, the
Compliance Assessment Approach specific to COM-002-4, R3 as drafted provides the CEAs too
much subjectivity. There needs to be more defined rule set and objective criteria that are used
to determine if an entity’s internal controls around operating personnel adherence to the
documented communications are insufficient. For example, CEAs should not have the flexibility
to determine if the design frequency, volume of communications reviewed, and independence
of the review party are sufficient. These parameters should be left up to the entity. The
compliance approach should simply provide for the auditors to review the entity’s
management practices related to assessing operators’ communications and actual evidence of
such review to ensure these management practices are occurring. The RSAW should be
modified to state that entity’s management practices should only be allowed to be deemed
insufficient if: a) there is no evidence that management practices exist to assess operating
personnel’s adherence to communications protocols or b) evidence demonstrates a pattern of
not following the documented communications protocols.
Individual
John Brockhan
CenterPoint Energy Houston Electric
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Yes
CenterPoint Energy agrees that the proposed COM-002-4 Standard addresses the August 2003
Blackout Report Recommendation number 26, FERC Order 693, and the COM-003-1 SAR
however, the Company believes it goes beyond what is necessary to address the
recommendations and ensure reliable communications. In addition CenterPoint Energy is
concerned the proposed Standard may actually have the unintended opposite impact and
impair reliable communication. See response to Q3 below.
No
CenterPoint Energy strongly disagrees with any Moderate or higher VSL for failure to document
part of a procedure. See proposed VSL’s for R1 and R2. The focus should remain on reliable
operation of the system. If an entity is consistently using the required elements in its normal
and emergency communications, failure to document a portion of that procedure should result
in no more than a Lower VSL.
Yes
CenterPoint Energy strongly believes the stakeholder and NERC BOT approved COM-002-3
adequately addresses the FERC directive and no other Standard is necessary. CenterPoint
Energy is very concerned regarding certain aspects of the proposed COM-002-4. The Company
firmly believes R1.1 has great potential to detract from reliable operation of the Bulk Electric
System (BES). By definition, a Reliability Directive is issued when an entity is in an Emergency
situation or an unplanned system event has occurred that is causing an Adverse Reliability
Impact on the BES. In these situations System Operators are analyzing multiple screens of data,
reviewing various options of possible actions to take, and determining the other entities and
personnel that need to be notified of the event. To inject a requirement to identify a command
as a Reliability Directive into this environment has a high probability of negatively impacting
the System Operator’s response by causing the System Operator to hesitate in issuing the
appropriate command thereby delaying the needed action. In addition this introduces the
possibility of confusion on the part of the issuer and the receiver. At what point during an
unplanned system event does it become an Emergency and therefore an Operating Instruction
becomes a Reliability Directive requiring a special identification? In this highly stressful
situation the System Operator does not need to be considering anything else other than what
actions need to be taken in order to stabilize the BES and to protect life and property.
CenterPoint Energy does not believe this requirement enhances reliable operation of the BES
and in fact could impair that reliability at a crucial time. In addition CenterPoint Energy believes
R1.8 is unnecessary since it is redundant with current TOP-002-2.1b requirement R18 which
requires the use of common line identifiers when referring to transmission facilities of an
interconnected network. CenterPoint Energy strongly recommends deletion of R1.1. While the
Company believes R1.8 is unnecessary, redundant, and offers no enhancement to reliable
communication CenterPoint Energy would be able to support COM-002-4 if R1.1 was deleted.
Individual
Patricia Robertson
BC Hydro
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Yes
1. Purpose: The word "tighten" implies what the revisions to the standard are expected to do
and doesn't reflect what the standard purpose is. BC Hydro recommends revising. 2. R1.5: Why
is the requirement to confirm receipt for only one receiver and not all receivers for the
multiple party message?
Group
SPP Standards Review Group
Robert Rhodes
Yes
We can support the combination of the two standards although we still have reservations
regarding the need to introduce Operating Instructions in order to address Recommendation
26 which we see as strictly for emergency situations. We provide Recommendation 26 to
support our position. “NERC should work with reliability coordinators and control area
operators to improve the effectiveness of internal and external communications during alerts,
emergencies, or other critical situations, and ensure that all key parties, including state and
local officials, receive timely and accurate information. NERC should task the regional councils
to work together to develop communications protocols by December 31, 2004, and to assess
and report on the adequacy of emergency communications systems within their regions
against the protocols by that date.”
No
The VSLs need to be modified to reflect the changes we propose in response to Question 3.
Yes
In order to more closely link the internal control process in R5 to the implementation of the
protocols as required in R3 and R4, we propose revised language for R3 and R4. Additionally,
we believe it was the intent of the SDT to provide the flexibility contained in R5 to the DP and
GOP in addition to the BA, RC and TOP. Therefore, the DP and GOP should be included in R5.
With that linkage established to R3 and R4, we propose that Parts 5.1 and 5.2 be deleted.
Associated Measures and VSLs will need to be modified to reflect these changes. For example,
the High VSL for R3 should now incorporate the remediation concept since without it the VSL
implies zero-tolerance even though consistent pattern language is provided. To be noncompliant the responsible entity would have to demonstrate a consistent pattern of nonadherence to its protocols and a lack of remediation for the given situation. R3 - Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall implement the documented
communications protocols developed in Requirement R1 and remediate noted exceptions for
Operating Instructions which are not Reliability Directives in fulfillment of Requirement R5.
Exceptions are not allowed for Reliability Directives. R4 - Each Distribution Provider and
Generator Operator shall implement the documented communications protocols developed in
Requirement R2 and remediate noted exceptions for Operating Instructions which are not
Reliability Directives in fulfillment of Requirement R5. Exceptions are not allowed for Reliability
Directives. Furthermore, this process should not be an audit of our internal controls. It should
be an audit of the implementation of our communications protocols and our efforts to correct
exceptions to the non-use of those protocols. This being the case, language such as ‘reasonable
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assurance’ and ‘reasonably designed’ which is in both the standard (M3 and M4) and the RSAW
(pages 9 and 15) needs to be eliminated. R1.5 and R1.6 cover one-way burst messaging
systems which create unique operating situations when it comes to issuing Operating
Instructions. In previous versions of COM-003-1 the SDT deleted this requirement. We suggest
deleting it in this draft. It is a difficult situation to handle and does not present itself to cleanly
handling 3-part communication. Having only one party confirm receipt of a Reliability Directive
which has been sent to potentially tens of entities, does not provide a secure mode of
operation nor does it address Recommendation 26. To eliminate the possibility of confusion
over the use of ‘internal operations’ we suggest pulling the language in its entirety from COM001-1.1, R4 into COM-002-4, R1.2. Replace ‘real-time’ with ‘Real-time’ in M3, M4 and M5.
Individual
Jason Snodgrass
Georgia Transmission Corporation
No
Both Reliability Directives and Operating Instructions have a HIGH VRF which appears
inconsistent with previous drafts of the definitions and use of the two terms. R3 & R4 - While
there is the potential of risk if documented communications protocols are not followed, this
should not somehow imply that incorrect operations were performed as a result. The severe
category should be reserved only for those instances in which documented communications
protocols were not followed *and* which resulted in an emergency operation or reliability
issue. As a result, we suggest “demoting” each existing VSL to a lower level, and editing the
Severe VSL and limit it to only those instances that resulted in an emergency operation or
reliability issue (suggestions for R4 provided below). Lower - The responsible entity
demonstrates a consistent pattern of not using the documented communications protocols
developed in Requirement R2 for Operating Instructions that are not Reliability Directives.
Moderate – The responsible entity did not use the documented communications protocols
developed in Requirement R2 when receiving a Reliability Directive. High – The responsible
entity did not use the documented communications protocols developed in Requirement R2
when receiving an Operating Instruction *and* resulting in an emergency operation or
reliability issue. Severe - The responsible entity did not use the documented communications
protocols developed in Requirement R2 when receiving a Reliability Directive *and* resulting
in an emergency operation or reliability issue. These aforementioned suggestions could also be
duplicated for R3 with respect to issuers.
Yes
R2 - GTC disagrees with the DP and GOP being required to have a documented
communications protocol. The requirement should simply require these two entities to use 3part communication (i.e. repeat back) for Operating Instructions. Requiring a document is a
purely administrative requirement and certainly meets the Paragraph 81 criteria. The following
is suggested: R2 Each Distribution Provider and Generator Operator that receives an Operating
Instruction shall: 2.1 Respond using the English language unless agreed to otherwise. An
alternate language may be used for internal operations. 2.1.1 Oral Operating Instructions shall
be responded to orally. 2.1.2 Written Operating Instructions shall be responded to in writing.
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2.2 Take one of the following actions: • Repeat the Operating Instruction and wait for
confirmation from the issuer that the repetition was correct. • Request that the issuer reissue
the Operating Instruction. 2.3 Request clarification from the issuer if the communication is not
understood when receiving the Operating Instruction through a one-way burst messaging
system used to communicate a common message to multiple parties in a short time period
(e.g., an all call system). R5 - GTC believes internal controls type language is not appropriate
within Reliability Standards Requirements and recommends deletion of R5. Specifically, since
R3 and R4 are requirements to implement the communication protocols of R1 and R2 and must
be adhered to (zero tolerance), it seems R5 is unnecessary to meet the objective of this
Standard identified in the purpose statement and would seem to be more closely aligned with
Paragraph 81 principles as administrative. Additionally, in NERC’s own Q&A document for RAI
prepared by the Risk-Based Reliability Compliance Working Group (RBRCWG), the following
statements are made: “An entity can voluntarily establish internal controls designed to reduce
its control risk, which could have a positive influence on the scoping of compliance monitoring
by the Regional Entity. Conversely, the entity can voluntarily elect to not establish internal
controls or share them with the Regional Entity.” This is inconsistent with the direction of the
proposed Standard COM-002-4, R5. This not only requires an internal control, but also requires
that the control be shared with the Regional Entity (during audits). In summary, internal
controls should not be listed as a requirement in a Reliability Standard. This goes against the
principle of “Results-Based”. The intended result is effective communications. This can be
attained with Requirements 1 through 4. However, Requirement 5 is not absolutely necessary
for the results to be achieved, and therefore, should not be included in the standard and
should be removed. While GTC firmly supports moving away from zero-tolerance standard
requirements, the RAI-related compliance elements of the proposed COM-002-4 appear to be
premature as the RAI remains under development. Until the RAI program is more fully
developed it’s unclear how COM-002-4 would be audited. RAI and related changes to the
Compliance Monitoring and Enforcement Program (CMEP) must be fully developed to ensure
all parties (NERC, Regional Entities and Registered Entities) understand the rules of the road
before being asked to approve a standard that relies on information and processes not yet
finalized. Additionally, the RSAW for COM-002-4 depends on the implementation of the
Reliability Assurance Initiative (RAI) which is not expected to be implemented until 2016. It
seems unreasonable to utilize an internal controls approach to auditing until the criteria for
such evaluation has been clearly explained to the stakeholders. -Both the terms Operating
Instruction and Reliability Directive are used in this standard with little guidance on when to
use a Reliability Directive which is described as a type of Operating Instruction.
Individual
Allen Mosher - APPA Staff
American Public Power Association
Yes
APPA staff supports the development and approval of a single, combined communication
protocols Reliability Standard that covers emergency, alert and normal operating conditions for
the BES, while recognizing that performance expectations for applicable registered entities and
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NERC’s approach to compliance and enforcement should differentiate between emergency and
non-emergency conditions. Our initial review indicates the recently proposed draft standard
COM-002-4 strikes an appropriate balance between these considerations, while fully
responding to the NERC Board’s and Standards Oversight and Technology Committee’s
Resolutions. We commend the SDT for its efforts. However, additional work is necessary to
address technical concerns with the draft standard. See below.
No
No. APPA has concerns with several Compliance Elements, including the VRFs and VSLs in
proposed COM-002-4. (1) The VRFs for DPs under R3 and R4 should be lowered, since noncompliance by these functions (within vertically integrated entities) or by these functional
entities (if structurally separate) will pose minimal risk to the BES because they do not own or
operate BES facilities. BES protective devices such as UFLS and UVLS relays operate
automatically. (2) The Severe VSL for R3 and R4 requires specific zero defect performance
when a Reliability Directive is issued or received. This is conceptually sound reliability
performance objective, but it should be stated in the Requirements, as is the case in COM-0023, with appropriate limitations to Reliability Directives, rather than burying the Requirement in
the VSLs or in other Compliance Elements. (3) More fundamentally, the proposed draft relies
heavily on the as-yet untested application of the NERC Reliability Assurance Initiative. Even
modest changes to the Compliance Elements of the proposed standard – the Measures,
Violation Risk Factors, Violation Severity Levels and Reliability Standard Audit Worksheets –
would undermine the balance outlined above. Further delays in the development and
implementation of RAI will certainly jeopardize successful implementation of COM-002-4.
Yes
(1) Project Plan: APPA staff supports the development and approval of a single, combined
communication protocols Reliability Standard that covers emergency, alert and normal
operating conditions for the BES, while recognizing that performance expectations for
applicable registered entities and NERC’s approach to compliance and enforcement should
differentiate between emergency and non-emergency conditions. Our initial review indicates
the recently proposed draft standard COM-002-4 strikes an appropriate balance between these
considerations, while fully responding to the NERC Board’s and Standards Oversight and
Technology Committee’s Resolutions. We are nonetheless concerned that the severely
shortened, 15-day comment and ballot period directed by the Standards Committee for COM002-4 will foreclose resolution of major technical objections to the proposed standard. (2)
Reliability Objectives and Approach to Compliance Assurance: APPA Staff believes a strict, zero
defect performance expectation for use of three-part communications by operating personnel
is appropriate for the issuance of and response to Reliability Directives during emergencies and
other adverse operating conditions on the BES. In marked contrast, the emphasis for Operating
Instructions issued during normal conditions should be on behavioral, management and
compliance assurance. First, each BES system operator should be trained in three-part
communications (and other communication protocols) such that his or her use of such
practices during normal operations is equally routine during emergency conditions. Second,
each registered entity’s management team should be confident that its operating personnel
will follow the protocols on a consistent basis and that management practices and controls will
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detect both departures from these communication protocols, as well as opportunities for
improved performance. Third, NERC and regional compliance and enforcement staff should
have reasonable assurance that the evidence proffered by each registered entity demonstrates
it meets these performance expectations. (3) Applicability of the Standard: For a number of
very practical considerations, APPA Staff urges the SDT, NERC staff and the NERC Board of
Trustees to be cautious and measured in their efforts to bring this project to conclusion. The
combined communication standard is unusual if not unique among NERC standards in that it
touches on the day-to-day activities of thousands of industry employees engaged in real time
operations and that its application as drafted will apply to many thousands of routine
communications every day. APPA Staff urges the SDT to clarify which operation personnel are
subject to the proposed standard, including whether Operating Instructions include oral
communications issued and received within a single functional entity. The standard does not
clarify such applicability beyond referring to “issuers” and “receivers” of Operating
Instructions. Is the standard’s applicability limited to NERC certified operators? Control center
operating personnel for all functions, even for individuals that do not operate or supervise
operation of BES elements? Does the standard include training for field personnel? APPA Staff
believes that operators and field personnel should use three-part communications to ensure
safety, equipment protection and quality of retail service. However, the proposed open-ended
Applicability to potentially ALL operating and field personnel of all BAs, DPs, RCs, TOPs and
GOPs is overly broad for a NERC reliability standard. The training burdens and the
documentation that each entity has implemented a systematic approach to such training is
clearly burdensome. APPA Staff also recommends that the SDT clarify the Applicability of the
draft standard, to eliminate applicability to small DPs under either a size threshold such as a
peak load of less than 100 MW or that do not operate and staff a 24/7 distribution control
center. (4) Compliance Assurance, Implementation Plan and Regulatory Certainty: APPA Staff
believes the immature, untested nature of RAI takes the proposed standard beyond “in flight
maintenance” into the world of simultaneous program design and operation. A poorly
designed or implemented standard could actually increase the risk of BES performance errors,
by diverting the focus of operators and management from what is being communicated to how
the communication takes place. For these reasons, it is imperative that NERC and the industry
have a clear, common understanding of the communication protocols and management
controls that will be required at least one year prior to the effective date of the proposed
standard. We support a balanced approach that focuses on education and training during a 12month trial period to allow the industry to implement training programs and test its processes.
Any failures identified in an audit or an events analysis during the trial period would not trigger
any penalties, but would be noted for further evaluation. After the trial period, any failures
would trigger an automatic re-training or coaching of the individual(s) in question, as well as
improvements to the registered entity’s management controls. Finally, APPA Staff seeks
assurance that NERC will not seek to modify the Compliance Elements of proposed COM-002-4
after it has been approved by the registered ballot body, without due process that protects the
balance now present in the standard. Even modest changes to the Measures, VSLs, or RSAWs,
such as changing “Reliability Directive” to “Operating Instruction” in the Severe VSL for
Requirement R3, would transform COM-002-4 into a zero defect standard and drown the
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industry and NERC in compliance administrivia.
Individual
Ronald L Donahey
Tampa Electric Company
No
Yes
The issue of zero defect in operating Instructions requiring three way communications is
unacceptable. The Notes to the Auditorgiving the auditor unlimited power to determine that
the internal controls are not properly designed or is ineffective is not acceptible
Group
National Grid
Michael Jones
Yes
National Grid appreciates the opportunity to provide the following comments. National Grid
believes that clear communication is important for the reliable operation of the system in both
normal and emergency conditions. To ensure that communication protocols are followed in
both normal and emergency conditions, National Grid includes proper communication
protocols in continuing operating training. In addition, National Grid has internal controls to
assess adherence to communication protocols in both normal and emergency conditions.
National Grid’s concern regarding COM-002-4 is the additional, open-ended, compliance
burden that will be added if communication protocols under normal conditions are added to
the scope of the COM standard. National Grid appreciates the information provided in the
draft Reliability Standard Audit Worksheet (RSAW) regarding the audit and enforcement
approach. It should be clearly described, within the reliability standard, that the reliability
standard is not a “zero-defect” standard for every communication. As written, the draft COM002-4 standard requirements could be interpreted to be “zero-defect” requirements. National
Grid provides the following recommended solution for the COM-002-4 standard:
Requirements: R1. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall document communications protocols that specify the use of repeat-back and
acknowledgements (three-way communication) of Operating Instructions and Reliability
Directives for Normal and Emergency communications. 1.1. The communication protocol shall
require the issuer and receiver of an oral Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may be used for internal operations.
Violation Risk Factor: Low - Time Horizon: Long-term Planning R2. Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall implement a method to evaluate the
communications protocols developed in requirement R1 that: 2.1. Assesses adherence to the
communications protocols to provide feedback to issuers and receivers of Operating
Instructions and Reliability Directives. 2.2. Assesses the effectiveness of the communications
protocols and modifies those protocols, as necessary. Violation Risk Factor: Low - Time
Horizon: Operations Planning
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Individual
D Mason
Hetch Hetchy Water and Power
Yes
The Independent Industry Experts Panel provided a "point-on" review of the COM-003 draft
standard. That review included recommended some simple and clear language to define the
reliability objectives of a combined COM-002/COM-003 Standard. Instead, the drafting team
has opted to draft more complex and unintuitive language without any obvious need for the
for the additional requirements, despite the availability a simpler, more intuitive solution.
Individual
Ryan Walter
Tri-State Generation and Transmission Association, Inc.
No
Tri-State believes that this proposal goes beyond what was contemplated in the Blackout
Recommendation as well as FERC Order 693 directives 1 and 3 of paragraph 540. Additionally,
Tri-State feels that a new term to define “Operating Instruction” is not warranted or required
to fulfill either the FERC directive or Blackout Recommendations and is creating confusion
where it is not needed. While the Final Blackout Report Recommendation 26 recommended
tightening communications protocols, it emphasized communications during alerts and
emergencies. This draft has pulled Reliability Directives and Operating Instructions into one
definition and the draft does little to differentiate between the two. They appear to both be
held to the same expectations and standards with minimal differentiation. Further work needs
to be done on the definition and differentiation between the expectations and risk for
communicating during alerts and emergencies and during normal operating instructions. The
additional administrative burden added here for normal Operating Instructions does not add
value to BES reliability and substantially increases the compliance burden. Tri-State requests
further clarity of the Operations Instructions definition with clear expectations between
emergencies, alerts and normal communication. Also, Tri-State requests feedback as to how
standards for normal communication will address actual events that occurred during the
Blackout and how this standard is providing a foundation for BES risk assessments and
prioritization, which the RAI is working towards. R3 and R4 are written in a zero tolerance
fashion: “implement the documented communications protocols”. This opens up industry to
have to document, review and monitor all communications for emergencies, alerts and normal
communications to effectively complete audits with no findings. Having the normal Operating
Instructions included with the emergency and alert communications does not allow the
industry to maximize their limited resources for the issues that are of higher risk. The added
burden of assessing and evaluation the programs for identifying, assessing and correcting (R3R4 RSAW) are also premature. The industry has not developed and vetted these practices to
have a strong and regionally consistent foundation to be audited from. Tri-State requests
feedback for what exactly R5 is seeking. R5.1 appears to be a reiteration of R3 and R4
(“implement” versus “assess adherence”). Who or what determines “effectiveness of the
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communication protocols” in 5.2? What are the expectations for documentation of this? It is
the communication programs and the final results of that program that impact the BES
reliability. The internal control programs will support the industry to achieve these goals with
more consistency, but should not be included within the standards. Tri-State recommends
eliminating R5. Language more specific to the communication as opposed to the control
programs should be considered, if needed.
No
In order to develop appropriate VRFs and VSLs, it will be imperative to differentiate between
Reliability Directives and Operating Instructions. It must be clear which Operating Instructions
will be monitored and audited and the expectations for each type of communication. There is a
difference between the risk and impact to the BES under these various conditions and the VSLs
should reflect that. Tri-State does not find that evaluating, auditing and administratively
following normal Operating Instructions to this degree of specificity provides the BES reliability
value that the Blackout recommendations were seeking.
Yes
For the reasons listed in response to Questions 1 and 2, Tri-State cannot support expanding
COM-002 as it is shown in this draft. It adds a tremendous amount of administrative burden
and does not enhance the BES reliability.
Group
Colorado Springs Utilities
Kaleb Brimhall
SPP Standards Review Group
Yes
Requirement 1.8 should not be included, it is proposed to be removed under Paragraph 81.
Group
Luminant
Brenda Hampton
Yes
While neither the August 2003 Blackout Report Recommendation number 26 nor Order 693
requires three-part communications or any established communication protocol for normal
operations, EOP-001-2, R3.1 and COM-002-2, R2 already address the requirements of the
Blackout Report and FERC Order 693. Therefore, in keeping the requirements from COM-002-2
as part of the COM-002-4 standard, we can reasonably argue that the Standard addresses the
recommendation.
No
We do not agree with VSLs for R3 & R4. While there is the potential of risk if documented
communications protocols are not followed, this should not somehow imply that incorrect
operations were performed as a result. The severe category should be reserved only for those
instances in which documented communications protocols were not followed *and* the
Operating Instructions were not implemented correctly which resulted in an Emergency or
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Adverse Reliability Impact. As a result, we suggest the following Violation Severity Levels which
results in limiting the High and Severe levels to only those instances that resulted in an
Emergency or Adverse Reliability Impact: Low - The responsible entity demonstrates a
consistent pattern of not using the documented communications protocols developed in
Requirement R1 for Operating Instructions that are not Reliability Directives. Moderate – The
responsible entity did not use the documented communications protocols developed in
Requirement R1 when issuing or receiving a Reliability Directive. High – The responsible entity
did not use the documented communications protocols developed in Requirement R1 when
issuing or receiving an Operating Instruction *and* the Operating Instruction was not
implemented correctly resulting in an Emergency or Adverse Reliability Impact. Severe - The
responsible entity did not use the documented communications protocols developed in
Requirement R1 when issuing or receiving a Reliability Directive *and* the Reliability Directive
was not implemented correctly which make the Emergency or Adverse Reliability Impact
worse.
Yes
While, under the circumstances, we fully support combining COM-002-3 and COM-003-1 into
one communication protocol and appreciate the efforts of the Standards Drafting Team to
draft this combined standard in such a short time frame, we do not believe this standard
contains clear requirements at this point. Requirements R3 and R4 simply requires the
communication protocols to be implemented. The Measure for those requirements requires
evidence which may include descriptions of management practices that provide the entity
reasonable assurance that protocols are being followed. The RSAW requires the auditor to
consider the frequency and volume of communications reviewed as part of the audit process
even though communication review is not required by R3 & R4 nor M3 & M4. Additionally we
do not believe that this "communication review" should be a requirement to reasonably assure
compliance with the communication protocol. Not only is it not necessary to reasonably assure
compliance as ongoing periodic training can suffice but due to the fact that we have hundreds
of communications with the RC, BA and TOP on a monthly basis and very few if any of those
communications result in an Operating Instructions it will be very burdensome to find calls to
review. So to reasonably assure compliance with the communication protocol and to not
create an undue compliance burden we suggest that R3 & R4 implementation requirement be
changed to require periodic communication protocol reviews and ongoing operator training on
the communication protocol. In addition, Requirements 1.2 and 2.1 introduce the idea of
written Operating Instructions while the other requirements covering the issuance of clear
concise instructions and the requirements covering the receipt and understanding of the
instruction do not cover written Operating Instructions at all. To ensure that communications
are tightened as required by Recommendation #26 and the SAR then the reference to a written
instruction should be removed from the requirements and the definition of the Operating
Instruction should be refined as follows: “An oral command by operating personnel
responsible….”
Individual
Cheryl Moseley
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Electric Reliability Council of Texas, Inc.
Yes
ERCOT respectfully submits these comments on COM-002-4 in conjunction with the IRC’s input
to the NERC BoT, and the IRC SRC comments. ERCOT does not believe that COM-002-4, or
COM-003 if it is developed furth.er, should be a zero tolerance standard.
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
Yes
BPA generally supports the proposed standard and suggests that a note be included for R1.5
and R1.6 stating that one-way burst communications for operating instructions is not
recommended as it would limit the ability to receive a response from all entities involved.
Group
PacifiCorp
Ryan Millard
Yes
Yes
Yes
PacifiCorp appreciates the diligence and dedication of the Standard Drafting Team and
recognizes the improvements that were made in response to industry comments from the
previous draft. There are a few additions, however, that PacifiCorp would like the drafting
team to clarify: Firstly, in light of the fact that NERC has not finalized or implemented the RAI
project, PacifiCorp would like to know why the drafting team included internal control
language in the COM-002-4 RSAW? This language seems to anticipate what the end-state of
the RAI Initiative is going to be (see “Note to Auditor” on pages 9-15 of the RSAW). In the
absence of a final auditor handbook (which is supposed to be consistent across regions),
PacifiCorp would like to know how an auditor can determine whether an internal control is
“properly designed” or “effective”? Secondly, in M3 and M4 of the proposed COM-002-4
standard the drafting team has added language that includes, “Evidencing periodic,
independent review of operating personnel’s adherence to the protocols established in R2 and
R5.” It does not seem clear to PacifiCorp what the periodicity is expected to be or what
constitutes an “independent” review? Although these points do not influence our support of
the COM-002-4 standard, PacifiCorp strongly recommends that the drafting reconsider
including internal control review language in the RSAW until the RAI initiative has been fully
implemented and auditor guidance has been formally developed and distributed across all
regions.
Individual
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Russell A. Noble
Cowlitz County PUD
No
Please see comment submitted by the Western Small Entity Comment Group, Steve
Alexanderson.
Yes
Cowlitz voted affirmative only to avoid the possibility of the BOD circumventing the Standard
Development process. Please consider carefully comment by the Western Small Entity
Comment Group submitted by Steve Alexanderson. We strongly suggest the standard be
further amended as suggested before submittal to FERC.
Group
ACES Standards Collaborators
Ben Engelby
No
(1) This standard does not address the directive to “tighten communications.” This draft is a
reproduction of prior COM-003-1 drafts, with unnecessary protocols that do not improve
reliability of the BES. For example, it is unnecessary to include a requirement to use the English
language in all but a small handful of areas of the Eastern, Western and ERCOT
interconnections. This will result in unnecessary compliance burdens that do not support
reliability contrary to the RAI. (2) We appreciate the SDT combining COM-002-3 and COM-0031. (3) Broad applicability to DPs is inappropriate. DPs do not operate or own Elements of the
BES. Thus, they cannot "change or preserve the state, status, output, or input of an Element of
the Bulk Electric System or Facility of the Bulk Electric System" as defined in the definition of
Operating Instruction. Thus, they will never receive an operating instruction and should not be
put in the position of having to demonstrate compliance with a requirement that can never
impact them. This approach is contrary to the RAI initiative to refocus compliance efforts on
higher risk requirements that actually impact reliability. While a DP may be required to reduce
load, this is essentially a reliability directive and not an operating instruction. What other
actions would a BA, TOP or RC require of a DP besides to reduce load? We can think of none
and cannot fathom applicability for operating instructions to DPs.
No
We disagree with the content of COM-003-1, as there should not be detailed protocols. Since
we disagree with the content of the standard, we also disagree with the VSLs. Further, both
Reliability Directives and Operating Instructions have a HIGH VRF which appears inconsistent
with previous drafts of the definitions and use of the two terms.
Yes
We do not understand the urgency to request a waiver to the SPM for this project. The NERC
BOT resolution did not require a new standard to be developed by the November BOT meeting.
Due to the shortened time frame, industry does not have enough time to fully vet the issues
with SMEs. This standard lacks technical justification to justify the reduced comment and ballot
period. There are serious compliance impacts from the proposed requirements and not enough
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guidance on when to self-report instances of miscommunication. This will only further serve to
perpetuate the current compliance approaches that place too much emphasis on minor details
that do not support reliability.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC Review Group
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
Agree
American Public Power Association ("APPA")
Individual
John Tolo
Tucson Electric Power
Yes
Yes
Yes
While I agree with the combining of COM standards, I have a disagreement with the definition
of operating instruction. I would whole-heartedly agree that this protocol be adhered to during
emergency or abnormal conditions, but not during normal conditions. The mere fact that a
System Operator calls a remote generation plant to raise 25-30-50 MW should not necessitate
a three-point communication. There are times when those instructions are given to another
System Operator who then calls the plant, therefore doubling up on three-point
communications.
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Consideration of
Comments Summary
Project 2007-02 Operating Personnel
Communications Protocols
January 2, 2014
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC | Consideration of Comments – Project 2007-02 | January 2, 2014
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Table of Contents
Table of Contents .......................................................................................................................................................2
Introduction ................................................................................................................................................................3
Consideration of Comments .......................................................................................................................................4
Purpose of Consideration of Comments Summary ................................................................................................4
COM-002-4 Comments ...........................................................................................................................................4
Operating Instruction Definition .........................................................................................................................4
Applicability .........................................................................................................................................................4
Non-Emergency Operations ................................................................................................................................4
Requirement R1 Clarification ..............................................................................................................................5
GOP and DP Documented Communications Protocols and Three-Part Communications...................................5
“Implement” and Training...................................................................................................................................5
Consistent Pattern ...............................................................................................................................................6
VRFs and VSLs......................................................................................................................................................6
Zero Defect Standard ..........................................................................................................................................6
Compliance/Enforcement....................................................................................................................................7
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Introduction
The Project 2007-02 Drafting Team (OPCP SDT) thanks all commenters who submitted comments on the COM002-4 Operating Personnel Communications Protocols standard. The standard was posted for a 14-day public
comment period from October 21, 2013 through November 4, 2013. Stakeholders were asked to provide
feedback on the standard and associated documents through a special electronic comment form. There were 77
sets of comments, including comments from approximately 178 different people from approximately 115
companies representing all 10 Industry Segments.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process. If you feel there has been an error or omission, you can contact
the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at [email protected]. In
addition, there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf
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Consideration of Comments
Purpose of Consideration of Comments Summary
The OPCP SDT appreciates the comments from industry regarding the COM-002-4 standard. All comments were
reviewed carefully by the OPCP SDT and changes were made to the standard accordingly. While all comments
were reviewed, the new Standards Process Manual (SPM) does not require responses to each individual
comment when an additional ballot is needed. However, this document provides a summary of responses to
comments. The following pages will provide a summary of the comments received and how the comments were
addressed by the OPCP SDT.
COM-002-4 Comments
Operating Instruction Definition
Several commenters provided alternative language to provide clarity for the Operating Instruction
definition. After reviewing the comments, and considering the NERC Board of Trustees’ November 7th 2013
Resolution2, the OPCP SDT has revised the definition of Operating Instruction to remove the reference to
Reliability Directive. This was primarily in response to a NOPR issued by FERC 3 which proposed to remand
the filing that contained the definition of Reliability Directive. This action would result in Reliability Directive
not being a defined term. Furthermore, the OPCP SDT inserted parentheses to offset the type of
communication that is not included in the Operating Instruction definition to provide additional clarity.
Applicability
Several commenters expressed concern with the standard’s applicability to Generator Operators (GOP) and
Distribution Providers (DP). The concerned entities commented that some DPs and GOPs do not have 24/7
staff or do not use, own, or operate Bulk Electric System (BES) facilities. Further, some entities expressed
concern that the current wording of the standard might require them to begin 24-hour operations, and
require them to install recording equipment, even if they never receive an Operating Instruction.
In response to the comments and the NERC Board Resolution, the OPCP SDT revised the standard to clarify
that DPs and GOPs are required to a) train their operators prior to receiving an Operating Instruction, and b)
use three-part communication when receiving an Operating Instruction during an Emergency. In addition,
the measures have been revised to show that a DP or GOP can demonstrate compliance for use of threepart communication when receiving an Operating Instruction during an Emergency by providing an
attestation from the issuer of the Operating Instruction. If a DP or GOP never receives an Operating
Instruction, no requirement in this standard would apply to them. To clarify, it was never the intent of the
OPCP SDT to require entities to change their staffing, or to install any additional equipment to demonstrate
compliance.
Non-Emergency Operations
Some entities stated that the communications protocols specified in COM-002-4 should not apply to nonEmergency or day-to-day operations. Similarly, some entities expressed concern that three-part
communications are not necessary for non-Emergency and day-to-day operations.
2
See http://www.nerc.com/gov/bot/Board of Trustees Quarterly Meetings/Board COM Resolution 11.7.13 v1
AS APPROVED BY BOARD.pdf
3
See http://www.nerc.com/FilingsOrders/us/FERCOrdersRules/NOPR_TOP_IRO_RM13-12_RM13-14_RM1315_20131121.pdf
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The OPCP SDT respectfully disagrees with these comments. From a practical standpoint, one set of
communications protocols for both emergency and non-emergency situations will reduce confusion for
operating personnel. In particular, operating personnel would not have to switch to a different set of
(potentially unfamiliar) communications protocols in stressful emergency situations. This is especially true
for three-part communications. Operating personnel should be using three-part communications in day-today operations so that the use of three-part communications during emergency conditions is natural and
supports effective communications. Also, FERC Order No. 693 directed the OPCP SDT to address both
emergency and non-emergency communications protocols. The NERC Board of Trustees also directed the
Standards Committee and the OPCP SDT to draft a single Reliability Standard that includes communications
protocols for emergency and non-emergency operations. A new draft of COM-002-4 was developed in
response to this input.
Requirement R1 Clarification
Several commenters requested more clarity in Requirement R1. Some entities expressed confusion over
whether a receiver of an Operating Instruction was required to respond when operating personnel that
issued an Operating Instruction were required to confirm a response. Other entities wanted more clarity as
to what actions may be taken by operating personnel issuing an Operating Instruction when no response
was received. Additionally, several entities stated that some of the protocols were unnecessary, specifically
the use of English and the use of alpha-numeric clarifiers.
The OPCP SDT revised Requirement R1 to provide more clarity as well as provide more latitude to operating
personnel issuing an Operating Instruction. The revised requirement states that operating personnel that
issue an Operating Instruction may take an alternate action to issue an Operating Instruction when the
receiver does not respond or if the receiver does not understand the Operating Instruction. This revision
more accurately reflects the scope of actions that an issuer of an Operating Instruction can take. In
response to the comments above, the OPCP SDT removed Part 1.8 which required entities to specify which
instances required alpha-numeric clarifiers in their communications protocols. The requirement for the use
of the English language was retained, since it was incorporated from COM-001-1.1 Requirement R4.
GOP and DP Documented Communications Protocols and Three-Part Communications
Some entities commented that GOPs and DPs should not be required to develop documented
communications protocols because they only receive Operating Instructions and/or Reliability Directives.
The OPCP SDT agrees that the requirement to develop documented communications protocols for DPs and
GOPs is not necessary. The OPCP SDT removed the seventh posting’s Requirement R2, which required
documented communications protocols for GOPs and DPs that receive Operating Instructions. In the eighth
posting, the only requirements that apply to DPs and GOPs are Requirements R3 and R6. Requirement R3
requires initial training for operating personnel who can receive an Operating Instruction. Requirement R6
requires receivers of Operating Instructions issued during an Emergency to use three-part communications.
Requirement R5 supports Requirement R6 by requiring each BA, RC, and TOP that issues an Operating
Instruction during an Emergency to use three-part communications. Therefore, the OPCP SDT reduced the
administrative burden on GOP and DP while covering any reliability gap by requiring GOPs and DPs receiving
Operating Instructions during an Emergency to engage in three-part communications.
“Implement” and Training
Several entities requested clarification for the word “implement” in Requirements R3 and R4 from the
seventh posting. They expressed concern that the term was difficult to demonstrate compliance with.
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In response, the OPCP SDT removed those requirements and added Requirements R2 and R3 in the eighth
posting. Requirement R2 now requires each BA, RC, and TOP to conduct initial training for each operator
responsible for the Real-time operation of the interconnected BES on the documented communications
protocols developed in Requirement R1. Requirement R3 requires each DP and GOP to conduct initial
training for each operator who can receive an Operating Instruction. The OPCP SDT originally intended
“implement” to include this initial training but determined an initial training requirement more clearly
captures this intent. In addition, Requirement R4 was added to require BAs, RCs, and TOPs to at least once
every 12 months assess adherence by its operating personnel to the documented communication protocols
in Requirement R1 and to provide feedback to its operators on their performance, including any appropriate
corrective actions. It also requires these entities to assess the effectiveness of their communications
protocols and make changes as necessary to improve the effectiveness of the protocols. The requirement of
entities to self assess, self identify and provide feedback to its operators was also included in the Board of
Trustees’ resolution. Further, the OPCP SDT believes that it is good operating practice for an entity to
periodically evaluate the effectiveness of their protocols and improve them when possible. Additionally, the
OPCP SDT also believes it is good operating practice to provide operators with performance feedback on
their adherence to the entity’s documented protocols. This provides entities an opportunity to evaluate
their operators’ performance and take corrective actions where necessary, which could prevent a
miscommunication from occurring and thus quite possibly prevent an event which could harmful to the
reliability of the Bulk Electric System.
The OPCP SDT believes the combination of R1-R4 and a non-zero tolerance approach to compliance, for
Operating Instructions issued/received during a non-Emergency, represents an improvement over the
previous “implement” terminology as it better captures an approach that improves reliability by providing a
shorter assessment and correction cycle for an entity than a traditional audit schedule and reduces the
associated compliance burden concurrently.
Consistent Pattern
Several commenters expressed concern with the phrase “consistent pattern” in the VSLs for Requirements
R3 and R4.
The OPCP SDT agrees that the term is vague and has removed it from the revised VRFs and VSLs.
VRFs and VSLs
Several commenters requested revised VRFs and VSLs.
The OPCP SDT modified the VRFs and VSLs to better reflect the differences in severity of violating a
documents requirement (i.e. Requirement R1), violating a training or assessment requirement (i.e.
Requirements R2, R3 and R4) and violating a requirement when issuing or receiving an Operating Instruction
during an Emergency (i.e. Requirements R5, R6 and R7). In addition, the OPCP SDT focused on using clear
language in the VSLs.
Zero Defect Standard
Some entities expressed concern that posting seven of the standard had elements that had no tolerance for
compliance deviations. Given that the Board directed the OPCP SDT to include no exceptions for using
three-part communications for emergency communications, the OPCP SDT determined that the standard
must maintain this aspect in a few requirements. However, the OPCP SDT took this approach only for
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Operating Instructions issued during an Emergency in Requirements R5, R6, and R7. Therefore, the OPCP
SDT limited the zero tolerance approach to only Emergency communications in the standard.
Compliance/Enforcement
Several commenters expressed concern over compliance with the requirements and their enforceability.
In response, the OPCP SDT focused on eliminating vague terms from the standard that would create
ambiguity in compliance with the standard. In addition, the comments have been provided to NERC
Compliance to use in revising the RSAW that is posted with the eighth posting of the standard.
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COM-002-4 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting of the SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of COM-003-1 Standard posted November 2009 for Informal Comments
closed January 15, 2010.
7. Version 2 draft of COM-003-1 Standard posted May 2012 for Formal Comments, Initial
Ballot closed June 20, 2012.
8. Version 3 draft of COM-003-1 Standard posted August 2012 for Formal Comments,
Ballot closed September 22, 2012.
9.
Version 4 draft of COM-003-1 Standard posted November 2012 for Formal Comments,
Ballot closed December 13, 2012.
10. Version 5 draft of COM-003-1 Standard posted March 2013 for Formal Comments,
Ballot closed April 5, 2013.
11. Version 6 draft of COM-003-1 Standard posted June 2013 for Formal Comments, Ballot
closed July 19, 2013.
12. COM-003-1 renumbered as COM-002-4. Version 1 draft of COM-002-4 Standard posted
October 2013 for Formal Comments, Ballot closed November 7, 2013.
13. On December 12, 2013, the Standards Committee approved a waiver of the Standard
Processes Manual to shorten the formal comment and ballot period, from 45 days to 30
days.
Description of Current Draft:
This is the second draft of a revised standard (eighth posting of a communications standard)
requiring the use of standardized communication protocols during normal and emergency
operations to improve situational awareness and shorten response time. The standard drafting
team is posting this standard for a shortened 30 day formal Comment and 10 day Ballot period
per the Standards Committee wavier.
Future Development Plan:
Anticipated Actions
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Anticipated Date
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COM-002-4 Operating Personnel Communications Protocols
1. Additional ballot of Standard
January 2014
2. Final ballot of Standard
February 2014
3. Board adopts standard
TBD
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COM-002-4 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Operating Instruction — A command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. (A discussion of general information and of potential options or alternatives to resolve
Bulk Electric System operating concerns is not a command and is not considered an Operating
Instruction.)
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COM-002-4 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4.
Applicability:
COM-002-4
4.1. Functional Entities
4.1.1 Balancing Authority
5.
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
(Proposed) Effective Date: The standard shall become effective on the first day of
the first calendar quarter that is twelve (12) months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop documented communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a minimum: [Violation
Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
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•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver.
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COM-002-4 Operating Personnel Communications Protocols
•
Take an alternative action if a response is not received or if the
Operating Instruction was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
conduct initial training for each of its operating personnel responsible for the Realtime operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual
operator issuing an Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall conduct initial training for
each of its operating personnel who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator receiving an oral two-party,
person-to-person Operating Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
at least once every twelve (12) calendar months: [Violation Risk Factor:
Medium][Time Horizon: Operations Planning]
4.1. Assess adherence to the documented communications protocols in Requirement
R1 by its operating personnel that issue and receive Operating Instructions,
provide feedback to those operating personnel and take corrective action, as
appropriate to address deviations from the documented protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
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COM-002-4 Operating Personnel Communications Protocols
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues an oral two-party, person-to-person Operating Instruction during an
Emergency, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
•
Confirm the receiver’s response if the repeated information is correct (in
accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R7. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction. [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its initial training
records for its operating personnel such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence of its assessments, including spreadsheets, logs or other evidence of
feedback, findings of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in fulfillment of
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COM-002-4 Operating Personnel Communications Protocols
Requirement R4. The entity shall provide evidence that it took appropriate corrective
actions as part of its assessment for all instances where an operating personnel’s nonadherence to the protocols developed in Requirement R1 is the sole or partial cause of
an Emergency and for all other instances where the entity determined that it was
appropriate to take a corrective action to address deviations from the documented
protocols developed in Requirement R1.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issued an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from the recipient of the
Operating Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings, or dated and time-stamped transcripts of voice recordings, or
dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings dated operator logs, an
attestation from the issuer of the Operating Instruction, voice recordings (if the entity
has such recordings), memos or transcripts.
M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator that
issued a written or oral single or multiple-party burst Operating Instruction during an
Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings, dated operator logs, electronic records, voice recordings (if
the entity has such recordings), memos or transcripts.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
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COM-002-4 Operating Personnel Communications Protocols
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
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COM-002-4 Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity
did not specify the
instances that require
time identification
when issuing an oral
or written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.5
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.1. An alternate
language may be used for
internal operations.
The responsible entity did
not include Requirement
R1, Part 1.4 in its
documented
communication protocols.
The responsible entity did not
include Requirement R1, Part
1.2 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
OR
The responsible entity
did not specify the
nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.6.
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Severe VSL
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COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R2
Long-term
Planning
Low
N/A
N/A
An individual operator
responsible for the Realtime operation of the
interconnected Bulk
Electric System at the
responsible entity issued
an Operating Instruction,
prior to being trained on
the documented
communications protocols
developed in Requirement
R1.
An individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity issued an
Operating Instruction during an
Emergency prior to being trained
on the documented
communications protocols
developed in Requirement R1.
R3
Long-term
Planning
Low
N/A
N/A
An individual operator at
the responsible entity
received an Operating
Instruction prior to being
trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
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COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Operations
Planning
Medium
The responsible entity
assessed adherence to
the documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible entity
assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive Operating
Instructions and
modified its
documented
communication
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Moderate VSL
High VSL
Severe VSL
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions, but
did not provide feedback
to those operating
personnel
The responsible entity did
not assess adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating
Instructions
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions and
provided feedback to those
operating personnel but
did not take corrective
action, as appropriate
OR
The responsible entity did
not assess the
effectiveness of its
documented
communications protocols
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
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AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for
its operating personnel that issue
and receive Operating
Instructions.
COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
protocols, as
necessary
AND
The responsible entity
exceeded twelve (12)
calendar months
between assessments.
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January 2, 2014
Moderate VSL
High VSL
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions, but
did not modify its
documented
communication protocols,
as necessary.
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Severe VSL
COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R5
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity that
issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
Draft 8
January 2, 2014
High VSL
N/A
Severe VSL
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
Confirmed the
receiver’s response if
the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating Instruction
if the repeated
information was
incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or if
the Operating
Instruction was not
understood by the
receiver.
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the Operating
Instruction was not
understood by the receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Page 13 of 15
COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R6
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request that
the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
High VSL
N/A
Severe VSL
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or oral
single-party to multipleparty burst Operating
Instruction during an
Emergency did not
confirm or verify that the
Operating Instruction was
received by at least one
receiver of the Operating
Instruction.
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
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COM-002-4 Operating Personnel Communications Protocols
E. Regional Variances
None
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
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COM-002-4 Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting of the SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of COM-003-1 Standard posted November 2009 for Informal Comments
closed January 15, 2010.
7. Version 2 draft of COM-003-1 Standard posted May 2012 for Formal Comments, Initial
Ballot closed June 20, 2012.
8. Version 3 draft of COM-003-1 Standard posted August 2012 for Formal Comments,
Ballot closed September 22, 2012.
9.
Version 4 draft of COM-003-1 Standard posted November 2012 for Formal Comments,
Ballot closed December 13, 2012.
10. Version 5 draft of COM-003-1 Standard posted March 2013 for Formal Comments,
Ballot closed April 5, 2013.
11. Version 6 draft of COM-003-1 Standard posted June 2013 for Formal Comments, Ballot
closed July 19, 2013.
12. COM-003-1 renumbered as COM-002-4. Version 1 draft of COM-002-4 Standard posted
October 2013 for Formal Comments, Ballot closed November 7, 2013.
13. On December 12, 2013, the Standards Committee approved a waiver of the Standard
Processes Manual to shorten the formal comment and ballot period, from 45 days to 30
days.
Description of Current Draft:
This is the firstsecond draft of a revised standard (seventheighth posting of a communications
standard) requiring the use of standardized communication protocols during normal and
emergency operations to improve situational awareness and shorten response time. The standard
drafting team is posting this standard for a 15-shortened 30 day concurrent Formalformal
Comment period and 10 day Ballot period per the Standards Committee wavier.
Future Development Plan:
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19
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COM-002-4 Operating Personnel Communications Protocols
Anticipated Actions
Anticipated Date
1. Additional ballot of Standard
October 2013January 2014
2. Final ballot of Standard.
November 2013 February
2014
3. Board adopts standard.
November 2013TBD
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COM-002-4 Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Operating Instruction — A command by operating personnel responsible for the Real-time
generation control and operation of the interconnected Bulk Electric System to change or
preserve the state, status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System. (A discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is not a command and is not
considered an Operating Instruction. A Reliability Directive is one type of an Operating
Instruction..)
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19
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COM-002-4 Operating Personnel Communications Protocols
A. Introduction
1.
Title: Operating Personnel Communications Protocols
2.
Number:
3.
Purpose: To tightenimprove communications for the issuance of Operating
Instructions with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4.
Applicability:
COM-002-4
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
(Proposed) Effective Date: The standard shall become effective on the first day of
the first calendar quarter that is twelve (12) months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
havedevelop documented communications protocols for its operating personnel that
issue and receive Operating Instructions. The protocols shall, at a minimum:
[Violation Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require the issuer of a Reliability Directive to identify the action as a Reliability
Directive to the receiver.
1.2.1.1.
Require the issuer and receiver ofits operating personnel that issue and
receive an oral or written Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may be used for internal
operations.
1.3.1.2.
Require the issuer ofits operating personnel that issue an oral two-party,
person-to-person Operating Instruction to wait for a response from the receiver.
Once a response is received, or if no response is received, require the issuer to
take one of the following actions:
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COM-002-4 Operating Personnel Communications Protocols
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect,
if the receiver does not issue a response, or if requested by the receiver.
•
Require the receiver ofTake an alternative action if a response is
not received or if the Operating Instruction was not understood by
the receiver.
1.4.1.3.
Require its operating personnel that receive an oral two-party, personto-person Operating Instruction to take one of the following actions:
•
•
•
Repeat, not necessarily verbatim, the Operating Instruction and wait
forreceive confirmation from the issuer that the repetitionresponse was
correct.
Request that the issuer reissue the Operating Instruction.
Request that the issuer reissue the Operating Instruction.
1.5. Require the issuer of an its operating personnel that issue a written or oral
single-party to multiple-party burst Operating Instruction to verbally or
electronically confirm receipt by at least one receiver when issuingor verify that
the Operating Instruction through awas received by at least one-way burst
messaging system used to communicate a common message to multiple parties
in a short time period (e.g., an all call system).
1.6.1.4.
Require the receiver of an oralthe Operating Instruction to request
clarification from the issuer if the communication is not understood when
receiving the Operating Instruction through a one-way burst messaging system
used to communicate a common message to multiple parties in a short time
period (e.g., an all call system)..
1.7.1.5.
Specify the instances that require time identification when issuing an oral
or written Operating Instruction and the format for that time identification.
1.8.1.6.
Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
2.0. Specify Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall conduct initial training for each of its operating personnel
responsible for the instances where alpha-numeric clarifiers are required
whenReal-time operation of the interconnected Bulk Electric System on the
documented communications protocols developed in Requirement R1 prior to
that individual operator issuing an oral Operating Instruction and the format for
those clarifiers.
R3.R2. Each Distribution Provider and Generator Operator shall have documented
communications protocols. The protocols shall, at a minimum:. [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
2.1. Require the receiver of an oral or written Operating Instruction to respond using
the English language, unless agreed to otherwise. An alternate language may be
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COM-002-4 Operating Personnel Communications Protocols
usedEach Distribution Provider and Generator Operator shall conduct initial
training for internal operations.
2.2.R3. Require the receiver ofeach of its operating personnel who can receive an oral
two-party, person-to-person Operating Instruction prior to that individual operator
receiving an oral two-party, person-to-person Operating Instruction to take one of
the following actions: either: [Violation Risk Factor: Low][Time Horizon: Longterm Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and wait
forreceive confirmation from the issuer that the repetitionresponse was
correct. , or
•
Request that the issuer reissue the Operating Instruction.
2.0. Require the receiver of an oral Operating Instruction to request clarification
from the issuer if the communication is not understood when receiving the
Operating Instruction through a one-way burst messaging system used to
communicate a common message to multiple parties in a short time period (e.g.,
an all call system).
R5.R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall implement the documented communications protocols developed in
Requirement R1. at least once every twelve (12) calendar months: [Violation Risk
Factor: HighMedium][Time Horizon: Real-time Operations] Planning]
Each Distribution Provider and Generator Operator4.1. Assess adherence to the
documented communications protocols in Requirement R1 by its operating
personnel that issue and receive Operating Instructions, provide feedback to
those operating personnel and take corrective action, as appropriate to address
deviations from the documented protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
R6.R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
that issues an oral two-party, person-to-person Operating Instruction during an
Emergency, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall implement the documented communications protocols developed
in Requirement R2.either: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
•
Confirm the receiver’s response if the repeated information is correct (in
accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
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COM-002-4 Operating Personnel Communications Protocols
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
implement a method to evaluate the communications protocols developed in
Requirement R1 that: [Violation Risk Factor: Low][Time Horizon: Operations
Planning]
R7. 5.1.
Assesses adherence to the communications protocolsthat issues a written
or oral single-party to provide feedback to issuers and receiversmultiple-party burst
Operating Instruction during an Emergency shall confirm or verify that the Operating
Instruction was received by at least one receiver of Operating Instructions. the
Operating Instruction. [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
5.2. Assesses the effectiveness of the communications protocols and modifies those
protocols, as necessary.
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M2.M3. Each Distribution Provider and Generator Operator shall provide its documented
communications protocols developed for Requirement R2.initial training records for its
operating personnel such as attendance logs, agendas, learning objectives, or course
materials in fulfillment of Requirement R3.
M3.M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator
shall provide evidence that it implemented the documented communication protocols
which may include, but is not limited to, descriptions of the management practices in
place that provide the entity reasonable assurance that protocols established in
Requirement R1 are being followed by personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System,
spreadsheets, memos, or logs, evidencing periodic, independent review of operating
personnel’s adherence to the protocols established in Requirement R1 and the
remediation of noted exceptions in fulfillment of Requirement R5of its assessments,
including spreadsheets, logs or other evidence of feedback, findings of effectiveness
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COM-002-4 Operating Personnel Communications Protocols
and any changes made to its documented communications protocols developed for
Requirement R1 in fulfillment of Requirement R4. The entity shall provide evidence
that it took appropriate corrective actions as part of its assessment for all instances
where an operating personnel’s non-adherence to the protocols developed in
Requirement R1 is the sole or partial cause of an Emergency and for all other instances
where the entity determined that it was appropriate to take a corrective action to
address deviations from the documented protocols developed in Requirement R1.
M4. Each Distribution Provider and Generator Operator shall provide evidence that it
implemented the documented communication protocols which may include, but is not
limited to, descriptions of the management practices in place that provide the entity
reasonable assurance that protocols established in Requirement R2 are being followed
by personnel responsible for the real-time generation control and operation of the
interconnected Bulk Electric System, spreadsheets, memos, or logs, evidencing
periodic, independent review of operating personnel’s adherence to the protocols
established in Requirement R2.
M5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide descriptions and associated evidence of the management practices in place that
demonstrate a review of communications with operating personnel responsible for the
real-time generation control and operation of the interconnected Bulk Electric System
and evidence that the entity evaluates the effectiveness of its documented
communications protocols in fulfillment of Requirement R5.Each Reliability
Coordinator, Transmission Operator, and Balancing Authority that issued an oral twoparty, person-to-person Operating Instruction during an Emergency, excluding oral
single-party to multiple-party burst Operating Instructions, shall have evidence that the
issuer either: 1) confirmed that the response from the recipient of the Operating
Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings, or dated and time-stamped transcripts of voice recordings, or
dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings dated operator logs, an
attestation from the issuer of the Operating Instruction, voice recordings (if the entity
has such recordings), memos or transcripts.
M5.M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator
that issued a written or oral single or multiple-party burst Operating Instruction during
an Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timeDraft 7
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COM-002-4 Operating Personnel Communications Protocols
stamped voice recordings, dated operator logs, electronic records, voice recordings (if
the entity has such recordings), memos or transcripts.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
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COM-002-4 Operating Personnel Communications Protocols
1.3. Additional Compliance Information
None
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Page 10 of
COM-002-4 Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible
entity did not specify
the instances that
require time
identification when
issuing an oral or
written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.75
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.21. An
alternate language may be
used for internal
operations.
The responsible entity did
not include Requirement
R1, Part 1.54 in its
documented
communication protocols.
OR
The responsible entity did
not include Requirement
R1, Part 1.6 in its
documented
communications
protocols.
OR
The responsible
entity did not specify
the nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.86.
Posting 8
The responsible entity did not
include Requirement R1, Part
1.12 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.4 in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
OR
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October 21, 2013January 2, 2014
Severe VSL
Page 11 of 19
COM-002-4 Operating Personnel Communications Protocols
The responsible
entity did not specify
the instances where
alpha-numeric
clarifiers are required
when issuing an oral
Operating Instruction
and the format for
those clarifiers, as
required in
Requirement R1, Part
1.9.
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R2
Long-term
Planning
Low
Draft 7
October 21, 2013January 2, 2014
N/A
Posting 8
Moderate VSL
High VSL
Severe VSL
The responsible entity did
not require the receiver of
an oral or written
Operating Instruction to
use the English language,
unless agreed to
otherwise, as required in
Requirement R2, Part 2.1.
An alternate language
may be used for internal
operations. N/A
TheAn individual
operator responsible for
the Real-time operation of
the interconnected Bulk
Electric System at the
responsible entity did not
include Requirement R2,
Part 2.3 in itsissued an
Operating Instruction,
prior to being trained on
the documented
communicationcommunic
TheAn individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity did not
include Requirement R2, Part
2.2 in itsissued an Operating
Instruction during an
Emergency prior to being
trained on the documented
communications protocols
developed in Requirement R1.
Page 12 of 19
COM-002-4 Operating Personnel Communications Protocols
R3
Real-time
Operations
Long-term
Planning
HighLo
w
N/A
N/A
ations protocols
developed in Requirement
R1.
OR
The An individual
operator at the responsible
entity demonstrates a
consistent pattern of not
using the documented
communications protocols
developed in Requirement
R1 forreceived an
Operating Instructions
The responsible entity did not
use the documented
communications protocols
developed in Requirement R1
when issuing or receiving a
Reliability Directive.
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R2.
that are not Reliability
Directives.Instruction
prior to being trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
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October 21, 2013January 2, 2014
Posting 8
Page 13 of 19
COM-002-4 Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Real-time
Operations
HighMe
dium
Planning
N/AThe responsible
entity assessed
adherence to the
documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive
Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible
entity assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive
Operating
Instructions and
modified its
Draft 7
October 21, 2013January 2, 2014
Posting 8
Moderate VSL
High VSL
N/AThe responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions,
but did not provide
feedback to those
operating personnel
The responsible entity
demonstrates a consistent
pattern of did not
usingassess adherence to
the documented
communications protocols
developed in Requirement
R2 for in Requirements
R1 by its operating
personnel that issue and
receive Operating
Instructions that are
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
and provided feedback to
those operating personnel
but did not take corrective
action, as appropriate
OR
The responsible entity did
not Reliability
Directivesassess the
effectiveness of its
documented
communications protocols
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
Page 14 of 19
Severe VSL
The responsible entity did not
useassess adherence to the
documented communications
protocols developedin
Requirements R1 by its
operating personnel that issue
and receive Operating
Instructions
AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R2
when receiving a Reliability
Directive.R1 for its operating
personnel that issue and receive
Operating Instructions.
COM-002-4 Operating Personnel Communications Protocols
documented
communication
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Draft 7
October 21, 2013January 2, 2014
Posting 8
Moderate VSL
High VSL
Page 15 of 19
Severe VSL
COM-002-4 Operating Personnel Communications Protocols
protocols, as
necessary
AND
The responsible
entity exceeded
twelve (12) calendar
months between
assessments.
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Draft 7
October 21, 2013January 2, 2014
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions,
but did not modify its
documented
communication protocols,
as necessary.
Posting 8
Moderate VSL
High VSL
Page 16 of 19
Severe VSL
COM-002-4 Operating Personnel Communications Protocols
R5
Real-time
Operations
Planning
LowHig
h
N/A
N/AThe responsible entity
that issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
R#
Time
Horizon
VRF
The responsible entity that
issued an Operating Instruction
during an Emergency did not
implement a method for
evaluating its communications
protocols as specified take one
of the following actions:
Confirmed the
receiver’s response
if the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating
Instruction if the
repeated information
was incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or
if the Operating
Instruction was not
understood by the
receiver.
•
Confirmed the receiver’s
response if the repeated
information was correct
(in accordance with
Requirement R5R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the
Operating Instruction was
not understood by the
receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Violation Severity Levels
Lower VSL
Draft 7
October 21, 2013January 2, 2014
N/A
Posting 8
Moderate VSL
High VSL
Page 17 of 19
Severe VSL
COM-002-4 Operating Personnel Communications Protocols
R6
Real-time
Operations
High
N/A
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request
that the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
N/A
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer
that the response was correct, or
request that the issuer reissue
the Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or
oral single-party to
multiple-party burst
Operating Instruction
during an Emergency did
not confirm or verify that
the Operating Instruction
was received by at least
one receiver of the
Operating Instruction.
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Draft 7
October 21, 2013January 2, 2014
Posting 8
Page 18 of 19
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COM-002-4 Operating Personnel Communications Protocols
E. Regional Variances
None.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
Draft 7
19
October 21, 2013January 2, 2014
Posting 8
Page 19 of
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
• COM-002-4 – Operating Personnel Communications Protocols
Retirements:
• COM-001-1.1 Requirement R4 – Telecommunications
• COM-002-2 – Communication and Coordination
• COM-002-3 – Communication and Coordination
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real-time operation of the interconnected Bulk
Electric System to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A discussion of general information and of
potential options or alternatives to resolve Bulk Electric System operating concerns is not a command
and is not considered an Operating Instruction.)
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
None
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Effective Date
COM-002-4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM-001-1.1 Requirement R4, COM-002-2, and COM-002-3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM-002-4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
• COM-002-4 – Operating Personnel Communications Protocols
Retirements:
• COM-001-1.1 Requirement R4 – Telecommunications
• COM-002-2 – Communication and Coordination
• COM-002-3 – Communication and Coordination
Prerequisite Approvals
None
Approval of the definition of “Reliability Directive”
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real-time generation control and operation of
the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System operating concerns
is not a command and is not considered an Operating Instruction.) . A Reliability Directive is one type
of an Operating Instruction.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
None
Effective Date
COM-002-4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM-001-1.1 Requirement R4, COM-002-2, and COM-002-3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM-002-4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT Reliability Standard Audit Worksheet1
COM-002-4 – Operating Personnel Communications Protocols
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s) 2:
Compliance Monitoring Method:
Names of Auditors:
Applicability of Requirements
R1
R2
R3
R4
R5
R6
R7
BA
X
X
X
X
X
X
DP
GO
X
X
X
X
GOP
IA
Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
Audit
Supplied by CEA
LSE
PA
PSE
RC
X
X
RP
RSG
TO
TOP
X
X
X
X
X
X
X
X
TP
TSP
1
NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered
entity’s compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW
should choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the
methodology that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a
substitute for the Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language
contained in the Reliability Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability
Standards can be found on NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the
same frequency. Therefore, it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability
Standard. It is the responsibility of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable
governmental authority, relevant to its registration status.
The NERC RSAW language contained within this document provides a non-exclusive list, for informational purposes only, of examples of the types of evidence a
registered entity may produce or may be asked to produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples
contained within this RSAW does not necessarily constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW
reserves the right to request additional evidence from the registered entity that is not included in this RSAW. Additionally, this RSAW includes excerpts from FERC
Orders and other regulatory references. The FERC Order cites are provided for ease of reference only, and this document does not necessarily include all applicable
Order provisions. In the event of a discrepancy between FERC Orders, and the language included in this document, FERC Orders shall prevail.
2
Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
Subject Matter Experts
Identify Subject Matter Expert(s) responsible for this Reliability Standard. (Insert additional rows if necessary)
Registered Entity Response (Required):
SME Name
Title
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
2
Organization
Requirement(s)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
R1 Supporting Evidence and Documentation
R1.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop
documented communications protocols for its operating personnel that issue and receive
Operating Instructions. The protocols shall, at a minimum:
1.1. Require its operating personnel that issue and receive an oral or written Operating Instruction
to use the English language, unless agreed to otherwise. An alternate language may be used
for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
•
•
•
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect or if requested
by the receiver.
Take an alternative action if a response is not received or if the Operating Instruction
was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive confirmation
from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to multiple-party
burst Operating Instruction to confirm or verify that the Operating Instruction was received
by at least one receiver of the Operating Instruction.
1.5. Specify the instances that require time identification when issuing an oral or written
Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and Transmission interface
Facilities when issuing an oral or written Operating Instruction.
Definition of Operating Instruction
A command by operating personnel responsible for the Real-time operation of the interconnected
Bulk Electric System to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general information and
of potential options or alternatives to resolve Bulk Electric System operating concerns is not a
command and is not considered an Operating Instruction.)
M1.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide its
documented communications protocols developed for Requirement R1.
Registered Entity Response to General Compliance with this Requirement (Required):
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 3:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
A copy of the documented communication protocols that cover the Requirements outlined in Requirement R1
Parts 1.1 to 1.6.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM-002-4, R1
This section to be completed by the Compliance Enforcement Authority
Review the documented communications protocols provided by entity and ensure they address the Parts
of R1 as follows:
(1.1) Requires its operating personnel that issue and receive an oral or written Operating Instruction to
use the English language, unless agreed to otherwise. An alternate language may be used for
internal operations.
(1.2) Requires its operating personnel that issue an oral two-part, person-to-person Operating
Instruction to take one of the following actions: confirm the receiver’s response if the repeated
information is correct, reissue the Operating Instruction if the repeated information is incorrect or
if requested by the receiver, or take an alternative action to issue a new or the same Operating
Instruction if the receiver does not respond.
(1.3) Requires its operating personnel that receive an oral two-party, person-to-person Operating
Instruction to take one of the following actions: repeat, not necessarily verbatim, the Operating
3
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
(1.4)
(1.5)
(1.6)
Instruction and receive confirmation from the issuer that the response was correct, or request that
the issuer reissue the Operating Instruction.
Requires its operating personnel that issue a written or oral single-party to multiple-party burst
Operating Instruction to confirm or verify that the Operating Instruction was received by at least
one receiver of the Operating Instruction.
Specifies the instances that require time identification when issuing an oral or written Operating
Instruction and the format for that time identification.
Specifies the nomenclature for Transmission interface Elements and Transmission interface
Facilities when issuing an oral or written Operating Instruction.
Note to Auditor:
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
R2 Supporting Evidence and Documentation
R2.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall conduct initial
training for each of its operating personnel responsible for the Real-time operation of the
interconnected Bulk Electric System on the documented communications protocols developed in
Requirement R1 prior to that individual operator issuing an Operating Instruction.
M2.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide training
records related to its documented communications protocols developed for Requirement R1 such as
attendance logs, agendas, learning objectives, or course materials in fulfillment of Requirement R2.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 4:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Copies of dated attendance logs, agendas, learning objectives, or course materials as outlined in M2.
Organization chart or similar artifact identifying the operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System and the date such personnel began operating the Realtime Bulk Electric System.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
4
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
Compliance Assessment Approach Specific to COM-002-4, R2
This section to be completed by the Compliance Enforcement Authority
Verify applicable operating personnel, or a sample thereof, received the required training prior to the date
they began operating the Real-time Bulk Electric System by agreeing selected personnel names to training
records.
Note to Auditor: Requirement R2 requires only initial training; continuing training is not required.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
R3 Supporting Evidence and Documentation
R3.
Each Distribution Provider and Generator Operator shall conduct initial training for each of its
operating personnel who can receive an oral two-party, person-to-person Operating Instruction
prior to that individual operator receiving an oral two-party, person-to-person Operating
Instruction to either:
•
Repeat, not necessarily verbatim, the Operating Instruction and receive confirmation from
the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
M3. Each Distribution Provider and Generator Operator shall provide its initial training records for its
operating personnel such as attendance logs, agendas, learning objectives, or course materials in
fulfillment of Requirement R3.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 5:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Copies of dated attendance logs, agendas, learning objectives, or course materials as outlined in M3.
Organization chart or similar artifact identifying the operating personnel who can receive an oral two-party,
person-to-person Operating Instruction and the date such personnel began receiving such instructions.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
5
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
DRAFT NERC Reliability Standard Audit Worksheet
Compliance Assessment Approach Specific to COM-002-4, R3
This section to be completed by the Compliance Enforcement Authority
Verify applicable operating personnel, or a sample thereof, received the required training prior to the date
they began receiving oral two-party, person-to-person Operating Instructions by agreeing selected
personnel names to training records.
Note to Auditor: Requirement R3 requires only initial training; continuing training is not required.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
9
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DRAFT NERC Reliability Standard Audit Worksheet
R4 Supporting Evidence and Documentation
R4.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall, at least once
every twelve (12) calendar months:
4.1. Assess adherence to the documented communications protocols in Requirement R1 by its
operating personnel that issue and receive Operating Instructions, provide feedback to those
operating personnel and take corrective action as appropriate to address deviations from the
documented protocols.
4.2. Assess the effectiveness of its documented communications protocols in Requirement R1 for
its operating personnel that issue and receive Operating Instructions and modify its
documented communication protocols, as necessary.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide
evidence of its assessments, including spreadsheets, logs or other evidence of feedback, findings of
effectiveness and any changes made to its documented communications protocols developed for
Requirement R1 in fulfillment of Requirement R4. The entity shall provide evidence that it took
appropriate corrective actions as part of its assessment or all instances where an operating
personnel’s non-adherence to the protocols developed in Requirement R1 is the sole or partial cause
of an Emergency, and for all other instances where the entity determined that it was appropriate to
take a corrective action to address deviations from the documented protocols developed in
Requirement R1.
Definition of Emergency
Any abnormal system condition that requires automatic or immediate manual action to prevent or
limit the failure of transmission facilities or generation supply that could adversely affect the
reliability of the Bulk Electric System.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 6:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
(4.1) Dated spreadsheets, logs, or other evidence of assessment and feedback of operating personnel as
outlined in M4.
6
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
10
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DRAFT NERC Reliability Standard Audit Worksheet
(4.2) Revisions made to documented communications protocols based on assessments, or minutes of
meetings or others summaries evidencing the effectiveness of documented protocols were assessed.
A list or log of corrective actions taken in response to Emergencies occurring on the entity’s system due to
non-adherence to documented communications protocols during the audit period.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM-002-4, R4
This section to be completed by the Compliance Enforcement Authority
(4.1) Review evidence to gain reasonable assurance that an assessment of operating personnel issuing
and receiving Operating Instructions adherence to the documented protocols established in Requirement
R1 occurred every twelve months during the audit period. Verify assessment or another artifact includes
evidence such as annotations or summaries of providing feedback and taking corrective action, as
necessary, in accordance with the requirement.
(4.2) Review evidence such as document revisions, meetings minutes, or other summaries to gain
reasonable assurance that the effectiveness of documented communications protocols in Requirement R1
was assessed every twelve months during the audit period.
For Emergencies, occurring on the entity’s system, or a sample thereof, assess whether or not an
operating personnel’s non-adherence to the documented protocols was the partial or sole cause of the
Emergency and if so, verify entity took appropriate corrective actions by reviewing summaries, meeting
minutes, or the like, outlining corrective actions taken.
Note to Auditor: Auditors can use their general knowledge of the entity’s system, discussions with other
Regional Entity/NERC personnel, and discussions with entity personnel to gain an awareness of Emergencies
resulting potentially from non-adherence to communications protocols. Such Emergency events can then be
reviewed during an audit to determine, if the Emergency was indeed attributable to an instance of nonadherence to communications protocols ,that corrective action was taken.
The extent of audit procedures applied related to this requirement will vary depending on certain risk factors
to the Bulk Electric System. In general, more extensive audit procedures will be applied where risks to the Bulk
Electric System are determined by the auditor to be higher for non-compliance with this requirement.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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Based on the auditor’s assessment of risk, as described above, specific audit procedures applied for this
requirement may range from exclusion of this requirement from audit scope to the auditor reviewing, in
accordance with the above Compliance Assessment Approach, evidence associated with the entity’s responses
to numerous Emergencies.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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R5 Supporting Evidence and Documentation
R5.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator that issues an oral
two-party, person-to-person Operating Instruction during an Emergency, excluding written or oral
single-party to multiple-party burst Operating Instructions, shall either:
•
Confirm the receiver’s response if the repeated information is correct (in accordance
with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect or if requested
by the receiver.
•
Take an alternative action if a response is not received or if the Operating Instruction
was not understood by the receiver.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that issued an oral
two-party, person-to-person Operating Instruction during an Emergency, excluding oral singleparty to multiple-party burst Operating Instructions, shall have evidence that the issuer either: 1)
confirmed that the response from the recipient of the Operating Instruction was correct; 2)
reissued the Operating Instruction if the repeated information was incorrect or if requested by the
receiver; or 3) took an alternative action if a response was not received or if the Operating
Instruction was not understood by the receiver. Such evidence could include, but is not limited to,
dated and time-stamped voice recordings, or dated and time-stamped transcripts of voice
recordings, or dated operator logs in fulfillment of Requirement R5.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 7:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Dated and time-stamped voice recordings or transcripts of such voice recordings or operator logs, as described
in M5.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
7
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
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Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM-002-4, R5
This section to be completed by the Compliance Enforcement Authority
Review evidence and determine for Operating Instructions issued during an Emergency the entity
confirmed the receiver’s response if the repeated information was correct (in accordance with
Requirement R6), reissued the Operating Instruction if the repeated information was not correct or if
requested by the receiver, and took alternative action to issue a new or the same Operating Instruction if
the receiver did not respond.
Note to Auditor: Auditors can use their general knowledge of the entity’s system, discussions with other
Regional Entity/NERC personnel, and discussions with entity personnel to gain an awareness of Emergencies
resulting potentially from non-adherence to Requirement R5. Such Emergency events can then be reviewed
during an audit to determine if the evidence indicates the entity complied with Requirement R5 in issuing
Operating Instructions during the Emergency.
The extent of audit procedures applied related to this requirement will vary depending on certain risk factors
to the Bulk Electric System. In general, more extensive audit procedures will be applied where risks to the Bulk
Electric System are determined by the auditor to be higher for non-compliance with this requirement.
Based on the auditor’s assessment of risk, as described above, specific audit procedures applied for this
requirement may range from exclusion of this requirement from audit scope to the auditor reviewing, in
accordance with the above Compliance Assessment Approach, evidence associated with the entity’s responses
to numerous Operating Instructions issued during Emergencies.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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R6 Supporting Evidence and Documentation
R6.
Each Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator
that receives an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding written or oral single-party to multiple-party burst Operating Instructions, shall either:
•
Repeat, not necessarily verbatim, the Operating Instruction and receive confirmation from
the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator
that was the recipient of an oral two-party, person-to-person Operating Instruction during an
Emergency, excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence to show that the recipient either repeated, not necessarily verbatim, the Operating
Instruction and received confirmation from the issuer that the response was correct, or requested
that the issuer reissue the Operating Instruction in fulfillment of Requirement R6. Such evidence
may include, but is not limited to, dated and time-stamped voice recordings, dated operator logs,
an attestation from the issuer of the Operating Instruction, voice recordings (if the entity has such
recordings), memos or transcripts.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 8:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Dated operator logs, voice recordings, memos, or transcripts, or other evidence (per M6) describing the
entity’s response to Operating Instructions received during an Emergency selected by the auditor.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
8
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
Compliance Assessment Approach Specific to COM-002-4, R6
This section to be completed by the Compliance Enforcement Authority
Review evidence and determine for Operating Instructions received during an Emergency entity repeated,
not necessarily verbatim, the Operating Instruction and received confirmation from the issuer that the
response was correct, or requested that the issuer reissue the Operating Instruction.
Note to Auditor: Auditors can use their general knowledge of the entity’s system, discussions with other
Regional Entity/NERC personnel, and discussions with entity personnel to gain an awareness of Emergencies
resulting potentially from non-adherence to Requirement R6. Such Emergency events can then be reviewed
during an audit to determine if the evidence indicates the entity complied with Requirement R6 for Operating
Instructions received during the Emergency.
The extent of audit procedures applied related to this requirement will vary depending on certain risk factors
to the Bulk Electric System. In general, more extensive audit procedures will be applied where risks to the Bulk
Electric System are determined by the auditor to be higher for non-compliance with this requirement.
Based on the auditor’s assessment of risk, as described above, specific audit procedures applied for this
requirement may range from exclusion of this requirement from audit scope to the auditor reviewing, in
accordance with the above Compliance Assessment Approach, evidence associated with the entity’s responses
to numerous Operating Instructions received during Emergencies.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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R7 Supporting Evidence and Documentation
R7.
Each Balancing Authority, Reliability Coordinator, and Transmission Operator that issues a written
or oral single-party to multiple-party burst Operating Instruction during an Emergency shall
confirm or verify that the Operating Instruction was received by at least one receiver of the
Operating Instruction.
M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator that issued a written
or oral single or multiple-party burst Operating Instruction during an Emergency shall provide
evidence that the Operating Instruction was received by at least one receiver. Such evidence may
include, but is not limited to, dated and time-stamped voice recordings, dated operator logs,
electronic records, voice recordings (if the entity has such recordings), memos or transcripts.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in
your own words, of how you meet compliance with this Requirement. References to supplied evidence,
including links to the appropriate page, are recommended.
Evidence Requested 9:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
Dated operator logs, voice recordings, memos, or transcripts, as described in M5 and for Emergencies
requested by the auditor.
Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), and Description.
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.
Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):
9
Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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Compliance Assessment Approach Specific to COM-002-4, R7
This section to be completed by the Compliance Enforcement Authority
Review evidence and determine entity confirmed or verified that the multiple-party burst Operating
Instruction was received by at least one receiver of the Operating Instruction.
Note to Auditor: Auditors can use their general knowledge of the entity’s system, discussions with other
Regional Entity/NERC personnel, and discussions with entity personnel to gain an awareness of Emergencies
resulting potentially from non-adherence to Requirement R7. Such Emergency events can then be reviewed
during an audit to determine if the evidence indicates the entity complied with Requirement R7 when issuing
written or oral burst Operating Instructions during the Emergency.
The extent of audit procedures applied related to this requirement will vary depending on certain risk factors
to the Bulk Electric System. In general, more extensive audit procedures will be applied where risks to the Bulk
Electric System are determined by the auditor to be higher for non-compliance with this requirement.
Based on the auditor’s assessment of risk, as described above, specific audit procedures applied for this
requirement may range from exclusion of this requirement from audit scope to the auditor reviewing
evidence, in accordance with the above Compliance Assessment Approach, associated with the entity’s
responses to numerous burst Operating Instructions issued during Emergencies.
Auditor Notes:
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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Revision History
Version
1
Date
10/2013
2
1/2/2014
Reviewers
NERC Compliance,
Standards
NERC Compliance,
Standards
Revision Description
New Document
Revised to reflect revisions to Reliability
Standard language
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_COM-002-4_2013_v2 Revision Date: January, 2014
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Unofficial Comment Form
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
Please DO NOT use this form. Please use the electronic comment form to submit comments on the
proposed draft COM-002-4 (Operating Personnel Communications Protocols) standard. Comments
must be submitted by January 31, 2014. If you have questions please contact Stephen Eldridge by email
or by telephone at 404-446-9686.
http://www.nerc.com/pa/Stand/Pages/Op_Comm_Protocol_Project_2007-02.aspx
Background Information:
Effective communication is critical for Bulk Electric System (BES) operations. Failure to successfully
communicate clearly can create misunderstandings resulting in improper operations increasing the
potential for failure of the BES. The eighth posting of Project 2007-02 is a continuation of the previous
draft which combined COM-002-3 and COM-003-1 into one standard titled COM-002-4 that addresses
communications protocols for operating personnel in Emergency, alert, and non-emergency situations.
The Standard Authorization Request (SAR) for this project was initiated on March 1, 2007 and approved
by the Standards Committee on June 8, 2007. It established the scope of work for Project 2007-02
Operating Personnel Communications Protocols (OPCP). The scope described in the SAR is to establish
essential elements of communications protocols and communications paths such that operators and
users of the North American BES will efficiently convey information and ensure mutual understanding.
The August 2003 Blackout Report, Recommendation Number 26, calls for a tightening of
communications protocols. Federal Energy Regulatory Commission (FERC) Order 693 paragraph 532
reiterates this need. This proposed standard’s goal is to ensure that effective communication is
practiced and delivered in clear and consistent language.
The standard will be applicable to Transmission Operators, Balancing Authorities, Reliability
Coordinators, Generator Operators, and Distribution Providers. These requirements ensure that
communications include essential elements such that information is efficiently conveyed and mutually
understood for communicating Operating Instructions.
The Purpose statement of COM-002-4 states: “To improve communications for the issuance of
Operating Instructions with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the Bulk Electric
System (BES).”
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1) New NERC Glossary term: The OPCP Standards Drafting Team (SDT) revised the definition of
Operating Instruction from its previous drafts. The current definition reads “A command by
operating personnel responsible for the Real-time operation of the interconnected Bulk Electric
System to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A discussion of general information and
of potential options or alternatives to resolve Bulk Electric System operating concerns is not a
command and is not considered an Operating Instruction.)” The Project 2007-02 SDT removed
the term “Reliability Directive” in order to avoid complications that may result from the Notice
of Proposed Rulemaking issued by the Federal Energy Regulatory Commission on November 21,
2013 proposing to remand the definition of “Reliability Directive.” COM-002-4 uses the defined
term “Operating Instruction” to define the circumstances when documented communications
protocols must be used. This term is proposed for addition to the North American Electric
Reliability Corporation (NERC) Glossary to establish meaning and usage within the electricity
industry.
2) Project 2007-02, Posting 8 continues to combine COM-002-3 and COM-003-1 into COM-002-4.
The OPCP SDT combined COM-002-3 and COM-003-1 in posting 7 into one standard in order to
simplify communications protocols for operating personnel. This construct has been
maintained in the posting 8 draft. The OPCP SDT determined that one communications
protocols standard that addresses Emergency, alert, and non-emergency situations will improve
communications because system operators will not need to refer to a different set of protocols
during an emergency situation. The OPCP SDT believes this will improve consistency of
communications and mitigate confusion during stressful emergency situations. The OPCP SDT
decided to combine the standards under the title COM-002-4 to further reduce confusion. The
COM-002-4 title keeps the numbering of COM standards consecutive (e.g., COM-001, COM002).
3) Project 2007-02, Posting 8 features 7 requirements. The The OPCP SDT developed the
requirement structure and language in posting 8 to incorporate Emergency, alert, and nonemergency communications protocols. The language in COM-002-4, Requirement R1 permits
applicable entities flexibility to develop their communication protocols but requires a set of
minimum elements in the communications protocols. Requirement R1 requires
communications protocols to include the following elements:
a. English Language: Requirement R1, Part 1.1 – Require the issuer and receiver of an oral
or written Operating Instruction to use the English language, unless agreed to
otherwise. An alternate language may be used for internal operations.
b. Three-part Communication for Oral Operating Instructions: Requirement R1, Parts 1.2
and 1.3 – Require three-part communication for issuers and receivers of oral two-party,
person-to-person Operating Instructions.
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | January 2014
2
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c. One-way Burst Message Receipt Confirmation and Clarification: Requirement R1, Part
1.4– Requires the issuer of a written or oral single-party to multiple-party burst
Operating Instruction to verbally or electronically confirm receipt by at least one
receiver of the Operating Instruction. Time Identification: Requirement R1, Part 1.5 –
Specify the instances that require time identification when issuing an oral or written
Operating Instruction and the format for that time identification.
d. Transmission Interface Elements and Facilities Nomenclature: Requirement R1, Part 1.6
– Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
Requirements R2 and R3 require each Balancing Authority, Reliability Coordinator,
Transmission Operator, Distribution Provider and Generator Operator to conduct initial
training for operating personnel who can issue and/or receive Operating Instructions . These
requirements mandate that before operating personnel can issue or receive an Operating
Instruction, the operating personnel in question must receive the training listed in the
respective requirement.
Requirement R4 mandates a feedback loop for each Balancing Authority, Reliability
Coordinator, and Transmission Operator, where the entity must assess the adherence of its
operating personnel to the communication protocols the entity developed (with appropriate
corrective actions) as well as assess the effectiveness of its documented communication
protocols for its operating personnel that issue Operating Instructions.
Requirements R5 and R6 require the use of three part communication during Emergency
conditions without exception, per the November 13, 2013 NERC Board of Trustees resolution.
Requirement R7 requires each Balancing Authority, Reliability Coordinator, and Transmission
Operator that issues a written or oral single-party to multiple-party burst Operating Instruction to
confirm the receipt of that Operating Instruction by at least one receiver.
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | January 2014
3
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The OPCP SDT is posting the standard for industry comment for a 30-day comment period. The OPCP
SDT received a waiver of the 45-day comment period required in the NERC Standards Process Manual
from the NERC Standards Committee on December 11, 2013. Accordingly, we request that you include
your comments on the electronic form by January 31, 2014.
Questions
1. Do you agree that that the COM-002-4 standard addresses addresses the NERC Board of
Trustees November 19th, 2013 Resolution? If not, please explain in the comment area?
Yes
No
Comments:
2. Do you agree that COM-002-4 addresses the August 2003 Blackout Report
Recommendation number 26, and FERC Order 693? If not, please explain in the
comment area.
Yes
No
Comments:
3. Do you agree with the VRFs and VSLs for the Requirements? If not, please
explain.
Yes
No
Comments:
4. Do you have any additional comments? Please provide them here.
Yes
No
Comments:
Unofficial Comment Form
Project 2007-02 OPCP COM-002-4 | January 2014
4
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Project 2007-02, COM-002-4 Operating
Personnel Communications Protocols
Rationale and Technical Justification
Background and Justification for COM-002-4 Requirements
The purpose of the proposed COM-002-4 Reliability Standard is to improve communications for
the issuance of Operating Instructions with predefined communications protocols to reduce the
possibility of miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES). The proposed Reliability Standard combines COM-002-3 and former draft
COM-003-1 into one standard that addresses communications protocols for operating personnel in
Emergency, alert and non-emergency conditions. The Operating Personnel Communications Protocols
Standard Drafting Draft (OPCP SDT) believes that one communications protocols standard that
addresses emergency and non-emergency situations will improve communications because operating
personnel will not need to refer to a different set of protocols during the different operating conditions.
A single standard will improve consistency of communications and mitigate confusion during stressful
emergency situations. As a result of the combination, the standard has been numbered as COM-002-4 to
maintain the consecutive numbering of the standards (e.g., COM-001, COM-002) since the combined
standard will replace COM-002-2 and COM-002-3, where necessary.
In preparing COM-002-4, the OPCP SDT considered industry comments and also drew from a
variety of other resources including:
•
•
•
•
1
the NERC Board of Trustees’ November 7th, 2013 Resolution for Operating Personnel
Communication Protocols, discussed below; 1
a survey distributed to a sample of industry experts by the Director of Standards Development
and the Standards Committee Chair requesting feedback on the draft standard in posting 8;
consultation on the use of the term “Reliability Directive” in the COM-002-4 standard with the
Project 2007-03 Real-time Transmission Operations Standard Drafting Team and the Project
2006-06 Reliability Coordination Standard Drafting Team; and
a full-day “Communications in Operations” technical conference held February 14-15, 2013 to
gather industry input on a consensus communications standard approach.
Resolution for Agenda Item 8.i: Operating Personnel Communication Protocols, NERC Board of Trustees Meeting,
Nov. 7, 2013, available at:
http://www.nerc.com/gov/bot/Board%20of%20Trustees%20Quarterly%20Meetings/Board%20COM%20Resolution%2011.7
.13%20v1%20AS%20APPROVED%20BY%20BOARD.pdf.
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Structure of the COM-002-4 Draft
In response to the Board of Trustees direction to draft a combined COM-002 and COM-003
standard that addresses, at a minimum certain protocols, NERC staff prepared a “strawman” draft
standard and provided it as a starting point for the standard drafting team to edit and adjust as it deemed
appropriate. The structure of posting 8 of COM-002-4 reflects the minimum elements listed by the
Board in its resolution (see below for detail on the Board resolution). The structure also allows for the
implementation of a compliance/enforcement approach also described by the Board’s resolution that
maintains the current requirement that entities should be accountable for incorrect use of communication
protocols in connection with emergency communications, without exception.
In COM-002-4, the same protocols are required to be used in connection with the issuance of
Operating Instructions for all operating conditions – i.e. non-emergency, alert, and Emergency
communications. However, the standard uses the phrase “Operating Instruction during an Emergency”
in certain Requirements (R5, R6, R7) to provide a demarcation for what is subject to a zero-tolerance
compliance/enforcement approach and what it not. This is necessary to allow the creation of Violation
Severity Levels for each compliance/enforcement approach. Where “Operating Instruction during an
Emergency” is not used, an entity will be assessed under a non-zero tolerance compliance/enforcement
approach that focuses on whether an entity met the initial training Requirement (either R2 or R3) and/or
whether an entity performed the assessment and took corrective actions according to Requirement R4.
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Their use is measured for compliance/enforcement differently using the operating
condition as an indicator of which compliance/enforcement approach applies.
For example, an entity should expect its operating personnel that issue and receive Operating
Instructions to use the documented communication protocols for all Operating Instructions. The way
that they reinforce that with its operating personnel is through training, assessing adherence by its
operating personnel to the documented communication protocols and providing feedback those
operating personnel on their use of the protocols. During Emergencies, operating personnel must use the
communication protocol without exception, since clear communication is essential to providing swift
and coordinated response to events that are directly impacting the reliability of the BES.
Definition of “Operating Instruction”
The current draft of COM-002-4 does not include the term “Reliability Directive,” which was
included in previous postings as a subset within the definition of “Operating Instruction.”
Project 2007-02, COM-002-4 Operating Personnel Communications Protocols Rationale and Technical Justification
2
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The proposed definition of “Operating Instruction” in COM-002-4 reads as follows:
A command by operating personnel responsible for the Real-time operation
of the interconnected Bulk Electric System to change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility
of the Bulk Electric System. (A discussion of general information and of
potential options or alternatives to resolve Bulk Electric System operating
concerns is not a command and is not considered an Operating Instruction.)
The OPCP SDT debated whether to remove the term “Reliability Directive” in response to
comments suggesting it should be removed from the definition of “Operating Instruction” and in light of
FERC’s issuance of the TOP/IRO NOPR, which proposes to remand the definition of “Reliability
Directive.” A detailed description of the FERC action is included in the section below titled
“Developments Following Posting 7.”
In order to avoid unnecessary complications, the OPCP SDT consulted on the use of the term
“Reliability Directive” in the COM-002-4 standard with the Project 2007-03 Real-time Transmission
Operations and the Project 2006-06 Reliability Coordination Standard Drafting Teams to ask whether
they believed removal of the term would cause concerns. Both teams agreed that the COM-002-4
standard did not need to require a protocol to identify Reliability Directives as such and that the
definition of Operating Instruction could be used absent the term Reliability Directive in COM-002-4 to
set the protocols. The OPCP SDT ultimately voted to remove the term and incorporate the phrase
“Operating Instruction during an Emergency” in the Requirements where it was needed to preserve the
structure created to ensure that only an Operating Instruction issued during an Emergency is subject to a
zero-tolerance compliance/enforcement approach.
A “command” as used in the definition refers to both oral and written commands by operating
personnel. In the requirements of COM-002-4, the OPCP SDT has specified “oral” or “written” as
needed to define which Operating Instructions are covered by the requirement. The definition continues
to clarify that general discussions are not considered Operating Instructions.
Applicability
In addition to Balancing Authorities, Reliability Coordinators, and Transmission Operators, the
proposed standard applies to Distribution Providers and Generator Operators. The OPCP SDT added
these Functional Entities in the Applicability section because they can be and are on the receiving end of
some Operating Instructions. The OPCP SDT determined that it would leave a gap to not cover them in
a communications standard that addresses operating personnel. The addition of Distribution Providers as
an applicable entity also responds to FERC’s directive in Order No. 693 to add them as applicable
entities to the communications standard.
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Recognizing that Generator Operators and Distribution Providers typically only receive
Operating Instructions, the OPCP SDT proposed that only Requirements R3 and R6 apply to these
Functional Entities. In response to the comments and the NERC Board Resolution, the OPCP SDT
revised the standard to clarify that DPs and GOPs are required to a) train their operators prior to
receiving an Operating Instruction, and b) use three part communication when receiving an Operating
Instruction during an Emergency. In addition, the measures have been revised to show that a DP or
GOP can demonstrate compliance for use of three-part communication when receiving an Operating
Instruction during an Emergency by providing an attestation from the issuer of the Operating Instruction
(i.e., a voice recording is not required). If a DP or GOP never receives an Operating Instruction, no
requirement in COM-002-4 would apply to them. In both Requirements R3 and R6, qualifying language
that discusses the “receipt” of an Operating Instruction is included to make this point clear. This
construct ensures that appropriate entities are trained and able to use three-part communication for
reliability purposes, while seeking to minimize the compliance burden on DPs and GOPs.
Requirements in COM-002-4
Requirement R1
Requirement R1 requires entities that can both issue and receive Operating Instructions to have
documented communications protocols that include a minimum set of elements, outlined in Parts 1.1
through 1.6 of the requirement. Because Operating Instructions affect Facilities and Elements of the
Bulk Electric System, the communication of those Operating Instructions must be understood by all
involved parties, especially when those communications occur between Functional Entities. An EPRI
study reviewed nearly 400 switching mishaps by electric utilities and found that roughly 19% of errors
(generally classified as loss of load, breach of safety, or equipment damage) were due to communication
failures. 2 This was nearly identical to another study of dispatchers from 18 utilities representing nearly
2000 years of operating experience that found that 18% of the operators’ errors were due to
communication problems. 3 The necessary protocols include the use of the English language unless
agreed to otherwise (except for internal operations), protocols for use of a written or oral single-party to
multiple-party burst Operating Instruction, specification of instances that require time identification,
nomenclature for Transmission interface Elements, and three-part communications (including a protocol
for taking an alternate action if a response is not received or if the Operating Instruction was not
understood by the receiver).
The OPCP SDT drafted Requirement R1 to ensure consistency among communications protocols
while also allowing flexibility for entities to develop additional communications protocols. The OPCP
SDT determined that the inclusion of the elements in Parts 1.1 through 1.6 are necessary to improve
communications protocols but are not overly prescriptive. The OPCP SDT determined that this
2
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
3
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University, 1998.
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approach is the best way to promote effective communications while maintaining flexibility for entities
to include additional communications protocols based on its own operating environment.
It should be noted that requiring the use of alphanumeric clarifiers has been removed in this
posting. Several entities have provided the comment that it is unnecessary to include them in a
requirement, and pointed to the fact that the lack of use has not been shown to contribute to any
investigated event. The drafting team agreed to remove the term, and NERC will continue to monitor
events to determine if these clarifiers should be added in a future modification to the standard.
The term documented communication protocols in R1 refers to a set of required protocols
specific to the Functional Entity and the Functional Entities they must communicate with. An entity
should include as much detail as it believes necessary in their documented protocols, but they must
address all of the applicable parts of Requirement R1. Where an entity does not already have a set of
documented protocols that meet the parts of Requirement R1, the entity must develop the necessary
communications protocols. Entities may also adopt the documented protocols of another entity as its
own communications protocols, but the entity must maintain its own set of documented communications
protocols to meet Requirement R1.
On September 19, 2012, the NERC Operating Committee issued a Reliability Guideline entitled:
“System Operator Verbal Communications – Current Industry Practices.” As stated on page one, the
purpose of the Reliability Guideline “. . . is to document and share current verbal BES communications
practices and procedures from across the industry that have been found to enhance the effectiveness of
system operator communications programs.” This guideline serves as an additional source of
information on best practices that entities can draw on in creating the documented communications
protocols.
Each part of Requirement R1 is discussed below:
1.1.
Require its operating personnel that issue and receive an oral or written Operating
Instruction to use the English language, unless agreed to otherwise. An alternate language may
be used for internal operations.
The OPCP SDT has included this part to carry forward the same use of English language
included in COM-001-1.1, Requirement R4. Retirement of this Requirement in COM-001-1.1 was
specifically referred to this Project 2007-02. The requirement continues to permit the issuer and receiver
to use an agreed to alternate language. This has been retained since use of an alternate language on a
case-by-case basis may serve to better facilitate effective communications where the use of English
language may create additional opportunities for miscommunications. Part 1.1 requires the use of
English language when issuing oral or written (e.g. switching orders) Operating Instructions. This
creates a standard language (unless agreed to otherwise) for use when issuing commands that could
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System. It also clarifies that an alternate language can be used internally
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within the organization. The phrase has been modified slightly from the language in COM-001-1.1,
Requirement R4 to incorporate the term “Operating Instruction,” which defines the communications that
require the use of the documented communications protocols.
1.2.
Require its operating personnel that issue an oral two-party, person-to-person Operating
Instruction to take one of the following actions:
•
•
•
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect, if the
receiver does not issue a response, or if requested by the receiver.
Take an alternative if a response is not received or if the Operating Instruction
was not understood by the receiver.
1.3.
Require the receiver of an oral two-party, person-to-person Operating Instruction to take
one of the following actions:
•
Repeat the Operating Instruction and wait for confirmation from the issuer that
the repetition was correct.
•
Request that the issuer reissue the Operating Instruction.
The OPCP SDT has included part 1.2 to require communications protocols for the use of threepart communications for oral two-party, person-to-person Operating Instructions by the issuer. The
OPCP SDT has included part 1.3 to require communications protocols for the use of three-part
communications for oral two-party, person-to-person Operating Instructions by the receiver. This
carries forward the requirement to use three-part communications in COM-002-2 and COM-002-3 and
also adds an option in part 1.2 for the issuer to take an alternative action to resolve the issue if the
receiver does not respond or understand the Operating Instruction. The addition of this third bullet
serves to clarify in the requirement language itself that the issuing entity can take alternate action in lieu
of reissuance if necessary.
The reliability benefits of using three-part communication (Requirement R1, parts 1.2 and 1.3)
are threefold:
1. The removal of any doubt that use of the documented communication protocols is required
when issuing or receiving Operation Instructions. This will reduce the opportunity for
confusion and misunderstanding during all operating conditions.
2. There will be no mental “transition” between protocols when operating conditions shift from
non-emergency to Emergency. The documented communication protocols for the operating
personnel will remain the same during transitions through all conditions.
3. The formal requirement for three-part communication will create a heightened sense of
awareness in operating personnel that the task they are about to execute is critical, and
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recognize the risk to the reliable operation of the BES is increased if the communication is
misunderstood.
1.4.
Require its operating personnel that issue a written or oral single-party to multiple-party
burst Operating Instruction to confirm or verify that the Operating Instruction was received by
at least one receiver of the Operating Instruction.
The OPCP SDT has included this part to require communications protocols for an issuer for the
use of a one-way burst messaging system. The drafting team has included this because the use of threepart communications is not practical when utilizing this type of communication. Therefore, it is
necessary to include a different set of protocols for these situations. In addition, many entities expressed
concern that if one-way burst messaging systems were not addressed, it would imply that three part
communication would be required for all participants. For this reason, the drafting team chose to
address one-way burst messaging systems.
1.5.
Specify the instances that require time identification when issuing an oral or written
Operating Instruction and the format for that time identification.
The OPCP SDT has included this part to add necessary clarity to Operating Instructions to
reduce the risk of mistakes. Clarifying time and time zone (where necessary) contributes to reducing
misunderstandings and reduces the risk of a grave error during BES operations, especially when
communicating across time zones or specifying an action that will take place at a future time. Note that
an action that is to occur immediately would not be required to have time identification, unless the entity
specified that requirement in its communication protocols.
1.6.
Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
Project 2007-03 chose to eliminate TOP-002-2a, Requirement R18 when it developed TOP-002-3. This
Requirement stated “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers when
referring to transmission facilities of an interconnected network.” COM-002-4, while reintroducing the
concept of line identifiers, limits the scope to only Transmission interface Elements or Transmission
interface Facilities (e.g. tie lines and tie substations). This ensures that both parties are readily familiar
with each other’s interface Elements and Facilities, eliminating hesitation and confusion when referring
to equipment for the Operating Instruction. This shortens response time and improves situational
awareness. It also permits entities to jointly develop the nomenclature for their interface.
Requirements R2 and R3
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Requirement R2 requires the entities listed in Requirement R1 (i.e. each Balancing Authority,
Reliability Coordinator, and Transmission Operator) to conduct initial training for each of their
operating personnel responsible for the Real-time operation of the Bulk Electric System on the entity’s
documented communication protocols.
Requirement R3 requires Distribution Providers and Generator Operators to conduct initial
training on three part communication for each of their operating personnel who can who can receive an
oral two-party, person-to-person Operating Instruction prior to that individual operator receiving an oral
two-party, person-to-person Operating Instruction. Distribution Providers and Generator Operators
would have to train their operating personnel prior to placing them in a position to receive an oral twoparty, person-to-person Operating Instruction. Operating Personnel that would never be in a position to
receive an oral two-party, person-to-person Operating Instruction, therefore, would not need initial
training unless their circumstance changes. The purpose of the language in Requirement R3, is to
minimize the training burden, and demonstration of compliance, to only those operating personnel that
can receive an oral two-party, person-to-person Operating Instruction.
The OPCP SDT has included an initial training requirement in the standard in response to the NERC
Board of Trustees resolution, which directs that a training requirement be included in the COM-002-4
standard. Additionally, requiring entities who issue and or receive Operating Instructions to conduct
initial training with their operating personnel will ensure that all applicable operators will be trained in
three-part communication. The OPCP SDT believes this training will reduce the possibility of a
miscommunication, which could eventually lead to action or inaction harmful to the reliability of the
Bulk Electric System. Ongoing training would fall under an entities training program in PER-005 or
could be listed as a type of corrective action under Requirement R4.
Requirement R4
Requirement R4 requires Balancing Authorities, Reliability Coordinators, and Transmission
Operators to, at least once every 12 months, assess adherence by its operating personnel to the
documented communication protocols in Requirement R1 and to provide feedback to its operating
personnel on their performance. This also includes any corrective action taken, as appropriate, to
address deviations from the documented protocols. It also requires the aforementioned entities to assess
the effectiveness of their documented communications protocols and make changes, as necessary, to
improve the effectiveness of the protocols. An entity may determine that corrective action beyond
identification of the misuse of the documented communications protocols to the operating personnel is
not necessary, therefore, the phrase “as appropriate” is included in the Requirement R4 language to
indicate that whether to take additional corrective action is determined by the entity and not dictated by
the Requirement for all instances of a misuse of a documented communication protocol.
Requiring entities to assess, identify and provide feedback to its operating personnel, was also
included in the November 7, 2013 NERC Board of Trustees resolution as an element to include in the
standard. Further, the OPCP SDT believes that it is good operating practice for an entity to periodically
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evaluate the effectiveness of their protocols and improve them when possible. Most entities currently
engage in some type of assessment activity for their operating personnel. Additionally, the OPCP SDT
also believes it is good operating practice to provide operators with performance feedback on their
adherence to the entity’s documented protocols. Doing so, provides entities an opportunity to evaluate
the performance of their operating personnel and take corrective actions where necessary, which could
prevent a miscommunication from occurring and thus possibly prevent an event which could be harmful
to the reliability of the Bulk Electric System.
The associated Measure M4 for Requirement R4 lists the types of evidence that an entity can
provide to demonstrate compliance and also explains when an entity should show the corrective actions
taken. Of particular interest is any corrective action taken where the miscommunication is the sole or
partial cause of an Emergency and the entity has opted to take a corrective action. While the Measure
lists out this particular set of circumstances to highlight the importance, the Measure does not modify
the Requirement to require corrective action. Again, to reiterate, whether a corrective action is
necessary is best determined by the entity based on the facts and circumstances of the particular
communication.
Requirements R5 and R6
Requirement R5 requires entities that issue oral two-party, person-to-person Operating
Instructions during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, to use three-part communication or take an alternate action if the receiver does
not respond or if the Operating Instruction was not understood by the receiver. The language of
Requirement R5 specifically excludes written or oral single-party to multiple-party burst Operating
Instructions to make clear that three-part communication is not required when issuing Operating
Instructions in this manner. Requirement R5 applies to each Balancing Authority, Reliability
Coordinator, and Transmission Operator since these are the entities that would be in a position to issue
oral two-party, person-to-person Operating Instructions during an Emergency.
Requirement R6 requires entities that receive an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, to repeat (not necessarily verbatim) the Operating Instruction and receive
confirmation from the issuer that the response was correct or request that the issuer reissue the Operating
Instruction. Requirement R6 includes the same clarifying language as Requirement R5 for the exclusion
of single-party to multiple-party burst Operating Instructions. Requirement R6 applies to each
Balancing Authority, Distribution Provider, Generator Operator, and Transmission Operator since these
are the entities that would be in a position to receive oral two-party, person-to-person Operating
Instructions during an Emergency
The use of three-part communication when issuing and receiving Operating Instructions is
always important because a miscommunication could create an Emergency. An entity should expect its
operating personnel that issue and receive Operating Instructions to use the documented communication
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protocols for all Operating Instructions. The way that they reinforce that with its operating personnel is
through training, assessing adherence by its operating personnel to the documented communication
protocols and providing feedback those operating personnel on their use of the protocols. However, the
use of three-part communication is critically important if an Emergency condition already exists, as
further action or inaction could cause exponentially increase the harmful effects to the BES. Clear
communication is essential to providing swift and coordinated response to events that are directly
impacting the reliability of the BES.
Requirement R7
Requirement R7 requires that when a Balancing Authority, Reliability Coordinator, or
Transmission Operator issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency, it must confirm or verify that the Operating Instruction was received by at least
one receiver of the Operating Instruction. Because written or oral single-party to multiple-party burst
Operating Instruction during an Emergency are excluded from Requirements R5 and R6, this separate
Requirement is necessary to specify the standard an entity must meet to demonstrate clear
communication for the use of written or oral single-party to multiple-party burst Operating Instructions
during an Emergency. This prevents leaving a gap in the types of communications used during an
Emergency.
The OPCP SDT believes this requirement is necessary because without confirmation from at
least one receiver, the issuer has no way of confirming if the Operating Instruction was transmitted and
received by any of the recipients. Therefore, the issuer cannot know whether to resend the Operating
Instruction, wait for the recipient to take an action, or take an alternate action because the recipient
cannot perform the action. As a best practice, an entity can opt to confirm receipt from more than one
recipient, which is why the requirement states “at least one.”
NERC Board’s Resolution
At its November meeting, the Board passed a resolution that directs the Standards Committee and
the standard drafting team “to continue development of a combined COM-002 and COM-003 standard
that addresses, at a minimum, the following:
•
•
Draws on the Operating Committee Guideline for good communication practice;
Includes an essential set of communications protocols to be used by all entities that would be
included in an entity’s overall communications protocol approach;
o The protocol should at a minimum require the use of three-part communications for
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•
•
(i) emergency and alert communications (“Emergency Communications”) and (ii) nonemergency communications that change or preserve the state, status, output, or input of
the Bulk Electric System (“Non-Emergency Communications”);
Requires training and periodic review of communications subject to the communications
protocols; and
Requires each entity to (i) periodically self assess its effectiveness in implementing the
communications protocols, (ii) self identify any necessary changes to the entity’s
protocols based upon experience and the results of periodic review, and (iii) provide
feedback to its operators regarding their adherence to the protocols.”
The resolution further directs the standard drafting team to “consider the following
compliance/enforcement approach:
•
•
Maintain the current requirement that entities should be accountable for incorrect use of
communication protocols in connection with Emergency Communications, without exception.
For all other use of communication protocols in connection with Non-Emergency
Communications, the standard should provide that compliance with the standard should only
entail assessing whether an entity has: (i) adopted a communications protocol consistent with the
foregoing; (ii) implemented training and periodic review of communications subject to the
protocols; and (iii) implemented a process to (x) periodically self assess its effectiveness in
implementing the communications protocols, (y) self identify any necessary changes to the
entity’s protocols based upon experience and the results of periodic review, and (z) provide
feedback to its operators regarding their adherence to the protocols.”
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11
Project 2007-02: Operating Personnel Communication
Protocols
Mapping Document
COM-001-1.1 to COM-002-4
Board Approved Standard
COM-001-1.1
R4.Unless agreed to otherwise, each Reliability Coordinator,
Transmission Operator, and Balancing Authority shall use English
as the language for all communications between and among
operating personnel responsible for the real-time generation
control and operation of the interconnected Bulk Electric System.
Transmission Operators and Balancing Authorities may use an
alternate language for internal operations.
Proposed Replacement Requirement(s)
COM-002-4
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall have documented
communications protocols. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Longterm Planning]
1.1. Require the issuer and receiver of an oral or written
Operating Instruction to use the English language,
unless agreed to otherwise. An alternate language may
be used for internal operations
Notes: Moved COM-001-1 R4 into COM-002-4 Requirement R1 Part 1.1 and modified language to include the defined term “Operating
Instruction.”
COM-002-2 to COM-002-3
Board Approved Standard
COM-002-2
R1. Each Transmission Operator, Balancing Authority, and
Generator Operator shall have communications (voice and data
links) with appropriate Reliability Coordinators, Balancing
Authorities, and Transmission Operators. Such communications
shall be staffed and available for addressing a real-time emergency
condition. [Violation Risk Factor: High]
Proposed Replacement Requirement(s)
The Project 2006-06 SDT proposed retiring COM-002-2, R1 and
R1.1 during the development of proposed standard COM-002-3.
The following rationale was provided by that drafting team in
the Implementation Plan for Draft 6 of Project 2006-06. The
same rationale continues to apply for the current version of
COM-002-4:
“The communications requirements of R1 are addressed in
existing COM-001-1.1 as well as the proposed COM-001-2
requirements. Additionally, IRO-010-1a addresses data
R1.1 Each Balancing Authority and Transmission Operator shall
notify its Reliability Coordinator, and all other potentially affected provisions.
Balancing Authorities and Transmission Operators through
The Project 2006-06 SDT contends that COM-002-2, R1.1 is a low
predetermined communication paths of any condition that could level facilitating requirement that is more appropriately and
threaten the reliability of its area or when firm load shedding is
inherently monitored under various higher level performanceanticipated. [Violation Risk Factor: High]
based reliability requirements for each entity throughout the
body of standards. Examples include:
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
•
EOP-002-1, R3 – outlines BA to RC communications.IRO001-1, R3 requires adequate telecommunication for the
Reliability Coordinator to direct actions of multiple
entities, including TOPs and BAs.
•
TOP-001-1, R3 requires adequate telecommunications
facilities for the TOP, BA, and GOP to be able to receive
directives from the RC.
•
TOP-001-1, R5 requires communications between TOPs
and RCs for emergency situations.
2
Board Approved Standard
Proposed Replacement Requirement(s)
•
TOP-005-1, R1 and R3 require adequate
telecommunications for BAs and TOPs to provide each
other with operating data as well as providing data to the
RC.
•
TOP-006-1, R1 requires adequate telecommunications for
the GOP to inform the BA and TOP of resources. The BA
and TOP will then inform the RC, other TOP and BAs of all
transmission and generation available for use.
•
PER-001-1, R1 and PER-004-1, R1 set forth the staffing
requirements.”
Notes: None. The rationale provided above is available at the following hyperlink: Project 2006-06 Draft 6 Implementation Plan
COM-002-2
COM-002-3
R2. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority shall issue directives in a clear, concise, and
definitive manner; shall ensure the recipient of the directive
repeats the information back correctly; and shall acknowledge the
response as correct or repeat the original statement to resolve any
misunderstandings. [Violation Risk Factor: Medium]
The Project 2006-06 expanded COM-002-2 R2 into three
requirements in COM-002-3:
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
Horizon: Real-Time]
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time
Horizon: Real-Time]
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
3
Board Approved Standard
Proposed Replacement Requirement(s)
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
•
Reissue the Reliability Directive to resolve any
misunderstandings.
Notes: The Project 2006-06 expanded the list of responsible entities to include the DP and GOP and subdivided the requirement to
improve clarity.
COM-002-3 to COM-002-4
Board Approved Standard
Proposed Replacement Requirement(s)
COM-002-3
COM-002-4
R1. When a Reliability Coordinator, Transmission Operator or
Balancing Authority requires actions to be executed as a Reliability
Directive, the Reliability Coordinator, Transmission Operator or
Balancing Authority shall identify the action as a Reliability
Directive to the recipient. [Violation Risk Factor: High][Time
Horizon: Real-Time]
None
Notes: The Project 2007-02 SDT removed the term “Reliability Directive” in order to avoid complications that may result from the
Notice of Proposed Rulemaking issued by the Federal Energy Regulatory Commission on November 21, 2014 proposing to remand the
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
4
Board Approved Standard
Proposed Replacement Requirement(s)
definition of “Reliability Directive”. COM-002-4 uses the defined term Operating Instruction to define the circumstances when
documented communications protocols must be used, and uses the phrase “Operating Instruction during an Emergency” to designate
Operating Instructions that would have qualified as Reliability Directives. The Project 2007-02 SDT coordinated with the Project 2009-02
Real time Operations team and Project 2006-06 SDT and all parties agreed that requirement for an issuer to identity a command as a
Reliability Directive is not a communication protocol, and will be considered by each team for future modifications.
R2. Each Balancing Authority, Transmission Operator, Generator
Operator, and Distribution Provider that is the recipient of a
Reliability Directive, shall repeat, restate, rephrase or recapitulate
the Reliability Directive. [Violation Risk Factor: High][Time Horizon:
Real-Time]
R3. Each Reliability Coordinator, Transmission Operator, and
Balancing Authority that issues a Reliability Directive shall either:
[Violation Risk Factor: High] [Time Horizon: Real-Time]
•
R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented
communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
1.1
Require its operating personnel that issue and receive an
oral or written Operating Instruction to use the English
language, unless agreed to otherwise. An alternate
language may be used for internal operations.
1.2.
Require the issuer of an oral two-party, person-to-person
Operating Instruction to wait for a response from the
receiver. Once a response is received, or if no response is
received, require the issuer to take one of the following
actions:
Confirm that the response from the recipient of the
Reliability Directive (in accordance with Requirement R2)
was accurate, or
Reissue the Reliability Directive to resolve any misunderstandings.
Project 2007-02 Operating Personnel Communications Protocols
Mapping
Document
•
Confirm the receiver’s response if the repeated
information is correct.
•
Reissue the Operating Instruction if the repeated
information is incorrect or if requested by the receiver.
5
Board Approved Standard
Proposed Replacement Requirement(s)
•
1.3
Take an alternative action if a response is not received or
if the Operating Instruction was not understood by the
receiver.
Require its operating personnel that receive an oral two
party, person-to-person Operating Instruction to take
one of the following actions:
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the
issuer that the response was correct.
•
Request that the issuer reissue the Operating
Instruction.
1.4
Require its operating personnel that issue a written or
oral single-party to multiple-party burst Operating
Instruction to confirm or verify that the Operating
Instruction was received by at least one receiver of the
Operating Instruction.
1.5
Specify the instances that require time identification
when issuing an oral or written Operating Instruction and
the format for that time identification.
1.6
Specify the nomenclature for Transmission interface
Elements and Transmission interface Facilities when
issuing an oral or written Operating Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall conduct initial training for each
of its operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System on the
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Board Approved Standard
Proposed Replacement Requirement(s)
documented communications protocols developed in
Requirement R1 prior to that individual operator issuing an
Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall
conduct initial training for each of its operating personnel
who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator
receiving an oral two-party, person-to-person Operating
Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R4.
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the issuer that
the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall at least once every twelve (12)
calendar months: [Violation Risk Factor: Medium][Time
Horizon: Operations Planning]
4.1. Assess adherence to the documented
communications protocols in Requirement R1 by
its operating personnel that issue and receive
Operating Instructions, provide feedback to those
operating personnel and take corrective action,
as deemed appropriate by the entity, to address
deviations from the documented protocols.
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Board Approved Standard
Proposed Replacement Requirement(s)
4.2. Assess the effectiveness of its documented
communications protocols in Requirement R1 for
its operating personnel that issue and receive
Operating Instructions and modify its
documented communication protocols, as
necessary.
R5. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues an oral two-party, person-toperson Operating Instruction during an Emergency, excluding
written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Confirm the receiver’s response if the repeated
information is correct (in accordance with Requirement
R6).
•
Reissue the Operating Instruction if the repeated
information is incorrect or if requested by the receiver, or
•
Take an alternative action if a response is not received or
if the Operating Instruction was not understood by the
receiver.
R6. Each Balancing Authority, Distribution Provider, Generator
Operator, and Transmission Operator that receives an oral twoparty, person-to-person Operating Instruction during an
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Board Approved Standard
Proposed Replacement Requirement(s)
Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk
Factor: High][Time Horizon: Real-time Operations]
R7.
•
Repeat, not necessarily verbatim, the Operating
Instruction and receive confirmation from the issuer that
the response was correct, or
•
Request that the issuer reissue the Operating
Instruction.
Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues a written or oral singleparty to multiple-party burst Operating Instruction during
an Emergency shall confirm or verify that the Operating
Instruction was received by at least one receiver of the
Operating Instruction. [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
Notes: COM-002-3 Requirements R2 and R3 were moved into COM-002-4. The Project 2007-02 SDT has developed COM-002-4 to
provide more stringent communication requirements during Emergencies and Alerts as well as establish communication protocols for
non-Emergency/non-alert communications that occur between entities.
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Project 2007-02 – Operating Personnel Communications Protocol
VRF and VSL Justifications
This document provides the drafting team’s justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in COM-002-4 Operating Personnel Communications Protocols.
Each primary requirement is assigned a VRF and a set of one or more VSLs. These elements support the determination of an
initial value range for the Base Penalty Amount regarding violations of requirements in FERC-approved Reliability Standards, as
defined in the ERO Sanction Guidelines.
The Operations Personnel Communications Protocol Standard Drafting Team applied the following NERC criteria and FERC
Guidelines when proposing VRFs and VSLs for the requirements under this project:
NERC Criteria - Violation Risk Factors
High Risk Requirement
A requirement that, if violated, could directly cause or contribute to bulk electric system instability, separation, or a cascading
sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or cascading
failures; or, a requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability, separation, or a
cascading sequence of failures, or could place the bulk electric system at an unacceptable risk of instability, separation, or
cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement
A requirement that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability
to effectively monitor and control the bulk electric system. However, violation of a medium risk requirement is unlikely to lead
to bulk electric system instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated,
could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. However, violation of a medium risk requirement is unlikely, under emergency, abnormal, or restoration conditions
anticipated by the preparations, to lead to bulk electric system instability, separation, or cascading failures, nor to hinder
restoration to a normal condition.
Lower Risk Requirement
A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric system;
or, a requirement that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under
the emergency, abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system, or the ability to effectively monitor, control, or restore the bulk electric
system. A planning requirement that is administrative in nature.
FERC Violation Risk Factor Guidelines
Guideline (1) — Consistency with the Conclusions of the Final Blackout Report
The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified
areas appropriately reflect their historical critical impact on the reliability of the Bulk-Power System.
In the VSL Order, FERC listed critical areas (from the Final Blackout Report) where violations could severely affect the reliability
of the Bulk-Power System:
•
•
Emergency operations
Vegetation management
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•
•
•
•
•
•
•
•
•
•
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
Clearer criteria for operationally critical facilities
Appropriate use of transmission loading relief
Guideline (2) — Consistency within a Reliability Standard
The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main
Requirement Violation Risk Factor assignment.
Guideline (3) — Consistency among Reliability Standards
The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability
goals in different Reliability Standards would be treated comparably.
Guideline (4) — Consistency with NERC’s Definition of the Violation Risk Factor Level
Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s
definition of that risk level.
Guideline (5) — Treatment of Requirements that Co-mingle More Than One Obligation
Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF
assignment for such Requirements must not be watered down to reflect the lower risk level associated with the less important
objective of the Reliability Standard.
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NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement
must have at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have
multiple “degrees” of noncompliant performance and may have only one, two, or three VSLs.
Violation severity levels should be based on the guidelines shown in the table below:
Lower
Missing a minor element (or
a small percentage) of the
required performance
The performance or product
measured has significant
value as it almost meets the
full intent of the
requirement.
Moderate
Missing at least one
significant element (or a
moderate percentage) of
the required performance.
The performance or
product measured still has
significant value in meeting
the intent of the
requirement.
High
Missing more than one
significant element (or is
missing a high percentage)
of the required performance
or is missing a single vital
component.
The performance or product
has limited value in meeting
the intent of the
requirement.
Severe
Missing most or all of the significant
elements (or a significant percentage) of
the required performance.
The performance measured does not meet
the intent of the requirement or the
product delivered cannot be used in
meeting the intent of the requirement.
FERC Order on Violation Severity Levels
In its June 19, 2008 Order on Violation Severity Levels, FERC indicated it would use the following four guidelines for determining
whether to approve VSLs:
Guideline 1: Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the
Current Level of Compliance
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Compare the VSLs to any prior Levels of Non-compliance and avoid significant changes that may encourage a lower level
of compliance than was required when Levels of Non-compliance were used.
Guideline 2: Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the
Determination of Penalties
Guideline 2a: A violation of a “binary” type requirement must be a “Severe” VSL.
Guideline 2b: Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3: Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4: Violation Severity Level Assignment Should Be Based on A Single Violation, Not on A Cumulative
Number of Violations
. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation.
Section 4 of the Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty
calculations.
VRFs for COM-002-4
The following discussion addresses how the SDT considered FERC’s VRF Guidelines 2 through 5. The team did not address
Guideline 1 directly because of an apparent conflict between Guidelines 1 and 4. Whereas Guideline 1 identifies a list of topics
that encompass nearly all topics within NERC’s Reliability Standards and implies that these requirements should be assigned a
“High” VRF, Guideline 4 directs assignment of VRFs based on the impact of a specific requirement to the reliability of the system.
The SDT believes that Guideline 4 is reflective of the intent of VRFs and the SDT, therefore, concentrated its approach on the
reliability impact of the requirements.
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There are seven requirements in COM-002-4. Requirements R1, R2, and R3 are assigned a “Low” VRF. Requirement R4 is
assigned a “Medium” VRF. Requirement R5, R6 and R7 are each assigned a “High” VRF.
•
•
•
R1 reads: “Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop documented
communications protocols for its operating personnel that issue and receive Operating Instructions. The protocols shall,
at a minimum:”
R2 reads: “Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall conduct initial training for
each of its operating personnel responsible for the Real-time operation of the interconnected Bulk Electric System on the
documented communications protocols developed in Requirement R1 prior to that individual operator issuing an
Operating Instruction.”
R3 reads: “Each Distribution Provider and Generator Operator shall conduct initial training for each of its operating
personnel who can receive an oral two-party, person-to-person Operating Instruction prior to that individual operator
receiving an oral two-party, person-to-person Operating Instruction to either:”
R4 reads: “Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall at least once every twelve (12)
calendar months:” This Requirement warrants a VRF of “Medium” because R4 is a requirement in an operations planning time
frame that, if violated, could directly affect the electrical state or the capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. However, a violation of this requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures. ”
R5 now reads: ”Each Balancing Authority, Reliability Coordinator, and Transmission Operator that issues an oral two-party,
person-to-person Operating Instruction during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, shall either:”
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R6 is a new requirement which reads “Each Balancing Authority, Distribution Provider, Generator Operator, and Transmission
Operator that receives an oral two-party, person-to-person Operating Instruction during an Emergency, excluding written or oral
single-party to multiple-party burst Operating Instructions, shall either:”
R7 is a new requirement which reads “Each Balancing Authority, Reliability Coordinator, and Transmission Operator that issues a
written or oral single-party to multiple-party burst Operating Instruction during an Emergency shall confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating Instruction.” Requirements R5, R6, and R7 warrant
VRFs of “High” because failure to use the communications protocols during an emergency could directly cause or contribute to
bulk electric system instability, separation, or a cascading sequence of failures, or could place the bulk electric system at an
unacceptable risk of instability, separation, or cascading failures.
VRF and VSL Justifications – COM-002-4, R1
Proposed VRF
Low
NERC VRF Discussion
R1 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R1 establishes communications protocols, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard:
The requirement has sub-parts that similarly address communication protocols; only one VRF was
assigned so there is no conflict. There are no other requirements in COM-002-4 that address specific
protocols.
Guideline 3- Consistency among Reliability Standards:
There are no other standards which address documented communications protocols.
FERC VRF G2 Discussion
FERC VRF G3 Discussion
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VRF and VSL Justifications – COM-002-4, R1
FERC VRF G4 Discussion
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to utilize communication protocols properly could result in actions that directly affect the electrical
state or the capability of the bulk electric system, or the ability to effectively monitor and control the bulk
electric system. However, violation of the requirement is unlikely to lead to bulk electric system
instability, separation, or cascading failures since R1 strictly deals with documenting clear, formal and
universally applied communication protocols. The VRF for this requirement is “Low,” which is consistent
with NERC guidelines for similar requirements.
FERC VRF G5 Discussion
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R1 contains only one objective which is to document clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
only one objective, only one VRF was assigned.
Proposed VSL
Lower
Moderate
The responsible entity did not
specify the instances that
require time identification
when issuing an oral or written
Operating Instruction and the
format for that time
identification, as required in
Requirement R1, Part 1.5
The responsible entity did not
require the issuer and receiver
of an oral or written Operating
Instruction to use the English
language, unless agreed to
otherwise, as required in
Requirement R1, Part 1.1. An
alternate language may be
used for internal operations.
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High
The responsible entity did not
include Requirement R1, Part 1.4
in its documented communication
protocols.
Severe
The responsible entity did not
include Requirement R1, Part 1.2
in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part 1.3
VRF and VSL Justifications – COM-002-4, R1
OR
The responsible entity did not
specify the nomenclature for
Transmission interface
Elements and Transmission
interface Facilities when issuing
an oral or written Operating
Instruction, as required in
Requirement R1, Part 1.6.
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in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
VRF and VSL Justifications – COM-002-4, R1
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Based on the VSL Guidance, the SDT developed four VSLs based on misapplication or absence of common
communication protocols, with varied VSLs. The SDT determined how the protocols should be divided in
the VSLs by judging the severity of the potential risk to the bulk electric system if the protocols ultimately
are not used. If the severity is greater, then not having the protocol documented should carry a higher
severity level and similarly for protocols where the severity is lesser. If no communication protocols were
addressed at all then the VSL is Severe.
Guideline 2a:
The SDT has intentionally not structured the VSL assignment for R1 as binary in order to reflect the relative
severity of each protocol should the protocol not ultimately be employed.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
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VRF and VSL Justifications – COM-002-4, R1
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R1.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
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VRF and VSL Justifications – COM-002-4, R1
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM-002-4, R2
Proposed VRF
Low
NERC VRF Discussion
R2 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
R2 establishes that entities who issue and receive Operating Instructions shall conduct initial training with
their operating personnel to ensure that all applicable operators will be trained on their documented
communication protocols established in Requirement R1. This training reduces the possibility of a
miscommunication, which could eventually lead to action or inaction harmful to the reliability of the Bulk
Electric System, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
Only one VRF is assigned for this requirement.
FERC VRF G2 Discussion
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VRF and VSL Justifications – COM-002-4, R2
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 3- Consistency among Reliability Standards:
This requirement establishes that each Balancing Authority, Reliability Coordinator and Transmission
Operator conduct initial training with each of its operating personnel responsible for the Real-time
operation of the BES on documented communication protocols to reduce the possibility of
miscommunication which could eventually lead to action or inaction harmful to the reliability of the bulk
electric system. This VRF is consistent with other training requirements within the body of NERC
Reliability Standards, including CIP-004-5.1 Requirements R1 and R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
Violation of the requirement is unlikely to lead to bulk electric system instability, separation, or cascading
failures. The VRF for this requirement is “Low,” which is consistent with NERC guidelines for similar
requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R2 contains only one objective which is to conduct initial training for each of its
operating personnel responsible for the Real-time operation of the BES. Since the requirement has only
one objective, only one VRF was assigned.
Proposed VSL
Lower
N/A
Moderate
N/A
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High
An individual operator responsible
for the Real-time operation of the
interconnected Bulk Electric
System at the responsible entity
issued an Operating Instruction,
prior to being trained on the
Severe
An individual operator responsible
for the Real-time operation of the
interconnected Bulk Electric
System at the responsible entity
issued an Operating Instruction
during an Emergency prior to
VRF and VSL Justifications – COM-002-4, R2
documented communications
protocols developed in
Requirement R1.
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being trained on the documented
communications protocols
developed in Requirement R1.
VRF and VSL Justifications – COM-002-4, R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs for R2. These VSLs were determined based on
the potential consequences of an operator issuing an Operating Instruction without having first received
training on the communication protocols. An operator who is not trained on the communication
protocols could miscommunicate an Operating Instruction, which could put the BES in an undesirable
state. This warrants a High VSL. An operator who is not trained on the communication protocols could
miscommunicate an Operating Instruction during an Emergency, which could directly put the BES in an
undesirable state. This warrants a Severe VSL.
Since training requirements were not in prior versions of COM-002, the introduction of this training
requirement will not have the unintended consequence of lowering the current level of compliance.
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VRF and VSL Justifications – COM-002-4, R2
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment is not binary. The VSL accounts for two different operating conditions to differentiate
two levels of severity based on which condition, Emergency or other condition, is present when the
miscommunication occurs.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement. In addition, the VSLs are consistent with Requirement R3.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations.
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
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VRF and VSL Justifications – COM-002-4, R2
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R3
Proposed VRF
Low
NERC VRF Discussion
R3 is a requirement in a Long-term Planning time frame that, if violated, would not, under the emergency,
abnormal, or restorative conditions anticipated by the preparations, be expected to adversely affect the
electrical state or capability of the bulk electric system. The VRF for this requirement is “Low,” which is
consistent with NERC guidelines.
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VRF and VSL Justifications – COM 002-4, R3
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 1- Consistency w/ Blackout Report:
R3 establishes that entities who only receive Operating Instructions shall conduct initial training with their
operating personnel to ensure that all applicable operators will be trained in three part communication.
This training reduces the possibility of a miscommunication, which could eventually lead to action or
inaction harmful to the reliability of the Bulk Electric System, which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements; only one VRF was assigned so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement establishes that Distribution Providers and Generator Operators conduct initial training
with each of its operating personnel responsible for the Real-time operation of the BES on three part
communication to reduce the possibility of miscommunication which could eventually lead to action or
inaction harmful to the reliability of the bulk electric system. This VRF is consistent the VSL assignment for
COM-002-4 R2 and other training requirements within the body of NERC Reliability Standards, including
CIP-004-5.1 Requirements R1 and R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
Failure to conduct initial training for individual operators on three part communication could directly
affect the electrical state or the capability of the bulk electric system, or the ability to effectively monitor
and control the bulk electric system. However, violation of the requirement is unlikely to lead to bulk
electric system instability, separation, or cascading failures. The VRF for this requirement is “Low,” which
is consistent with NERC guidelines for similar requirements.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R3 contains only one objective which to conduct initial training with individual
system operators on three part communication. Since the requirement has only one objective, only one
VRF was assigned.
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VRF and VSL Justifications – COM 002-4, R3
Proposed VSL
Lower
N/A
Moderate
N/A
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High
An individual operator at the
responsible entity received an
Operating Instruction prior to
being trained.
Severe
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being trained.
VRF and VSL Justifications – COM 002-4, R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs. These VSLs were determined based on the
potential consequences of an operator receiving an Operating Instruction without having first received
training on the communication protocols. An operator who is not trained on three part communication
could miscommunicate an Operating Instruction, which could put the BES in an undesirable state. This
warrants a High VSL. An operator who is not trained on three part communication could miscommunicate
an Operating Instruction during an Emergency, which could directly put the BES in an undesirable state.
This warrants a Severe VSL.
Since training requirements were not in prior versions of COM-002, the introduction of this training
requirement will not have the unintended consequence of lowering the current level of compliance.
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
Guideline 2a:
The VSL assignment for R3 is not binary. The VSL accounts for two different operating conditions to
differentiate two levels of severity based on which condition, Emergency or other condition, is present
when the miscommunication occurs.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
Project 2007-2 – Operating Personnel Communications Protocols
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20
VRF and VSL Justifications – COM 002-4, R3
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
Project 2007-2 – Operating Personnel Communications Protocols
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21
VRF and VSL Justifications – COM 002-4, R3
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R4
Proposed VRF
Medium
NERC VRF Discussion
R4 is a requirement in an Operations planning requirement time frame that, if violated, could directly
affect the ability to effectively monitor and control the bulk electric system. However, a violation of this
requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
FERC VRF G1 Discussion
Guideline 1- Consistency w/ Blackout Report:
This requirement establishes that responsible entities from R1 to periodically assess their operator’s
adherence to the entity’s documented communication protocols and provide feedback to those operators.
It also requires entities to assess the effectiveness of these protocols and modify them where necessary.
The requirement addresses Recommendation 26 of the Blackout Report. The VRF for this requirement is
“Medium,” which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
FERC VRF G2 Discussion
Project 2007-2 – Operating Personnel Communications Protocols
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VRF and VSL Justifications – COM 002-4, R4
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
The requirement has no sub-requirements. Only one VRF was assigned to the requirement and its subparts, so there is no conflict.
Guideline 3- Consistency among Reliability Standards:
This requirement calls for responsible entities from R1 to periodically assess their operator’s adherence to
the entity’s documented communication protocols and provide feedback to those operators. It also
requires entities to assess the effectiveness of these protocols and modify them where necessary. This
VRF is consistent with similar requirements within the body of NERC Reliability Standards, including PER005-1 Requirements R1 and R2.
Guideline 4- Consistency with NERC Definitions of VRFs:
R4 is a requirement in an Operations planning requirement time frame that, if violated, could directly
affect the ability to effectively monitor and control the bulk electric system. However, a violation of this
requirement is unlikely to lead to bulk electric system instability, separation, or cascading failures. The VRF
for this requirement is “Medium,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R4 contains only one objective which is to implement clear, formal and
universally applied communication protocols that reduce the possibility of miscommunication which could
lead to action or inaction harmful to the reliability of the bulk electric system. Since the requirement has
only one objective, only one VRF was assigned.
Proposed VSL
Lower
The responsible entity
implemented a method to
evaluate the documented
communications protocols
developed in Requirement R1,
Moderate
The responsible entity
implemented a method for
evaluating its communications
protocols as specified in
Requirement R4 and assessed
Project 2007-2 – Operating Personnel Communications Protocols
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23
High
The responsible entity
implemented a method for
evaluating its communications
protocols as specified in
Requirement R4 but did not assess
Severe
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
VRF and VSL Justifications – COM 002-4, R4
but exceeded twelve (12)
calendar months between
evaluations.
adherence to the documented
communications protocols in
Requirements R1 by its
operating personnel that issue
and receive Operating
Instructions but did not provide
feedback to those operating
personnel
OR
The responsible entity
implemented a method for
evaluating its communications
protocols as specified in
Requirement R4 and assessed
adherence to the documented
communications protocols in
Requirements R1 by its
operating personnel that issue
and receive Operating
Instructions and provided
feedback to those operating
personnel but did not take
corrective action, as
appropriate
OR
Project 2007-2 – Operating Personnel Communications Protocols
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24
adherence to the documented
communications protocols in
Requirements R1 by its operating
personnel that issue and receive
Operating Instructions
OR
The responsible entity
implemented a method for
evaluating its communications
protocols as specified in
Requirement R4 but did not assess
the effectiveness of its
documented communications
protocols in Requirement R1 for its
operating personnel that issue and
receive Operating Instructions.
its operating personnel that issue
and receive Operating Instructions
AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for its
operating personnel that issue and
receive Operating Instructions.
VRF and VSL Justifications – COM 002-4, R4
The responsible entity
implemented a method for
evaluating its communications
protocols as specified in
Requirement R4 and assessed
the effectiveness of its
documented communications
protocols in Requirement R1
for its operating personnel that
issue and receive Operating
Instructions but did not modify
its documented communication
protocols, as necessary.
Project 2007-2 – Operating Personnel Communications Protocols
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VRF and VSL Justifications – COM 002-4, R4
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
26
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed four VSLs to establish the severity of an entity not
assessing their operator’s adherence to the entity’s communications protocols and/or not assessing the
effectiveness of those protocols at least once every 12 calendar months. If an entity implemented a
method to evaluate the documented communications protocols developed in Requirement R1, but
exceeded twelve (12) calendar months between evaluations then it is a “Low” VSL, since the performance
or product measured has significant value as it almost meets the full intent of the requirement.
If an entity implemented a method for evaluating its communications protocols as specified in
Requirement R4 and assessed adherence to the documented communications protocols in Requirements
R1 by its operating personnel that issue and receive Operating Instructions but did not provide feedback
to those operating personnel it is a “Medium” VSL. If an entity implemented a method for evaluating its
communications protocols and assessed adherence to the communications protocols by its operating
personnel and provided feedback to those personnel but did not take corrective action, as appropriate
It is also a “Medium” VSL. If an entity implemented a method for evaluating its communications protocols
and assessed the effectiveness of its protocols for its operating personnel but did not modify its
documented communication protocols, as necessary, it is also a “Medium” VSL. The value of “Medium” is
justified based one significant element (or a moderate percentage) of the required performance is missing
but the performance or product measured still has significant value in meeting the intent of the
requirement.
If an entity implemented a method for evaluating its communications protocols but did not assess
adherence to them by its operating personnel then it is a “High” VSL. If an entity implemented a method
for evaluating its communications protocols as specified in Requirement R4 but did not assess the
effectiveness of its protocols in for its operating personnel it is a “High” VSL. The value of “High” is
justified because the entity is missing more than one significant element (or is missing a high percentage)
of the required performance.
Project 2007-2 – Operating Personnel Communications Protocols
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27
VRF and VSL Justifications – COM 002-4, R4
If an entity did not assess adherence to the documented communications protocols by its operating
personnel and it did not assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel, then it is a “Severe” VSL. The value of “Severe” is justified
because the performance measured does not meet the intent of the requirement.
Project 2007-2 – Operating Personnel Communications Protocols
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28
VRF and VSL Justifications – COM 002-4, R4
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R4 is not binary. The VSL accounts for two different operating conditions to
differentiate two levels of severity based on which condition, Emergency or other condition, is present
when the miscommunication occurs.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement.
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-2 – Operating Personnel Communications Protocols
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29
VRF and VSL Justifications – COM 002-4, R4
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R5
Proposed VRF
High
NERC VRF Discussion
R5 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
30
VRF and VSL Justifications – COM 002-4, R5
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 1- Consistency w/ Blackout Report:
R5 requires entities who issue an Operating Instruction during an Emergency to use three part
communication or take an alternative action if the receiver does not respond. The requirement addresses
Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which is consistent
with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
There are no other standards which address documented communications protocols.
Guideline 4- Consistency with NERC Definitions of VRFs:
R5 is a requirement in an Operations Planning time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R5 contains only one objective which is for entities that issue Operating
Instructions to use three part communication or take an alternative action if the receiver does not
respond to reduce the possibility of miscommunication which could lead to action or inaction harmful to
the reliability of the bulk electric system. Since the requirement has only one objective, only one VRF was
assigned.
Project 2007-2 – Operating Personnel Communications Protocols
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31
VRF and VSL Justifications – COM 002-4, R5
Proposed VSL
Lower
N/A
Moderate
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
•
Confirmed the receiver’s
response if the repeated
information was correct
(in accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the
Operating Instruction was
not understood by the
receiver.
Project 2007-2 – Operating Personnel Communications Protocols
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32
High
N/A
Severe
The responsible entity that issued
an Operating Instruction during an
Emergency did not take one of the
following actions:
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect or
if requested by the receiver.
•
Took an alternative action if a
response was not received or
if the Operating Instruction
was not understood by the
receiver.
AND
VRF and VSL Justifications – COM 002-4, R5
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
33
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure to use three part
communication when issuing an Operating Instruction during an Emergency.
If an entity, when issuing an Operating Instruction during an Emergency, did not use three part
communication or take an alternative action if the receiver does not respond, yet instability, uncontrolled
separation, or cascading failures did not occur as a result, the entity violated the Requirement with a
“Medium” VSL. The value of “Medium” is justified based one significant element (or a moderate
percentage) of the required performance is missing but the performance or product measured still has
significant value in meeting the intent of the requirement, which is to avoid action or inaction that is
harmful to the reliability of the Bulk Electric System.
If an entity, when issuing an Operating Instruction during an Emergency, did not use three part
communication or take an alternative action if the receiver does not respond, and instability, uncontrolled
separation, or cascading failures occurred as a result, the entity violated the Requirement with a “Severe”
VSL. The value of “Severe” is justified because the performance outcome does not meet the intent of the
requirement.
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
34
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R5 is not binary. See explanation in G1 above.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-2 – Operating Personnel Communications Protocols
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35
VRF and VSL Justifications – COM 002-4, R5
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R6
Proposed VRF
High
NERC VRF Discussion
R6 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
36
VRF and VSL Justifications – COM 002-4, R6
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 1- Consistency w/ Blackout Report:
R6 requires entities who receive an Operating Instruction during an Emergency to repeat, not necessarily
verbatim, the Operating Instruction and receive confirmation from the issuer that the response was
correct, or request that the issuer reissue the Operating Instruction. The requirement addresses
Recommendation 26 of the Blackout Report. The VRF for this requirement is “High,” which is consistent
with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements. and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
There are no other standards which address documented communications protocols
Guideline 4- Consistency with NERC Definitions of VRFs:
R6 is a requirement in an Operations Planning time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R6 contains only one objective which is for entities that receive Operating
Instructions during an Emergency to repeat, not necessarily verbatim, the Operating Instruction in order
to reduce the possibility of miscommunication which could lead to action or inaction harmful to the
reliability of the bulk electric system. Since the requirement has only one objective, only one VRF was
assigned.
Project 2007-2 – Operating Personnel Communications Protocols
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37
VRF and VSL Justifications – COM 002-4, R6
Proposed VSL
Lower
N/A
Moderate
The responsible entity did not
repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the issuer
that the response was correct,
or request that the issuer
reissue the Operating
Instruction when receiving an
Operating Instruction.
High
N/A
Severe
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Project 2007-2 – Operating Personnel Communications Protocols
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38
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure of the recipient of an
Operating Instruction to use three part communication after receiving an Operating Instruction during an
Emergency.
If an entity, when receiving an Operating Instruction during an Emergency, did not repeat, not necessarily
verbatim, the Operating Instruction during an Emergency and receive confirmation from the issuer that
the response was correct, or request that the issuer reissue the Operating Instruction when receiving an
Operating Instruction, yet instability, uncontrolled separation, or cascading failures did not occur as a
result, the entity violated the Requirement with a “Medium” VSL. The value of “Medium” is justified
based one significant element (or a moderate percentage) of the required performance is missing but the
performance or product measured still has significant value in meeting the intent of the requirement,
which is to avoid action or inaction that is harmful to the reliability of the Bulk Electric System.
If an entity, when receiving an Operating Instruction during an Emergency, did not repeat, not necessarily
verbatim, the Operating Instruction during an Emergency and receive confirmation from the issuer that
the response was correct, or request that the issuer reissue the Operating Instruction when receiving an
Operating Instruction, and instability, uncontrolled separation, or cascading failures occurred as a result,
the entity violated the Requirement with a “Severe” VSL. The value of “Severe” is justified because the
performance outcome does not meet the intent of the requirement.
Project 2007-2 – Operating Personnel Communications Protocols
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39
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R6 is not binary. The VSL accounts for two different operating conditions to
differentiate two levels of severity based on which condition, Emergency or other condition, is present
when the miscommunication occurs.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
40
VRF and VSL Justifications – COM 002-4, R6
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
VRF and VSL Justifications – COM 002-4, R7
Proposed VRF
High
NERC VRF Discussion
R7 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures; or, a
requirement in a planning time frame that, if violated, could, under emergency, abnormal, or restorative
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
41
VRF and VSL Justifications – COM 002-4, R7
conditions anticipated by the preparations, directly cause or contribute to bulk electric system instability,
separation, or a cascading sequence of failures, or could place the bulk electric system at an unacceptable
risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion
FERC VRF G4 Discussion
FERC VRF G5 Discussion
Guideline 1- Consistency w/ Blackout Report:
R7 requires entities that issue a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency to confirm or verify that the Operating Instruction was received by at least one
receiver. The requirement addresses Recommendation 26 of the Blackout Report. The VRF for this
requirement is “High,” which is consistent with FERC guideline G1.
Guideline 2- Consistency within a Reliability Standard :
The requirement has no sub-requirements and only one VRF was assigned therefore, there is no conflict.
Guideline 3- Consistency among Reliability Standards:
There are no other standards which address documented communications protocols
Guideline 4- Consistency with NERC Definitions of VRFs:
R7 is a requirement in a Real-time Operations time frame that, if violated, could directly cause or
contribute to bulk electric system instability, separation, or a cascading sequence of failures, or could
place the bulk electric system at an unacceptable risk of instability, separation, or cascading failures. The
VRF for this requirement is “High,” which is consistent with NERC guidelines.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation:
COM-002-4 Requirement R7 contains only one objective which requires entities that issue a written or
oral single-party to multiple-party burst Operating Instruction during an Emergency confirm or verify that
the Operating Instruction was received by at least one receiver of the Operating Instruction. Since the
requirement has only one objective, only one VRF was assigned.
Project 2007-2 – Operating Personnel Communications Protocols
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42
VRF and VSL Justifications – COM 002-4, R7
Proposed VSL
Lower
N/A
Moderate
The responsible entity that that N/A
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction.
High
Severe
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Project 2007-2 – Operating Personnel Communications Protocols
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43
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance
Based on the VSL Guidance, the SDT developed two VSLs based on the failure of the issuer of a written or
oral single-party to multiple-party burst Operating Instruction during an Emergency to confirm or verify
that the Operating Instruction was received by at least one receiver.
If an entity, when issuing a written or oral single-party to multiple-party burst Operating Instruction during
an Emergency, did not confirm or verify that the Operating Instruction was received by at least one
receiver, yet instability, uncontrolled separation, or cascading failures did not occur as a result, the entity
violated the Requirement with a “Medium” VSL. The value of “Medium” is justified based one significant
element (or a moderate percentage) of the required performance is missing but the performance or
product measured still has significant value in meeting the intent of the requirement, which is to avoid
action or inaction that is harmful to the reliability of the Bulk Electric System.
If an entity, when issuing a written or oral single-party to multiple-party burst Operating Instruction during
an Emergency, did not confirm or verify that the Operating Instruction was received by at least one
receiver, and instability, uncontrolled separation, or cascading failures occurred as a result, the entity
violated the Requirement with a “Severe” VSL. The value of “Severe” is justified because the
performance outcome does not meet the intent of the requirement.
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
44
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement
Guideline 2a:
The VSL assignment for R7 is not binary. The VSL accounts for two different operating conditions to
differentiate two levels of severity based on which condition, Emergency or other condition, is present
when the miscommunication occurs.
Guideline 2b:
The proposed VSL does not use any ambiguous terminology, thereby supporting uniformity and
consistency in the determination of similar penalties for similar violations.
The proposed VSL uses the same terminology as used in the associated requirement, and is, therefore,
consistent with the requirement
FERC VSL G4
The VSL is based on a single violation and not cumulative violations
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
45
VRF and VSL Justifications – COM 002-4, R7
FERC VSL G5
Requirements where a single
lapse in protection can
compromise computer network
security, i.e., the ‘weakest link’
characteristic, should apply
binary VSLs
The requirement does not address cyber security protection.
The requirement does not address cyber security protection.
FERC VSL G6
VSLs for cyber security
requirements containing
interdependent tasks of
documentation and
implementation should account
for their interdependence
Project 2007-2 – Operating Personnel Communications Protocols
VRF and VSL Justificationsand VSL Justifications
46
Project YYYY-##.# - Project Name
VRF and VSL Justifications – COM 002-4, R7
for their interdependence
VRF and VSL Justifications
47
Table of Issues and Directives
Project 2007-02
Operating Personnel Communications Protocols
Table of Issues and Directives Associated with COM-002-4
Source
FERC Order No.
693, P 512 and
540 (Part 1)
Directive Language
512. The Commission finds that, during both
normal and emergency operations, it is
essential that the transmission operator,
balancing authority and reliability coordinator
have communications with distribution
providers. In response to APPA, as discussed
above, any distribution provider that is not a
user, owner or operator of the Bulk-Power
System would not be required to comply with
COM-002-2, even though the Commission is
requiring the ERO to modify the Reliability
Standard to include distribution providers as
applicable entities. APPA’s concern that 2,000
public power systems would have to be added
to the compliance registry is misplaced, since,
as we explain in our Applicability discussion
above, we are approving NERC’s registry
process, including the registry criteria.
Therefore, we adopt our proposal to require
Disposition
Distribution Providers have been included as
applicable entities in COM-002-4
Section and/or
Requirement(s)
Applicability 4.1.2
Requirements R3 and R6
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
the ERO to modify COM-002-2 to apply to
distribution providers through its Reliability
Standards development process.
540. ... In addition, pursuant to section
215(d)(5) of the FPA and § 39.5(f) of our
regulations, the Commission directs the ERO to
develop a modification to COM-002-2 through
the Reliability Standards development process
that: (1) expands the applicability to include
distribution providers as applicable entities; (2)
includes a new Requirement for the reliability
coordinator to assess and approve actions that
have impacts beyond the area view of a
transmission operator or balancing authority
and (3) requires tightened communications
protocols, especially for communications
during alerts and emergencies. Alternatively,
with respect to this final issue, the ERO may
develop a new Reliability Standard that
responds to Blackout Report Recommendation
No. 26 in the manner described above. Finally,
we direct the ERO to include APPA’s
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
2
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
suggestions to complete the Measures and
Levels of Non-Compliance in its modification of
COM-002-2 through the Reliability Standards
development process.
FERC Order No.
693, P 531, 534,
535, 540 (Part 3)
531. We adopt our proposal to require the ERO
to establish tightened communication
protocols, especially for communications
during alerts and emergencies, either as part of
COM-002-2 or as a new Reliability Standard.
We note that the ERO’s response to the Staff
Preliminary Assessment supports the need to
develop additional Reliability Standards
addressing consistent communications
protocols among personnel responsible for the
reliability of the Bulk-Power System.
COM-002-4 improves communications
protocols for the issuance of Operating
Instructions, in order to reduce the possibility
of miscommunication that could lead to
action or inaction harmful to the reliability of
the Bulk Electric System.
Definition of Operating
Instruction
Requirements R1, R2,
R3, R4, R5, R6 and R7
534. In response to MISO’s contention that
Blackout Report Recommendation No. 26 has
been fully implemented, we note that
Recommendation No. 26 addressed two
matters. We believe MISO is referring to the
second part of the recommendation requiring
NERC to “[u]pgrade communication system
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
3
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
hardware where appropriate” instead of
tightening communications protocols. While we
commend the ERO for taking appropriate
action in upgrading its NERCNet, we remind the
industry to continue their efforts in addressing
the first part of Blackout Recommendation No.
26. (Emphasis added)
535. Accordingly, we direct the ERO to either
modify COM-002-2 or develop a new Reliability
Standard that requires tightened
communications protocols, especially for
communications during alerts and
emergencies.
FERC Order No.
693, P 532
532. While we agree with EEI that EOP-001-0,
Requirement R4.1 requires communications
protocols to be used during emergencies, we
believe, and the ERO agrees, that the
communications protocols need to be
tightened to ensure Reliable Operation of the
Bulk-Power System. We also believe an integral
component in tightening the protocols is to
establish communication uniformity as much as
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
Reliability Standard EOP-001-2.1b —
Emergency Operations Planning (successor
standard to EOP-001-0) requires that the
emergency plans for each Transmission
Operator and Balancing Authority include:
communications protocols to be used during
emergencies (Requirement R3.1). This
requirement is compatible with COM-002-4,
which establishes the documented
Requirements R1, R5,
R6, R7
4
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
practical on a continent-wide basis. This will
eliminate possible ambiguities in
communications during normal, alert and
emergency conditions. This is important
because the Bulk- Power System is so tightly
interconnected that system impacts often cross
several operating entities’ areas.
Disposition
Section and/or
Requirement(s)
communications protocols and requires their
use.
COM-002-4 requires a set of protocols be
used by all applicable entities, establishing
communication uniformity as much as
practical on a continent-wide basis
533. Regarding APPA’s suggestion that it may
be beneficial to include communication
protocols in the relevant Reliability Standard
that governs those types of emergencies, we
direct that it be addressed in the Reliability
Standards development process.
FERC Order No.
693, P 514, 515
514. APPA notes that the Levels of NonCOM-002-4 includes Measures, VRFs and VSLs
Compliance for COM-002-2 are inadequate in
for each requirement.
two respects: (1) reliability coordinators are not
included in any Level of Non-Compliance and
(2) the Levels of Non-Compliance for
transmission operators and balancing
authorities in Compliance D.2 do not reference
Requirements R1 and R2. Therefore, APPA
would support approval of COM-002-2 as a
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
Section C, Measures
Section D, Compliance
5
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
mandatory Reliability Standard, but would not
support levying penalties for violating
incomplete portions of the Reliability Standard.
515. As stated in the Common Issues section, a
Reliability Standard is enforceable even if it
does not contain Levels of Non-Compliance.
However, the Commission agrees with APPA
that this Reliability Standard could be improved
by incorporating the changes proposed by
APPA. Therefore, when reviewing the Reliability
Standard through the Reliability Standards
development process, the ERO should consider
APPA’s concerns.
2003 Blackout
Report
Recommendation
No. 26
NERC should work with reliability coordinators
and control area operators to improve the
effectiveness of internal and external
communications during alerts, emergencies, or
other critical situations, and ensure that all key
parties, including state and local officials,
receive timely and accurate information. NERC
should task the regional councils to work
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
The requirements in COM-002-4 require the
use of predefined communications protocols
in order to reduce the possibility of a
miscommunication(s) that could lead to
action or inaction harmful to the reliability of
the Bulk Electric System (BES).
Requirements R1, R2,
R3, R4, R5, R6, and R7
6
Table of Issues and Directives Associated with COM-002-4
Source
Directive Language
Disposition
Section and/or
Requirement(s)
together to develop communications protocols
by December 31, 2004, and to assess and
report on the adequacy of emergency
communications systems within their regions
against the protocols by that date.
Table of Issues and Directives
Project 2007-02 Operating Personnel Communications Protocols – January 2014
7
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Agenda Item 6
Standards Committee Meeting
December 11‐12, 2013
Waiver for Project 2007-02 Operating Personnel Communications Protocols
Action
Authorize a waiver of the Standard Processes Manual to shorten the comment period for
Project 2007‐02 from 45 days to 30 days, with a ballot conducted during the last 10 days of the
comment period; and, also require NERC Staff to post a notice of the waiver on the project page
and work with the Chair of the Standards Committee to notify the NERC Board of Trustees
Standards Oversight and Technology Committee of the waiver.
Background
On November 7, 2013 the NERC Board of Trustees (Board) passed a resolution that, among
other things, directed the Standards Committee and relevant Standards Drafting Team (SDT) to
develop a combined COM‐002 and COM‐003 Standard and requested “that the Standards
Committee direct the standard drafting team to work toward providing an industry approved
combined standard, as contemplated by the foregoing resolutions, for Board approval as
quickly as possible, but in no event later than the Board’s February 2014 meeting.” The Project
2007‐02 SDT has been working to draft a COM Standard that is responsive to the Board’s
resolution.
The defined term “Reliability Directive” is currently being considered by the Project 2007‐02
SDT in proposed Reliability Standard COM‐002‐4. The same term is used in revised TOP and IRO
Standards pending with the Federal Energy Regulatory Commission (FERC). On November 21,
2013, FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to remand the TOP and
IRO Standards including the definition of “Reliability Directive.” As a result of the NOPR, the
Project 2007‐02 SDT is also considering alternatives to using the term Reliability Directive. The
SDT needs additional time to conduct outreach to the IRO and TOP SDTs to obtain feedback on
the options currently under consideration for COM‐002‐4 with respect to the definition of
“Reliability Directive.”
Currently, to meet the Board deadline, the SDT would likely need to post on or about December
4, 2013 for a full 45‐day comment and ballot period. In order to provide the Project 2007‐02
SDT time to coordinate with the IRO and TOP SDTs and meet the February Board deadline, a
reduction in the comment and ballot period is needed from 45 days to 30 days.
As required by Section 16 of the NERC Standard Processes Manual, NERC provided stakeholders
with notice of this request on December 3, 2013 (see attached).
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Notice of Request to Waive the Standard Process
Project 2007-02 Operating Personnel Communications Protocols
COM-002 and COM-003
Notice of Request to Waive the Standard Process
As required by Section 16 of the Standards Processes Manual, this is official notice to stakeholders that
the Chair of the Standards Committee is requesting that the Standards Committee consider a waiver of
the Standard Processes Manual to shorten the formal comment and ballot period, from 45 days to 30
days to meet a NERC Board of Trustees (“Board”) requested deadline to “work toward providing an
industry approved combined standard, as contemplated by the foregoing resolutions, for Board approval
as quickly as possible, but in no event later than the Board’s February 2014 meeting.”
To comply with the five day business day notice requirement, the Standards Committee will meet to
consider this waiver request on December 11, 2013. Notice of the Standards Committee’s meeting has
been announced and posted on the NERC website. Additional details about the waiver request are
included below, and should a waiver be granted by the Standards Committee, it will be posted on the
project page.
Authority
Pursuant to Section 16 of the NERC Standard Processes Manual, the Standards Committee may reduce
the days for formal comment and ballot for good cause shown and to meet a Board’s deadline.
Justification for Waiver Request
On November 7, 2013 the Board passed a resolution that, among other things, directed the Standards
Committee and relevant Standards Drafting Team (SDT) to develop a combined COM-002 and COM-003
Standard and requested “that the Standards Committee direct the standard drafting team to work
toward providing an industry approved combined standard, as contemplated by the foregoing
resolutions, for Board approval as quickly as possible, but in no event later than the Board’s February
2014 meeting.” The Project 2007-02 SDT has been working to draft a COM Standard that is responsive to
the Board’s resolution.
The defined term “Reliability Directive” is currently being considered by the Project 2007-02 SDT in
proposed Reliability Standard COM-002-4. The same term is used in revised TOP and IRO Standards
pending with the Federal Energy Regulatory Commission (FERC). On November 21, 2013, FERC issued a
Notice of Proposed Rulemaking (NOPR) proposing to remand the TOP and IRO Standards including the
definition of “Reliability Directive.” As a result of the NOPR, the Project 2007-02 SDT is also considering
alternatives to using the term “Reliability Directive.” The SDT needs additional time to conduct outreach
to the IRO and TOP SDTs to obtain feedback on the options currently under consideration for
COM-002-4 with respect to the definition of “Reliability Directive.”
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Currently, to meet the Board deadline, the SDT would likely need to post on or about December 4, 2013
for a full 45-day comment and ballot period. In order to provide the Project 2007-02 SDT time to
coordinate with the IRO and TOP SDTs and meet the February Board deadline, a reduction in the
comment and ballot period is needed from 45 days to 30 days.
For more information or assistance, please contact Howard Gugel,
Director of Standards Development, or by phone at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Notice of Request to Waive the Standard Process
Project 2007-02 | COM-002 and COM-003 | December 2013
2
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Project 2007-02 Posting 8
Frequently Asked Questions Guide
General Questions
1. What were the inputs that drove the development of posting 8 of Project 2007-02?
The NERC Board of Trustees’ November 7th, 2013 Resolution for Operating Personnel Communication
Protocols, discussed below;
Two separate surveys distributed to a sample of industry experts by the Director of Standards
Development and the Standards Committee Chair requesting feedback on the draft standard; and
Consultation on the use of the term “Reliability Directive” in the COM-002-4 standard with the Project
2007-03 Real-time Transmission Operations Standard Drafting Team and the Project 2006-06
Reliability Coordination Standard Drafting Team.
Industry stakeholder comments from previous drafts of Project 2007-02.
2. Why was the term “Reliability Directive” removed from the definition of Operating Instruction?
The OPCP SDT debated whether to remove the term “Reliability Directive” in response to comments
suggesting it should be removed from the definition of “Operating Instruction” and in light of FERC’s
issuance of the TOP/IRO Notice of Proposed Rulemaking (NOPR), which proposes to remand the definition
of “Reliability Directive” along with the proposed TOP and IRO standards. To avoid unnecessary
complications with the timing of the NOPR and posting 8, the OPCP SDT consulted with the Project 200703 Real-time Transmission Operations and the Project 2006-06 Reliability Coordination Standard Drafting
Teams to ask whether they believed removal of the term “Reliability Directive” in the COM-002-4
standard would cause concerns. Both teams agreed that the COM-002-4 standard did not need to require
a protocol to identify Reliability Directives as such and that the definition of Operating Instruction could
be used absent the term Reliability Directive in COM-002-4 to set the protocols. The OPCP SDT ultimately
voted to remove the term. The OPCP SDT also decided to incorporate the phrase “Operating Instruction
during an Emergency” in certain Requirements, where needed, to identify Requirements that are subject
to a zero-tolerance compliance/enforcement approach.
3. Why does this standard apply to Generator Operators and Distribution Providers?
The OPCP SDT included these Functional Entities in the Applicability section because they can be and are
on the receiving end of some Operating Instructions. The OPCP SDT determined that it would leave a gap
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
to not cover them in a standard that addresses communications protocols for operating personnel. The
inclusion of Distribution Providers as an applicable entity also responds to FERC’s directive in Order No.
693 to add them as applicable entities to the communications standard. The inclusion of Distribution
Providers and Generator Operators is also consistent withwith the currently approved COM-002-3
standard, which the Board directed be combined with COM-003-1.
Recognizing that Generator Operators and Distribution Providers typically only receive Operating
Instructions, the OPCP SDT proposed that only Requirements R3 and R6 apply to these Functional Entities.
4. What does the term documented communications protocols refer to?
The term documented communication protocols in R1 refers to a set of required protocols specific to the
Functional Entity and the Functional Entities they must communicate with. An entity should include as
much detail as it believes necessary in their documented protocols, but they must address all of the
applicable parts of Requirement R1. Where an entity does not already have a set of documented
protocols that meet the parts of Requirement R1, the entity must develop the necessary communications
protocols. Entities may also adopt the documented protocols of another entity as its own
communications protocols, but the entity must maintain its own set of documented communications
protocols to meet Requirement R1.
5. Is this a “zero tolerance” standard
The standard uses the phrase “Operating Instruction during an Emergency” in certain Requirements (R5,
R6, R7) to provide a demarcation for what is subject to a “zero tolerance” compliance/enforcement
approach and what is not. This is necessary to allow the creation of Violation Severity Levels for each
compliance/enforcement approach. Where “Operating Instruction during an Emergency” is not used, an
entity will be assessed under a compliance/enforcement approach that focuses on whether or not an
entity met the initial training Requirement (either R2 or R3) and whether or not an entity performed
the assessment and took corrective action according to Requirement R4. The proposed COM-002-4
does not contain a Requirement to adhere to all documented communications protocols during nonEmergency conditions. Under COM-002-4, the assessment and training documentation will provide
auditors assurance that responsible entities are using their documented communications protocols and
taking corrective actions, as necessary.
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Compliance/enforcement is measured differently using the operating condition as
an indicator of which compliance/enforcement approach applies.
Project 2007-02 Frequently Asked Questions Guide
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6. Do any of the proposed requirements require the use of three-part communication when issuing
or receiving an Operating Instruction outside of an Emergency?
Compliance with the standard during non-Emergencies is based on whether or not an entity met the
initial training Requirement (either R2 or R3) and whether or not an entity performed the assessment and
took corrective action according to Requirement R4. An instance of an Operating Instruction outside of
an Emergency not using three-part communication, or any of the other protocols in Requirement R1, is
not in and of itself a violation of any requirement of COM-002-4. However, an entity will need be using
three-part communication when issuing or receiving an Operating Instruction outside of an Emergency in
order to complete the assessment of adherence to the entities’ documented communications protocols.
7. Why are entities required to assess the adherence of its operating personnel to the documented
communication protocols the entity developed and provide feedback?
Requiring entities to assess and provide feedback to its operating personnel, was also included in the
November 7, 2013 NERC Board of Trustees’ resolution as an element to include in the standard. Further,
the OPCP SDT believes that it is good operating practice for an entity to periodically evaluate the
effectiveness of their protocols and improve them when possible. Most entities currently engage in this
type of assessment activity for their operating personnel. This assessment and feedback activity by the
entity improves reliability as it provides a shorter evaluation and correction cycle than a traditional audit
cycle, while reducing the associated compliance burden as well.
Additionally, the OPCP SDT believes it is good operating practice to provide operators with performance
feedback on their adherence to the entity’s documented protocols. Doing so, provides entities an
opportunity to evaluate the performance of their operating personnel and take corrective actions where
necessary, which could prevent a miscommunication from occurring and thus possibly prevent an event
which could be harmful to the reliability of the Bulk Electric System.
8. Should the BA, RC, and TOP provide their protocols to the GOPs and DPs and each other?
While an entity may choose to provide their protocols to entities to which they communicate, there is not
a mandatory and enforceable requirement that they do so.
9. Why is the standard not applicable to Transmission Owners?
Please refer to the Functional Model, found at http://www.nerc.com/pa/Stand/Pages/
FunctionalModel.aspx. In the document, the following is provided for the Transmission Operator:
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3
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The Transmission Operator operates or directs the operation of transmission
facilities, and maintains local-area reliability, that is, the reliability of the
system and area for which the Transmission Operator has responsibility. The
Transmission Operator achieves this by operating the transmission system
within its purview in a manner that maintains proper voltage profiles and
System Operating Limits, and honors transmission equipment limits
established by the Transmission Owner. The Transmission Operator is under
the Reliability Coordinator’s direction respecting wide-area reliability
considerations, that is, considerations beyond those of the system and area for
which the Transmission Operator has responsibility and that include the
systems and areas of neighboring Reliability Coordinators. The Transmission
Operator, in coordination with the Reliability Coordinator, can take action,
such as implementing voltage reductions, to help mitigate an Energy
Emergency, and can take action in system restoration.
The following is provided for the Transmission Owner:
The Transmission Owner owns its transmission facilities and provides for the
maintenance of those facilities. It also specifies equipment operating limits,
and supplies this information to the Transmission Operator, Reliability
Coordinator, and Transmission Planner and Planning Coordinator. In many
cases, the Transmission Owner has contracts or interconnection agreements
with generators or other transmission customers that would detail the terms
of the interconnection between the owner and customer.
While the Transmission Owner owns the facilities, the Transmission Operator operates the
facilities, and as such is subject to this standard. In the case where a Transmission Owner
operates facilities, that Transmission Owner is bundled with a Reliability Coordinator or
Transmission Operator, and as such would be covered by the standard.
10. If an entity cannot complete a task included in an Operating Instruction, are they noncompliant?
COM-002-4 deals with communication protocols, not actions taken by any entity. If an entity does not
take action on an Operating Instruction, it may be a violation of another standard, but is not a violation of
COM-002-4.
11. A GOP contacts its TOP and notifies the TOP that a generator is about to trip due to a tube leak.
Is this considered an Operating Instruction?
No. This is not a command; it is simply relaying information about the generator to the Transmission
Operator.
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12. If a Distribution Provider cannot operate a BES Element, would this standard apply to them?
Distribution Providers are applicable entities for this standard. However, if they never receive an
Operating Instruction due to their particular circumstance, they would not need to prove compliance with
Requirements R3 and R6.
Requirement R1 and Measure M1
13. Pursuant to R1, is it correct that an oral two-party, person-to-person Operating Instruction
requires three part communication, but a single-party to multiple-party burst Operating
Instruction message only requires two part communication?
Yes. Since the use of three-part communications is not practical when issuing a single-party to multipleparty burst Operating Instruction, it is necessary to include a different set of protocols for these
situations.
14. Can you provide some examples of what is meant by written Operating Instructions as
contemplated in Requirement R1 Parts 1.1 and 1.4 - 1.6?
One example of a written Operating Instruction is a written switching order. Another example is an
Operating Instruction issued by using a text message.
15. Please explain how the current draft does not conflict with TOP-002 R18 (uniform line
identifiers)?
Project 2007-03 chose to eliminate TOP-002-2a, Requirement R18 when it developed TOP-002-3. This
Requirement stated “Neighboring Balancing Authorities, Transmission Operators, Generator Operators,
Transmission Service Providers and Load Serving Entities shall use uniform line identifiers when referring
to transmission facilities of an interconnected network.” COM-002-4, while reintroducing the concept of
line identifiers, limits the scope to only Transmission interface Elements or Transmission interface
Facilities (e.g. tie lines and tie substations) for Operating Instructions. This supports both parties being
familiar with each other’s interface Elements and Facilities, minimizing hesitation and confusion when
referring to equipment for the Operating Instruction.
16. Can you explain what "specify when time identification required"? Is this just for entities in
multiple time zones?
The OPCP SDT has included this part to add necessary clarity to Operating Instructions to reduce the risk
of miscommunications. The inclusion of “specify when time identification required” allows for an entity to
evaluate its particular circumstances and communications to determine when it may be appropriate to
use time identification in its Operating Instructions. The drafting recognized from comments the need to
provide this flexibility while still requiring an entity to address this part in its documented communication
protocols. Clarifying time and time zone (where necessary) contributes to reducing misunderstandings
and reduces the risk of a grave error during BES operations. This is not exclusively for entities in multiple
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5
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time zones, but Operating Instructions between entities in multiple time zones is one example of
instances that may need time identification when issuing and receiving Operating Instructions.
17. Why did the drafting team remove the protocol requiring alphanumeric clarifiers?
Based on feedback from industry and consideration of the NERC Board resolution, the drafting team
chose to remove alphanumeric clarifiers as a required protocol. Entities are free to include it in their
documented communication protocols.
18. Why is there a requirement for the use of the English language?
The drafting team included this part to carry forward the same use of English language included in COM001-1, Requirement R4 and to retire this requirement from COM-001. The requirement continues to
permit the issuer and receiver to use an agreed to alternate language. This has been retained since use of
an alternate language on a case-by-case basis may serve to better facilitate effective communications
where the use of English language may create additional opportunities for miscommunications. Part 1.1
requires the use of English language when issuing oral or written (e.g. switching orders) Operating
Instructions. This creates a standard language (unless agreed to otherwise) for use when issuing
commands that could change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. It also clarifies that an alternate language can be
used internally within the organization. The phrase has been modified slightly from the language in COM001-1, Requirement R4 to incorporate the term “Operating Instruction,” which defines the
communications that require the use of the documented communications protocols.
Requirements R2 and R3 and Measures M2 and M3
19. Is there an obligation on the part of the entity issuing an Operating Instruction to ensure the
receiving operator is trained to receive it?
No. It is the responsibility of the receiving entity to ensure that their operator has received training prior
to receiving an Operating Instruction.
20. Why is there a requirement to conduct initial training?
The OPCP SDT has included an initial training requirement in the standard in response to the NERC Board
of Trustees’ resolution, which directs that a training requirement be included in the COM-002-4 standard.
Additionally, requiring entities that issue and/or receive Operating Instructions to conduct initial training
with their operating personnel will ensure that all applicable operators will be trained in three-part
communication. The OPCP SDT believes this training will reduce the possibility of a miscommunication,
which could eventually lead to action or inaction harmful to the reliability of the Bulk Electric System.
Ongoing training would fall under an entity’s training program in PER-005 or could be listed as a type of
corrective action under Requirement R4. As such, this requirement is not in conflict with PER-005, but
complements it.
Project 2007-02 Frequently Asked Questions Guide
6
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21. Current operating personnel issue and receive Operating Instructions now and thus it is not
possible to train them on documented protocols *prior* to their issuing or receiving their first
Operating Instruction. If training takes place before the enforcement date for COM-002-4,
would an entity meet the expectations of Requirement R2 and/or R3?
Yes.
Requirement R4 and Measure M4
22. Would you please provide more specificity as to how the R.4.1 and 4.2 assessments may be
performed?
An entity could perform an assessment by listening to random samplings of each of their operating
personnel issuing and/or receiving Operating Instructions. If there were instances where an Operator
deviated from the entity’s protocols, the entity would provide feedback to the operator in question in any
method it sees as appropriate. An example would be counseling or retraining the operator on the
protocols.
An entity could assess the effectiveness of its protocols by reviewing instances where operators deviated
from those protocols and determining if whether the deviations were caused by operator error or by
flaws in the protocols that need to be changed.
23. Doesn’t Measure M4 extend beyond the scope of the requirement when it addresses
communications which deviated from the protocol and contributed to an emergency?
The purpose of COM-002-4 is “To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of miscommunication that could lead
to action or inaction harmful to the reliability of the Bulk Electric System (BES).” If the deviation from the
protocol contributed to an emergency, the purpose of this standard was not met. The entity must
determine what caused that deviation and address any necessary corrective actions.
Requirements R5 and R6 and Measures M5 and M6
24. What is defined as an Emergency and who is responsible for declaring when an Emergency
begins and ends?
The NERC Glossary of Terms defines Emergency as “Any abnormal system condition that requires
automatic or immediate manual action to prevent or limit the failure of transmission facilities or
generation supply that could adversely affect the reliability of the Bulk Electric System.” It is expected
that these are abnormal and rare circumstances. There is not an expectation that an Emergency be
declared. For further information, please refer to Question 15.
25. Is it a violation of R5 if three-part communication is not used, but an alternative action is taken?
Project 2007-02 Frequently Asked Questions Guide
7
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If an operator issues an Operating Instruction during an Emergency and, based on the response from the
receiver, or lack thereof, chooses to take an alternative action, that operator has satisfied Requirement R5
and is not in violation.
26. How does the SDT envision operators differentiating, during Real-time, between Emergency
Operating Instructions and non-emergency Operating Instructions? Are the operators to
explicitly say "this is an Emergency Operating Instruction"?
Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an
Emergency” in them does not require a different set of protocols to be used during Emergencies or
mandate the identification of a communication as an “Operating Instruction during an Emergency.” The
same protocols are required to be used in connection with the issuance of Operating Instructions for all
operating conditions. Their use is measured for compliance/enforcement differently using the operating
condition as an indicator of which compliance/enforcement approach applies. In other words, it is not the
drafting team’s expectation that the operator must differentiate between Emergency and non-Emergency
Operating Instructions.
27. Does this standard require TOPs to provide evidence of another parties' compliance in Measure
M6?
No. The Measures provide various options that the drafting team considered as ways to demonstrate
compliance for Requirement R6. It is not an exhaustive list, and in no way places an expectation on any
entity that they must provide evidence of another party's compliance. It simply provides a few options to
consider.
28. Can you provide an example of an alternative action being taken?
The following scenario is provided as an example of an alternative action:
A Transmission Operator (TOP) calls a Generator Operator (GOP) to reduce generation due to an
Emergency. The GOP does not respond verbally. At that point the TOP could:
Ask if the GOP understood the Operating Instruction (alternative action).
Hang up and redial the GOP, assuming that the communication line was dead (alternative action),
Request a different generator that is effective to reduce (alternative action);
or
Call a different contact at the GOP (alternative action)
29. Must the receiver repeat the Operating Instruction back verbatim?
No. The Operating Instruction does not have to be repeated verbatim. The issuer must confirm that the
receiver’s response of the Operating Instruction was correct.
Project 2007-02 Frequently Asked Questions Guide
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement Reminder
Project 2007-02 Operating Personnel Communication Protocols
Additional Ballot and Non-binding Poll Now Open through January 31, 2014
Now Available
An additional ballot for COM-002-4 – Operating Personnel Communication Protocols and non-binding
poll of the associated Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) are open
through 8 p.m. Eastern on Friday, January 31, 2014.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
definition by clicking here.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a final
ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement- Update
Project 2007-02 – Operating Personnel Communications Protocols
Formal Comment Period and RSAW Posted for Industry Comments: January 2 –
31, 2014
Additional Ballot and Non-binding Poll: January 22 – 31, 2014
Now Available
A 30-day formal comment period for COM-002-4 – Operating Personnel Communication Protocols is
open through 8 p.m. Eastern on Friday, January 31, 2014. An additional ballot of COM-002-4 and a
non-binding poll of the associated VRFs and VSLs will be conducted beginning on Wednesday, January
22, 2014 through 8 p.m. Eastern on Friday, January 31, 2014.
On December 11, 2013, the NERC Standards Committee authorized a waiver of the standard process,
in accordance with Section 16 of the Standard Processes Manual, to shorten this comment period
from 45 days to 30 days with a ballot during the last 10 days of the comment period to meet the
NERC Board of Trustees requested deadline. A link to the waiver request is available on the project
page.
In response to comments received during the last comment period for COM-002-4 and other input, the
drafting team has created a new communications standard, which requires the use of standardized
communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Friday, January 31,
2014. Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Arielle Cunningham. An off-line, unofficial copy of the comment form is
posted on the project page.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Friday, January 31, 2014. The
draft RSAW is posted on the project page. Please submit comments on the draft RSAW using the RSAW
comment form to [email protected].
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For more information or assistance, please contact Arielle Cunningham,
Standards Development Administrator at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement- Update
Project 2007-02 – Operating Personnel Communications Protocols
Formal Comment Period and RSAW Posted for Industry Comments: January 2 –
31, 2014
Additional Ballot and Non-binding Poll: January 22 – 31, 2014
Now Available
A 30-day formal comment period for COM-002-4 – Operating Personnel Communication Protocols is
open through 8 p.m. Eastern on Friday, January 31, 2014. An additional ballot of COM-002-4 and a
non-binding poll of the associated VRFs and VSLs will be conducted beginning on Wednesday, January
22, 2014 through 8 p.m. Eastern on Friday, January 31, 2014.
On December 11, 2013, the NERC Standards Committee authorized a waiver of the standard process,
in accordance with Section 16 of the Standard Processes Manual, to shorten this comment period
from 45 days to 30 days with a ballot during the last 10 days of the comment period to meet the
NERC Board of Trustees requested deadline. A link to the waiver request is available on the project
page.
In response to comments received during the last comment period for COM-002-4 and other input, the
drafting team has created a new communications standard, which requires the use of standardized
communication protocols during normal and emergency operations to improve situational awareness
and shorten response time.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period on the draft standard is open through 8 p.m. Eastern on Friday, January 31,
2014. Please use this electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Arielle Cunningham. An off-line, unofficial copy of the comment form is
posted on the project page.
A comment period on the draft RSAW is open through 8 p.m. Eastern on Friday, January 31, 2014. The
draft RSAW is posted on the project page. Please submit comments on the draft RSAW using the RSAW
comment form to [email protected].
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For more information or assistance, please contact Arielle Cunningham,
Standards Development Administrator at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement: Project 2007-02—Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications
Protocols COM-002-4
Additional Ballot and Non-Binding Poll Results
Now Available
An additional ballot of COM-002-4 – Operating Personnel Communications Protocols and non-binding
poll of the associated Violation Risk Factors and Violation Severity Levels concluded at 8 p.m. Eastern
on Tuesday, February 4, 2014.
The standard achieved a quorum and received sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the
ballots.
Approval
Quorum: 76.03%
Approval: 71.86%
Non-Binding Poll Results
Quorum: 77.19%
Supportive Opinions: 66.81%
Background information for this project can be found on the project page.
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-02 OPCP COM-002-4 | February 2014
2
NERC
Standards
20140514-5129
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Newsroom • Site Map • Contact NERC
Advanced Search
User Name
Ballot Results
Ballot Name: Project 2007-02 COM-002-4
Password
Ballot Period: 1/22/2014 - 2/4/2014
Ballot Type: Additional Ballot
Log in
Register
Total # Votes: 314
Total Ballot Pool: 413
Quorum: 76.03 % The Quorum has been reached
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Weighted Segment
71.86 %
Vote:
Ballot Results: The Ballot has Closed
Home Page
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
9
107
1
51
0.622
31
0.378
0
5
20
11
0.9
8
0.8
1
0.1
0
1
1
97
1
42
0.636
24
0.364
0
3
28
39
1
18
0.692
8
0.308
0
0
13
88
1
42
0.677
20
0.323
0
5
21
50
1
27
0.675
13
0.325
0
2
8
0
0
0
0
0
0
0
0
0
7
0.3
2
0.2
1
0.1
0
0
4
5
0.1
1
0.1
0
0
0
0
4
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Standards
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10 Segment
10
Totals
9
0.8
7
0.7
1
0.1
0
1
0
413
7.1
198
5.102
99
1.998
0
17
99
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
Ameren Services
Kirit Shah
Negative
1
American Electric Power
Paul B Johnson
Negative
1
1
American Transmission Company, LLC
Arizona Public Service Co.
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
1
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Glen Sutton
James Armke
Scott J Kinney
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
1
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
1
1
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
John C Fontenot
John Brockhan
1
Central Electric Power Cooperative
Michael B Bax
1
City of Pasadena
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Marco A Sustaita
1
City Utilities of Springfield, Missouri
Jeff Knottek
1
1
City Water, Light & Power of Springfield
Clark Public Utilities
Shaun Anders
Jack Stamper
1
Chang G Choi
1
Cleco Power LLC
Danny McDaniel
1
1
1
1
1
1
1
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
1
Dominion Virginia Power
Michael S Crowley
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
NERC
Notes
COMMENT
RECEIVED SERC OC
SUPPORTS
THIRD PARTY
COMMENTS (thomas foltz
- AEP)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing and
NRECA)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (I support
Dominion's
previously
NERC
Standards
20140514-5129
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1
Duke Energy Carolina
Doug E Hils
Negative
1
Empire District Electric Co.
Ralph F Meyer
Negative
1
Entergy Services, Inc.
Edward J Davis
Negative
1
1
1
1
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
1
Georgia Transmission Corporation
Jason Snodgrass
1
Gordon Pietsch
1
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JEA
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Michael Gammon
Negative
1
1
1
1
1
1
1
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
1
1
1
1
1
submitted
comments)
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Affirmative
Michael Moltane
Abstain
Ted Hobson
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
1
M & A Electric Power Cooperative
William Price
1
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Affirmative
1
Nebraska Public Power District
Cole C Brodine
Negative
1
1
New York Power Authority
New York State Electric & Gas Corp.
Bruce Metruck
Raymond P Kinney
1
Northeast Missouri Electric Power Cooperative Kevin White
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Doug Peterchuck
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (NPPD)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS SPP Stnd
Review Team
Affirmative
COMMENT
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
NERC
Standards
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1
Oncor Electric Delivery
Jen Fiegel
1
1
1
Orlando Utilities Commission
Pacific Gas and Electric Company
PECO Energy
Brad Chase
Bangalore Vijayraghavan
Ronald Schloendorn
1
Platte River Power Authority
John C. Collins
1
1
1
1
1
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
1
1
1
1
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Affirmative
Affirmative
Affirmative
Affirmative
1
Santee Cooper
Terry L Blackwell
Negative
1
Seattle City Light
Pawel Krupa
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
1
1
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Rich Salgo
Long T Duong
Steven Mavis
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southern Illinois Power Coop.
William Hutchison
Negative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
1
Tennessee Valley Authority
Larry G Akens
Negative
1
Trans Bay Cable LLC
Steven Powell
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
Tucson Electric Power Co.
John Tolo
1
United Illuminating Co.
Jonathan Appelbaum
1
1
Westar Energy
Western Area Power Administration
Allen Klassen
Brandy A Dunn
1
Negative
Negative
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Rod Noteboom
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
2
Midwest ISO, Inc.
Marie Knox
2
2
2
2
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NRECA and
ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Alice Ireland,
Xcel Energy)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
COMMENT
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NERC
Standards
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3
Alabama Power Company
Richard J. Mandes
3
Alameda Municipal Power
Douglas Draeger
3
Ameren Services
Mark Peters
3
APS
Steven Norris
Affirmative
3
Associated Electric Cooperative, Inc.
Chris W Bolick
Negative
3
3
3
3
3
Atlantic City Electric Company
NICOLE BUCKMAN
Avista Corp.
Robert Lafferty
BC Hydro and Power Authority
Pat G. Harrington
Blachly-Lane Electric Co-op
Bud Tracy
Bonneville Power Administration
Rebecca Berdahl
Central Electric Cooperative, Inc. (Redmond,
Dave Markham
Oregon)
3
3
Central Electric Power Cooperative
Adam M Weber
3
3
3
3
3
3
3
3
3
3
3
3
3
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Negative
Negative
Negative
Affirmative
Affirmative
Negative
3
Colorado Springs Utilities
Charles Morgan
Negative
3
3
3
3
3
3
3
3
3
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
3
3
3
3
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities group
comments)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See
Dominion's
submitted
comments)
Affirmative
Affirmative
3
Florida Power Corporation
Lee Schuster
Negative
3
Georgia System Operations Corporation
Scott McGough
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Michelle A Corley
Connie B Lowe
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Cleco Corporation
Dominion Resources, Inc.
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
3
3
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
Great River Energy
Hydro One Networks, Inc.
Brian Glover
David Kiguel
3
KAMO Electric Cooperative
Theodore J Hilmes
3
3
3
3
3
3
3
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
3
M & A Electric Power Cooperative
Stephen D Pogue
3
3
3
3
3
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Greg C. Parent
Thomas C. Mielnik
Jack W Savage
Steven M. Jackson
John S Bos
3
Nebraska Public Power District
Tony Eddleman
3
3
New York Power Authority
Niagara Mohawk (National Grid Company)
David R Rivera
Michael Schiavone
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Nebraska
Public Power
District
(NPPD)
comments)
Affirmative
Affirmative
3
Northeast Missouri Electric Power Cooperative Skyler Wiegmann
Negative
3
3
Northern Indiana Public Service Co.
Northern Lights Inc.
William SeDoris
Jon Shelby
Affirmative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
3
3
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
3
Owensboro Municipal Utilities
Thomas T Lyons
Negative
3
3
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
John H Hagen
Rick Paschall
Affirmative
3
Platte River Power Authority
Terry L Baker
Negative
3
3
3
3
3
3
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Raft River Rural Electric Cooperative
Michael Mertz
Thomas G Ward
Robert Reuter
Jeffrey Mueller
Erin Apperson
Heber Carpenter
3
Rutherford EMC
Thomas Haire
3
3
3
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
James Leigh-Kendall
Ken Dizes
John T. Underhill
3
Santee Cooper
James M Poston
Negative
3
Seattle City Light
Dana Wheelock
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC's
Comment)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
SUPPORTS
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Seminole Electric Cooperative, Inc.
James R Frauen
Negative
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
3
3
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
3
Tennessee Valley Authority
Ian S Grant
3
Tri-County Electric Cooperative, Inc.
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
3
Umatilla Electric Cooperative
Westar Energy
Steve Eldrige
Bo Jones
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC)
Negative
COMMENT
RECEIVED
Affirmative
3
Wisconsin Electric Power Marketing
James R Keller
Negative
3
Xcel Energy, Inc.
Michael Ibold
Negative
4
4
4
4
4
4
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
4
4
THIRD PARTY
COMMENTS (NRECA)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Matt
Beilfuss)
SUPPORTS
THIRD PARTY
COMMENTS (Xcel Energy)
Affirmative
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
Affirmative
4
City Utilities of Springfield, Missouri
John Allen
4
4
4
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
David Frank Ronk
Rick Syring
Daniel Herring
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
4
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Frank Gaffney
Cairo Vanegas
Affirmative
Affirmative
4
Georgia System Operations Corporation
Guy Andrews
4
4
Illinois Municipal Electric Agency
Imperial Irrigation District
Bob C. Thomas
Diana U Torres
4
Indiana Municipal Power Agency
Jack Alvey
4
4
4
4
4
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Negative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Scott
McGough's
comments)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
4
Oklahoma Municipal Power Authority
Ashley Stringer
Negative
4
Old Dominion Electric Coop.
Mark Ringhausen
Negative
4
Pacific Northwest Generating Cooperative
Aleka K Scott
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
SUPPORTS
THIRD PARTY
COMMENTS (SPP and
NRECA)
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool)
SUPPORTS
THIRD PARTY
COMMENTS (NRECA)
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
4
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Henry E. LuBean
Affirmative
John D Martinsen
Affirmative
Mike Ramirez
Hao Li
Affirmative
Affirmative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
4
4
4
4
4
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Utility Services, Inc.
West Oregon Electric Cooperative, Inc.
Steven McElhaney
Richard L Koch
Keith Morisette
Brian Evans-Mongeon
Marc M Farmer
4
Wisconsin Energy Corp.
Anthony Jankowski
4
5
5
WPPI Energy
AEP Service Corp.
AES Corporation
Todd Komplin
Brock Ondayko
Leo Bernier
5
Amerenue
Sam Dwyer
5
Arizona Public Service Co.
Edward Cambridge
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
5
5
5
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
5
5
Cleco Power
Stephanie Huffman
Negative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Matt
Beilfuss, We
Energies)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
comments)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Aeci)
Abstain
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Affirmative
Affirmative
Affirmative
Affirmative
Negative
5
Cogentrix Energy, Inc.
Mike D Hirst
5
Colorado Springs Utilities
Jennifer Eckels
5
5
5
5
5
5
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
5
Dominion Resources, Inc.
Mike Garton
Negative
5
Duke Energy
Dale Q Goodwine
Negative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
SUPPORTS
THIRD PARTY
COMMENTS (Comments of
NRECA)
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (Dominion)
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
SUPPORTS
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
5
5
5
5
5
5
5
5
5
E.ON Climate & Renewables North America,
LLC
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
5
Kansas City Power & Light Co.
Brett Holland
5
5
Kissimmee Utility Authority
Lakeland Electric
Mike Blough
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
5
5
5
5
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
David Gordon
Abstain
5
5
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Steven Grego
Mike Avesing
Affirmative
Affirmative
5
Nebraska Public Power District
Don Schmit
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
5
5
Dana Showalter
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
5
5
5
5
5
5
5
5
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Annette M Bannon
Tim Kucey
Steven Grega
Abstain
Affirmative
Michiko Sell
Affirmative
5
5
5
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Tom Flynn
Bethany Hunter
William Alkema
Affirmative
Affirmative
Affirmative
5
Santee Cooper
Lewis P Pierce
5
Seattle City Light
Michael J. Haynes
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
SUPPORTS
THIRD PARTY
COMMENTS (ACES, SERC
OC, and
NRECA)
Affirmative
5
5
5
Brenda K. Atkins
COMMENT
RECEIVED
Affirmative
Affirmative
Tim Hattaway
Seminole Electric Cooperative, Inc.
COMMENT
RECEIVED
Affirmative
Affirmative
PowerSouth Energy Cooperative
5
COMMENT
RECEIVED
Affirmative
Affirmative
5
5
THIRD PARTY
COMMENTS (SERC OC)
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Review
Group)
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Endorses
NRECA
comments)
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
Affirmative
5
Southern Company Generation
William D Shultz
Negative
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Chris Mattson
RJames Rocha
Scott M. Helyer
Affirmative
Affirmative
Abstain
5
Tennessee Valley Authority
David Thompson
Negative
5
U.S. Army Corps of Engineers
Melissa Kurtz
Negative
5
5
U.S. Bureau of Reclamation
Westar Energy
Martin Bauer
Bryan Taggart
Affirmative
5
Wisconsin Electric Power Co.
Linda Horn
Negative
5
WPPI Energy
Steven Leovy
5
Xcel Energy, Inc.
Liam Noailles
Negative
6
AEP Marketing
Edward P. Cox
Negative
6
Ameren Energy Marketing Co.
Jennifer Richardson
Negative
6
APS
Randy A. Young
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Negative
Cleco Power LLC
Robert Hirchak
Negative
6
Colorado Springs Utilities
Lisa C Rosintoski
Negative
6
6
6
6
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Affirmative
Affirmative
Duke Energy
Greg Cecil
6
6
6
6
6
6
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
6
6
6
6
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (Matt
Beilfuss)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz AEP)
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
6
6
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
COMMENT
RECEIVED
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
6
6
6
6
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Daniel Prowse
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Affirmative
6
Platte River Power Authority
Carol Ballantine
Negative
6
6
6
6
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Affirmative
Abstain
Affirmative
Affirmative
6
Santee Cooper
Michael Brown
6
Seattle City Light
Dennis Sismaet
Affirmative
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NRECA's
comments)
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
6
William T Moojen
Lujuanna Medina
6
6
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Michael C Hill
Benjamin F Smith II
Affirmative
6
Tennessee Valley Authority
Marjorie S. Parsons
Negative
6
Westar Energy
Western Area Power Administration - UGP
Marketing
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
6
Xcel Energy, Inc.
David F Lemmons
8
8
8
8
8
8
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Utility System Effeciencies, Inc. (USE)
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Frederick R Plett
Margaret Ryan
Robert L Dintelman
6
Affirmative
Affirmative
John J. Ciza
COMMENT
RECEIVED
COMMENT
RECEIVED Alice Ireland
Negative
Affirmative
Affirmative
Volkmann Consulting, Inc.
Terry Volkmann
9
William M Chamberlain
9
9
10
10
10
10
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
10
ReliabilityFirst Corporation
Anthony E Jablonski
Negative
10
10
10
10
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Carter B Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
9
COMMENT
RECEIVED
Negative
8
9
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
6
6
Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Negative
Donald Nelson
Affirmative
Diane J. Barney
https://standards.nerc.net/BallotResults.aspx?BallotGUID=1bf61745-6ae3-4ce1-b7fd-88be6031703a[2/5/2014 8:00:11 PM]
Abstain
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Non-Binding Poll Results
Project 2007-02 COM-002-4
Non-Binding Results
Non-Binding Poll
Project 2007-02 COM-002-4
Name:
Poll Period: 1/22/2014 - 2/4/2014
Total # Opinions: 291
Total Ballot Pool: 377
77.19% of those who registered to participate provided an opinion or an abstention;
Ballot Results: 66.81% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results
Segment
Member
1
Ameren Services
Kirit Shah
1
1
American Electric Power
Arizona Public Service Co.
Paul B Johnson
Robert Smith
Opinions
Comments
Negative
COMMENT
RECEIVED SERC OC
Abstain
Affirmative
1
Associated Electric Cooperative, Inc.
John Bussman
Negative
1
1
1
Glen Sutton
James Armke
Scott J Kinney
Affirmative
Affirmative
Abstain
1
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern
California
BC Hydro and Power Authority
1
Beaches Energy Services
Joseph S Stonecipher
1
1
Black Hills Corp
Bonneville Power Administration
Eric Egge
Donald S. Watkins
1
Kevin Smith
Abstain
Patricia Robertson
Abstain
1
Brazos Electric Power Cooperative, Inc.
1
1
Bryan Texas Utilities
John C Fontenot
CenterPoint Energy Houston Electric, LLC John Brockhan
1
Organization
Central Electric Power Cooperative
Tony Kroskey
Michael B Bax
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing and
NRECA)
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
City of Pasadena
Marco A Sustaita
1
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
Chang G Choi
1
City Utilities of Springfield, Missouri
Jeff Knottek
1
City Water, Light & Power of Springfield
Shaun Anders
1
Clark Public Utilities
Jack Stamper
1
Cleco Power LLC
Danny McDaniel
1
Colorado Springs Utilities
Paul Morland
1
Consolidated Edison Co. of New York
1
1
1
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
1
Deseret Power
James Tucker
1
Dominion Virginia Power
Michael S Crowley
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Duke Energy Carolina
Doug E Hils
Negative
1
Empire District Electric Co.
Ralph F Meyer
Negative
1
Entergy Services, Inc.
Edward J Davis
Negative
1
1
1
1
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
1
Georgia Transmission Corporation
Jason Snodgrass
1
Gordon Pietsch
Bob Solomon
1
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Hydro One Networks, Inc.
1
Hydro-Quebec TransEnergie
Bernard Pelletier
1
Molly Devine
Michael Moltane
1
Idaho Power Company
International Transmission Company
Holdings Corp
JEA
1
KAMO Electric Cooperative
Walter Kenyon
1
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Ajay Garg
Ted Hobson
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
Affirmative
1
1
SUPPORTS
THIRD PARTY
COMMENTS (spp)
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
Kansas City Power & Light Co.
Michael Gammon
1
Keys Energy Services
Stanley T Rzad
1
Lakeland Electric
Larry E Watt
1
Lee County Electric Cooperative
John W Delucca
1
LG&E Energy Transmission Services
Bradley C. Young
1
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
Robert Ganley
Affirmative
John Burnett
Affirmative
1
1
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Joe D Petaski
Danny Dees
Terry Harbour
Negative
Affirmative
Abstain
Negative
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Affirmative
Nebraska Public Power District
Cole C Brodine
Negative
1
New York Power Authority
Bruce Metruck
Affirmative
1
New York State Electric & Gas Corp.
Raymond P Kinney
1
Northeast Missouri Electric Power
Cooperative
Kevin White
1
1
Northeast Utilities
Northern Indiana Public Service Co.
David Boguslawski
Kevin M Largura
1
NorthWestern Energy
John Canavan
1
Ohio Valley Electric Corp.
Robert Mattey
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
Omaha Public Power District
Doug Peterchuck
1
Oncor Electric Delivery
Jen Fiegel
1
Orlando Utilities Commission
Brad Chase
1
Pacific Gas and Electric Company
Bangalore Vijayraghavan
1
PECO Energy
Ronald Schloendorn
1
1
1
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
John C. Collins
John T Walker
Brenda L Truhe
Non‐Binding Poll Results
Project 2007‐02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Affirmative
1
1
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS SPP Stnd
Review Team
Affirmative
Negative
COMMENT
RECEIVED
Abstain
Affirmative
Abstain
3
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
1
1
1
1
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Affirmative
Affirmative
Abstain
Affirmative
1
Santee Cooper
Terry L Blackwell
Negative
1
Seattle City Light
Pawel Krupa
1
Laurie Williams
Kenneth D. Brown
Affirmative
Abstain
Rod Noteboom
Abstain
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
1
Snohomish County PUD No. 1
South California Edison Company
Long T Duong
Steven Mavis
1
Southern Company Services, Inc.
Robert A. Schaffeld
Negative
1
Southern Illinois Power Coop.
William Hutchison
Negative
1
Southwest Transmission Cooperative,
Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
1
1
Tennessee Valley Authority
Trans Bay Cable LLC
Larry G Akens
Steven Powell
Abstain
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
1
1
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
John Tolo
Jonathan Appelbaum
Allen Klassen
1
Western Area Power Administration
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
Mark B Thompson
2
BC Hydro
2
2
California ISO
Electric Reliability Council of Texas, Inc.
2
Independent Electricity System Operator Barbara Constantinescu
2
ISO New England, Inc.
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NRECA and
ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Kathleen Goodman
4
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
2
Midwest ISO, Inc.
Marie Knox
2
New Brunswick System Operator
Alden Briggs
2
2
2
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Southwest Power Pool, Inc.
Charles H. Yeung
3
Alabama Power Company
Richard J. Mandes
3
Alameda Municipal Power
Douglas Draeger
3
Ameren Services
Mark Peters
3
APS
Steven Norris
3
Associated Electric Cooperative, Inc.
Chris W Bolick
3
3
Avista Corp.
BC Hydro and Power Authority
Robert Lafferty
Pat G. Harrington
3
Bonneville Power Administration
Rebecca Berdahl
3
Central Electric Power Cooperative
Adam M Weber
3
3
3
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
3
City of Clewiston
Lynne Mila
3
City of Farmington
Linda R Jacobson
3
City of Garland
Ronnie C Hoeinghaus
3
City of Green Cove Springs
Gregg R Griffin
3
City of Lodi, California
Elizabeth Kirkley
3
City of Palo Alto
Eric R Scott
3
City of Redding
Bill Hughes
3
City of Ukiah
Colin Murphey
Negative
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
3
Cleco Corporation
Michelle A Corley
Negative
3
Colorado Springs Utilities
Charles Morgan
Negative
3
3
3
3
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Russell A Noble
Non‐Binding Poll Results
Project 2007‐02 | November 2013
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities group
comments)
Affirmative
Affirmative
Affirmative
Affirmative
5
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
3
CPS Energy
Detroit Edison Company
Jose Escamilla
Kent Kujala
3
Entergy
Joel T Plessinger
3
3
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Stephan Kern
Joe McKinney
Affirmative
Affirmative
3
Florida Power Corporation
Lee Schuster
Negative
3
Georgia System Operations Corporation
Scott McGough
Negative
3
3
Great River Energy
Hydro One Networks, Inc.
Brian Glover
David Kiguel
3
KAMO Electric Cooperative
Theodore J Hilmes
3
Kansas City Power & Light Co.
Charles Locke
Affirmative
Affirmative
Affirmative
Affirmative
Negative
3
Kissimmee Utility Authority
Gregory D Woessner
3
Lakeland Electric
Mace D Hunter
3
Lincoln Electric System
Los Angeles Department of Water &
Power
Jason Fortik
Affirmative
Daniel D Kurowski
Affirmative
3
3
Louisville Gas and Electric Co.
Charles A. Freibert
M & A Electric Power Cooperative
Stephen D Pogue
Negative
3
3
Manitoba Hydro
MidAmerican Energy Co.
Greg C. Parent
Thomas C. Mielnik
Affirmative
Affirmative
3
Modesto Irrigation District
Jack W Savage
3
3
Municipal Electric Authority of Georgia
Muscatine Power & Water
Steven M. Jackson
John S Bos
SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric
Cooperative)
Affirmative
Abstain
3
Nebraska Public Power District
Tony Eddleman
Negative
3
New York Power Authority
Niagara Mohawk (National Grid
Company)
David R Rivera
Affirmative
Michael Schiavone
Affirmative
3
Northeast Missouri Electric Power
Cooperative
Skyler Wiegmann
3
Northern Indiana Public Service Co.
William SeDoris
Affirmative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
Non‐Binding Poll Results
Project 2007‐02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (aeci)
Affirmative
3
3
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southwest
Power Pool
(SPP)
comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
6
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COMMENTS (AECI)
3
Orange and Rockland Utilities, Inc.
David Burke
3
Owensboro Municipal Utilities
Thomas T Lyons
3
3
Pacific Gas and Electric Company
Platte River Power Authority
John H Hagen
Terry L Baker
3
PNM Resources
Michael Mertz
3
3
3
3
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Thomas G Ward
Robert Reuter
Jeffrey Mueller
Erin Apperson
3
Rutherford EMC
Thomas Haire
3
Sacramento Municipal Utility District
James Leigh-Kendall
3
Salmon River Electric Cooperative
Ken Dizes
3
Salt River Project
John T. Underhill
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Santee Cooper
James M Poston
Negative
3
Seattle City Light
Dana Wheelock
Abstain
3
Seminole Electric Cooperative, Inc.
James R Frauen
Negative
3
Sho-Me Power Electric Cooperative
Jeff L Neas
Negative
3
3
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Hubert C Young
Travis Metcalfe
3
Tampa Electric Co.
Ronald L. Donahey
3
Tennessee Valley Authority
Ian S Grant
3
Tri-County Electric Cooperative, Inc.
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
Westar Energy
Bo Jones
3
Wisconsin Electric Power Marketing
James R Keller
3
4
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
Michael Ibold
Kenneth Goldsmith
American Municipal Power
Kevin Koloini
4
Blue Ridge Power Agency
Duane S Dahlquist
4
Central Lincoln PUD
Shamus J Gamache
4
City of Austin dba Austin Energy
Reza Ebrahimian
Non‐Binding Poll Results
Project 2007‐02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (NRECA)
Abstain
3
4
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC's
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
SUPPORTS
THIRD PARTY
COMMENTS (NRECA)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
Abstain
Affirmative
Abstain
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
7
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
4
4
4
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
Kevin McCarthy
Tim Beyrle
Nicholas Zettel
Affirmative
4
City Utilities of Springfield, Missouri
John Allen
4
4
4
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
David Frank Ronk
Rick Syring
Daniel Herring
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
4
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Frank Gaffney
Cairo Vanegas
Affirmative
Abstain
4
Georgia System Operations Corporation
Guy Andrews
4
Illinois Municipal Electric Agency
Bob C. Thomas
4
Imperial Irrigation District
Diana U Torres
4
Indiana Municipal Power Agency
Jack Alvey
4
LaGen
Richard Comeaux
4
Madison Gas and Electric Co.
Joseph DePoorter
4
Modesto Irrigation District
Spencer Tacke
4
Northern California Power Agency
Tracy R Bibb
4
4
Ohio Edison Company
Oklahoma Municipal Power Authority
Douglas Hohlbaugh
Ashley Stringer
4
4
4
4
4
4
Old Dominion Electric Coop.
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Negative
Abstain
Affirmative
Abstain
Affirmative
John D Martinsen
Affirmative
Steven R Wallace
Keith Morisette
4
Wisconsin Energy Corp.
Anthony Jankowski
SUPPORTS
THIRD PARTY
COMMENTS (Scott
McGough's
comments)
Abstain
Henry E. LuBean
Mike Ramirez
Hao Li
COMMENT
RECEIVED
Abstain
Negative
4
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Affirmative
Affirmative
Affirmative
Mark Ringhausen
South Mississippi Electric Power
Association
Tacoma Public Utilities
4
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
SUPPORTS
THIRD PARTY
COMMENTS (NRECA)
Abstain
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Comments of
NRECA)
Steven McElhaney
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS -
8
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
(Matt Beilfuss,
We Energies)
4
WPPI Energy
Todd Komplin
5
AEP Service Corp.
Brock Ondayko
5
AES Corporation
Leo Bernier
5
Amerenue
Sam Dwyer
5
Arizona Public Service Co.
Edward Cambridge
5
Associated Electric Cooperative, Inc.
5
5
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Bonneville Power Administration
Francis J. Halpin
5
5
Matthew Pacobit
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
Calpine Corporation
Phillip Porter
5
City and County of San Francisco
Daniel Mason
5
5
5
5
City
City
City
City
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
of Austin dba Austin Energy
of Redding
of Tallahassee
Water, Light & Power of Springfield
5
Cleco Power
Stephanie Huffman
5
Cogentrix Energy, Inc.
Mike D Hirst
5
Colorado Springs Utilities
Jennifer Eckels
5
5
5
5
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
5
Deseret Power
Philip B Tice Jr
5
5
Detroit Edison Company
Dominion Resources, Inc.
Christy Wicke
Mike Garton
5
Duke Energy
Dale Q Goodwine
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
comments)
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Aeci)
Abstain
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
9
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
Dynegy Inc.
Dan Roethemeyer
5
E.ON Climate & Renewables North
America, LLC
Dana Showalter
5
Electric Power Supply Association
John R Cashin
5
Essential Power, LLC
Patrick Brown
5
Exelon Nuclear
Michael Korchynsky
5
ExxonMobil Research and Engineering
Martin Kaufman
5
5
5
5
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
5
Imperial Irrigation District
Marcela Y Caballero
5
JEA
John J Babik
Affirmative
5
Kansas City Power & Light Co.
Brett Holland
Negative
5
5
Kissimmee Utility Authority
Lakeland Electric
Mike Blough
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
5
Lincoln Electric System
Los Angeles Department of Water &
Power
Dennis Florom
Affirmative
Kenneth Silver
Affirmative
5
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Luminant Generation Company LLC
Mike Laney
5
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
Muscatine Power & Water
S N Fernando
Affirmative
David Gordon
Abstain
Steven Grego
Mike Avesing
Affirmative
Affirmative
5
5
5
Nebraska Public Power District
Don Schmit
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
5
North Carolina Electric Membership Corp. Jeffrey S Brame
5
Northern Indiana Public Service Co.
William O. Thompson
5
5
Occidental Chemical
Omaha Public Power District
Michelle R DAntuono
Mahmood Z. Safi
5
Orlando Utilities Commission
Richard K Kinas
5
Pacific Gas and Electric Company
Richard J. Padilla
5
PacifiCorp
Sandra L. Shaffer
5
Platte River Power Authority
Roland Thiel
Non‐Binding Poll Results
Project 2007‐02 | November 2013
COMMENT
RECEIVED
Affirmative
Affirmative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (SERC OC)
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP)
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (ACES, SERC
OC, and
NRECA)
Affirmative
Affirmative
Affirmative
10
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
Portland General Electric Co.
Matt E. Jastram
5
PowerSouth Energy Cooperative
Tim Hattaway
5
5
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Annette M Bannon
Tim Kucey
5
5
5
5
5
Affirmative
Abstain
Abstain
Steven Grega
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Affirmative
Abstain
Affirmative
5
Santee Cooper
Lewis P Pierce
5
Seattle City Light
Michael J. Haynes
5
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
5
Snohomish County PUD No. 1
Sam Nietfeld
5
South Carolina Electric & Gas Co.
Edward Magic
5
Southeastern Power Administration
Douglas Spencer
5
Southern California Edison Co.
Denise Yaffe
Negative
Affirmative
Negative
Southern Company Generation
William D Shultz
Negative
5
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Abstain
Abstain
U.S. Army Corps of Engineers
Melissa Kurtz
5
U.S. Bureau of Reclamation
Martin Bauer
5
Wisconsin Electric Power Co.
Linda Horn
5
WPPI Energy
Steven Leovy
5
6
Xcel Energy, Inc.
AEP Marketing
Liam Noailles
Edward P. Cox
6
Ameren Energy Marketing Co.
Jennifer Richardson
6
APS
Randy A. Young
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
Brenda S. Anderson
Lisa Martin
Non‐Binding Poll Results
Project 2007‐02 | November 2013
SUPPORTS
THIRD PARTY
COMMENTS (Endorses
NRECA
comments)
Affirmative
5
5
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (Southern
Company)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Negative
Abstain
Negative
SUPPORTS
THIRD PARTY
COMMENTS SERC OC
Affirmative
Affirmative
11
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
City of Redding
Marvin Briggs
Affirmative
6
Cleco Power LLC
Robert Hirchak
Negative
6
Colorado Springs Utilities
Lisa C Rosintoski
Negative
6
Consolidated Edison Co. of New York
Nickesha P Carrol
Affirmative
6
Duke Energy
Greg Cecil
6
Entergy Services, Inc.
Terri F Benoit
6
6
6
6
6
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
6
6
Paul Shipps
Eric Ruskamp
Affirmative
Affirmative
Brad Packer
Affirmative
6
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Brad Jones
Affirmative
6
Manitoba Hydro
Daniel Prowse
6
Modesto Irrigation District
James McFall
6
6
6
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
John Stolley
Saul Rojas
Joseph O'Brien
6
NRG Energy, Inc.
Alan Johnson
6
Omaha Public Power District
David Ried
6
6
6
6
6
PacifiCorp
Platte River Power Authority
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Scott L Smith
Carol Ballantine
Peter Dolan
Diane Enderby
Steven J Hulet
6
6
Santee Cooper
Michael Brown
6
Seattle City Light
Dennis Sismaet
6
Seminole Electric Cooperative, Inc.
Trudy S. Novak
6
6
Snohomish County PUD No. 1
South California Edison Company
William T Moojen
Lujuanna Medina
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Negative
SUPPORTS
THIRD PARTY
COMMENTS (See SPP
Comments)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (SERC)
Negative
SUPPORTS
THIRD PARTY
COMMENTS (NRECA's
comments)
Affirmative
Affirmative
12
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
6
Tampa Electric Co.
Benjamin F Smith II
6
Tennessee Valley Authority
Marjorie S. Parsons
6
Westar Energy
Grant L Wilkerson
6
Western Area Power Administration UGP Marketing
Peter H Kinney
6
John J. Ciza
Michael C Hill
8
Edward C Stein
8
James A Maenner
8
8
Massachusetts Attorney General
Roger C Zaklukiewicz
Frederick R Plett
8
Utility Services, Inc.
Brian Evans-Mongeon
8
Utility System Effeciencies, Inc. (USE)
Robert L Dintelman
8
Volkmann Consulting, Inc.
Terry Volkmann
9
California Energy Commission
William M Chamberlain
9
Commonwealth of Massachusetts
Department of Public Utilities
Donald Nelson
9
Public Utilities Commission of Ohio
Klaus Lambeck
10
10
10
10
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
10
ReliabilityFirst Corporation
Anthony E Jablonski
10
10
10
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Carter B Edge
Emily Pennel
Donald G Jones
10
Western Electricity Coordinating Council
Steven L. Rueckert
Non‐Binding Poll Results
Project 2007‐02 | November 2013
Negative
COMMENT
RECEIVED
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
13
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual or group. (71 Responses)
Name (48 Responses)
Organization (48 Responses)
Group Name (23 Responses)
Lead Contact (23 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (18 Responses)
Comments (71 Responses)
Question 1 (35 Responses)
Question 1 Comments (53 Responses)
Question 2 (37 Responses)
Question 2 Comments (53 Responses)
Question 3 (38 Responses)
Question 3 Comments (53 Responses)
Question 4 (53 Responses)
Question 4 Comments (53 Responses)
Individual
Molly Devine
Idaho Power Company
Yes
Yes
Yes
No
Group
SERC OC Review Group
Stuart Goza
No
The SERC OC Review Group appreciates the efforts that the SDT has made on this draft
standard and the flexibility demonstrated to address the constantly evolving feedback
received. We do not believe the proposed requirements and measures clearly delineate the
differences in the actions required to be taken by the issuer and recipient depending upon
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
whether or not the Operating Instruction is being given to alleviate or avoid an Emergency.
Applicability Section: 4.1.2 Distribution Provider: We understand that it would be difficult to
remove the Distribution Provider from the applicability of COM-002-4 per FERC's directives.
Therefore, we are respectfully recommending an alternative that parallels the recently FERC
approved CIP-003-5 that we believe accurately captures those DPs that receive Operating
Instructions associated with the reliability of the BES. The following alternative to clarify
those Distribution Providers that have an impact on the BES is recommended: 4.1.2
Distribution Provider that: 4.1.2.1 Has capability to shed 300 MW or more of load in a single
manually initiated operation. 4.1.2.2 Has switching obligations related to Any Cranking Path
and group of Elements meeting the initial switching requirements from a Blackstart Resource
up to and including the first interconnection point of the starting station service of the next
generation unit(s) to be started. General Requirement Comment: The SDT is respectfully
requested to review the Requirements to ensure that it is clear that “during an Emergency”
is only applicable to the entities involved. Requirement 1: The proposed standard still
contains requirements that mandate the use of, and training to include, 3 part
communications during issuance of all Operating Instructions, including those issued during
non-Emergency situations. While we agree that the SDT has stated in its Rationale and
Technical Justification document that the proposed measures don’t specifically require that
auditors verify compliance of this for the requirements (and associated measures), a strict
read leads to a different conclusion. We are concerned that, absent a requirement that the
issuer make a definitive statement as to whether an Operating Instruction is being issued to
alleviate or avoid an Emergency, neither the recipient (during) nor an auditor (after) would
be able to make such determination. We respectfully recommend modifying requirement 1
so that it applies to all Operating Instructions but requires that those being issued to alleviate
or avoid an Emergency be specifically identified as such and that the issuer explicitly request
recipient confirm their understanding through use of 3 part communication. To accomplish
this we propose a new R1.1. The current R1.1 through R1.6 would be renumbered R1.2
through R1.7 Current R1 language: R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented communications protocols for its
operating personnel that issue and receive Operating Instructions. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Long-term Planning] 1.1.Require its
operating personnel that issue and receive an oral or written Operating Instruction to use
use the English language, unless agreed to otherwise. An alternate language may be used for
internal operations. Proposed R1 language: R1. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall develop documented communications
protocols for its operating personnel that issue and receive Operating Instructions. The
protocols shall, at a minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning] Proposed R1.1: ADD: Require that its operating personnel identify, at the time of
issuance, when the Operating Instruction is being issued to alleviate or avoid an Emergency
R1.2: Based on the SDT comments and zero tolerance for Emergency communications we
propose a new bullet be added to R1.2. Current R1.2 language: Require its operating
personnel that issue an oral two-party, person-to-person Operating Instruction to take one
of the following actions: • Confirm the receiver’s response if the repeated information is
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
correct. • Reissue the Operating Instruction if the repeated information is incorrect or if
requested by the receiver. • Take an alternative action if a response is not received or if the
Operating Instruction was not understood by the receiver. Proposed R1.2: Require its
operating personnel that issue an oral two-party, person-to-person Operating Instruction to
take one of the following actions: • Confirm the receiver’s response if the repeated
information is correct. • Reissue the Operating Instruction if the repeated information is
incorrect or if requested by the receiver. • Take an alternative action if a response is not
received or if the Operating Instruction was not understood by the receiver. • ADD: Request
recipient use 3 part communication when the Operating Instruction is being issued to
alleviate or avoid an Emergency R1.3: We respectfully recommend a word change (correct to
understood) in 1.3, bullet 1. Current 1.3 sub-bullet 1 follows: Repeat, not necessarily
verbatim, the Operating Instruction and receive confirmation from the issuer that the
response was correct. Proposed 1.3, sub-bullet 1: Repeat, not necessarily verbatim, the
Operating Instruction and receive confirmation from the issuer that the response was
understood. Requirement R2: This group feels that R2 should be eliminated as redundant
with the systematic approach to training requirements of PER-005 (Operations Personnel
Training) which are applicable to all BAs, RCs & TOPs. Communications protocols must be
included in each company’s specific reliability-related task list. Inherent in systematic
approach is initial training on all reliability-related tasks, since each task must be analyzed as
to its Difficulty, Importance & Frequency (DIF analysis). As a result of the DIF analysis,
systematic approach would require that communications protocols have both initial and
continuing training. Requirement R3: We agree with the SDT concern that Operating
Personnel should not be placed in a position to receive an oral two-party, person-to-person
Operating Instruction prior to being trained. This Group understands that OPCP SDT included
an initial training requirement in the standard in response to the NERC Board of Trustees’
resolution, which directs that a training requirement be included in the COM-002-4 standard.
We would like to recommend that the term “initial” be removed so not to give the
impression that training is a one-time effort. Current R3 language: Each Distribution Provider
and Generator Operator shall conduct initial training for each of its operating personnel who
can receive an oral two-party, person-to-person Operating Instruction prior to that individual
operator receiving an oral two-party, person-to-person Operating Instruction to either:
[Violation Risk Factor: Low][Time Horizon: Long-term Planning] Proposed R3 language: Each
Distribution Provider and Generator Operator shall conduct training for each of its operating
personnel who can receive an oral two-party, person-to-person Operating Instruction prior
to that individual operator receiving an oral two-party, person-to-person Operating
Instruction to either: [Violation Risk Factor: Low][Time Horizon: Long-term Planning]
Requirements R5, R6, and R7: This Group feels that the relationship between R1, R5, R6, and
R7 requires further clarification to remove possible opportunities for different
interpretations which could result in uncertainty as to whether the Operating Instruction is
being issued to alleviate or avoid an Emergency. The concern centers on the absence of a
requirement that the issuer make a definitive statement as to whether an Operating
Instruction is being issued to alleviate or avoid an Emergency, neither the recipient (during)
nor an auditor (after) would be able to make such determination. This is the reason for the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
R1 modifications. If the recommended R1 modifications are accepted then R5, R6, and R7
should be considered for deletion (incorporating specific items deemed necessary by the SDT
as bullets or sub-requirements of R1). Measures: Measure 1: Base on the Group’s
recommendations above we propose for consideration the following modification to
Measure 1: Current M1 language: Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide its documented communications protocols developed
for Requirement R1. Proposed M1 language: Revised M1: Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall provide its documented
communications protocols developed for Requirement R1. For each Operating Instruction
issued to alleviate or avoid an Emergency; entity shall provide evidence that it identified such
at time Operating instruction was issued (R1.1) and requested recipient use of 3 part
communication (R1.2). Measure 2,5,6,and 7: If our recommendations are accepted then
Measures 2, 5, 6, and 7 should be deleted incorporating specific items deemed necessary by
the SDT as bullets or sub-requirements of R1 Measure 3: To align M3 with our R3
recommendation we propose deleting the word “initial”. Current M3 language: Each
Distribution Provider and Generator Operator shall provide its initial training records for its
operating personnel such as attendance logs, agendas, learning objectives, or course
materials in fulfillment of Requirement R3. Proposed M3 language: Each Distribution
Provider and Generator Operator shall provide its training records for its operating personnel
such as attendance logs, agendas, learning objectives, or course materials in fulfillment of
Requirement R3.
We are concerned that this draft goes further than mentioned in the blackout
recommendation that NERC should work with reliability coordinators and control area
operators to improve the effectiveness of internal and external communications during
alerts, emergencies, or other critical situations. This group feels that the modifications
recommended will add further clarity in communications and work towards the goal
identified in the Black Report recommendation number 26.
We believe that the VRFs/VSLs should be modified to better reflect the stated intent of the
NERC Board of Trustees November 19th, 2013 Resolution, which is to enforce ‘zero
tolerance’ only for failure to use 3 part communiations by the issuer or recipient of an
Operating Instruction when it is issued to alleviate or avoid an Emergency. VSL for R1: Modify
Severe to include any instance where entity either (1) failed to identify, at the time of
issuance, that the Operating Instruction is being issued to alleviate or avoid an Emergency or
(2) failed to request recipient use 3 part communication when the Operating Instruction was
issued to alleviate or avoid an Emergency Current VSL for R1 language: The responsible
entity did not include Requirement R1, Part 1.2 in its documented communications protocols
OR The responsible entity did not include Requirement R1, Part 1.3 in its documented
communications protocols OR The responsible entity did not develop any documented
communications protocols as required in Requirement R1. Proposed VSL for R1 language:
Moderate - The responsible entity did not require the issuer and receiver of an oral or
written Operating Instruction to use the English language, unless agreed to otherwise, as
required in Requirement R1, Part 1.2. An alternate language may be used for internal
operations. Severe - The responsible entity did not include Requirement R1, Part 1.1, in its
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
documented communications protocols OR Requirement R1, Part 1.3 in its documented
communications protocols OR The responsible entity did not include Requirement R1, Part
1.4 in its documented communications protocols OR The responsible entity did not develop
any documented communications protocols as required in Requirement R1 OR the
responsible entity either (1) failed to identify, at the time of issuance, that the Operating
Instruction is being issued to alleviate or avoid an Emergency or (2) failed to request
recipient use 3 part communication when the Operating Instruction was issued to alleviate
or avoid an Emergency. VSL for R3: This Group recommends that the “High VSL for R3” be
deleted. The reason for the High VSL deletion is to align with the concept that the standard
should provide that compliance with the standard should only entail assessing whether an
entity has utilized their documented communications for Operating Instructions that are not
issued during an Emergency. VSL for R2, R5, R6, and R7: If the SDT modifies the requirements
based on this Group’s recommendation VSL for R2, R5, R6, and R7 can be deleted except for
any sections that are applicable in revised requirements.
Yes
The SERC OC Review Group understands the position that the SDT is working in and greatly
appreciates the patience and dedication shown in developing this draft standard. Thank you.
The comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Review Group only and should not be construed as the position of
the SERC Reliability Corporation, or its board or its officers.
Group
North American Generator Forum - Standards Review Team (NAGF-SRT)
Allen Schriver
Yes
Yes
1) R1.3 and R3 should also allow the receiver of an Operating Instruction to respond by
explaining that a requested action cannot be performed (e.g., due to safety, equipment,
regulatory, or statutory requirements as described in TOP-001 R3 and IRO-001 R8). The
requirement to either repeat or request that the instruction be reissued does not account for
the realistic situation that an entity may not be able to perform an Operating Instruction. 2)
Specific to R.6, consideration should be given to revise the verbiage from, “during an
Emergency” to “identified by the sender as constituting an Emergency directive.” The
rational for the recommendation is offered to provide clarity to the Requirement, as it is
anticipated that there will be cases when it is not clear the Operating Instruction is
associated with an Emergency. Additionally, the definition of “Emergency” in the NERC
Glossary is broad and consequently it may be difficult, at times, to determine which inputs
are subject to COM-002-4 requirements, especially if the TO or TOP calls a plant operator
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
directly rather than going through the respective dispatchers. Note: On the 1/17/14 COM002-4 SDT webinar the question was asked, how a DP or GOP would know that an Operating
Instruction occurred during an Emergency. The drafting team stated that after every
Operating Instruction the DP should call its TOP to determine if the Operating Instruction
occurred during and Emergency. The NAGF-SRT once again reiterates that it would be more
efficient and the industry would benefit as a whole, if the sender of the Operational
Instruction, states the instruction is associated with an Emergency. 3) Specific to Measures
M5 and M6, which contain language associated with the issuer and the recipient both
maintaining evidence of two-party communication respectively. It is recommended that M5
be revised such that the all associated evidence is maintained by the issuer and M6 be
deleted in its entirety. Consolidating the evidence requirements would benefit the industry
by reducing duplication of efforts, associated with maintaining evidence by different entities,
in support of the same requirement.
Individual
Colin Jack
Dixie Power
Agree
NRECA
Individual
Paul Titus
Northern Wasco County PUD
Agree
NRECA
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Agree
NRECA and SERC OC Review Group
Group
Salt River Project
Joshua Andersen
Yes
Yes
Yes
No
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
Yes
Yes
Yes
Yes
While the Public Utility District No.1 of Snohomish County supports this draft of COM-002-4,
we see an issue with R2 and R3 of this standard. These requirements both deal with entities
conducting training for its personnel, and feel it would be more appropriate if they were
addressed in the PER family of standards. The Public Utility District No.1 of Snohomish
County also supports the comments submitted by the SERC OC Review Group. Thank you
very much.
Individual
Jonathan Appelbaum
The United Illuminating Company
No
No
Yes
PER-005-2 introduced the concept of a Transmission Owner local control center that issues
and receives instructions independent of a TOP, RC or BA. COM-002-4 should apply to
Transmission Owners.
Individual
Daniel Duff
Liberty Electric Power LLC
Yes
Yes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
No
The "Moderate" VSL for R6 should be modified in the same manner as the "Severe" VSL. In
addition to repeating the Directive, the RE needs to fail to take action as directed. Suggest
the following language: "AND the RE failed to take action as requested by the issuer of the
Operating Instruction".
Yes
COM-002 remains a zero defect standard, and there is no FERC directive to provide a zero
defect standard in response to either blackout recommendation 26 or Paragraph 535 of
Order 693. Further, there is no requirement for the issuer of an Operating Instruction in an
Emergency to indicate the Emergency status. The webinar response to queries over the lack
of Emergency Status Indication was to suggest the RE "call and inquire" if the OI was in fact a
Directive. This adds to the regulatory burden while offering zero benefit. Identification of an
Emergency has positive effects far beyond three part communications. The realization of risk
to the BES should create a heightened sense of urgency among all parties. The standard must
require announcement of Emergency status in order to penalize RE's for actions which are
not violations in a non-Emergency situation.
Group
Northeast Power Coordinating Council
Guy Zito
No
The proposed Requirements and Measures do not clearly delineate the differences in the
actions required to be taken by the issuer and recipient depending upon whether or not the
Operating Instruction is being given to alleviate or avoid an Emergency.
No
We do not agree that the blackout recommendation calls for the use of 3 part
communication for every Operating Instruction and note that neither the NERC Board nor
the SDT has provided any evidence that indicates a direct correlation between errors due to
communication problems and events that adversely impact the BES. The justification for
reliability standard Requirements that require 3 part communication for every Operating
Instruction, and having to enforce compliance with the same, is not supported.
No
Regarding Requirement R4, the LOW VSL suggests that an entity is assigned a LOW VSL if
assessments are conducted more than 12 months apart. There is no maximum or “cap” to
the delayed assessment, and hence an entity may be 18, 19 or more months late in
conducting the next assessment. In other standards this could well be assessed a MEDIUM or
HIGH or even a SEVERE violation, depending on the time period that an entity failed the 12
month update requirement. Absent this “cap”, or staggered caps, the proposed HIGH and
SEVERE VSLs can only be assessed based on whether or not there was ever an assessment,
even if the last assessment was done 3 or 4 years prior to an audit. This is inconsistent with
the general guideline for VSLs. Regarding Requirement R5, the MEDIUM VSL and SEVERE VSL
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
are identical, except the latter has a condition that is associated with the impact of the
violation. This is inconsistent with the intent of the VSL, which is to assess the “extent to
which” the requirement was violated, not the impact of the violation which should be
captured by the VRF. This is also inconsistent with the VSL principle and guideline. Suggest
removing the MEDIUM VSL, and the condition under the proposed SEVERE VSL be: “AND
instability, uncontrolled separation, or cascading failures occurred as a result.” The same
comments apply for Requirements R6 and R7. We believe that the VRFs/VSLs should be
modified to better reflect the stated intent of the NERC Board of Trustees November 19,
2013 Resolution, which is to enforce ‘zero tolerance’ only for failure to use 3 part
communications by the issuer or recipient of an Operating Instruction when it is issued to
alleviate or avoid an Emergency.
Yes
Regarding Part 1.4, it must be considered that some ISOs issue multiple-party burst
Operating Instruction to Generator Operators through electronic means. Regarding Part 1.6,
the requirement is vague and needs to be clarified for Registered Entities to know how to
comply. How would one “specify the nomenclature” system wide? Regarding Requirements
R2 and R3, those “training” requirements aren’t necessary. Responsible Entities must adhere
to the Requirements of NERC Standards and how they accomplish this should not be dictated
by a standard’s requirement. Under RAI principles, NERC and Regions can determine what
type of monitoring is appropriate for Responsible Entities’ compliance with the new COM
Standard based on the quality of their Training programs. This would further support
reliability by changing the requirement from a one-time audit (i.e., initial training) to an
ongoing assessment. The proposed standard still contains requirements that mandate the
use of, and training to include 3 part communications during issuance of all Operating
Instructions, including those issued during non-Emergency situations. As stated in the
Rationale and Technical Justification document the proposed Measures and RSAW don’t
specifically require that auditors verify compliance of this for the Requirements (and
associated Measures), however a strict read leads us to a different conclusion. Under the
RSAW for R1 it states that the entity shall provide its documented communications protocols
developed for this requirement and the auditor shall review the documented
communications protocols provided by the entity and ensure they address the Parts of R1
(including the use of 3 part communications). The RSAW contains similar actions relative to
Requirements R2 and R3 in that the entity is to provide evidence consisting of agendas,
learning objectives, or course materials that it provides pursuant to these requirements.
Given this, an auditor can enforce to a ‘zero defect tolerance’ if the auditor chooses to do so,
and in fact would argue that an audit would be deficient if it failed to validate whether the
learning objective included ensuring that 3 part communication was used during issuance or
receipt of each Operating Instruction. Suggest that the training requirements contained with
R2 and R3 be removed and placed within the PER-005 Operations Personnel Training
standard. PER-005 should be the home of all system operator related training requirements.
There are no clear and concise differences between Requirements R1, R5 and R6. This
creates uncertainty as to whether the Operating Instruction is being issued to alleviate or
avoid an Emergency. Absent a Requirement that the issuer make a definitive statement as to
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
whether an Operating Instruction is being issued to alleviate or avoid an Emergency, neither
the recipient (during) nor an auditor (after) would be able to make such determination.
Suggest revising Requirement R1 so that it applies to all Operating Instructions, but requires
that those being issued to alleviate or avoid an Emergency be specifically identified as such
and that the issuer explicitly request that the recipient confirm their understanding through
use of 3 part communication. Remove Requirements R5, R6 and R7 (incorporating items
deemed necessary by the SDT as bullets or Parts of R1). Suggested rewording for Part 1.1:
1.1. Require that its operating personnel identify, at the time of issuance, that the Operating
Instruction is being issued to alleviate or avoid an Emergency. • Request recipient use 3 part
communication when the Operating Instruction is being issued to alleviate or avoid an
Emergency. Revise M1, VRF/VSLs and RSAW so that strict compliance with use of 3 part
communication is only applied when an Operating Instruction is issued to alleviate or avoid
an Emergency as identified by the issuer at the time of issuance. Suggested revisions to M1:
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1. For each
Operating Instruction issued to alleviate or avoid an Emergency; entity shall provide evidence
that it identified such at time Operating instruction was issued (R1.1) and requested
recipient use of 3 part communication (R1.2). VSL for R1 – modify Severe to include any
instance where entity either (1) failed to identify, at the time of issuance, that the Operating
Instruction is being issued to alleviate or avoid an Emergency or (2) failed to request
recipient use 3 part communication when the Operating Instruction was issued to alleviate
or avoid an Emergency Measure M4 requires compliance demonstration beyond
Requirement R4. Specifically, entities must provide evidence that appropriate corrective
action was taken for all instances where an operating personnel’s non-adherence to the
protocols developed in Requirement R1 is the sole or partial cause of an Emergency. The
format of the standard should be changed to conform with the current NERC direction—the
measures get listed with the associated requirement, and the rationale get included in the
standard, not a separate document.
Individual
Matthew P Beilfuss
Wisconsin Electric Power Company
Yes
Yes
Yes
Yes
The proscribed training requirements embedded in R2 and R3 should be removed. The
existence and usage of protocols should be the primary focus of the standard and regulatory
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
review, creating a training requirement within the standard shifts focus to training content
and administration. Additionally, PER-005-1 requires the Balancing Authority, Reliability
Coordinator, and Transmission Operator to have a systematic approach to training (SAT). The
adoption and management of a SAT would presumably include communications protocols as
a task for potential training. The current draft version of PER-005-2 includes a similar
requirement for a SAT applicable to the Generator Operator. The annual assessment and
corrective action process defined in R4 should be made applicable to Operating Instructions
during an Emergency. Although the NERC Glossary of terms provides a definition of
Emergency, two reasonable people looking at a situation can disagree as to when an
Operating Instruction is issued during an Emergency. Creating a zero defect standard
applicable to inherently ambiguous situations shifts focus from the adoption of
communication protocols to discussion of when an Operating Instruction is issued during an
Emergency. During an entities annual assessment process, the focus would be on
classification of an Emergency instead of process improvement for communications. An
alternate approach would be to draft the standard so as to require the explicit identification
of an Operating Instruction and/or Emergencies so as to remove the ambiguity. Finally, the
definition of Operating Instruction references a command issued by operating personnel,
without sufficiently defining operating personnel.
Individual
Thomas Borowiak
Citizens Electric Corporation
Agree
National Rural Electric Cooperative Association(NRECA)
Individual
Patricia Metro
NRECA
No
NRECA appreciates the efforts of the drafting team in working to address the FERC directives
and NERC BOT Resolution November 2013, but does not believe that COM-002-4 accurately
reflects the proper applicability for entities that have an impact on the operations of the Bulk
Electric System in normal and emergency conditions. NRECA understands that the inclusion
of Distribution Providers to this standard stems from various FERC directives, but because of
the relationship of Distribution Providers with Transmission Operators as identified in NERC's
functional model in being only a receiver of instructions to implement voltage reduction or
to shed load to prevent the failure of the BES, or related to restoration activities as
coordinated with the Transmission Operator; the TOP is ultimately responsible for the proper
execution of the instructions, continues to recommend that Distribution Providers be
removed from the applicability of COM-002-4. Knowing that it will be difficult to remove the
Distribution Provider from the applicability of COM-002-4 per FERC's directives, NRECA is
recommending an alternative that parallels the recently FERC approved CIP-003-5 that we
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
believe accurately captures those DPs that receive Operating Instructions associated with the
reliability of the BES. The following alternative to clarify those Distribution Providers that
have an impact on the BES is recommended: 4.1.2 Distribution Provider that: 4.1.2.1 Has
capability to shed 300 MW or more of load in a single manually initiated operation. 4.1.2.2
Has switching obligations related to Any Cranking Path and group of Elements meeting the
initial switching requirements from a Blackstart Resource up to and including the first
interconnection point of the starting station service of the next generation unit(s) to be
started. NRECA proposes to recommend an “affirmative” ballot to its members if the
applicability is modified in the next posting as provided.
No
See response to Question 1
No
Will need to be modified dependent on applicability modifications.
Yes
NRECA suggests that the “assess adherence and assess effectiveness” language in R4 be
removed from COM-002-4. This language is similar to the “Identify, Assess and Correct (IAC)”
language that was included in the CIP V5 standards. The removal or modification of this
language was included in the Final Rule on NERC CIP V5 Standards (Order No. 791). FERC
stated that IAC language and concepts would be best addressed in the NERC compliance
processes, such as through the NERC Reliability Assurance Initiative (RAI), rather than
standards requirements.
Individual
Howard Hughes
SLEMCO
Agree
NRECA
Individual
Michelle R D'Antuono
Ingleside Cogeneration LP
Yes
Ingleside Cogeneration LP ("ICLP") believes that the requirements that govern directives
issued during the course of an Emergency remain consistent with those in-place today. In
addition, the latest draft of COM-002-4 allows oversight of all other Operating Instructions –
although to a lesser degree. This is a good combination of compliance strategies that retains
focus on the important communications while adding attention on daily discussions which
may have impact on the BES if improperly transacted.
Yes
COM-002-4 adds requirements that call for protocols that add precision to operations
communications as called for in both documents. However, in the latest draft, ICLP believes
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
the compliance approach has been modified in a manner that ensures that routine Operating
Communications are conducted using a common protocol – but do not involve significant
tracking resources. In addition, the use of operator training and regular review of its
effectiveness is consistent with other NERC standards related to operator capabilities. As it is
written now, CIP-002-4 introduces new expectations related to routine communications, but
only puts incremental pressures on existing processes and equipment necessary to address
them.
Yes
Yes
ICLP would like to see the innovative approach that the drafting team used to develop COM002-4 applied to other standards as well. The issue that continues to arise is not so much
whether mandatory requirements are based upon sound reliability principles, but how they
can be reasonably enforced. In this case, it is clear that many entities do not have the tools
or resources to examine every Operating Instruction in detail in order to assure 100%
compliance with a rigorous communication protocol. Conversely, training and retention
programs are common – and have proven to be an effective means to drive consistent
Operator performance.
Individual
Jack Stamper
Clark Public Utilities
Yes
Yes
Yes
Yes
For the purposes of Requirements 5 and 6, Clark believes it should be an obligation of the
issuer of Operating Instruction given during an emergency to identify it as an Emergency
Operating Instruction. It should not an obligation of the reciever to determine after-the-fact
whether an Operating Instruction is an Emergency or not. All Operating Instructions issued
by a BA, RC, or TOP should be regarded with importance but a specification by the issuer that
the instruction is in response to an Emergency will alert the receiver that a particular
Operating Instruction action requirement has a role in the overall reliability of the BES
resulting in a higher level of BES reliability.
Individual
Josh Dellinger
Glacier Electric Cooperative
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Agree
NRECA
Individual
russ schneider
flathead co-op
Agree
Flathead supports the comments submitted by NRECA
Individual
Oliver Burke
Entergy Transmission
Agree
SERC OC Review Group
Individual
Donald E Nelson
Commonwealth of Massachusetts Department of Public Utilities
Agree
Northeast Power Coordinating Council (NPCC)
Individual
Thomas M. Haire
Rutherford EMC
Agree
NRECA
Individual
Venona Greaff
Occidental Chemical Corporation
Agree
Ingleside Cogeneration LP
Group
NERC Standards Review Forum
Russel Mountjoy
Yes
No
As it has been stated in previous comments, Recommendation 26 from the 2003 Blackout
report is about situational awareness and who and what entities need to be contacted
during emergencies. It is not about what System Operators should say in their conversations.
No
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R1, The NSRF does not understand why there is a Severe VSL for normal everyday Operating
Instructions. This Severe VSL is imposing the “zero defect” language that the industry is
trying to move away from. We understand if there were no protocols as in “The responsible
entity did not develop any documented communications protocols as required in
Requirement R1”, but not the sub requirements of R1.2 and R1.3. The highest VSL should be
High. Save the Severe VSL for R5, R6, and R7.
Yes
1. Per section one of this document, the SDT states: The Project 2007-02 SDT removed the
term “Reliability Directive” in order to avoid complications that may result from the Notice of
Proposed Rulemaking issued by the Federal Energy Regulatory Commission on November 21,
2013 proposing to remand the definition of “Reliability Directive.” But within the latest
Implementation Plan, there still is the prerequisite of approving the term “Reliability
Directive”. Please update whichever documentation that should be corrected in order to
provide the industry with accurate information so that we can determine if this Standard
supports the reliability of the BES.
Individual
William H. Chambliss
Virginia State Corporation Commission, Member OC
Yes
Yes
Yes
No
Group
Colorado Springs Utilities
Kaleb Brimhall
Southwest Power Pool
No
We do not agree with the following VSLs: 1) R4: The LOW VSL suggests that an entity is
assigned a LOW VSL if assessments are conducted more than 12 months apart. There is no
max or “cap” to the delayed assessment and hence an entity may be 18, 19 or more months
late in conducting the next assessment. In other standards, this could well be assessed a
MEDIUM or HIGH or even a SEVERE violation, depending on the time period that an entity
failed the 12 month update requirement. Absent this “cap”, or staggered caps, the proposed
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HIGH and SEVERE VSLs can only be assessed based on whether or not there was ever an
assessment, even the last assessment was done 3 or 4 years prior to an audit. This is
inconsistent with the general guideline for VSLs. 2) R5: The MEDIUM VSL and SEVERE VSL are
identical, except the latter has a condition that is associated with the impact of the violation.
This is inconsistent with the intent of the VSL, which is to assess the “extent to which” the
requirement was violated, not the impact of the violation which should be captured by the
VRF. This is also inconsistent with the VSL principle and guideline. We suggest removing the
MEDIUM VSL, and the condition under the proposed SEVERE VSL that: “AND Instability,
uncontrolled separation, or cascading failures occurred as a result.” 3) R6: Same comments
as in R5. 4) R7: Same comments as in R5.
Yes
Comments: 1. R1.4. – [Documented communications protocols for its operating personnel
that issue and receive Operating Instructions shall, at a minimum] Require its operating
personnel that issue a written or oral single-party to multiple-party burst Operating
Instruction to confirm or verify that the Operating Instruction was received by at least one
receiver of the Operating Instruction. • Some ISO’s issues multiple-party burst Operating
Instruction to Generator Operators through electronic means Associated real-time
requirement: R7. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator that issues a written or oral single-party to multiple-party burst Operating
Instruction during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction. Comment: The SRC does not
believe this requirement is necessary for reliability. Moreover, the Standard Drafting Team
has not provided any , nor have we been made aware of the substantiated rationale for
keeping this Requirement except that the SDT believes is it necessary. 2. R1.6. –
[Documented communications protocols for its operating personnel that issue and receive
Operating Instructions shall, at a minimum] Specify the nomenclature for Transmission
interface Elements and Transmission interface Facilities when issuing an oral or written
Operating Instruction. Comment: This requirement is vague and needs to be clarified for
Registered Entities to know how to comply with it; how would one “specify nomenclature”
system-wide? Comment: This requirement was dropped from TOP-002-2a, requirement 18.
Communication on transmission equipment must be equipment specific. Nomenclature
should not be used, rather entities should always be correctly communicating using the
unique and specific equipment identifiers. Adding nomenclature will reduce not improve
reliability. 3. R2. and R3. – …”shall conduct initial training for each of its operating personnel
…” Comment: The SRC does not believe a training Requirement is necessary; Responsible
Entities must adhere to the Requirements of NERC Standards and how they accomplish this
should not be dictated by a Standard Requirement. Under RAI principles, NERC and Regions
can determine what type of monitoring is appropriate of Responsible Entities’ compliance
with the new COM Standard based on the quality of their Training programs. This would
further support reliability by changing the requirement from a one-time audit (i.e., initial
training) to an ongoing assessment.
Individual
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Shirley Mayadewi
Manitoba Hydro
Yes
Yes
Yes
Although Manitoba Hydro agrees with the VRFs and VSLs for the Requirements, we have the
following comments: 1) VSLs, R2 – the term ‘individual operator’ is used in this VSL where
throughout the standard operating personnel is used. 2) VSLs, R5 – text of VSLS refer to
Requirement R6 instead of R5. 3) VSLs, R6 – inconsistent drafting as the words ‘that received
an oral, …..’ is not included here, but does appear in the VSL for R7. 4) VLSs, R5, R6, R7 – the
final criteria for a Severe VSL is for a specific outcome of non-compliance which does not
seem appropriate when measuring compliance. Depending on the outcome of the
circumstances, the VSL may be High or Severe. The outcome itself is not something that is
related to the entity’s compliance with the standard. The entity may take the same action
and comply to the same degree and by virtue of the outcome alone they are moved from a
High to a Severe VSL.
Yes
1) The protocols at minimum should require full name identification. 2) R2 – the description
of the applicable operating personnel (i.e. that are responsible for Real-Time operation of
the interconnected BES) is different in this part than others (that state it’s for operating
personnel that issue and receive certain Operating Instructions). Is that purposeful? 3) R5,
R6, R7 and R8 - the numbering seems to be mixed up. 4) M2 and M3 – are not drafted
consistently given the consistency in drafting of requirements R2 and R3. M3 refers to ‘its
initial’ training records while M2 does not and M3 refers to training records ‘for its operating
personnel’ while M2 does not. 5) M4 – contains a section of text that is not reflective of the
requirement itself and has no basis for appearing in the measure. The requirement states
only that the entity need only take corrective action to address deviations. The extra text
that discusses instances where non adherence is the sole or partial cause of an Emergency
should be deleted. 6) M6, M7 – the words ‘if the entity has such recordings’ seem
unnecessary. This qualifying language isn’t attached to any other type of evidence that is
listed as a possibility; presumably all of those are subject to the same qualifier and would
only be presented as evidence if the entity had them.
Individual
Jason Snodgrass
Georgia Transmission Corporation
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No
Comments: GTC recognizes FERC Order 693 directs the revision of COM-002 to include the
DP and specifically states how essential it is that the TOP, BA and RC have communications
with DPs. Additionally, GTC observes Order 693 also identifies the need for tightened
communications protocols, especially for communications during alerts and emergencies and
that such protocols shall be established with uniformity as much as practical on a continent
wide basis to eliminate possible ambiguities in communications during emergency
conditions. If the Standard requires the use of 3 part communications by the issuers of
Operating Instructions, then it would seem sensible that receivers of Operating Instructions
be trained for awareness and proper participation of such protocols. GTC sees parallels of
this approach in other Standards such as restoration training of DPs identified in the TOPs
restoration plan as required in EOP-005-2. GTC believes the current proposal of COM-002-4
still contains ambiguities that should be addressed before GTC can provide an affirmative
ballot. GTC is offering 3 alternatives such that if any of them is adopted by the SDT, GTC
would modify our position to cast an affirmative vote in the next recirculation. Alternative 1
(Modify the DP applicability): Applicability Section: 4.1.2 Distribution Provider: GTC is
recommending an alternative that parallels the recently FERC approved CIP-003-5 that we
believe accurately captures those DPs that receive Operating Instructions associated with the
reliability of the BES when in an Emergency. The following alternative to clarify those
Distribution Providers that have an impact on the BES is recommended: 4.1.2 Distribution
Provider that: 4.1.2.1 Has capability to shed 300 MW or more of load in a single manually
initiated operation. 4.1.2.2 Has switching obligations related to Any Cranking Path and group
of Elements meeting the initial switching requirements from a Blackstart Resource up to and
including the first interconnection point of the starting station service of the next generation
unit(s) to be started. Alternative 2 (Modify the DP applicability per above, modify R3;
Eliminate R6): Alternative 2 is an extension of alternative 1 for additional clarities.
Requirement 3: Revise R3 to insert the words [during an Emergency] within the sentence
“…who can receive an oral two-party, person-to-person Operating Instruction [during an
Emergency] prior to that individual operator…”. Additionally, replace the word “receive” with
the word “request” in the first bullet of R3. The word “receive” is ambiguous and the word
“request” is consistent with the receiver using his words to request a confirmation. GTC
maintains that R3 is sufficient to satisfy FERC Order 693 for the DP applicability during
emergencies, and would ensure uniformity on a continent wide basis to eliminate possible
ambiguities in communications during emergency conditions. GTC prefers the elimination of
R6. GTC does not believe that a receiver of an Operating Instruction in the field performing
field switching activities should be required to document evidence of following the oral
communication practices. Issuers of Operating Instructions are already recording the
Operating Instruction communications and have the capability to do so. Issuers are also
required to ensure the receiver responds accordingly per R5. Issuers are required to confirm
the receiver’s response is correct or else reissue if incorrect; issuers can also take an
alternative action. Having the receiver document the implementation of these practices for
compliance is redundant and duplicative to the issuer’s requirements. This is an unnecessary,
administrative requirement that introduces a double jeopardy situation that does not
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enhance the reliability of the BES. The SDT should recognize that all reliability bases are
covered with the training requirements of the issuers in R1, the training requirement of the
receivers in R3, and the performance of these are monitored via the issuers recording
capabilities in R5 and R7. With this approach, issuers can be satisfied that receivers are
prepared to receive instructions in accordance with their training, and the options the issuers
have per R5 in a live scenario. The receivers could not expose or cause a non-compliance
situation to the issuers. However, the issuers could expose the receivers to a non-compliance
situation if a recording is lost or damaged and the receiver was on his cell phone in the field
taking orders and performing switching, hence the double jeopardy and GTC’s plea to
remove this requirement 6. Alternative 3 (Modify the DP applicability above, Modify R3
above, Modify R6, create separate DP requirement): Requirement 6: If the SDT decides that
R6 must remain, then GTC requires the following changes to modify our negative vote to
affirmative. GTC appreciates the drafting team making concessions to eliminate the need for
DPs and GOPs being required to have documented communication protocols. Additionally,
GTC appreciates the drafting team’s willingness to limit the scope of performing the 3 part
communications to those Operating Instructions received during an Emergency. These
drafting team concessions are a testament to the team, along with industry, of
understanding that the DP will typically have a very limited role in receiving Operating
Instructions from the BA or TOP to protect the BES during an Emergency. This role is typically
limited to operating non-BES equipment (load serving stations) to shed load or reduce
voltage to prevent the failure of transmission facilities or generation supply that could
adversely affect the reliability of the BES. GTC would submit that the TOP would further limit
the DPs role to “manual” load shed type situations when the “automatic” load shed schemes
misoperate or malfunction as designed. This is highlighted in the NERC functional model
which identifies this real time function of the DP “Implements voltage reduction and sheds
load as directed by the Transmission Operator or Balancing Authority”. During an Emergency,
which NERC defines as any abnormal condition that requires automatic or immediate manual
action to prevent or limit the failure of transmission facilities or generation supply that could
adversely affect the reliability of the BES, the aforementioned function is what the DP will be
called upon to implement. The ambiguity that arises is captured within the various types of
utility registrations with NERC, and GTC believes the SDT can accommodate two distinct
types of DPs which GTC believes to be critical to pass this Standard. GTC observed there are
298 entities in the NERC registry that are true DP function only. Most of these are DP/LSE
and would not own BES assets, but they would be directly connected to the BES, hence
registration. These entities own load serving substations and implementing voltage reduction
or shedding load in an Emergency would not be ambiguous. However, GTC observed there
are 242 entities in the NERC registry that are registered DPs, and also registered TOs that
own BES assets. To these integrated entities, the scope of communications during an
Emergency would be more ambiguous, as these entities may perform actions at transmission
stations on a routine basis that the other DP only type entities would not have to consider.
With the addition of R6 as written, these entities have an amplified burden of compliance
risk associated with their TO registration even though R6 applies to them as a DP. This
burden is the separation of those Operating Instructions performed at transmission stations
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which occurs more often than the Emergency event which requires a manual operation for
reduction of voltage or load shed at load serving stations. GTC believes this ambiguity is
significant enough to justify the separation of the DP from R6 to provide a standalone
requirement commensurate to the DPs function as documented in the NERC functional
model. Proposed R6 language: Remove Distribution Provider from R6. Create a separate
standalone requirement for the DP. R#. Each Distribution Provider that receives an oral twoparty, person-to-person Operating Instruction to implement voltage reduction or shed load
during an Emergency, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall either: * Repeat, not necessarily verbatim, the Operating Instruction and
request confirmation from the issuer that the response was correct, or * Request that the
issuer reissue the Operating Instruction.
No
modify in accordance with selected alternative drafted above.
Yes
Comments: GTC suggests that the “assess adherence and assess effectiveness” language in
R4 be removed from COM-002-4. This language is similar to the “Identify, Assess and Correct
(IAC)” language that was included in the CIP V5 standards which FERC directed the removal
of. The removal or modification of this language was included in the Final Rule of NERC CIP
V5 (Order No. 791). FERC stated that IAC language was “overly-vague, lacking definition and
guidance is needed” and that these control concepts would be best addressed in the NERC
compliance processes, such as through the NERC Reliability Assurance Initiative (RAI), rather
than standards requirements. Lastly, GTC recommends a revision to the NERC Glossary term
Emergency. GTC recommends the removal of the terms “or limit” within this definition. One
could argue that every single Operating Instruction is utilized to limit failures of transmission
facilities. Emergency should be more appropriately defined without this ambiguity:
Proposed: Emergency or BES Emergency: Any abnormal system condition that requires
automatic or immediate manual action to prevent the failure of transmission facilities or
generation supply that could adversely affect the reliability of the Bulk Electric System.
Individual
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
Yes
Yes
ATC recommends changing the language in Requirement 4 to read as follows: “Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall at least once
every calendar year, and no more than every 15 months: “ ………….. This would be consistent
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with the NERC’s annual requirement assessment made in NERC’s Compliance Application
Notice (CAN)- 0010 issued on November16, 2011. In doing so, it should drive consistency
among the CEA on how it is enforced.
Group
Southern Company; Southern Company Services,Inc; Alabama Power Company; Georgia
power Company; Gulf Power Company; Mississippi Power Company; Southern Company
Generation and Energy Marketing
Marcus Pelt
Yes
Yes
No
R3 VSL is listed as high and severe; The concern is that if an operator receives instruction and
performs accurately using 3-part, but can’t show initial training for Operating Instruction and
Operating instruction during an Emergency, would this warrant a high or severe VSL. While
there is the potential of risk if Operating Instructions are received prior to being trained, this
should not somehow imply that incorrect operations were performed as a result of no
training. The severe category should be reserved only for those instances in which Operating
Instructions were received prior to being trained *and* which resulted in an emergency
operation or reliability issue. As a result, we suggest “demoting” each existing VSL to a lower
level, and editing the High and Severe VSL and limit it to only those instances that resulted in
an emergency operation or reliability issue (suggestions provided below). Low – An individual
operator at the responsible entity receiving an Operating Instruction prior to being trained.
Moderate – An individual operator at the responsible entity received an Operating
Instruction during an Emergency prior to being trained. High – An individual operator at the
responsible entity received an Operating Instruction prior to being trained *and* resulting in
an emergency operation or reliability issue. Severe - An individual operator at the
responsible entity received an Operating Instruction during an Emergency prior to being
trained *and* resulting in an emergency operation or reliability issue.
No
R1.2: Correct the formatting of the third bullet to match the first two so that it is clear that
there are three options permitted not just two with a sub bullet to number two. R3: Is
worded a little confusing. Suggestion would be to add the text below. Each Distribution
Provider and Generator Operator shall conduct initial training for each of its operating
personnel who can receive an oral two-party, person-to-person Operating Instruction prior
to that individual operator receiving an oral two-party, person-to-person Operating
Instruction that requires them to either: [Violation Risk Factor: Low][Time Horizon: Longterm Planning] • Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or • Request that the issuer
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reissue the Operating Instruction. R4 - In NERC’s own Q&A document for RAI prepared by the
Risk-Based Reliability Compliance Working Group (RBRCWG), the following statements are
made: “An entity can voluntarily establish internal controls designed to reduce its control
risk, which could have a positive influence on the scoping of compliance monitoring by the
Regional Entity. Conversely, the entity can voluntarily elect to not establish internal controls
or share them with the Regional Entity.” This is inconsistent with the direction of the
proposed Standard COM-002-4, R4. This not only requires an internal control, but also
requires that the control be shared with the Regional Entity (during audits). Also, consider
that an entity can develop and implement a robust communication protocol consistent with
COM-002-4 requirements and flawlessly follow its communication protocol, yet be found in
violation of COM-002-4 by failing to demonstrate that it has adequate (subjective)
management (internal) controls in place. This is inconsistent with the RAI guidance provided
by NERC regarding the voluntary nature of internal controls. So, in principle, internal controls
should not be dictated in a reliability standard. This goes against the principle of “ResultsBased” standards. The intended result is effective communications. This can be attained with
Requirements 1 through 3. No one will argue that internal controls won’t help ensure that
the desired results are achieved. However, Requirement 4 is not absolutely necessary for the
results to be achieved, and therefore, should not be included in the standard and should be
removed. Definition of Operating Instruction: The term “command” in the definition of
Operating Instruction implies authority, and Southern believes it should be made clear that
Operating Instructions (for purposes of this standard) are commands issued by those
functional entities that are expressly granted the responsibility and authority by the NERC
Reliability Standards to take actions or direct the actions of others to ensure the reliability of
the BES. These are the Balancing Authority, Reliability Coordinator and Transmission
Operator only. No other functions are expressly authorized in the NERC Reliability Standards
to issue a command. Our proposed definition Operating Instruction should be: Operating
Instruction — A command originated by a Balancing Authority, Transmission Operator or
Reliability Coordinator responsible for the Real-time operation of the interconnected Bulk
Electric System to change or preserve the state, status, output, or input of an Element of the
Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System operating
concerns is not a command and is not considered an Operating Instruction.) Measures: M4:
The inclusion of Emergency here is inappropriate due to the non-inclusion of Emergency in
R4. Also change the RSAW to reflect this change as well. Suggested rewording: “Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide
evidence of its assessments, including spreadsheets, logs or other evidence of feedback,
findings of effectiveness and any changes made to its documented communications
protocols developed for Requirement R1 in fulfillment of Requirement R4. The entity shall
provide evidence that it took appropriate corrective actions as part of its assessment for all
identified instances where operating personnel did not adhere to the protocols developed in
Requirement R1” Definition of Emergency Any abnormal system condition that requires
automatic or immediate manual action to prevent or limit the failure of transmission
facilities or generation supply that could adversely affect the reliability of the Bulk Electric
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System. If read literally, EVERY breaker operation on the system IS an EMERGENCY. This
causes a great deal of concern. From a DP and GOP standpoint, the RSAW and technical
justification wording states that an attestation that no emergency had been called requiring
a three part response would suffice for evidence. The rationale and technical justification
document has some very good explanations of the INTENT of the drafting team and how
they want the industry to view the standard requirements. If the standard and the
subsequent audits adhered ONLY to what was in the justification document, then there
should be little or no concerns. Unfortunately, the justification document carries no
statutory weight and the standard as written does.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
No
We do not agree with the following VSLs: i) R4: The LOW VSL suggests that an entity is
assigned a LOW VSL if assessments are conducted more than 12 months apart. There is no
max or “cap” to the delayed assessment and hence an entity may be 18, 19 or more months
late in conducting the next assessment. In other standards, this could well be assessed a
MEDIUM or HIGH or even a SEVERE violation, depending on the time period that an entity
failed the 12 month update requirement. Absent this “cap”, or staggered caps, the proposed
HIGH and SEVERE VSLs can only be assessed based on whether or not there was ever an
assessment, even the last assessment was done 3 or 4 years prior to an audit. This is
inconsistent with the general guideline for VSLs. ii) R5: The MEDIUM VSL and SEVERE VSL are
identical, except the latter has a condition that is associated with the impact of the violation.
This is inconsistent with the intent of the VSL, which is to assess the “extent to which” the
requirement was violated, not the impact of the violation that should have been reflected by
the VRF. This is also inconsistent with the VSL principle and guideline. We suggest removing
the MEDIUM VSL, and the condition under the proposed SEVERE VSL that: “AND Instability,
uncontrolled separation, or cascading failures occurred as a result.” iii) R6: Same comments
as in R5. iv) R7: Same comments as in R5.
Yes
Recently, FERC directed NERC to eliminate the ambiguity with language “identify, assess, and
correct” deficiencies for the CIP standards. Although it supported NERC’s move away from a
“zero tolerance” approach to compliance, FERC wanted NERC provide more guidance
regarding enforceability with the self-identify/assess/correct approach to compliance.
NERCmay want to consider that FERC may raise the same concerns with this proposed
standard. According to the draft standard, if DPs and GOPs receive an Operating Instruction,
they can provide an attestation from the issuer of the Operating Instruction to demonstrate
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compliance – they do not need to develop documented communications protocols. The
lighter compliance burden on DPs and GOPs may result in a higher administrative burden for
the RC/BA/TOP to provide attestations.
Individual
David Thorne
Pepco Holdings Inc.
Yes
Please provide the rationel as to why the standard is not applicable to TOs.
Individual
Thomas Foltz
American Electric Power
No
The AND qualifier provided for R5 which qualifies that Instability, uncontrolled separation, or
cascading failures occurred, should also be used for R3.
Yes
AEP believes the most recent changes represent a major step back in regards to clarity (as
compared to the draft proposed in October 2013), and has driven us to change our voting
position from affirmative to negative. We are concerned by the removal of Reliability
Directive, and instead, now basing requirements on whether or not the communications are
made during an Emergency. Who determines whether or not an Emergency state exists, and
in addition, how would that be communicated? AEP recommends returning to the
fundamentals and approach taken in the previous draft. If the phase “Reliability Directive” is
to be remanded, we encourage the drafting team to pursue alternative language which
would not require the need to know whether or not the communications are being made
during an “Emergency”. For example, perhaps the drafting team could change R1 (as taken
from the October 2013 draft) to state something like the following: “Require the issuer to
identify the action as a directive or instruction…”. R4.2: Though M4 specifies the kinds of
evidence needed to meet R4, we believe it would be too subjective in determining whether
or not the entity’s efforts properly assessed the effectiveness of the documented
communications protocols.
Individual
Brian Evans-Mongeon
Utility Services, Inc
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Yes
Smaller DPs and GOPs will have a significant problems demonstrating compliance with
Requirement 6 as written. 1. As there is no requirement to notify these entities that an
Operating Instruction is being issued during an Emergency, they will not be aware of which
communications will be subject to compliance review. 2. Since these entities typically do not
record phone conversations they would have to rely on other forms of evidence. Log book
enties will not document if three part communication was used and since the entities are not
made aware of Emergency conditions, they will not know to maintain a higher level of
documentation to demonstrate compliance. 3. Approaching the issuer for confirmation of
OIs during Emergency conditions and seeking Attestations from these entities will create a
significant administrative burden not only for the small entities, but for the Issuer of the OI
as well. 4. Any additional tasks that must be performed during Emergency situations runs
contrary to the intent of the standard, which is to normalize communication protocols during
all situations, and not have separate procedures during normal and Emergency conditions.
Individual
Christopher Wood
Platte River Power Authority
Yes
Yes
Yes
Yes
Platte River takes exception to the requirement for alpha-numeric clarifiers for
communications.
Individual
Don Schmit
Nebraska Public Power District
No
Recommendation 26 calls for work to be done to improve the effectiveness of
communications in emergency situations. The purpose of the standard is to improve
communications. However, the focus of the standard is primarily 3-part communications.
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There is no supporting documentation or data that 3-part communications improves the
effectiveness of communications. Focusing on 3-part communications provides an easy
target from a compliance perspective but all it teaches us is to mechanically repeat back
what we have been instructed to do. We’re focusing on the ‘how’ and ‘what’ rather than the
‘why’. Keeping the ‘why’ in mind improves communications and the reliability of the BES.
Keeping the ‘why’ in mind also leads to improved situational awareness. Improving effective
communications is difficult to quantify in a standard and even more difficult to measure. We
may be better off focusing on the principles contained in the OC’s Reliability Guideline
System Operator Verbal Communications – Current Industry Practices.
Yes
1) Applicability for Distribution Providers (DP’s) should be qualified similar to qualification
used for DP applicability in version 5 of CIP-003. Applicability needs to be focused on DP
employees that may receive instructions relative to the BES. 2) R1: Since Requirements R5,
R6 and R7 are zero tolerance, R1 protocols should state that when there is an emergency
condition on the system that those issuing Operating Instructions during an emergency shall
state that “this is an emergency”. Reason Number 1, there needs to be a triggering
mechanism that tells both the issuer and receiver that 3 part communication is zero
tolerance and in effect during an emergency; Reason Number 2, there is question in the
industry as to when the “emergency” begins and ends; and Reason Number 3 the RSAW for
R5, R6 and R7 are telling the auditor (in the auditors note) to predetermine before an audit
what are emergencies on an entities system, which could potentially create an issue of what
is a determined emergency between the auditor and the entity. By inserting a triggering
mechanism as suggested will create a demarcation for operating instructions during
emergencies. 3) R2 and R3 are already provided for in PER-005 and therefore are redundant
in this standard. If there is a need to include a training requirement in this standard, that
requirement could consist of a statement to include protocol training in the entity’s
reliability task list. 4) R4 as written puts a huge administrative burden on entities to
administer assessments of ‘each’ of its operating personnel that issue and/or receive
Operating Instructions. As in previous drafts of this Standard, entities should determine and
document their own assessments to the Standard and so that adherence and effectiveness
fits their program. In addition, the 12-month requirement in the Standard now provides for
an administrative burden and compliance trap in order to remain compliant to the 12-month
requirement. We’re a TOP and do many switching orders a day with operating personnel
throughout the state. R4 requires us to assess adherence to communications protocols by
our operating personnel (see FAQ #22 says "each" issuer/reciever) that receive these
operating instructions and provide feedback to the operating personnel, and take corrective
actions when appropriate. Currently, we have over 800 switch personnel, and some of these
are not NPPD employees. We utilize personnel from some of our public power partners, such
as rural power districts and municipalities. The 12 calendar month clock will be different for
each person. So, day-to-day will be a challenge to ensure we capture compliance
documentation on each person that changes the state of a BES element. The drafting team
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should revert back language similar to R5 of posting #7 (with exception to the “implement”
language) so that entities can manage their own compliance controls and can develop
assessments that fit their program. NPPD would suggest the following for Requirement 4: R4.
Each BA, RC and TOP shall have a documented method to evaluate the communication
protocols developed in R1 that: 4.1 Assess adherence to the communications protocols
developed in R1; 4.2 Assess the effectiveness of the communications protocols in R1; 4.3
Provide feedback to issuers and receivers of Operating Instructions; and 4.4 Modify
communication protocols as necessary as a result evaluated communication protocols in this
R4.
Group
Florida Municipal Power Agency
Frank Gaffney
Yes
Yes
Yes
Yes
FMPA is voting “affirmative” on this standard, yet we have concerns with the RSAW language
and lack of criteria on how an entity will be assessed and audited. There is language in the
RSAW “Notes to Auditor” for multiple requirements (R4-R7) that is of concern. (See example
below) The RSAW language is not clear regarding the nature and extent of audit procedures
that will be applied because there is reference to scoping the audit based on “certain risk
factors to the Bulk Electric System”. It is not clear what “risk factors” will be used. As an
example in R5 auditing “can range from exclusion of a requirement from audit scope to the
auditor reviewing, in accordance with the above Compliance Assessment Approach, evidence
associated with the entity’s responses to numerous Operating Instructions issued during
Emergencies.” This is essentially a zero tolerance approach, yet, also appears to be an
attempt to apply Reliability Assurance Initiative (RAI) concepts, that have not been finalized
and communicated to the industry. It is uncertain whether these concepts have been fully
developed yet; and therefore, this leaves too much auditor discretion, without providing the
industry information or criteria on how “risk” will be assessed. Stakeholders continue to
await the details of these RAI concepts that are being utilized in RSAWS. Clarity is needed
around how an entity’s risk to the BES will be assessed due to compliance or non-compliance
with this standard. This would also beneficial for an entity to know, so that they can lessen
that risk, as appropriate. Example language from RSAW: “The extent of audit procedures
applied related to this requirement will vary depending on certain risk factors to the Bulk
Electric System. In general, more extensive audit procedures will be applied where risks to
the Bulk Electric System are determined by the auditor to be higher for non-compliance with
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this requirement. Based on the auditor’s assessment of risk, as described above, specific
audit procedures applied for this requirement may range from exclusion of this requirement
from audit scope to the auditor reviewing, in accordance with the above Compliance
Assessment Approach, evidence associated with the entity’s responses to numerous
Operating Instructions issued during Emergencies. “
Group
Arizona Public Service Co.
Janet Smith
Yes
Yes
Yes
No
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
Yes
These comments are submitted on behalf of the following PPL NERC Registered Affiliates:
Louisville Gas and Electric Company and Kentucky Utilities Company; PPL EnergyPlus, LLC;
PPL Electric Utilities Corporation; and PPL Generation, LLC, on behalf of its NERC registered
entities. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC, RFC,
SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA,
LSE, PA, PSE, RP, TO, TOP, TP, and TSP. Each of the PPL NERC Registered Affiliates recognize
the need for and support the use of three part communications for Operating Instructions.
However, we are abstaining from voting on this standard because we believe that the
current version of COM-002-4 requires change to ensure consistency with the SDT’s intent. If
these clarifications are made, the PPL NERC Registered Affiliates would support the proposed
standard. First, the PPL NERC Registered Affiliates request that the SDT revise Measure M.4
to specifically state that sampling is allowed in performing the assessments required by
Requirements R.4.1 and R.4.2. This is consistent with the SDT’s oral statements during the
January 17, 2014 webinar and the FAQ (“An entity could perform an assessment by listening
to random samplings of each of their operating personnel issuing and/or receiving Operating
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Instructions….”). Additionally, for consistency and to avoid ambiguity, the SDT should also
conform the wording in Measure M.4 to Measures M.5-M.7 (i.e., “Such evidence may
include, but is not limited to,…”). Therefore, we recommend that the SDT revise Measure
M.4 as follows: M4. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall provide evidence of its assessments. Such evidence may include, but is not
limited to, sampling results, spreadsheets, logs or other evidence of feedback, findings of
effectiveness and any changes made to its documented communications protocols
developed for Requirement R1 in fulfillment of Requirement R4…. Second, the PPL NERC
Registered Affiliates request that the SDT clarify in the proposed standard that only a failure
to use three-part communications during an Emergency is a violation of COM-002-4.
Therefore, we recommend that the standard’s requirements be further revised to indicate
that if an entity does not adhere to its documented communications protocols developed in
accordance with Requirement R.1 during a non-Emergency, such action shall not be
considered a noncompliance event under Requirement R.1.
Individual
John Brockhan
CenterPoint Energy Houston Electric LLC
Yes
CenterPoint Energy agrees that the COM-002-4 standard addresses the NERC Board of
Trustees 2013 Resolution.
Yes
CenterPoint Energy agrees that the COM-002-4 standard addresses both the August 2003
Blackout Report Recommendation 26 and FERC Order 693.
No
CenterPoint Energy does not agree with the Severe VSL for Requirement R1. The Company
strongly believes that the focus of any Reliability Standard should be on enhancing the
reliable operation of the BES and not on documents. Simply failing to document a procedure
should never warrant a Severe VSL as long as the entity is operating according to the
Standard.
Yes
CenterPoint Energy would like to thank the COM-002-4 Standard Drafting Team and
appreciates the SDT’s time and effort dedicated in the development of this standard, in
engaging the industry, and incorporating industry feedback into the standard. The removal of
the requirement to identify an Operating Instruction in an emergency or a Reliability
Directive to the receiver is viewed as a positive change. CenterPoint Energy believes that
operating personnel’s focus should always be on monitoring and controlling the reliability of
the BES rather than a compliance burden of correctly identifying and aligning company
specific communication protocols to normal versus emergency operations. Overall,
CenterPoint Energy agrees with the standard, but still has general concerns. The Company
believes the prescriptiveness of the requirements: particularly R1.1 thru R1.6 exceeds the
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necessary components needed in establishing communication protocols for tightened
reliable communications.
Individual
David Jendras
Ameren
Agree
Ameren agrees with and supports the SERC OC comments on COM-002-4.
Group
Duke Energy
Michael Lowman
No
(1)Duke Energy believes that Operating Instruction during an Emergency is unclear, vague,
and subject to interpretation. By using the NERC defined term of Emergency, certain tasks
that Duke Energy believes is a non-emergency action would now be considered an
Emergency and subject to zero tolerance. Duke submits, for consideration by the SDT, a
revised definition of Emergency in an attempt to remove this ambiguity. Emergency – Any
abnormal system condition that requires automatic or immediate manual action to prevent
the failure of transmission facilities or generation supply that would adversely affect the
reliability of the Bulk Electric System.
No
(1)Based on our comments to Question 1, Duke Energy does not believe that the SDT has
addressed Recommendation 26 of the August 2003 Blackout report. The intent of the 2003
Blackout recommendation was to provide tighter communication during normal and
emergency situations. Due to the ambiguity that exists between Operating Instruction and
Operating Instruction during an Emergency, we believe that this recommendation was not
addressed.
Yes
(1)Duke Energy suggests rewording R1.6 as follows: “Specify the nomenclature to be used for
Transmission interface Elements and Transmission interface Facilities when issuing an oral or
written Operating Instruction to neighboring entities.” While the Technical Justification
document suggests that R1.6 applies to communication with neighboring entities, it is
unclear that this requirement, as worded in the current draft of COM-002-4, is specifically
discussing communication with neighboring entities. (2)M2 should include “initial training”
and be reworded as follows in order to maintain consistency with the requirement: “Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide initial
training records related to its documented communications protocols developed for
Requirement R1 such as attendance logs, agendas, learning objectives, or course materials in
fulfillment of Requirement R2.”
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Individual
Marie Knox
MISO
Yes
Yes
Yes
Yes
We recommend the drafting team: (1) Remove the attestation for another provision (2)
Restrict the zero-defect component of the standard to those operating instructions directly
related to the emergency (e.g. redistpach instructions for IROLs, committtment instructions
during EEAs, synchronizing during restoration, etc.) (3) Maintain Reliability Directives in the
toolkit as the clear indicator of an Operating Instruction that is directly applicable to the
emergency. We believe that DPs and LSEs don’t need stringent requirements. They just need
to follow Directives or explain why they cannot. We understand that the drafting team is
trying to meet a deadline, however we'd support the drafting team addressing all of the
industry comments even if it requires more time to get this standard right.
Group
DTE Electric
Kathleen Black
Yes
Yes
No
The evidence needed to avoid violation is not clear. The VSL for R2 is not reasonable and an
auditing nightmare. It should state an operator did not receive training on the documented
communication protocol. Adding "prior to issuing an operating instruction" cannot be
determined without excessive investigation. A check that all operators received training is
appropriate. Same issue with R3 as listed for R2.
No
None
Individual
Catherine Wesley
PJM Interconnection
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Yes
Yes
Yes
Yes
PJM supports the draft standard as it strikes a good balance between the industry and the
NERC BOT November, 2013 resolutions. The standard provides the industry some flexibility
regarding how communication protocols are developed. It also makes it cleaner and easier
for operators to use the same protocol for all Operating Instructions, whether in an
emergency or not, while not burdening System Operators with issues around how
compliance will be measured. PJM does not support the addition of a new training
requirement under R1. PJM recommends that all training requirements be included in one
standard and not spread throughout families of standards. Consolidation of all training
requirements under a single training standard will help in development of a clear, more
organized training process.
Group
SPP Standards Review Group
Robert Rhodes
No
Our understanding of Recommendation 26 is that it deals strictly with communications
during emergencies which COM-002-3 had already addressed. The addition of nonemergency communications, which are not mentioned in Recommendation 26 at all, has
expanded the scope of the standard beyond that called for by the recommendation. The
addition of non-emergency communications has added additional compliance burden for the
responsible entities without clearly improving the reliability of the BES.
No
We suggest changing the Moderate VSLs for R5, R6 and R7 to Lower. If the failure to
completely follow through with the protocols contained in R1 had no adverse impact on the
situation, then this VSL is purely administrative and is not deserving of being Moderate. The
Lower and Moderate VSLs for R1 contain specific details regarding each of the Parts
referenced in each of the VSLs. In the High and Severe VSLs for R1 only reference is made to
the Parts while the details contained in the Parts is not included in the VSLs. Either the
details should be removed from the Lower and Moderate VSLs or the details need to be
included in the High and Severe VSLs.
Yes
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The removal of Reliability Directive from the definition of Operating Instruction has removed
clarity from a compliance viewpoint. Without this clarity, which could also be provided by
requiring a statement which identifies the Emergency situation as an Emergency, the
operator does not know that he is in an Emergency situation. Although the operator’s
response may be the same as it is in a non-emergency, the compliance hook of zero
tolerance is there. We need a mechanism in place that we can use to identify when we are in
an Emergency situation which prevents Monday-morning quarterbacking during an audit
regarding whether an Emergency actually occurred or not. Reliability Directive gave us that
indication. We recommend requiring an Operating Instruction that is issued during an
Emergency situation be identified as ‘This is an Emergency.’ Recommendation 26 calls for
work to be done to improve the effectiveness of communications in emergency situations.
The purpose of the standard is to improve communications. However, the focus of the
standard is primarily 3-part communications. There is no supporting documentation or data
to support the position that 3-part communications improves the effectiveness of
communications. Focusing on 3-part communications provides an easy target from a
compliance perspective but all it teaches us is to mechanically repeat back what we have
been instructed to do. We’re focusing on the ‘how’ and ‘what’ rather than the ‘why’. Keeping
the ‘why’ in mind improves communications and the reliability of the BES. Keeping the ‘why’
in mind also leads to improved situational awareness. Improving effective communications is
difficult to quantify in a standard and even more difficult to measure. We may be better off
focusing on the principles contained in the OC’s Reliability Guideline System Operator Verbal
Communications – Current Industry Practices. We suggest that R2 and R3 are already
provided for in PER-005 and therefore are redundant in this standard. If there is a need to
include a training requirement in this standard, that requirement could consist of a
statement to include protocol training in the entity’s reliability task list. Measure 4 adds an
additional requirement regarding the failure to follow protocols which in turn leads to an
Emergency. The Measure basically requires the responsible entity to assess those particular
situations even though they are not specifically called out in the requirement. We
recommend adding the following sentence at the end of R4.1: ‘Such assessment shall
include, at a minimum, any instance that is an Emergency.’ We recommend that the drafting
team consider moving R4 back to language similar to that contained in R5 of Posting 7. This
language is much clearer and eliminates Paragraph 81 concerns of administrative burden
associated with the required 12-month assessments and removes the ambiguity of
‘corrective actions’ and ‘as appropriate’. In the last line of the Evidence Requested table in
the R2 section of the RSAW, the following evidence is requested: ‘Organization chart or
similar artifact identifying the operating personnel responsible for the Real-time operation of
the interconnected Bulk Electric System and the date such personnel began operating the
Real-time Bulk Electric System.’ This implies that an entity will be found non-compliant if
operating personnel operate the Real-time BES prior to receiving training on issuing
Operating Instructions. This is not what is stated in the requirement. This entry should be
reworded to the following: ‘Organization chart or similar artifact identifying the operating
personnel responsible for the Real-time operation of the interconnected Bulk Electric System
and the date such personnel began issuing Operating Instructions.’ Similarly, this change
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needs to be made in the Compliance Assessment Approach Specific to COM-002-4, R2 table.
That entry should read: ‘Verify applicable operating personnel, or a sample thereof, received
the required training prior to the date they began issuing Operating Instructions by agreeing
selected personnel names to training records.’
Group
Bureau of Reclamation
Erika Doot
Yes
Reclamation requests that R5 include a bullet requiring the issuer of an Operating Instruction
during an Emergency to identify the situation as an Emergency. This is important because R6
requires recipients of Operating Instructions to repeat the instructions during Emergencies,
but it may not be clear to the recipient that an Emergency is occurring. Reclamation
reiterates that R1.3 and R3 should also allow the receiver of an Operating Instruction to
respond by explaining that a requested action cannot be performed (e.g., due to safety,
equipment, regulatory, or statutory requirements as described in TOP-001 R3 and IRO-001
R8). The requirement to either repeat or request that the instruction be reissued does not
account for the realistic situation that an entity may not be able to perform an Operating
Instruction. The drafting team could choose to address this point with a footnote explaining
that the requirement to repeat the instruction does not obligate the recipient to perform the
action if he repeats the instruction, but then explains that he cannot perform the action
because doing so would violate safety, equipment, regulatory, or statutory requirements.
Individual
Brett Holland
Kansas City Power & Light
Agree
SPP - Robert Rhodes
Group
Dominion
Louis Slade
Agree
SERC OC Standards Review group
Group
Dominion
Louis Slade
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No
We do not believe the proposed requirements and measures clearly delineate the
differences in the actions required to be taken by the issuer and recipient depending upon
whether or not the Operating Instruction is being given to alleviate or avoid an Emergency.
No
We do not agree that the blackout recommendation calls for the use of 3 part
communication for every Operating Instruction and note that neither the NERC Board nor
the SDT has provided any evidence that indicates a direct correlation between errors due to
communication problems and events that adversely impacted the BES. Therefore we find it
difficult to support reliability standard requirements that require 3 part communication for
every Operating Instruction and enforce compliance with same.
No
We believe that the VRFs/VSLs should be modified to better reflect the stated intent of the
NERC Board of Trustees November 19th, 2013 Resolution, which is to enforce ‘zero
tolerance’ only for failure to use 3 part communiations by the issuer or recipient of an
Operating Instruction when it is issued to alleviate or avoid an Emergency.
Yes
The proposed standard still contains requirements that mandate the use of, and training to
include, 3 part communications during issuance of all Operating Instructions, including those
issued during non-Emergency situations. While Dominion agrees that the SDT has stated in
its Rationale and Technical Justification document that the proposed measures and RSAW
don’t specifically require that auditors verify compliance of this for the requirements (and
associated measures), a strict read leads us to a different conclusion. Under the RSAW for R1
it states that the entity shall provide its documented communications protocols developed
for this requirement and the auditor shall review the documented communications protocols
provided by entity and ensure they address the Parts of R1 (including the use of 3 part
communications). The RSAW contains similar actions relative to R2 and R3 in that the entity
is to provide evidence consisting of agendas, learning objectives, or course materials that it
provides pursuant to these requirements. Given this, Dominion believes an auditor can
enforce to a ‘zero defect tolerance’ if it chooses to do so and in fact would argue that an
audit would be deficient if it failed to validate whether the learning objective included
insuring that 3 part communication was used during issuance or receipt of each Operating
Instruction. Dominion also finds there are not clear and concise differences between
requirements 1, 5 and 6 resulting in uncertainty as to whether the Operating Instruction is
being issued to alleviate or avoid an Emergency. Dominion is concerned that, absent a
requirement that the issuer make a definitive statement as to whether an Operating
Instruction is being issued to alleviate or avoid an Emergency, neither the recipient (during)
nor an auditor (after) would be able to make such determination. Having said this, we could
support the standard if it were revised in a fashion similar to that described below. 1. Modify
requirement 1 so that it applies to all Operating Instructions but requires that those being
issued to alleviate or avoid an Emergency be specifically identified as such and that the issuer
explicitly request recipient confirm their understanding through use of 3 part
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communication. 2. Remove requirements 5, 6 & 7 (incorporating specific items deemed
necessary by the SDT as bullets or sub-requirements of R1). 3. Revise measures, VRFs/VSLs
and RSAW so that strict compliance with use of 3 part communication is only applied when
an Operating Instruction is issued to alleviate or avoid an Emergency as identified by the
issuer at the time of issuance. 4. Measure M4 requires compliance demonstration beyond
Requirement R4. Specifically, entities must provide evidence that appropriate corrective
action was taken for all instances where an operating personnel’s non-adherence to the
protocols developed in Requirement R1 is the sole or partial cause of an Emergency…,
Examples of suggested changes R1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented communications protocols for its
operating personnel that issue and receive Operating Instructions. The protocols shall, at a
minimum: [Violation Risk Factor: Low][Time Horizon: Long-term Planning] 1.1. Require that
its operating personnel identify, at the time of issuance, when the Operating Instruction is
being issued to alleviate or avoid an Emergency 1.2. Require its operating personnel that
issue an oral two-party, person-to-person Operating Instruction to take one of the following
actions: • Confirm the receiver’s response if the repeated information is correct. • Reissue
the Operating Instruction if the repeated information is incorrect or if requested by the
receiver. • Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver. • Request recipient use 3 part
communication when the Operating Instruction is being issued to alleviate or avoid an
Emergency 1.3 Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise. An alternate
language may be used for internal operations. 1.4. Require its operating personnel that issue
a written or oral single-party to multiple-party burst Operating Instruction to confirm or
verify that the Operating Instruction was received by at least one receiver of the Operating
Instruction. 1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification. 1.6. Specify the
nomenclature for Transmission interface Elements and Transmission interface Facilities
when issuing an oral or written Operating Instruction. M1. Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall provide its documented
communications protocols developed for Requirement R1. For each Operating Instruction
issued to alleviate or avoid an Emergency; entity shall provide evidence that it identified such
at time Operating instruction was issued (R1.1) and requested recipient use of 3 part
communication (R1.2). • VSL for R1 – modify Severe to include any instance where entity
either (1) failed to identify, at the time of issuance, that the Operating Instruction is being
issued to alleviate or avoid an Emergency or (2) failed to request recipient use 3 part
communication when the Operating Instruction was issued to alleviate or avoid an
Emergency
Group
ACES Standards Collaborators
Ben Engelby
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No
(1) We disagree that the current draft addresses the NERC Board resolution because the
Board charged the drafting team with developing an “essential set of communications
protocols” for reliable operation of the BES. The proposed standard conflicts with other
existing reliability standards, which would subject entities to double jeopardy. Therefore, the
standard includes more than an “essential set” of requirements as stated in the NERC Board
Resolution. (2) For example, the “nomenclature” protocol in Requirement R1 is duplicative
with TOP-002 R18. Since FERC issued a NOPR proposing to remand the TOP standards, the
requirement of using “uniform line identifiers” will remain as an enforceable standard.
Having a nomenclature requirement in COM-002-4 will subject entities to double jeopardy
and is not an “essential set of communication protocols.” (3) Another example of a
redundant requirement is training. Communications that impact the BES will be covered in a
reliability related task as part of the systematic approach to training. This will also subject
entities to double jeopardy with PER-005 R1 and is not an “essential set of communication
protocols.” (4) We appreciate the efforts of the drafting team in working to address the FERC
directives and NERC November 2013 BOT Resolution, but we do not believe that COM-002-4
accurately reflects the proper applicability for entities that have an impact on the operations
of the Bulk Electric System in normal and emergency conditions. We understand that the
inclusion of Distribution Providers to this standard stems from various FERC directives, but
because of the relationship of Distribution Providers with Transmission Operators as
identified in NERC's functional model in being only a receiver of instructions to implement
voltage reduction or to shed load to prevent the failure of the BES, or related to restoration
activities as coordinated with the Transmission Operator; the TOP is ultimately responsible
for the proper execution of the instructions. Thus, we continue to recommend that
Distribution Providers be removed from the applicability of COM-002-4. (5) Knowing that it
will be difficult to remove the Distribution Provider from the applicability of COM-002-4 per
FERC's directives, we recommend an alternative that parallels the recently FERC approved
CIP-003-5 applicability section 4.1.2, which we believe accurately captures those DPs that
receive Operating Instructions associated with the reliability of the BES. The following
alternative can be used as technical justification to clarify those Distribution Providers that
have an impact on the BES is recommended: “4.1.2 Distribution Provider that: 4.1.2.1 Has
capability to shed 300 MW or more of load in a single manually initiated operation. 4.1.2.2
Has switching obligations related to any Cranking Path and group of Elements meeting the
initial switching requirements from a Blackstart Resource up to and including the first
interconnection point of the starting station service of the next generation unit(s) to be
started.”
No
(1) We believe recommendation number 26 of the 2003 Blackout Report continues to be
misinterpreted. The recommendation is focused on how the ERO should communicate with
governmental agencies. It states, “Standing hotline networks, or a functional equivalent,
should be established for use in alerts and emergencies (as opposed to one-on-one phone
calls) to ensure that all key parties, [including state and local officials] are able to give and
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receive timely and accurate information.” The recommendation does not state anywhere to
utilize three-part communication. COM-002-4 does not address the development of hotline
networks or “upgrading communication system hardware where appropriate” for contacting
governmental agencies, including state and local officials.
No
(1) We disagree with some of the requirements of including training and several aspects of
the communication protocols. Since we disagree with the underlying requirements, we also
disagree with the corresponding VSLs and VRFs.
Yes
(1) We disagree with training requirements as they are redundant with PER-005. Similar to a
FERC directive, the drafting team should be able to provide the BOT with technical
justification that other alternatives exist to developing a new requirement such as pointing
to an existing requirement. Training is already included in the PER requirements. The drafting
team should provide the feedback from industry and show that there is an already existing
enforceable standard that covers this issue of training and there are no gaps in reliability. (2)
We do not think the Distribution Provider should be an applicable function. Most
Distribution Providers simply do not have a materially impact on BES reliability. We suggest
an alternative to have the standard apply to those DP that may impact the BES. According to
the FERC-approved CIP version 5 standards, a Distribution Provider is subject to the
standards if the DP has UFLS/UVLS systems that have the capability of shedding 300 MW or
more of load. We ask the drafting team to consider revising the applicability section to
mirror the CIP standards. There was technical justification provided during the development
of those standards, NERC and FERC both approved those standards, and therefore, a
precedent exists for this reasonable approach to focusing on entities that pose an impact,
however minimal, to the BES. (3) Many DPs have no practical way to demonstrate
compliance with “repeat backs.” Many DPs do not have recording systems for the telephonic
communications. This puts the DP in a position to request the voice recordings or
attestations from the issuer. The issuer is not obligated to provide the data and, in fact,
history has shown that many registered entities will not provide this type of data to a third
party for fear of compliance issues being identified with the issuer. Thus, from a practical
perspective the standard puts the DP in the position of having to use weak evidence to
demonstrate compliance. This is an unreasonable burden on the DP. (4) We recommend that
the drafting team remove references to “taking alternative actions.” This is ambiguous and
could potentially tie in actions that should be taken in accordance to directives in IRO-001
and TOP-001. COM-002 is related only to communications, so taking alternative actions must
be limited to alternative communications. (5) We suggest that the “assess adherence and
assess effectiveness” language in R4 be removed from COM-002-4. This language is similar to
the “Identify, Assess and Correct (IAC)” language that was included in the CIP V5 standards.
The removal or modification of this language was included in the Final Rule on NERC CIP V5
Standards (Order No. 791). FERC stated that IAC language and concepts would be best
addressed in the NERC compliance processes, such as through the NERC Reliability Assurance
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Initiative (RAI), rather than standards requirements. (6) Thank you for the opportunity to
comment.
Group
Tennessee Valley Authority
Brandy Spraker
Agree
SERC Operating Committee Review Team
Individual
Scott McGough
Georgia System Operations Corporation
Yes
No
GSOC recommends modifying R1 so that it applies to all Operating Instructions but requires
that those being issued to alleviate or avoid an Emergency be specifically identified as such
and that the issuer explicitly request recipient confirm understanding through use of 3 part
communication. This would require a revised R1.1 Proposed R1: ADD: Require that its
operating personnel identify, at the time of issuance, when the Operating Instruction is being
issued to alleviate or avoid an Emergency. Proposed R1.2: ADD: Request recipient use 3 part
communication when the Operating Instruction is being issued to alleviate or avoid an
Emergency. Proposed R1.3: change the word “correct” to “understood” Requirement 2:
GSOC believes R2 should be elminiated as redundant with the systematic approach to
training requirements of PER-005-2(Operating Personnel Training) which are applicable to all
Bas, RCs and TOPs. Communication protocols must be included in each company’s specific
relilability-related task list. GSOC believes the current proposal of COM-002-4 still contains
ambiguities that can be resolved with the following alternative. GSOC recognizes the
following alternative in that it parallels the recently FERC approved CIP-003-5. GSOC believes
this alternative more accurately captures those DPs that receive Operating Instructions
associated with the reliability of the BES. 4.1.2 Distribution Provider that: 4.1.2.1 Has
capability to shed 300 MW or more of load in a single manually initiated operation. 4.1.2.2
Has switching obligations related to Any Cranking Path and group of Elements meeting the
initial switching requirements from a Blackstart Resource up to and including the first
interconnection point of the starting station service of the next generation unit(s) to be
started.
No
R1 – GSOC requests that there not be applied a Severe VSL for normal everyday Operating
Instructions.
Yes
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With consideration that an Emergency may not be initially recognized by system operators
for several minutes, GSOC requests Requirements R5 thru R7 include the word “recognized”
precede the work “Emergency”. GSOC cites the newly effective EOP-004-2, R2 currently
affords this consideration. It requires reporting “within 24 hours of recognition of meeting an
event type threshold”. In addition, GSOC recommends R5 thru R7 replace the words “during
an Emergency” with “addressing a recognized Emergency” so as to avoid confusion should
there be Operating Instructions issued during an Emergency that may have nothing to do
with an Emergency. GSOC suggests that the “assess adherence and assess effectiveness”
language in R4 be removed from COM-002-4. This language is similar to the “Identify, Assess
and Correct (IAC)” language that was included in the CIP V5 standards. The removal or
modification of this language was included in the Final Rule on NERC CIP V5 Standards (Order
No. 791). FERC stated that IAC language and concepts would be best addressed in the NERC
compliance processes, such as through the NERC Reliability Assurance Initiative (RAI), rather
than standards requirements
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
No
This standard is not responsive to the Blackout Recommendation #26. The prevention of
miscommunication is the current focus of this standard, while nothing in the Blackout Report
commented on an instruction not being followed due to miscommunication. Rather, the
Blackout Report focused on a lack of situational awareness based on one entity not
understanding what the other entity was describing because different entities used different
terminology. Flow of communications or “who” should be notified was also lacking in
addition to “what” needed to be communicated. The report highlighted that effective
communication was based on communication of important and prioritized information to
each other in a timely way. In essence, this focuses on communication protocols to prevent
miscommunications while Recommendation #26 focused on effective communication
protocols that improve situational awareness, where the former is process and the latter is
substantive. That being said, and regardless of whether COM-002-4 addresses the August
2003 Blackout Report Recommendation number 26 or not, ERCOT ISO can support the COM002-4 standard. However, ERCOT ISO believes the draft standard could be improved and
offers suggestions in Question 4 below, for the SDT’s consideration.
No
R2 and R3 VSLs should not have the “during an Emergency” distinction between a high and
severe VSL. VSL’s grade the severity or “how bad” did an entity violate a requirement. The
risk and situation of non-compliance is included in the VRF and not the VSL. ERCOT ISO would
recommend percentage indicator across the severity levels as detailed in the VSL guideline
document. R5-R7 VSLs should remove “Instability, uncontrolled separation, or cascading
failures occurred as a result.“ as that stipulation is not appropriate in the VSLs. The resulting
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impact of non-compliance is addressed in the enforcement process and not in how severe an
entity did not comply with a requirement. ERCOT ISO suggests a binary or severe only VSL to
coincide with the VSL Guideline document. Additionally, ERCOT ISO would recommend
adding “at least” in the R5 VSL to better clarify that a minimum of one of the three actions is
required and not all three. The responsible entity that issued an Operating Instruction during
an Emergency did not take ‘at least’ one of the following actions:
Yes
ERCOT ISO believes the draft standard could be improved and offers the following
suggestions for the SDT’s consideration. Definition of Operating Instruction The definition of
Operating Instruction could be improved by making the following changes: 1) Delete the
word “interconnected” before BES in the first sentence. It is not used instances where BES is
used. Unless there is a substantive reason for using interconnected in some BES references
and not others, the standard should be consistent to mitigate ambiguity; 2) “Potential
Options” in the parenthetical is redundant – delete “potential”. Also, “option” and
“alternatives” in the parenthetical are also redundant – delete one of them; 3) The
parenthetical doesn’t need to be a parenthetical – make it the last sentence in the definition.
As revised, the definition would read as follows: Operating Instruction — A command by
operating personnel responsible for the Real-time operation of the Bulk Electric System (BES)
to change or preserve the state, status, output, or input of an Element of the BES or Facility
of the BES. A discussion of general information to resolve BES operating concerns is not a
command and is not considered an Operating Instruction. Purpose Section The purpose
statement could be improved by making the following changes: 1) Delete “the issuance of” in
the first sentence. It is inherent that a communication is “issued”. Therefore, this language is
superfluous and should be deleted to mitigate any potential ambiguity; 2) Delete
“predefined” in the first sentence. This adjective is not needed - the existence of
communication protocols means they are predefined. Therefore, this is superfluous language
and should be deleted to mitigate potential ambiguity. As revised, the purpose section would
read as follows: Purpose: To improve communications for Operating Instructions with
communications protocols to reduce the possibility of miscommunication that could lead to
action or inaction harmful to the reliability of the Bulk Electric System (BES). Requirements
Section R1 1) ERCOT ISO disagrees with changing “have” to “develop” in the first sentence.
The point of this requirement is to have protocols that meet the minimum requirements.
Obviously, in order to have the protocols an entity would need to develop them, but that is
not the focus – as noted, having the protocols is the intent; 2) Change “and” to “or” in the
following - “…for its operating personnel that issue or receive Operating Instructions…” The
intent is to make the obligation to have protocols applicable to all operating personnel of the
relevant functions. It may be that some functions only issue or only receive operating
instructions. In those cases this requirement would not apply to those entities because the
requirement is conjunctive – issue and receive. By making it disjunctive by using “or” the
requirement applies to all circumstances – i.e. issue and receive or just issue or just receive;
3) The change suggested in (2) above should be made in R1.1 as well; 4) Also in R1.1, the
triggering condition for using another language besides English - i.e. “unless otherwise
agreed to” – is unclear in terms of how that would work. How do you demonstrate that such
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an agreement is in place? Also, practically speaking, the ability to reach such an agreement
assumes that all operators are capable of speaking the alternative language. It seems way
too complicated because it would depend on the languages spoken by the different
operators at different entities, and their schedules would have to be coordinated. These
issues are less of a concern for allowing alternative languages for internal communications
because the entity’s personnel know one another and are located in the same
place/organization. ERCOT ISO appreciates the intent of allowing for this exception, but it is
difficult to see how it would work in practice, and even assuming it could work, the
requirement is unclear as to what sort of agreement would be required; 5) R1.2 – Change
“repeated information” to “response”. First, this change promotes consistency in
terminology. Second, it is more consistent with the intent that the receiver is not required to
repeat the directive verbatim – response contemplates flexibility as long as intent is there,
while repeated information seems to require a verbatim reply; 6) The last bullet in R1.2
requires the issuer to take an alternative action if a response is not received or if the
instruction is not understood. It is unclear what this means. Is the obligation related to trying
to re-issue the instruction, or does it require the issuer take an alternative operating action?
This is a communications standard, not an operations standard. Accordingly, the intent of
this bullet should be clarified, and if it requires the issuer to take an alternative operating
action, ERCOT ISO questions whether that obligation should be in a COM standard.
Operational requirements are already covered in other standards, and if entities act under
those other standards then the relevant communications protocols would apply to those
“alternative” operating actions. ERCOT ISO believes that the “alternative action” described in
the third bullet of R1.2 and R5 should be limited only to communications and not operating
actions. ERCOT ISO would recommend replacing R1.2 and R5 third bullet with the following:
Attempt an alternative means to communicate the Operating Instruction if a response is not
received or if the Operating Instruction was not understood by the receiver, if deemed
necessary by the issuer. ERCOT ISO also recommends including “or receiving” to capture that
the training should be prior to that individual operator issuing ‘or receiving’ an Operating
Instruction to address the subparts of R1 that deal with receiving Operating Instructions. 7)
R1.4 – Delete “single-party”. It is clear that an issuer is one entity without having to add
“single-party”. Accordingly, this is superfluous language and should be deleted to mitigate
ambiguity. If this deletion is made, “operating instruction” would have to be moved to where
“single-party” was in the sentence; 8) R1.4 requires the issuer to “confirm” or “verify” that
the instruction was received by at least one entity. They are the same thing – delete one of
them for clarity and to mitigate ambiguity; 9) R1.5 requires the communication protocols to
specify the instances where time identification is required and to specify the format for time
identification. As written, this appears to require the protocols to specifically list all relevant
instances and, where relevant, requires the use of a specific time ID format. The SDT should
consider revising this so the requirement imposes a general obligation for the protocols to
time ID instructions when necessary, but not require the establishment of an exclusive list.
This will accomplish the goal of time stamping and provide the entity with flexibility to
implement the requirement, which will also mitigate the need to revise protocols if an entity
determines prospectively that time ID is not needed in some instances on the list and is
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needed in other instances that are not on the list. Similarly, the protocols should not require
a specific format. Providing flexibility with respect to format will mitigate the potential for
form over substance violations of the protocols – time ID is the point, not the format; 10)
R1.6 requires the protocols to establish nomenclature for transmission elements. It is unclear
how this will facilitate clearer communications unless all entities that are issuers or recipients
of instructions use the same nomenclature. As drafted, it appears that it is an independent
obligation that applies to each entity. If that is the case, each entity could use different
nomenclature, which arguably could have a negative impact on communications. R4 1)
ERCOT ISO understands the inclusion of R4 as a means to make normal operations Operating
Instructions not subject to zero tolerance enforcement. However, ERCOT ISO has
reservations concerning potential subjectivity surrounding who determines “appropriate”
and “as necessary”. As a general comment, these types of “internal controls” requirements
are better handled through the RAI initiative and subsequent CMEP processes. However, if
the language remains, ERCOT ISO believes the clarity and effectiveness of the standard will
benefit by clarifying that the entity who is conducting the assessments determine the
appropriateness and necessity, and that the role of the ERO is simply to review if such
activities were performed. ERCOT ISO recommends modifications as below. 4.1. Assess
adherence by its operating personnel that issue or receive Operating Instructions to the
documented communications protocols ‘required’ in ‘by the subparts’ of Requirement R1, ,
provide feedback to those operating personnel and take corrective action, as ‘deemed’
appropriate ‘by the entity’ to address deviations from the documented protocols. 4.2. Assess
the effectiveness of its documented communications protocols ‘required’ in ‘by the subparts
of’ Requirement R1, for its operating personnel that issue or receive Operating Instructions
and modify its documented communication protocols, as ‘deemed’ necessary ‘by the entity’.
Additionally, ERCOT ISO recommends including language to specify that R4 only be required
to apply to those communication protocols that are identified in the subparts of R1, and not
to other practices that an entity may choose to employ or improve upon. This clarification
will mitigate creating a “fill in the blank” type standard approach for future potential changes
to the R1 documented communication protocols. R5 1) How does the term “Emergency” in
this requirement align with/relate to the term “Reliability Directive” in other standards, both
in terms of meaning and scope of related responsibilities – is there overlap that could create
ambiguity or unnecessary redundancy? There is a concern regarding the use of “Operating
Instruction during an Emergency”. While ERCOT ISO understands the rationale behind
replacing Reliability Directive with the new terminology based on the FERC NOPR potentially
remanding the term, to avoid overlap/redundancy/confusion if this is retained, any potential
conflicts must be addressed through other projects. Use of Reliability Directive up until this
draft created clear synergy between COM-003/002 and the IRO/TOP revisions. If the term is
not remanded, ERCOT ISO would support a more uniform approach by including Reliability
Directive; 2) Change “repeated information” to “response” in first two bullets. See comment
5 in R1 comments above for rationale for this suggested change; 3) Third bullet – see
comment 6 under R1 comments – same comment for the third bullet under R5; R7 1) Delete
“single party” and delete either “confirm” or “verify” – see comments 7 and 8 under R1 for
rationale for these suggested revisions. Measures M4 is too prescriptive and inappropriately
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imposes requirements on the entity. This measure should align with previous comments
concerning R4. M4 should be modified to reflect appropriate measures or types of evidence
that should be provided without being overly prescriptive with respect to the level of quality
of evidence. Additionally each part should be included and reflect the requirements without
imposing additional requirements. M5-M7 should not identify attestations from the issuer or
include “dated and time stamped” as part of the measure. Compliance should be
demonstrated by the relevant entity – third parties should not be required either directly or
indirectly to support the compliance activities of another entity by providing attestations.
“Dated and time stamped” goes to the quality of evidence and is not appropriate for a
measure. ERCOT ISO comments that inclusion of attestations, documented observations,
procedures, or other equivalent evidence would improve M5-M7.
Individual
Michael Landry
DEMCO
Agree
NRECA
Group
ISO/RTO Council Standards Review Committee
Greg Campoli
No
We do not agree with the following VSLs: i) R4: The LOW VSL suggests that an entity is
assigned a LOW VSL if assessments are conducted more than 12 months apart. There is no
max or “cap” to the delayed assessment and hence an entity may be 18, 19 or more months
late in conducting the next assessment. In other standards, this could well be assessed a
MEDIUM or HIGH or even a SEVERE violation, depending on the time period that an entity
failed the 12 month update requirement. Absent this “cap”, or staggered caps, the proposed
HIGH and SEVERE VSLs can only be assessed based on whether or not there was ever an
assessment, even the last assessment was done 3 or 4 years prior to an audit. This is
inconsistent with the general guideline for VSLs. ii) R5: The MEDIUM VSL and SEVERE VSL are
identical, except the latter has a condition that is associated with the impact of the violation.
This is inconsistent with the intent of the VSL, which is to assess the “extent to which” the
requirement was violated, not the impact of the violation which should be captured by the
VRF. This is also inconsistent with the VSL principle and guideline. We suggest removing the
MEDIUM VSL, and the condition under the proposed SEVERE VSL that: “AND Instability,
uncontrolled separation, or cascading failures occurred as a result.” iii) R6: Same comments
as in R5. iv) R7: Same comments as in R5.
Yes
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1. R1.4. – [Documented communications protocols for its operating personnel that issue and
receive Operating Instructions shall, at a minimum] Require its operating personnel that
issue a written or oral single-party to multiple-party burst Operating Instruction to confirm or
verify that the Operating Instruction was received by at least one receiver of the Operating
Instruction. • Some ISO’s issues multiple-party burst Operating Instruction to Generator
Operators through electronic means Associated real-time requirement: R7. Each Balancing
Authority, Reliability Coordinator, and Transmission Operator that issues a written or oral
single-party to multiple-party burst Operating Instruction during an Emergency shall confirm
or verify that the Operating Instruction was received by at least one receiver of the
Operating Instruction. NOTE – ERCOT does not support the following Comment: The SRC
members (excluding ERCOT) do not believe this requirement is necessary for reliability.
Moreover, the Standard Drafting Team has not provided any, nor have we been made aware
of the substantiated rationale for keeping this Requirement except that the SDT believes is it
necessary. 2. R1.6. – [Documented communications protocols for its operating personnel
that issue and receive Operating Instructions shall, at a minimum] Specify the nomenclature
for Transmission interface Elements and Transmission interface Facilities when issuing an
oral or written Operating Instruction. Comment: This Requirement is vague and needs to be
clarified for Registered Entities to know how to comply with it; how would one “specify
nomenclature” system-wide? Even though the posted “Rationale and Technical Justification”
(RTJ) document notes that R1.6 is limited in scope to only Transmission interface Elements or
Transmission interface Facilities (e.g. tie lines and tie substations), this RTJ document should
define these terms and substantiate to what registered entities this needs to apply. For
example, if the intent is to apply this requirement to Inter-Area tie-lines, then it should
probably be limited to Reliability Coordinator-to-Reliability Coordinator communications. If
the intent is to apply this requirement to every type of transmission – say generation
interconnection facilities – it should be clear so that Registered Entities can clearly
understand the burdens associated with this new Requirement. 3. R2. and R3. – …”shall
conduct initial training for each of its operating personnel …” Note – ERCOT and IESO do not
support the following Comment: The SRC members, (excluding ERCOT and IESO) do not
believe a training Requirement is necessary; Responsible Entities must adhere to the
Requirements of NERC Standards and how they accomplish this should not be dictated by a
Standard Requirement. Additionally, to the extent that the SDT concludes that training on 3part communication is necessary to ensure an adequate level of reliability, then any training
requirements should this would already be covered under the PER Standard, which
requiresing training on job tasks. To the extent training requirements should be imposed on
GOP/DP personnel, the PER Standard could be slightly modified to include them. Overall, if
NERC is going to add additional training requirements, they should be located in PER to avoid
complexity in the organization of NERC Standards. Finally, under RAI principles, NERC and
Regions can determine what type of monitoring is appropriate of Responsible Entities’
compliance with the new COM Standard based on the quality of their Training programs. This
would further support reliability by changing the requirement from a one-time audit (i.e.,
initial training) to an ongoing assessment. In conclusion, even though the BOT resolved that
there should be training associated with the COM requirements, it would be beneficial to
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address the BOT’s concern through existing Standards (PER). Basic principles of drafting
regulation should strive to avoid making the organization and relationship among NERC
Standards more complex than need to be. 4. Measurement 6. Meaurement 6 needs to be
revised so that it is consistent with NERC Enforcement policies. Specifically, the last sentence
needs to be rewritten so that “Such evidence may include, but is not limited to, dated and
time-stamped voice recordings[,] dated operator logs, an attestation from the issuer of the
Operating Instruction, voice recordings (if the entity has such recordings), memos and
transcripts.” NERC has repeatedly affirmed that a Registered Entity may provide an
attestation that it has complied with a Standard. See NERC Compliance Process
Bulletin#2011-001 (“Data Retention Requirements”) (May 20, 2011), at p 3 (in the context of
explaining that the CMEP requires a registered entity to demonstrate that it was compliant
through the entire audit period, NERC stated that some examples of evidence may include
“An attestation of any employee who has participated in the activity on a regular basis
throughout the audit period, supported by other corroborating evidence (such as schedules,
emails and other applicable documentation). Recipients of oral Operating Instructions during
an Emergency have ample means of maintaining records, providing corroborating material,
etc… demonstrating that they adhered to the emergency Operating Instruction. To establish
an expectation that other Registered Entities may be maintaining audit evidence for the
Registered Entity to which the Requirement applies is inconsistent with NERC’s enforcement
rules and establishes a flawed practice and expectation with regard to recordkeeping
requirements and “audit trails.”
Individual
Scott Berry
Indiana Municipal Power Agency
Yes
Requirement R3 is not clear in defining if it covers all Operating Instructions received by a
Distribution Provider and Generator Operator. Distribution Providers and Generator
Operators can receive Operating Instructions from outside parties (Balancing Authority,
Reliability Coordinator, and Transmission Operator) and from internal parties (its own
Market Operations). The current word in Requirement 3 requires Distribution Providers and
Generator Operators to repeat back both outside and internal parties Operating Instructions.
IMPA does not believe this was the intent of the SDT since there are no requirements that
cover Distribution Providers or Generator Operators issuing Operating Instructions (the
Generator Operator’s Market Operations issuing an Operating Instruction to its generating
power plant; Generator Operators cannot issue Operating Instructions to any Registered
Entities such as the Balancing Authority or Reliability Coordinator). IMPA also believes that
operating personnel need to know at the time an instruction is given if it is an Operating
Instruction or a Directive. This clarification needs to come from the entity giving the
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instruction and reviewing the call afterwards to make that determination is very
problematic.
Individual
Gregory Campoli
New York Independent System Operator
Yes
The NYISO would like to request confirmation that Operating Instructions are limited to
verbal or written communications and that electronic dispatch signals are not in scope for
this standard. The NYISO would also note that we support comments submitted by both the
IRC/SRC and NPCC/RSC.
Individual
Bill Temple
Northeast Utilities
Yes
Yes
Yes
Yes
Comment 1 Systematic Approach to Training is already covered in PER-005-1 and including a
requirement for training would seem to be redundant. Comment 2 The applicability of
Distribution Provider (DP) functional responsibility presents potential for confusion. New
England LCC’s (Transmission Operators) operate at the direction of ISO-NE the Regional
Transmission Operator (RTO) and enforcing the communication protocols to distribution
companies/distribution providers may present challenges, identifying, documenting and
implementing COM-002-4 to the DP. Comment 3 The language used in Requirement 1.6 is
vague and needs to be clarified for Registered Entities to know how to comply with it. How
would one “specify nomenclature” system-wide?
Individual
Jen Fiegel
Oncor Electric Delivery Company LLC
No
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The Operating Instruction during an Emergency is unclear, vague, and subject to
interpretation. By using the NERC defined term of Emergency, certain tasks that are a nonemergency action would now be considered an Emergency. Oncor supports GTC’s
recommendation of the removal of the terms “or limit” within this definition. One could
argue that every single Operating Instruction is utilized to limit failures of transmission
facilities. Emergency should be more appropriately defined without this ambiguity. We
submit, for the SDT’s consideration, a revised definition of Emergency in an attempt to
remove this ambiguity. Emergency – Any abnormal system condition that requires automatic
or immediate manual action to prevent the failure of transmission facilities or generation
supply that would adversely affect the reliability of the Bulk Electric System. Oncor does not
believe that COM-002-4 accurately reflects the proper applicability for entities that have an
impact on the operations of the Bulk Electric System in normal and emergency conditions.
Oncor understands that the inclusion of Distribution Providers to this standard stems from
various FERC directives, but because of the relationship of Distribution Providers with
Transmission Operators as identified in NERC's functional model in being only a receiver of
instructions to implement voltage reduction or to shed load to prevent the failure of the BES,
or related to restoration activities as coordinated with the Transmission Operator; the TOP is
ultimately responsible for the proper execution of the instructions, continues to recommend
that Distribution Providers be removed from the applicability of COM-002-4. Knowing that it
will be difficult to remove the Distribution Provider from the applicability of COM-002-4 per
FERC's directives, Oncor supports the alternatives recommended by GTC as an opportunity
to address this. In addition, the COM-002-4 does not align with the evaluation and findings of
the NERC Reliability Issues Steering Committee (RISC) and Operating Committee (OC) which
supports the importance of clear communications but found no evidence that nonemergency communications represent a reliability gap.
No
COM-002-4 goes beyond the August 2003 Blackout Report Recommendation number 26,
FERC Order 693 for neither identify requirements for normal operations. EOP-001-2, R3.1
and COM-002-2, R2 already address the requirements of the Blackout Report and FERC
Order 693. The intent of the 2003 Blackout recommendation was to provide tighter
communication during emergency situations. Due to the ambiguity that exists between
Operating Instruction and Operating Instruction during an Emergency, we believe that this
recommendation was not addressed. In addition, the NERC BOT directed the NERC Operating
Committee (OC) to evaluate the COM standards (previously COM-003) and responses from
the Reliability Issues Steering Committee (RISC), the Independent Experts Review and NERC
Management. Their report issued September 23, 2013 to the NERC BOT Chairman identifies
the importance of clear communications but found no evidence including the NERC event
analysis process nor recent events which supports that non-emergency communications
represents a reliability gap. The OC created a guideline for verbal communications which
provides industry best practices and recommended utilizing the guideline to promote
continuous improvement versus implementing a mandatory standard.
Yes
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Yes
Oncor recommends Requirement 4 and Measurement 4 be removed. The “assess adherence
and assess effectiveness” language mirrors the same concepts as the “Identify, Assess and
Correct (IAC)” language that was included in the CIP V5 standards which FERC directed the
removal of. The removal or modification of this language was included in the Final Rule of
NERC CIP V5 (Order No. 791). FERC stated that IAC language was “overly-vague, lacking
definition and guidance is needed” and that these control concepts would be best addressed
in the NERC compliance processes, such as through the NERC Reliability Assurance Initiative
(RAI), rather than standards requirements. Reliability Standards must be revised to focus on
strategic and critical reliability objectives incorporating requirements for meeting and
sustaining reliability of the BES. The current state of Standards must transition from a
prescriptive zero tolerance approach to results-based requirements which assure the
reliability and security of the critical infrastructure. A reliability results-based approach
should not be an additive to the Reliability Standards; hence, controls requirements should
not be incorporated within the Standards, rather controls should be considered at the
Program level. Reliability Standards should define the results (“what”) Entities are mandated
to meet and maintain and the “how” should be handled by each Entity for there is not a “one
size fits all”. Incorporating detective controls as requirements and prescriptive
measurements can lead to unintended consequences and again, an additive versus a process
that helps provide a registered entity with reasonable assurance they comply with the
Standard(s) or the operating function(s) and processes that the Standard(s) require.
Rewording of R1.6 as follows: “Specify the nomenclature to be used for Transmission
interface Elements and Transmission interface Facilities when issuing an oral or written
Operating Instruction to Neighboring Entities.” While the Technical Justification document
suggests that R1.6 applies to communication with neighboring entities, it is unclear that this
requirement, as worded in the current draft of COM-002-4, is specifically discussing
communication with neighboring entities. M2 should include “initial training” and be
reworded as follows in order to maintain consistency with the requirement: “Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall provide initial training
records related to its documented communications protocols developed for Requirement R1
such as attendance logs, agendas, learning objectives, or course materials in fulfillment of
Requirement R2.”
Individual
Maggy Powell
Exelon Corp and its affiliated business units
No
Revision 8 addresses the Board Resolution, but it goes beyond the resolution by including
GOP’s and DP’s as applicable entities thereby creating redundant and unnecessary
compliance obligations for many of those entities. See comments below in response #4.
Furthermore, while the new approach in this draft is an improvement, it does not achieve
the desired goal to move away from a zero tolerance focus on the use of three part
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
communication within this standard. If time is allowed for further work on this standard, we
offer potential adjustments below in response #4. A couple points of potential confusion: Question 1 and the link to the Board Resolution on the Project page cites a November 19,
2013 Resolution; however, the link takes readers to a November 7, 2013 Resolution. We
assume the November 7, 2013 Resolution is the correct reference. - The first bullet of the
November 7, 2013 Board Resolution refers to the Operating Committee Guidelines for good
communication practice. This OC document does not appear to be linked to the Project page.
It is unlikely that many stakeholders would have found and/or reviewed the document
relative to the proposed COM-002-4 draft.
No
2003 Blackout Report Recommendation No. 26 reads: “Tighten communications protocols,
especially for communications during alerts and emergencies. Upgrade communication
system hardware where appropriate (footnote omitted). NERC should work with reliability
coordinators and control area operators to improve the effectiveness of internal and
external communications during alerts, emergencies, or other critical situations, and ensure
that all key parties, including state and local officials, receive timely and accurate
information. NERC should task the regional councils to work together to develop
communications protocols by December 31, 2004, and to assess and report on the adequacy
of emergency communications systems within their regions against the protocols by that
date.” While Exelon believes that COM-002-4 goes beyond the Recommendation and
includes the requirement to implement communication protocols for operating BES
elements in non-emergency and other non-critical situations, Exelon also recognizes that the
NERC Board believes that the words “especially for” in the recommendation are the reason
to include a standard for normal communications. We also understand that in paragraph 540
of Order No. 693, FERC directed the ERO to expand the applicability of the communication
standard to distribution providers (DP’s) but that directive tied back to communications
protocols “especially for communications during alerts and emergencies.” Although
Recommendation 26 addresses “key parties” and FERC directive addresses DP’s in the
context of Blackout Recommendation No. 26, we don’t believe that either was intended to
include DP’s and GOP’s for non-emergency /Operating Instructions communications.
Yes
• A “qualified” application of COM-002-4 for a DP that performs voltage reduction or load
shedding as directed by an RC, BA or TOP could clarify the standard and place the emphasis
on the functional entities that matter most. • Remove R6 and M6. The BA, RC or TOP, as
issuers, record Operating Instructions (OI). R1.2 requires an entity issuing an OI to confirm
the receiver’s response, reissue if necessary and take alternate action if the receiver does not
confirm or understand the OI. Similarly, per R5, issuers of an OI are required to confirm the
receiver’s response, reissue if necessary and take alternate action if the receiver does not
confirm or understand the OI. There is little reliability benefit in requiring the DP and GOP
receiver documenting their role in this exchange. The training requirement for receivers of
OI’s in R3 is sufficient. • If R6 and M6 are not removed. R6. To clarify, suggest that the word
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
“Operating Instruction” be inserted after “excluding written” so it is clear it is applicable to
both conditions. M6. Need a comma after “voice recordings” so as to separate it from dated
operator logs. "Voice recordings" is repeated twice in M6. M7. "Voice recordings" is repeated
twice in M7. • R6 / M6. Exelon is concerned that demonstrating compliance with R6 may
prove difficult for some entities. A generator operator may not have voice recording
available at the entity’s facility and it may not be possible to procure voice recording or
attestations from the issuer of an Operating Instruction. The measurement says dated
operator logs are acceptable evidence. The RSAW further discusses auditor discretion and
risk assessment respecting this requirement and measure. If audited per the measurement
and RSAW guidance, log entries would be acceptable evidence but we are concerned that an
auditor may find otherwise. • Should this proposal fail to pass ballot, we encourage the
drafting team to build on the positive work done in this version and address the compliance
concerns that remain. All stakeholders would be best served if this standard could incent
improvement in communication through effective self-assessment and applied lessons
learned. This iteration presents an opportunity to truly step away from placing the
compliance burden that judges operators for their use of three-part communication and to
focus on programmatic measures to promote effective communication. Specifically,
replacing R5, R6 and R7 with meaningful assessment criteria to include in entity review
programs could increase the qualitative components of the program, focus on efforts to
improve effective communication and remove the zero tolerance compliance approach that
currently exists. • While it’s been difficult to keep “starting over” with new standard
language approaches, we believe that this version sets solid groundwork to address the
hurdles and conflicts of previous approaches. Should more time be allowed to continue
development of this most recent proposal, we would welcome the chance to discuss our
ideas further.
Individual
Alice Ireland
Xcel Energy
Yes
Xcel Energy is voting negative because the standard no longer contains clarity for all parties
on when they have entered an emergency state and therefore 3-part communication would
be required. Since the requirements to conduct 3-part communication on emergency
operating instructions will remain zero tolerance, it is important that the line of when the
entity entered an emergency state be clear to the registered entities involved as well as ERO
compliance and enforcement personnel. We think incorporating some of the mechanics from
COM-002-3 could easily remedy our concerns. Alternatively, please consider requiring an
Operating Instruction that is issued during an Emergency situation be identified as ‘This is an
Emergency.'.
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Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC
Group
Bonneville Power Administration
Jamison Dye
Yes
Yes
Yes
No
Individual
Anthony Jablonski
ReliabilityFirst
No
ReliabilityFirst submits the following comments related to the VSL for the SDTs
consideration: 1. Requirement R4 VSL - For the Lower VSL, ReliabilityFirst recommends
gradating the number of months an entity is late in assessing adherence and effectiveness of
the documented communications protocols. For example, there is a big difference if an
entity is late by one month or 12 months. As drafted, an entity that is late by 12 months
would still fall under the Lower VSL. ReliabilityFirst recommends gradating the VSLs in three
month intervals. For example, the last “AND” text for the Lower VSL would read: “The
responsible entity exceeded twelve (12) but less than or equal to fifteen (15) calendar
months between assessments.” The Moderate VSL would read; “The responsible entity
exceeded fifteen (15) but less than or equal to eighteen (18) calendar months between
assessments.” The High and Severe VSLs would follow the same rationale. 2. Requirement R5
VSL - Requirement R5 does not speak to instability, uncontrolled, separation, or cascading
failures occurring as a result of correctly issuing an oral two-party, person-to-person
Operating Instruction. To be consistent with the requirement, ReliabilityFirst recommends
deleting the text after the AND qualifier and deleting the Moderate VSL. Hence, there will
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only be one Severe VSL for this requirement. 3. Requirement R6 VSL - Similar comment as
the Requirement R5 VSL 4. Requirement R7 VSL - Similar comment as the Requirement R5
VSL
Yes
ReliabilityFirst submits the following comments for consideration: 1. Requirements R1, R2,
R3 and R4 - The term “operating personnel” is used throughout the draft standard. This term
is undefined and it is unclear to which individuals the communications protocol applies.
ReliabilityFirst recommends defining this term to eliminate any confusion and remove any
questions around who encompasses “operating personnel”. ReliabilityFirst suggests
replacing the term “operating personnel” with the draft PER-005-2 definition of “System
Operator” (e.g., “An individual at a Control Center of a Balancing Authority, Transmission
Operator, or Reliability Coordinator, who operates or directs the operation of the Bulk
Electric System in Real‐time.”). ReliabilityFirst believes it is the intent of the standard to apply
to individuals who operate or direct the operation of the Bulk Electric System in Real‐time,
and not personnel that may be involved in supporting roles. 2. Requirement R4 a. The intent
of Requirement R4 a. R4.1 appears to limit possible violations for deviations to the context of
emergency operations, while only requiring that Responsible Entities to assess and correct
deviations “as appropriate” in the non-Emergency setting. ReliabilityFirst is concerned that
the qualifier “as appropriate” is vague and creates concerns similar to those expressed by
the Commission in Order 791. In Order 791, the Commission supported the RAI’s goal to
develop a framework for the ERO Enterprise’s use of discretion in the compliance monitoring
and enforcement space, but rejected the codification of “identify, assess, and correct”
language within the CIP Version 5 Reliability Standards because it is vague. ReliabilityFirst is
also concerned that the qualifier “as appropriate” codifies discretion within COM-002-4.
ReliabilityFirst believes that neither discretion nor controls should be codified in Reliability
Standards. Rather, the ERO Enterprise should utilize discretion in the compliance monitoring
and enforcement space when determining the relevant scope of audits and whether to
decline to pursue a noncompliance as a violation. With the RAI, the ERO Enterprise is
developing a singular and uniform framework to inform the ERO Enterprise’s use of
discretion in the compliance monitoring and enforcement space. Therefore, ReliabilityFirst
recommends removing the qualifier “as appropriate” from R4.1 and allowing the ongoing RAI
effort to create a meaningful and unambiguous framework that the ERO Enterprise will
utilize to inform its use of discretion in the compliance monitoring and enforcement of all
Reliability Standards. ReliabilityFirst cautions that codifying discretion in some Reliability
Standards may create confusion once the ERO Enterprise begins to implement RAI discretion
in its compliance monitoring and enforcement work. For example, there may be confusion of
whether discretion codified in certain Requirements of Reliability Standards precludes the
ERO Enterprise’s use of RAI discretion for those Requirements where discretion is not
codified. b. Flowing from 2.a. above, ReliabilityFirst recommends that Measure 4 be modified
to remove discretion, and should read as follows: M4. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator shall provide evidence of its assessments, including
spreadsheets, logs or other evidence of feedback, findings of effectiveness and any changes
made to its documented communications protocols developed for Requirement R1 in
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fulfillment of Requirement R4. The entity shall also provide evidence that it took appropriate
corrective actions as part of its assessment for all instances of operating personnel’s
nonadherence to the protocols developed in Requirement R1.
Individual
Richard Vine
California ISO
Yes
1. Requirement R4 is an administrative task, not a reliability-related task. The ISO does not
see the value added or where BES reliability is enhanced by R4. 2. The ISO uses an
Automated Dispatch System (ADS) to direct dispatch levels of generation in the ISO Balancing
Authority Area. Though different ADS instructions are sent to multiple parties (different
Generators) each individual instruction is an electronic communication that is “resource
specific” (i.e. – we send one resource an electronic communication to position its unit at a
specific level and another resource a different electronic communication to position its
resource at a different level, etc.) In this respect the ISO considers the ADS to be a “singleparty to single-party” communication rather than a “single-party to multiple-party burst”
communication. The ISO requests standards drafting team confirmation that it does not
interpret R1.4 (or R7 which contains similar language in the Emergency context) to apply to
resource-specific ADS dispatch instructions.
Individual
Sergio Banuelos
Tri-State Generation and Transmission Association Inc.
Yes
Yes
Yes
Yes
Tri-State G&T disagrees with removing the term reliability directive. The proposed definition
for Reliability Directive should be modified to provide technical justification, as requested in
the November 21, 2013 FERC NOPR, and require Reliability Coordinators to use Reliability
Directives to issue instructions to maintain reliable operations. As addressed in the NOPR,
Reliability Directives from an entity responsible for the reliable operation of the BES should
be mandatory at all times, not just during emergencies. Owners, Operators and others
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
responsible for reliability of the BES have used the term reliability directive effectively for
many years. Removing this term does not enhance the reliability of the BES and places a
burden on industry to adjust to accommodate a new method to accomplish what is done
today with reliability directives. Our proposal is to make Reliability Directives applicable to
RC, TOP and BA’s to ensure reliable operation the BES. The term Operating Instructions
should be applicable to Operators who issue commands to control elements essential to the
reliable operation of the BES. We do not believe the term, as currently defined, should apply
to Reliability Coordinators. According to the NERC Functional Model, Reliability Coordinators
are not real time operators and are not operating personnel. Reliability Coordinators oversee
the reliability of the BES and direct real time operations as needed to assure reliability of the
BES. TSGT requests clarification of the term operating personnel, which positions is this term
referring to? As previously stated, if operating personnel are the personnel that operate BES
elements, then operating personnel should not include Reliability Coordinators since that is
not the role they currently provide. TSGT requests clarification on the proposed multipleparty burst communication. This method of communication is not widely used and we are
concerned that the use of this type of communication may create additional reliability issues.
TSGT requests a clarification of time identification in R1.5.
Group
Luminant
Brenda Hampton
Yes
No
Recoomendation 26 of the August 2003 Blackout Report was to "Tighten communications
protocols, especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate." Technology is now available and
already in use in some places that allow receiptants of an All-Call/Burst Message type
Operating Instruction to press a button on the phone keypad to ackowledge understanding
of the Operating Instruction. This allows the issuer a quick and easy way to confirm the
understanding of all reciepents of the Operating Instruction. Allowing the issuer of an
Operating Instruction to seek confirmation from only one recipient in R7 ignores the
recommendation from the Black Out Report to use new technology.
Yes
Yes
1). R1.3 and R3 should also allow the receiver of an Operating Instruction to respond by
explaining that a requested action cannot be performed (e.g., due to safety, equipment,
regulatory, or statutory requirements as described in TOP-001 R3 and IRO-001 R8). The
requirement to either repeat or request that the instruction be reissued does not account for
the realistic situation that an entity may not be able to perform an Operating Instruction. 2).
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Specific to R.6, consideration should be given to revise the verbiage from, “during an
Emergency” to “identified by the sender as constituting an Emergency directive.” The
rational for the recommendation is offered to provide clarity to the Requirement, as it is
anticipated that there will be cases when it is not clear the Operating Instruction is
associated with an Emergency. Additionally, the definition of “Emergency” in the NERC
Glossary is broad and consequently it may be difficult, at times, to determine which inputs
are subject to COM-002-4 requirements, especially if the TO or TOP calls a plant operator
directly rather than going through the respective dispatchers. Note: On the 1/17/14 COM002-4 SDT webinar the question was asked, how a DP or GOP would know that an Operating
Instruction occurred during an Emergency. The drafting team stated that after every
Operating Instruction the DP should call its TOP to determine if the Operating Instruction
occurred during and Emergency. Luminant once again reiterates that it would be more
efficient and the industry would benefit as a whole, if the sender of the Operational
Instruction, states the instruction is associated with an Emergency.
Group
Santee Cooper
S. Tom Abrams
Agree
We agree with the comments submitted by SERC.
Individual
Ralph Meyer
The Empire District Electric Company
Yes
Yes
Yes
Yes
I feel that the requiment to an assessment to communication protocols is somewhat
excessive and should be left as a part of the audit process or following NERCs RAI directive be
left up to the internal compliance department of the company rather than having this as a
requirement in the standard.
Individual
daniel mason
HHWP
no comment
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
no comment
no comment
Yes
I appreciate the work done on this Standard by the SDT. The current version of the draft is
much improved. I propose one change before supporting this proposed standard. That
change is in Requirement 4 where I believe the standard would be improved by replacing the
"at least once every twelve (12) calendar months" language with "at least annually, with no
more than X months between reviews." Such a change to the language or Requirement 4
would allow each entity to determine the best cycle for its review of adherance to and
effectiveness of its communcications protocols per CAN-0010. If that language is used, I
believe that 15 months is an appropriate value for 'X'.
Additional comments received from Marcus Pelt, Southern Company
Definition of Emergency
Southern does not agree with replacing Reliability Directive with Emergency as it is
currently used in Draft 8. In the NERC Glossary, the term Emergency is defined as
follows:
Any abnormal system condition that requires automatic or immediate manual action to
prevent or limit the failure of transmission facilities or generation supply that could
adversely affect the reliability of the Bulk Electric System.
This definition is very broad and, if read literally, every breaker operation on the
system would be considered an Emergency. This causes a great deal of concern. If this
is the case and absent any compliance guidance to state otherwise, it would require
Operating Entities to add additional staff to listen to all voice recordings to review
adherence to the strict 100% compliance requirement for communications
issued/received during Emergencies. These requirements/measures create an undue
burden for Operating Entities and would likely not garner support from the industry.
We suggest that the SDT modify this approach to scope down actions that could be
considered “Emergencies” by allowing entities to define and make it very clear that the
expectation is not for Operating Entities to have to review all voice recordings (could be
millions in a single year) to ensure compliance, but only a representative sample of
voice recordings for both non-emergency and emergency communications.
From a DP and GOP standpoint, the RSAW and technical justification wording states that an
attestation that no emergency had been called requiring a three part response would suffice
for evidence. The rationale and technical justification document has some very good
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explanations of the INTENT of the drafting team and how they want the industry to view the
standard requirements. If the standard and the subsequent audits adhered ONLY to what was
in the justification document, then there should be little or no concerns. Unfortunately, the
justification document carries no statutory weight and the standard as written does.
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Consideration of Comments
Project 2007-02 Operating Personnel Communications Protocols
The Project 2007-02 Drafting Team thanks all commenters who submitted comments on the proposed
draft COM-002-4 (Operating Personnel Communications Protocols) standard. These standards were
posted for a 30-day public comment period from January 2, 2014 through January 31, 2014.
Stakeholders were asked to provide feedback on the standards and associated documents through a
special electronic comment form. There were 70 sets of comments, including comments from
approximately 185 different people from approximately 125 companies representing all 10 Industry
Segments as shown in the table on the following pages.
As a result of select industry stakeholder comments, the Operating Personnel Communications
Protocols Standards Drafting Team (OPCP SDT) made minor, non-substantive changes to COM-002-4
after the most recent comment and ballot period in order to clarify the OPCP SDT’s intent and better
align the language in the measures with the requirements. Requirement R4.1 was altered from “as
appropriate” to “as deemed appropriate by the entity” in order to highlight the OPCP SDT’s intent. In
Measure M2 the words “its initial” were added to the sentence “shall provide its initial training records
. . .” in order to align the language in Measure M2 with the language in Requirement R2. Measure M4
was altered to include the phrase “as part of its assessment” and “of any corrective actions taken”
within the sentence “The entity shall provide, as part of its assessment, evidence of any corrective
actions taken.” Lastly, Measure M6 and M7 were changed to add the parenthetical “(if an entity has
such recordings)” after the words “time-stamped recordings,” and the second entry for “time-stamped
recordings” was removed due to redundancy.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or
at [email protected]. In addition, there is a NERC Reliability Standards Appeals Process. 1
1
The appeals process is in the Standard Processes Manual: http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Index to Questions, Comments, and Responses
1.
2.
3.
4.
Do you agree that that the COM-002-4 standard addresses the NERC Board
of Trustees November 19, 2013 Resolution? If not, please explain in the
comment area. ..................................................................................................15
Do you agree that COM-002-4 addresses the August 2003 Blackout Report
Recommendation number 26, and FERC Order 693? If not, please explain in
the comment area..............................................................................................30
Do you agree with the VRFs and VSLs for the Requirements? If not, please
explain. ............................................................................................................44
Do you have any additional comments? Please provide them here. ..........................56
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
2
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
1.
Group
Stuart Goza
SERC OC Review Group
X
2
3
X
4
5
X
Additional Member Additional Organization Region Segment Selection
1. William Berry
OMU
SERC
3
2. Rene Free
Santee Cooper
SERC
1, 3, 5, 6
3. Tim Hattaway
PowerSouth
SERC
1, 5
4. Louis Slade
Dominion
SERC
1, 3, 6
5. Dan Roethemeyer
Dynegy
SERC
5
6. John Bussman
AECI
SERC
1, 3, 5, 6
7. Scott Brame
NCEMC
SERC
1, 3, 4, 5
2.
Group
Allen Schriver
North American Generator Forum Standards Review Team (NAGF-SRT)
X
6
X
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional Member
Additional Organization
e.ON Climate & Renewables ERCOT 5
2. William Shultz
Southern Company
Group
SERC
SERC
1, 3
2. KAMO Electric Cooperative
SERC
1, 3
3. M & A Electric Power Cooperative
SERC
1, 3
4. Northeast Missouri Electric Power Cooperative
SERC
1, 3
5. N.W. Electric Power Cooperative, Inc.
SERC
1, 3
6. Sho-Me Power Electric Cooperative
SERC
1, 3
4.
Group
Joshua Andersen
No Additional Responses
Salt River Project
5.
Northeast Power Coordinating Council
Guy Zito
Additional Member
5
6
7
8
9
10
X
X
X
X
X
X
X
X
Additional Organization Region Segment Selection
1. Central Electric Power Cooperative
Group
4
5
Associated Electric Cooperative, Inc. JRO00088
David Dockery
Additional Member
3
Region Segment Selection
1. Dana Showalter
3.
2
Additional Organization
X
Region Segment Selection
1.
Alan Adamson
New York State Reliability Council, LLC
NPCC 10
2.
David Burke
Orange and Rockland Utilities Inc.
NPCC 3
3.
Greg Campoli
New York Independent System Operator
NPCC 2
4.
Sylvain Clermont
Hydro-Quebec TransEnergie
NPCC 1
5.
Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6.
Gerry Dunbar
Northeast Power Coordinating Council
NPCC 10
7.
Mike Garton
Dominion Resources Services, Inc.
NPCC 5
8.
Kathleen Goodman
ISO - New England
NPCC 2
9.
Michael Jones
National Grid
NPCC 1
10. Mark Kenny
Northeast Utilities
NPCC 1
11. Christina Koncz
PSEG Power LLC
NPCC 5
12. Helen Lainis
Independent Electricity System Operator
NPCC 2
13. Michael Lombardi
Northeast Power Coordinating Council
NPCC 10
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
4
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
14. Alan MacNaughton
New Brunswick Power
NPCC 9
15. Bruce Metruck
New York Power Authority
NPCC 6
16. Silvia Parada Mitchell NextEra Energy, LLC
NPCC 5
17. Lee Pedowicz
Northeast Power Coordinating Council
NPCC 10
18. Robert Pellegrini
The United Illuminating Company
NPCC 1
19. Si Truc Phan
Hydro-Quebec TransEnergie
NPCC 1
20. David Ramkalawan
Ontario Power Generation, Inc.
NPCC 5
21. Brian Robinson
Utility Services
NPCC 8
22. Ayesha Sabouba
Hydro One Networks Inc.
NPCC 1
23. Brian Shanahan
National Grid
NPCC 1
24. Wayne Sipperly
New York Power Authority
NPCC 5
25. Ben Wu
Orange and Rockland Utilities Inc.
NPCC 1
26. Peter Yost
Consolidated Edison Co. of New York, Inc. NPCC 3
6.
Russel Mountjoy
Group
Additional Member
Additional Organization
NERC Standards Review Forum
X
2
X
3
X
4
X
5
X
6
7
X
Region Segment Selection
1.
Alice Ireland
Xcel Energy
MRO
1, 3, 5, 6
2.
Chuck Wicklund
Otter Tail Power
MRO
1, 3, 5
3.
Dan Inman
Minnkota Power Coop
MRO
1, 3, 5, 6
4.
Dave Rudolph
Basin Electric
MRO
1, 3, 5, 6
5.
Kayleigh Wilkerson Lincoln Electric
MRO
1, 3, 5, 6
6.
Jodi Jensen
WAPA
MRO
6
7.
Joseph Depoorter
Madison Gas & Electric
MRO
3, 4, 5, 6
8.
Ken Goldsmith
Alliant Energy
MRO
4
9.
Mahmood Safi
Omaha Public Power District
MRO
1, 3, 5, 6
10. Marie Knox
MISO
MRO
2
11. Mike Brytowski
Great River Energy
MRO
1, 3, 5, 6
12. Randi Nyholm
Minnesota Power
MRO
1, 5
13. Scott Bos
Muscatine Power & Water
MRO
1, 3, 5, 6
14. Scott Nickels
Rochester Public Utilities
MRO
4
15. Terry Harbour
MidAmerican Energy
MRO
1, 3, 5, 6
16. Tom Breene
Wisconsin Public Service
MRO
3, 4, 5, 6
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
5
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
17. Tony Eddleman
Nebraska Public Power District MRO
2
3
4
5
6
1, 3, 5
7.
Colorado Springs Utilities
X
X
X
X
8.
Southern Company; Southern Company
Services,Inc; Alabama Power Company;
Georgia power Company; Gulf Power
Company; Mississippi Power Company;
Southern Company Generation and Energy
Marketing
X
X
X
X
Florida Municipal Power Agency
X
X
X
X
X
X
X
X
X
X
X
X
Group
Kaleb Brimhall
No Additional Responses
Group
Marcus Pelt
No Additional Responses
9.
Group
Frank Gaffney
7
X
Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle
City of New Smyrna Beach FRCC
4
2. Jim Howard
Lakeland Electric
FRCC
3
3. Greg Woessner
Kissimmee Utility Authority FRCC
3
4. Lynne Mila
City of Clewiston
FRCC
3
5. Cairo Vanegas
Fort Pierce Utility Authority FRCC
4
6. Randy Hahn
Ocala Utility Services
FRCC
3
7. Stanley Rzad
Keys Energy Services
FRCC
1
8. Don Cuevas
Beaches Energy Services FRCC
1
9. Mark Schultz
Green Cove Springs
3
FRCC
10.
Group
Janet Smith
No Additional Responses
11.
Group
Arizona Public Service Co.
Brent Ingebrigtson
Additional
Member
PPL NERC Registered Affiliates
Additional Organization
Region
1.
Charlie Freibert
Louisville Gas and Electric Company and Kentucky Utilities
Company
SERC
2.
Brenda Truhe
PPL Electric Utilities Corporation
RFC
3.
Annette Bannon
PPL Generation, LLC
RFC
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
Segment
Selection
3
5
6
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
4.
5.
6.
Elizabeth Davis
PPL Susquehanna, LLC
RFC
PPL Montana, LLC
WECC 5
PPL EnergyPlus, LLC
MRO
8.
RFC
6
9.
SERC
6
10.
SPP
6
11.
WECC 6
Michael Lowman
Duke Energy
4
5
6
7
6
NPCC 6
Group
3
5
7.
12.
2
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Doug Hils
RFC
1
2. Lee Schuster
FRCC
3
3. Dale Goodwine
SERC
5
4. Greg Cecil
RFC
6
13.
Group
Kathleen Black
Additional Member
DTE Electric
Additional Organization
X
NERC Compliance
RFC
3
2. Daniel Herring
NERCTraining & Standards Development RFC
4
3. Mark Stefaniak
Regulated Marketing
NPCC
5
4. Jeffrey DePriest
NERC Compliance
RFC
14.
Group
RFC
Robert Rhodes
Additional Member
X
Region Segment Selection
1. Kent Kujala
5. Barbara Holland
X
Additional Organization
SPP Standards Review Group
Region Segment Selection
1.
John Allen
City Utilities of Springfield
SPP
1, 4
2.
Ron Gunderson
Nebraska Public Power District
MRO
1, 3, 5
3.
John Hare
Oklahoma Gas & Electric
SPP
1, 3, 5
4.
Don Hargrove
Oklahoma Gas & Electric
SPP
1, 3, 5
5.
Stephanie Johnson Westar Energy
SPP
1, 3, 5, 6
6.
Bo Jones
SPP
1, 3, 5, 6
Westar Energy
X
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
7
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
7.
Allen Klassen
Westar Energy
SPP
1, 3, 5, 6
8.
Tiffany Lake
Westar Energy
SPP
1, 3, 5, 6
9.
Greg McAuley
Oklahoma Gas & Electric
SPP
1, 3, 5
10. Shannon Mickens
Southwest Power Pool
SPP
2
11. James Nail
City of Independence, MO
SPP
3
12. Kevin Nincehelser
Westar Energy
SPP
1, 3, 5, 6
13. Terri Pyle
Oklahoma Gas & Electric
SPP
1, 3, 5
14. Randy Root
Grand River Dam Authority
SPP
1
15. Ashley Stringer
Oklahoma Municipal Power Authority SPP
4
16. Bryan Taggart
Westar Energy
SPP
1, 3, 5, 6
17. Sing Tay
Oklahoma Gas & Electric
SPP
1, 3, 5
18. Scott Williams
City Utilities of Springfield
SPP
1, 4
15.
Group
Erika Doot
No Additional Responses
Bureau of Reclamation
X
16.
Dominion
X
Group
Louis Slade
Additional
Member
Connie Lowe
NERC Compliance Policy RFC
5, 6
2.
Randi Heise
NERC Compliance Policy SERC
5, 6
3.
Mike Garton
NERC Compliance Policy NPCC 5, 6
4.
Chip Humphrey
Power Generation
SERC
5
5.
Michael Crowley
Electric Transmission
SERC
1, 3
6.
Jeff Bailey
Nuclear
SERC
5
7.
Michael Crowley
SERC
1, 3, 5, 6
8.
Randi Heise
MRO
6
9.
Mike Garton
NPCC 5, 6
10. Connie Lowe
Group
RFC
Ben Engelby
Additional Member
1. Shari Heino
3
4
5
6
7
X
X
X
X
Additional Organization Region Segment Selection
1.
17.
2
5, 6
ACES Standards Collaborators
Additional Organization
Brazos Electric Power Cooperative, Inc.
X
Region Segment Selection
ERCOT 1, 5
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
8
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
2. Kevin Lyons
Central Iowa Power Cooperative
3. Scott Brame
North Carolina Electric Membership Corporation SERC
1, 3, 4, 5
4. Mark Ringhausen
Old Dominion Electric Cooperative
SERC
3, 4
5. Ginger Mercier
Prairie Power, Inc.
SERC
3
6. Ellen Watkins
Sunflower Electric Power Corporation
SPP
1
7. Bob Solomon
Hoosier Energy Rural Electric Cooperative, Inc. RFC
1
8. Bill Hutchison
Southern Illinois Power Cooperative
1
18.
Group
Brandy Spraker
2
3
4
5
6
7
MRO
SERC
Tennessee Valley Authority
X
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Marjorie Parsons
SERC
6
2. Daivd Thompson
SERC
5
3. DeWayne Scott
SERC
1
4. Ian Grant
SERC
3
5. Stuart Goza
SERC
1
6. Paul Palmer
SERC
5
19.
Group
ISO/RTO Council Standards Review
Committee
Greg Campoli
X
Additional Member Additional Organization Region Segment Selection
1. Ali Merimadi
CAISO
WECC 2
2. Cheryl Mosley
ERCOT
ERCOT 2
3. Ben Li
IESO
NPCC
2
4. Kathleen Goodman ISO New England
NPCC
2
5. Terry Bilke
MISO
RFC
2
6. Charles Yeung
SPP
SPP
2
20.
Group
Jamison Dye
Bonneville Power Administration
X
Additional Member Additional Organization Region Segment Selection
1. Richard Ellison
Transmission Dispatch
WECC 1
2. Tim Loepker
Transmission Dispatch
WECC 1
21.
Group
Brenda Hampton
Luminant
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
X
9
8
9
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Additional Member
1. Rick Terrill
22.
Additional Organization
2
3
4
5
6
7
8
9
Region Segment Selection
Luminant Generation Company LLC ERCOT 5
Group
S. Tom Abrams
Santee Cooper
X
X
X
X
X
X
Additional Member Additional Organization Region Segment Selection
1. Rene Free
Santee Cooper
SERC
1, 3, 5, 6
2. Tom Abrams
Santee Cooper
SERC
1, 3, 5, 6
23.
Individual
Molly Devine
Idaho Power Company
24.
Individual
Colin Jack
Dixie Power
25.
Individual
Paul Titus
Individual
Kenn Backholm
Northern Wasco County PUD
Public Utility District No.1 of Snohomish
County
27.
Individual
Jonathan Appelbaum
The United Illuminating Company
28.
Individual
Daniel Duff
Liberty Electric Power LLC
29.
Individual
Matthew P Beilfuss
Wisconsin Electric Power Company
30.
Individual
Thomas Borowiak
Citizens Electric Corporation
31.
Individual
Patricia Metro
NRECA
32.
Individual
Howard Hughes
SLEMCO
33.
Individual
Michelle R D'Antuono
Ingleside Cogeneration LP
34.
Individual
Jack Stamper
Clark Public Utilities
35.
Individual
Josh Dellinger
Glacier Electric Cooperative
36.
Individual
russ schneider
flathead co-op
37.
Individual
Oliver Burke
Individual
Donald E Nelson
Entergy Transmission
Commonwealth of Massachusetts
Department of Public Utilities
Individual
40. Individual
Thomas M. Haire
Venona Greaff
Rutherford EMC
Occidental Chemical Corporation
26.
38.
39.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
Individual
William H. Chambliss
Virginia State Corporation Commission,
Member OC
Individual
Shirley Mayadewi
Manitoba Hydro
X
Individual
44. Individual
Jason Snodgrass
Andrew Z. Pusztai
Georgia Transmission Corporation
American Transmission Company, LLC
X
45.
Individual
Michael Falvo
Independent Electricity System Operator
46.
Individual
David Thorne
Pepco Holdings Inc.
47.
Individual
Thomas Foltz
American Electric Power
48.
Individual
Brian Evans-Mongeon
Utility Services, Inc
49.
Individual
Christopher Wood
Platte River Power Authority
50.
Individual
Don Schmit
Nebraska Public Power District
51.
Individual
John Brockhan
CenterPoint Energy Houston Electric LLC
52.
Individual
David Jendras
Ameren
53.
Individual
Marie Knox
MISO
54.
Individual
Catherine Wesley
PJM Interconnection
55.
Individual
Brett Holland
Kansas City Power & Light
56.
Individual
Scott McGough
Georgia System Operations Corporation
57.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
58.
Individual
Michael Landry
DEMCO
59.
Individual
Scott Berry
Indiana Municipal Power Agency
60.
Individual
Gregory Campoli
New York Independent System Operator
61.
Individual
Bill Temple
Northeast Utilities
62.
Individual
Jen Fiegel
Oncor Electric Delivery Company LLC
63.
Individual
Maggy Powell
Exelon Corp and its affiliated business units
64.
Individual
Alice Ireland
Xcel Energy
65.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
41.
42.
43.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
2
3
4
X
5
6
X
X
X
X
7
8
9
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
11
10
Group/Individual
Commenter
Organization
Registered Ballot Body Segment
1
66.
Individual
Anthony Jablonski
ReliabilityFirst
67.
Individual
Richard Vine
Individual
69. Individual
Sergio Banuelos
Ralph Meyer
California ISO
Tri-State Generation and Transmission
Association Inc.
The Empire District Electric Company
70.
daniel mason
HHWP
68.
Individual
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
2
3
4
5
6
7
8
9
10
X
X
X
X
X
X
X
X
12
If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).
Organization
Agree
Supporting Comments of “Entity Name”
Associated Electric
Cooperative, Inc. - JRO00088
Agree
NRECA and SERC OC Review Group
Dominion
Agree
SERC OC Standards Review group
Tennessee Valley Authority
Agree
SERC Operating Committee Review Team
Santee Cooper
Agree
We agree with the comments submitted by SERC.
Dixie Power
Agree
NRECA
Northern Wasco County PUD
Agree
NRECA
Citizens Electric Corporation
Agree
National Rural Electric Cooperative
Association(NRECA)
SLEMCO
Agree
NRECA
Glacier Electric Cooperative
Agree
NRECA
flathead co-op
Agree
Flathead supports the comments submitted by
NRECA
Entergy Transmission
Agree
SERC OC Review Group
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
13
Organization
Agree
Supporting Comments of “Entity Name”
Commonwealth of
Massachusetts Department
of Public Utilities
Agree
Northeast Power Coordinating Council (NPCC)
Rutherford EMC
Agree
NRECA
Occidental Chemical
Corporation
Agree
Ingleside Cogeneration LP
Ameren
Agree
Ameren agrees with and supports the SERC OC
comments on COM-002-4.
Kansas City Power & Light
Agree
SPP - Robert Rhodes
DEMCO
Agree
NRECA
South Carolina Electric and
Gas
Agree
SERC OC
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
14
1.
Do you agree that that the COM-002-4 standard addresses the NERC Board of Trustees November 19, 2013 Resolution? If not,
please explain in the comment area.
Summary Consideration: The OPCP SDT would like to thank all parties who took the time to submit comments. The NERC Board of
Trustees Resolution directed the OPCP SDT to continue development of a combined COM-002- and COM-003 standard that, among
other things, requires the use of the three-part communication for both Emergency Communications and non-emergency
communications that change or preserve the state, status, output, or input of the Bulk Electric System; requires training and periodic
review of communications subject to the communications protocols; and requires entities to assess the effectiveness of their
communications protocols as well as their operators adherence to the protocols. Additionally, the Resolution directed that entities
must use three-part communication when issuing and/or receiving Operating Instructions during Emergency Communications without
exception. The following is provided as a summary response to the comments on Question 1. Any necessary additional responses are
provided to individual commenters below.
Several commenters, including SERC OC Review Group, Georgia Transmission Company, and NRECA, commented that Distribution
Providers should not be included as an applicable entity to COM-002-4 or that, if included, the applicability be limited to Distribution
Providers who “shed 300 MW or more of load in a single manually initiated operation or have switching obligations related to Any
Cranking Path and group of Elements meeting the initial switching requirements from a Blackstart Resource . . .”
The OPCP SDT chose to include Distribution Providers in the Applicability section because they can be and are on the receiving end of
some Operating Instructions. The OPCP SDT could not determine a technical basis to support a threshold to exclude certain Distribution
Providers. The OPCP SDT continues to believe that the language in COM-002-4, R6 that limits the application of R6 to only a Distribution
Provider “that receives an oral two-party, person-to-person Operating Instruction during an Emergency” properly excludes Distribution
Providers that do not receive Operating Instructions from the requirement. The inclusion of Distribution Providers is also responsive to
the FERC directive to include Distribution Providers as an applicable entity under the standard.
Other commenters noted that the requirements do not differentiate clearly between the actions operators must take during nonEmergency and Emergency situations. In COM-002-4, the same protocols are to be used for Operating Instructions in all operating
conditions, i.e., non-emergency, alert, and Emergency communications. The OPCP SDT believes that one set of communication
protocols should be used at all times by operators in order to improve consistency and minimize confusion. The standard uses the
phrase “Operating Instruction during an Emergency” in certain Requirements (R5, R6, and R7) to provide a demarcation for what is
subject to a zero-tolerance compliance/enforcement approach. Where “Operating Instruction during an Emergency” is not used, an
entity will be assessed based on the language of the other requirements, which focus on whether an entity met the initial training
requirement (either R2 or R3) and/or whether an entity performed the assessment and took corrective actions according to
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
15
Requirement R4. Separately listing out Requirements R5, R6, and R7 and using “Operating Instruction during an Emergency” in them
does not require a different set of protocols to be used during Emergencies or mandate the identification of a communication as an
“Operating Instruction during an Emergency.” The same protocols are required to be used in connection with the issuance of Operating
Instructions for all operating conditions.
Several commenters also stated they believe the issuer of an Operating Instruction during an Emergency should be required to indicate
to the recipient that the instruction being issued is for the purpose of preventing or alleviating an Emergency. The OPCP SDT has
considered these comments but asserts that such a requirement could distract operators, causing them to focus on determining
whether or not a situation meets the definition of an Emergency, rather than resolving the issue at hand. Because the protocols do not
differ based on the operating condition, the OPCP SDT determined that it was not necessary to require such indication in the protocols
mandated by the standard. The OPCP SDT notes that the standard does not preclude entities from adding its own protocols to do so.
Some parties expressed a concern that the definition of “Emergency” was unclear, vague, and subject to interpretation. Commenters
also expressed concern about the auditor’s ability to make a distinct determination as to what Operating Instructions were in response
to an Emergency and at what point the actual Emergency began, as Emergency communications triggers the zero-tolerance compliance
approach. The NERC Glossary of Terms defines Emergency as “Any abnormal system condition that requires automatic or immediate
manual action to prevent or limit the failure of transmission facilities or generation supply that could adversely affect the reliability of
the Bulk Electric System.” It is expected that these are abnormal and rare circumstances, and that there will be no confusion about the
state. The term is an established NERC Glossary term that has been successfully used in other standards. Additionally, redefining the
NERC Glossary term “Emergency” has implications in other reliability standards beyond COM-002-4.
It was also suggested by several individuals and entities that the inclusion of a training requirement was not necessary and/or would be
better suited for inclusion in PER-005. The OPCP SDT consulted with the PER-005 Standard Drafting Team and was advised that while
training on communications protocols would fall into an entity’s systematic approach to training, the requirements do not explicitly
mandate training on communications protocols. The OPCP SDT asserts it is essential for all operators to have a common level of
understanding and be trained in three-part communication. Because PER-005 would not meet the NERC Board of Trustees November 7,
2013 Resolution to mandate training, the OPCP SDT included a requirement to conduct initial training in order to ensure that a baseline
of training is complete before an individual is placed in a position to use the communications protocols. The OPCP SDT further asserts
requiring initial training is not overly burdensome to an entity and any subsequent training can be covered in PER-005 or through the
operator feedback loop as determined by the entity.
Other entities have commented that the requirements in COM-002-4 subject entities to double jeopardy as a result of the currently
effective TOP and IRO requirements. The OPCP SDT disagrees with this assertion, as COM-002-4 only deals with communications and
communication protocols, whereas the TOP and IRO family of standards govern the actions which an entity must perform.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
16
Some parties asked how an entity would specify system wide nomenclature in their protocols, or stated they believed this was not
necessary since Project 2007-03 chose to eliminate TOP-002-2a, Requirement R18 when it developed TOP-002-3. This requirement
stated “Neighboring Balancing Authorities, Transmission Operators, Generator Operators, Transmission Service Providers and Load
Serving Entities shall use uniform line identifiers when referring to transmission facilities of an interconnected network.” The standard
drafting team addressed this issue in the FAQ document posted on the project page. The following response was provided: “COM-0024, while reintroducing the concept of line identifiers, limits the scope to only Transmission interface Elements or Transmission interface
Facilities (e.g. tie lines and tie substations) for Operating Instructions. This supports both parties being familiar with each other’s
interface Elements and Facilities, minimizing hesitation and confusion when referring to equipment for the Operating Instruction.” The
nomenclature is not specified as “system wide.” Requirement R1 Part 1.6 only requires entities to specify what, if any, nomenclature
must be used for Transmission interface Elements or Transmission interface Facilities (e.g., tie lines and tie substations). The OPCP SDT
did not want to be overly prescriptive in instructing an entity on how it should identify its nomenclature.
Lastly, some commenters noted that they felt the “assess adherence and assess effectiveness” contained within Requirement R4, the
associated Measure, and VRFs/VSLs was similar to the “identify assess and correct” (IAC) language contained in certain CIP Version 5
requirements, which FERC directed NERC to remove or clarify. However, the OPCP SDT asserts that there is a difference in the language,
and that the ambiguity FERC identified in the IAC language is not an issue in the COM-002-4 standard. The OPCP SDT added clarifying
language in the requirements to specify the actions that an entity is expected to take.
Organization
SERC OC Review
Group
Yes or No
Question 1 Comment
No
The SERC OC Review Group appreciates the efforts that the OPCP SDT has made on this draft
standard and the flexibility demonstrated to address the constantly evolving feedback
received. We do not believe the proposed requirements and measures clearly delineate the
differences in the actions required to be taken by the issuer and recipient depending upon
whether or not the Operating Instruction is being given to alleviate or avoid an Emergency.
Applicability Section:4.1.2 Distribution Provider: We understand that it would be difficult to
remove the Distribution Provider from the applicability of COM-002-4 per FERC's directives.
Therefore, we are respectfully recommending an alternative that parallels the recently FERC
approved CIP-003-5 that we believe accurately captures those DPs that receive Operating
Instructions associated with the reliability of the BES. The following alternative to clarify
those Distribution Providers that have an impact on the BES is recommended:4.1.2
Distribution Provider that: 4.1.2.1 Has capability to shed 300 MW or more of load in a single
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
17
Organization
Yes or No
Question 1 Comment
manually initiated operation.4.1.2.2 Has switching obligations related to Any Cranking Path
and group of Elements meeting the initial switching requirements from a Blackstart Resource
up to and including the first interconnection point of the starting station service of the next
generation unit(s) to be started.
General Requirement Comment: The OPCP SDT is respectfully requested to review the
Requirements to ensure that it is clear that “during an Emergency” is only applicable to the
entities involved.
Requirement 1: The proposed standard still contains requirements that mandate the use of,
and training to include, 3 part communications during issuance of all Operating Instructions,
including those issued during non-Emergency situations. While we agree that the OPCP SDT
has stated in its Rationale and Technical Justification document that the proposed measures
don’t specifically require that auditors verify compliance of this for the requirements (and
associated measures), a strict read leads to a different conclusion. We are concerned that,
absent a requirement that the issuer make a definitive statement as to whether an Operating
Instruction is being issued to alleviate or avoid an Emergency, neither the recipient (during)
nor an auditor (after) would be able to make such determination. We respectfully
recommend modifying requirement 1 so that it applies to all Operating Instructions but
requires that those being issued to alleviate or avoid an Emergency be specifically identified
as such and that the issuer explicitly request recipient confirm their understanding through
use of 3 part communication. To accomplish this we propose a new R1.1. The current R1.1
through R1.6 would be renumbered R1.2 through R1.7Current R1 language: R1. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop
documented communications protocols for its operating personnel that issue and receive
Operating Instructions. The protocols shall, at a minimum: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning] 1.1.Require its operating personnel that issue and receive an
oral or written Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations. Proposed R1 language: R1. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall develop
documented communications protocols for its operating personnel that issue and receive
Operating Instructions. The protocols shall, at a minimum: [Violation Risk Factor: Low][Time
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
18
Organization
Yes or No
Question 1 Comment
Horizon: Long-term Planning]Proposed R1.1: ADD: Require that its operating personnel
identify, at the time of issuance, when the Operating Instruction is being issued to alleviate or
avoid an Emergency R1.2: Based on the OPCP SDT comments and zero tolerance for
Emergency communications we propose a new bullet be added to R1.2. Current R1.2
language: Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions: o Confirm the receiver’s response
if the repeated information is correct. o Reissue the Operating Instruction if the repeated
information is incorrect or if requested by the receiver. o Take an alternative action if a
response is not received or if the Operating Instruction was not understood by the receiver.
Proposed R1.2: Require its operating personnel that issue an oral two-party, person-toperson Operating Instruction to take one of the following actions: o Confirm the receiver’s
response if the repeated information is correct. o Reissue the Operating Instruction if the
repeated information is incorrect or if requested by the receiver. o Take an alternative action
if a response is not received or if the Operating Instruction was not understood by the
receiver. o ADD: Request recipient use 3 part communication when the Operating Instruction
is being issued to alleviate or avoid an EmergencyR1.3: We respectfully recommend a word
change (correct to understood) in 1.3, bullet 1. Current 1.3 sub-bullet 1 follows: Repeat, not
necessarily verbatim, the Operating Instruction and receive confirmation from the issuer that
the response was correct. Proposed 1.3, sub-bullet 1: Repeat, not necessarily verbatim, the
Operating Instruction and receive confirmation from the issuer that the response was
understood.
Requirement R2: This group feels that R2 should be eliminated as redundant with the
systematic approach to training requirements of PER-005 (Operations Personnel Training)
which are applicable to all BAs, RCs & TOPs. Communications protocols must be included in
each company’s specific reliability-related task list. Inherent in systematic approach is initial
training on all reliability-related tasks, since each task must be analyzed as to its Difficulty,
Importance & Frequency (DIF analysis). As a result of the DIF analysis, systematic approach
would require that communications protocols have both initial and continuing training.
Requirement R3: We agree with the OPCP SDT concern that Operating Personnel should not
be placed in a position to receive an oral two-party, person-to-person Operating Instruction
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
19
Organization
Yes or No
Question 1 Comment
prior to being trained. This Group understands that OPCP SDT included an initial training
requirement in the standard in response to the NERC Board of Trustees’ resolution, which
directs that a training requirement be included in the COM-002-4 standard. We would like
to recommend that the term “initial” be removed so not to give the impression that training
is a one-time effort. Current R3 language: Each Distribution Provider and Generator Operator
shall conduct initial training for each of its operating personnel who can receive an oral twoparty, person-to-person Operating Instruction prior to that individual operator receiving an
oral two-party, person-to-person Operating Instruction to either: [Violation Risk Factor:
Low][Time Horizon: Long-term Planning] Proposed R3 language: Each Distribution Provider
and Generator Operator shall conduct training for each of its operating personnel who can
receive an oral two-party, person-to-person Operating Instruction prior to that individual
operator receiving an oral two-party, person-to-person Operating Instruction to either:
[Violation Risk Factor: Low][Time Horizon: Long-term Planning]
Requirements R5, R6, and R7: This Group feels that the relationship between R1, R5, R6, and
R7 requires further clarification to remove possible opportunities for different interpretations
which could result in uncertainty as to whether the Operating Instruction is being issued to
alleviate or avoid an Emergency. The concern centers on the absence of a requirement that
the issuer make a definitive statement as to whether an Operating Instruction is being issued
to alleviate or avoid an Emergency, neither the recipient (during) nor an auditor (after) would
be able to make such determination. This is the reason for the R1 modifications. If the
recommended R1 modifications are accepted then R5, R6, and R7 should be considered for
deletion (incorporating specific items deemed necessary by the OPCP SDT as bullets or subrequirements of R1).
Measures: Measure 1: Base on the Group’s recommendations above we propose for
consideration the following modification to Measure 1: Current M1 language: Each Balancing
Authority, Reliability Coordinator, and Transmission Operator shall provide its documented
communications protocols developed for Requirement R1. Proposed M1 language: Revised
M1: Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1. For each
Operating Instruction issued to alleviate or avoid an Emergency; entity shall provide evidence
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
20
Organization
Yes or No
Question 1 Comment
that it identified such at time Operating instruction was issued (R1.1) and requested recipient
use of 3 part communication (R1.2).
Response: Requirement R1 states “Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall develop documented communications protocols for its
operating personnel that issue and receive Operating Instructions. The protocols shall, at a
minimum:” The Measure and, therefore, evidence, is proof of the developed protocols.
Measure 2,5,6, and 7: If our recommendations are accepted then Measures 2, 5, 6, and 7
should be deleted incorporating specific items deemed necessary by the OPCP SDT as bullets
or sub-requirements of R1 Measure 3: To align M3 with our R3 recommendation we propose
deleting the word “initial”. Current M3 language: Each Distribution Provider and Generator
Operator shall provide its initial training records for its operating personnel such as
attendance logs, agendas, learning objectives, or course materials in fulfillment of
Requirement R3.Proposed M3 language: Each Distribution Provider and Generator Operator
shall provide its training records for its operating personnel such as attendance logs, agendas,
learning objectives, or course materials in fulfillment of Requirement R3.
Response: The OPCP SDT considered your suggestion but asserts that the existing language
provides sufficient clarity.
Northeast Power
Coordinating Council
No
The proposed Requirements and Measures do not clearly delineate the differences in the
actions required to be taken by the issuer and recipient depending upon whether or not the
Operating Instruction is being given to alleviate or avoid an Emergency.
Duke Energy
No
(1)Duke Energy believes that Operating Instruction during an Emergency is unclear, vague,
and subject to interpretation. By using the NERC defined term of Emergency, certain tasks
that Duke Energy believes is a non-emergency action would now be considered an
Emergency and subject to zero tolerance. Duke submits, for consideration by the OPCP SDT,
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
21
Organization
Yes or No
Question 1 Comment
a revised definition of Emergency in an attempt to remove this ambiguity. Emergency - Any
abnormal system condition that requires automatic or immediate manual action to prevent
the failure of transmission facilities or generation supply that would adversely affect the
reliability of the Bulk Electric System.
Dominion
No
We do not believe the proposed requirements and measures clearly delineate the differences
in the actions required to be taken by the issuer and recipient depending upon whether or
not the Operating Instruction is being given to alleviate or avoid an Emergency.
ACES Standards
Collaborators
No
(1) We disagree that the current draft addresses the NERC Board resolution because the
Board charged the drafting team with developing an “essential set of communications
protocols” for reliable operation of the BES. The proposed standard conflicts with other
existing reliability standards, which would subject entities to double jeopardy. Therefore, the
standard includes more than an “essential set” of requirements as stated in the NERC Board
Resolution.
(2) For example, the “nomenclature” protocol in Requirement R1 is duplicative with TOP-002
R18. Since FERC issued a NOPR proposing to remand the TOP standards, the requirement of
using “uniform line identifiers” will remain as an enforceable standard. Having a
nomenclature requirement in COM-002-4 will subject entities to double jeopardy and is not
an “essential set of communication protocols.”
(3) Another example of a redundant requirement is training. Communications that impact
the BES will be covered in a reliability related task as part of the systematic approach to
training. This will also subject entities to double jeopardy with PER-005 R1 and is not an
“essential set of communication protocols.”
(4) We appreciate the efforts of the drafting team in working to address the FERC directives
and NERC November 2013 BOT Resolution, but we do not believe that COM-002-4 accurately
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
22
Organization
Yes or No
Question 1 Comment
reflects the proper applicability for entities that have an impact on the operations of the Bulk
Electric System in normal and emergency conditions. We understand that the inclusion of
Distribution Providers to this standard stems from various FERC directives, but because of the
relationship of Distribution Providers with Transmission Operators as identified in NERC's
functional model in being only a receiver of instructions to implement voltage reduction or to
shed load to prevent the failure of the BES, or related to restoration activities as coordinated
with the Transmission Operator; the TOP is ultimately responsible for the proper execution of
the instructions. Thus, we continue to recommend that Distribution Providers be removed
from the applicability of COM-002-4.
(5) Knowing that it will be difficult to remove the Distribution Provider from the applicability
of COM-002-4 per FERC's directives, we recommend an alternative that parallels the recently
FERC approved CIP-003-5 applicability section 4.1.2, which we believe accurately captures
those DPs that receive Operating Instructions associated with the reliability of the BES. The
following alternative can be used as technical justification to clarify those Distribution
Providers that have an impact on the BES is recommended:”4.1.2 Distribution Provider that:
4.1.2.1 Has capability to shed 300 MW or more of load in a single manually initiated
operation. 4.1.2.2 Has switching obligations related to any Cranking Path and group of
Elements meeting the initial switching requirements from a Blackstart Resource up to and
including the first interconnection point of the starting station service of the next generation
unit(s) to be started.”
NRECA
No
NRECA appreciates the efforts of the drafting team in working to address the FERC directives
and NERC BOT Resolution November 2013, but does not believe that COM-002-4 accurately
reflects the proper applicability for entities that have an impact on the operations of the Bulk
Electric System in normal and emergency conditions. NRECA understands that the inclusion
of Distribution Providers to this standard stems from various FERC directives, but because of
the relationship of Distribution Providers with Transmission Operators as identified in NERC's
functional model in being only a receiver of instructions to implement voltage reduction or to
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
23
Organization
Yes or No
Question 1 Comment
shed load to prevent the failure of the BES, or related to restoration activities as coordinated
with the Transmission Operator; the TOP is ultimately responsible for the proper execution of
the instructions, continues to recommend that Distribution Providers be removed from the
applicability of COM-002-4. Knowing that it will be difficult to remove the Distribution
Provider from the applicability of COM-002-4 per FERC's directives, NRECA is recommending
an alternative that parallels the recently FERC approved CIP-003-5 that we believe accurately
captures those DPs that receive Operating Instructions associated with the reliability of the
BES. The following alternative to clarify those Distribution Providers that have an impact on
the BES is recommended: 4.1.2 Distribution Provider that: 4.1.2.1 Has capability to shed 300
MW or more of load in a single manually initiated operation. 4.1.2.2 Has switching obligations
related to Any Cranking Path and group of Elements meeting the initial switching
requirements from a Blackstart Resource up to and including the first interconnection point
of the starting station service of the next generation unit(s) to be started. NRECA proposes to
recommend an “affirmative” ballot to its members if the applicability is modified in the next
posting as provided.
Oncor Electric
Delivery Company LLC
No
The Operating Instruction during an Emergency is unclear, vague, and subject to
interpretation. By using the NERC defined term of Emergency, certain tasks that are a nonemergency action would now be considered an Emergency. Oncor supports GTC’s
recommendation of the removal of the terms “or limit” within this definition. One could
argue that every single Operating Instruction is utilized to limit failures of transmission
facilities. Emergency should be more appropriately defined without this ambiguity. We
submit, for the OPCP SDT’s consideration, a revised definition of Emergency in an attempt to
remove this ambiguity. Emergency - Any abnormal system condition that requires automatic
or immediate manual action to prevent the failure of transmission facilities or generation
supply that would adversely affect the reliability of the Bulk Electric System. Oncor does not
believe that COM-002-4 accurately reflects the proper applicability for entities that have an
impact on the operations of the Bulk Electric System in normal and emergency conditions.
Oncor understands that the inclusion of Distribution Providers to this standard stems from
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
24
Organization
Yes or No
Question 1 Comment
various FERC directives, but because of the relationship of Distribution Providers with
Transmission Operators as identified in NERC's functional model in being only a receiver of
instructions to implement voltage reduction or to shed load to prevent the failure of the BES,
or related to restoration activities as coordinated with the Transmission Operator; the TOP is
ultimately responsible for the proper execution of the instructions, continues to recommend
that Distribution Providers be removed from the applicability of COM-002-4. Knowing that it
will be difficult to remove the Distribution Provider from the applicability of COM-002-4 per
FERC's directives, Oncor supports the alternatives recommended by GTC as an opportunity to
address this. In addition, the COM-002-4 does not align with the evaluation and findings of
the NERC Reliability Issues Steering Committee (RISC) and Operating Committee (OC) which
supports the importance of clear communications but found no evidence that nonemergency communications represent a reliability gap.
Exelon Corp and its
affiliated business
units
No
Revision 8 addresses the Board Resolution, but it goes beyond the resolution by including
GOP’s and DP’s as applicable entities thereby creating redundant and unnecessary
compliance obligations for many of those entities. See comments below in response
#4.Furthermore, while the new approach in this draft is an improvement, it does not achieve
the desired goal to move away from a zero tolerance focus on the use of three part
communication within this standard. If time is allowed for further work on this standard, we
offer potential adjustments below in response #4.A couple points of potential confusion:Question 1 and the link to the Board Resolution on the Project page cites a November 19,
2013 Resolution; however, the link takes readers to a November 7, 2013 Resolution. We
assume the November 7, 2013 Resolution is the correct reference. - The first bullet of the
November 7, 2013 Board Resolution refers to the Operating Committee Guidelines for good
communication practice. This OC document does not appear to be linked to the Project page.
It is unlikely that many stakeholders would have found and/or reviewed the document
relative to the proposed COM-002-4 draft.
Response: The November 7 reference is correct and has been updated.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
25
Organization
Yes or No
Question 1 Comment
The OC document was posted in June of 2012 on the Operating Committee Related Files
page and may be found at the following
location: http://www.nerc.com/comm/OC/Related%20Files%20DL/OC%20Approved_COM002-2%20Guideline_6-242012_For%20Posting_w%20line%20numbers_Clean_Version%202.pdf.
The United
Illuminating Company
No
Ingleside
Cogeneration LP
Yes
Ingleside Cogeneration LP ("ICLP") believes that the requirements that govern directives
issued during the course of an Emergency remain consistent with those in-place today. In
addition, the latest draft of COM-002-4 allows oversight of all other Operating Instructions although to a lesser degree. This is a good combination of compliance strategies that retains
focus on the important communications while adding attention on daily discussions which
may have impact on the BES if improperly transacted.
CenterPoint Energy
Houston Electric LLC
Yes
CenterPoint Energy agrees that the COM-002-4 standard addresses the NERC Board of
Trustees 2013 Resolution.
North American
Generator Forum -
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
26
Organization
Yes or No
Question 1 Comment
Standards Review
Team (NAGF-SRT)
Salt River Project
Yes
NERC Standards
Review Forum
Yes
Southern Company;
Southern Company
Services,Inc; Alabama
Power Company;
Georgia power
Company; Gulf Power
Company; Mississippi
Power Company;
Southern Company
Generation and
Energy Marketing
Yes
Florida Municipal
Power Agency
Yes
Arizona Public Service
Co.
Yes
DTE Electric
Yes
Bonneville Power
Administration
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
27
Organization
Yes or No
Luminant
Yes
Idaho Power Company
Yes
Public Utility District
No.1 of Snohomish
County
Yes
Liberty Electric Power
LLC
Yes
Wisconsin Electric
Power Company
Yes
Clark Public Utilities
Yes
Virginia State
Corporation
Commission, Member
OC
Yes
Manitoba Hydro
Yes
Independent
Electricity System
Operator
Yes
Platte River Power
Authority
Yes
MISO
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
Question 1 Comment
28
Organization
Yes or No
PJM Interconnection
Yes
Georgia System
Operations
Corporation
Yes
Northeast Utilities
Yes
Tri-State Generation
and Transmission
Association Inc.
Yes
The Empire District
Electric Company
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
Question 1 Comment
29
2.
Do you agree that COM-002-4 addresses the August 2003 Blackout Report Recommendation number 26, and FERC Order No. 693?
If not, please explain in the comment area.
Summary Consideration: The OPCP SDT thanks all those who took the opportunity to comment on Question 2. The August 2003
Blackout Report Recommendation number 26 called entities to tighten communications protocols especially during Emergencies and
alerts. The following is provided as a summary response to the comments on Question 2. Any necessary additional responses are
provided to individual commenters below.
Some commenters expressed concern that neither the August 2003 Blackout Report Recommendation number 26 nor FERC Order No.
693 recommended the use of three-part communication. FERC Order No. 693 Paragraph 531 states “We adopt our proposal to require
the ERO to establish tightened communication protocols, especially for communications during alerts and emergencies, either as part of
COM-002-2 or as a new Reliability Standard. We note that the ERO’s response to the Staff Preliminary Assessment supports the need to
develop additional Reliability Standards addressing consistent communications protocols among personnel responsible for the reliability
of the Bulk-Power System.” FERC also states that the goal is to establish communication uniformity as much as practical on a continentwide basis to eliminate possible ambiguities in communications during normal, alert, and emergency conditions. The existing COM-0022 includes three-part communication and the OPCP SDT determined that three-part communication is a necessary protocol.
Other commenters stated that Recommendation 26 from the 2003 Blackout report is about situational awareness and not about what
System Operators should say in their conversations. The OPCP SDT asserts that situational awareness is improved by operationally
sound communication protocols, which decrease the possibility of miscommunications.
Other commenters stated that Recommendation 26 of the 2003 Blackout Report continues to be misinterpreted. The recommendation
is focused on how the ERO should communicate with governmental agencies. It states, “Standing hotline networks, or a functional
equivalent, should be established for use in alerts and emergencies (as opposed to one-on-one phone calls) to ensure that all key
parties, [including state and local officials] are able to give and receive timely and accurate information.” FERC Order No. 693 Paragraph
534 states “In response to MISO’s contention that Blackout Report Recommendation No. 26 has been fully implemented, we note that
Recommendation No. 26 addressed two matters. We believe MISO is referring to the second part of the recommendation requiring
NERC to ‘[u]pgrade communication system hardware where appropriate” instead of tightening communications protocols. While we
commend the ERO for taking appropriate action in upgrading its NERCNet, we remind the industry to continue their efforts in addressing
the first part of Blackout Recommendation No. 26.” In response, the OPCP SDT has not focused on hardware issues, instead focusing on
communication protocols.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
30
One commenter stated that allowing the issuer of an Operating Instruction to seek confirmation from only one recipient in Requirement
R7 ignores the recommendation from the Blackout Report to use new technology. The OPCP SDT asserts that it is important that the
issuer of a written or oral single-party to multiple-party burst Operating Instruction make sure that the communication channel was
complete. This can be accomplished by confirming with at least one party that the communication was received. This is not limited to
any particular technology that could be employed for the necessary confirmation.
Certain commenters indicated that COM-002-4 goes outside the scope of Recommendation 26 of the Blackout Report because it deals
with both non-Emergency and Emergency communications. However, the OPCP SDT contends that operators are often not aware they
are in an Emergency situation until after the event has ended. Therefore, in order to mitigate a potential reliability gap, it is essential
that COM-002-4 require a single set of communication protocols that are always used by operators.
Organization
Yes or No
Question 2 Comment
Northeast Power Coordinating
Council
No
We do not agree that the blackout recommendation calls for the use of 3 part
communication for every Operating Instruction and note that neither the NERC Board
nor the OPCP SDT has provided any evidence that indicates a direct correlation
between errors due to communication problems and events that adversely impact
the BES. The justification for reliability standard Requirements that require 3 part
communication for every Operating Instruction, and having to enforce compliance
with the same, is not supported.
NERC Standards Review
Forum
No
As it has been stated in previous comments, Recommendation 26 from the 2003
Blackout report is about situational awareness and who and what entities need to be
contacted during emergencies. It is not about what System Operators should say in
their conversations.
Consideration of Comments: Project 2007-02 COM-002-4
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31
Organization
Yes or No
Question 2 Comment
Duke Energy
No
(1)Based on our comments to Question 1, Duke Energy does not believe that the
OPCP SDT has addressed Recommendation 26 of the August 2003 Blackout report.
The intent of the 2003 Blackout recommendation was to provide tighter
communication during normal and emergency situations. Due to the ambiguity that
exists between Operating Instruction and Operating Instruction during an Emergency,
we believe that this recommendation was not addressed.
SPP Standards Review Group
No
Our understanding of Recommendation 26 is that it deals strictly with
communications during emergencies which COM-002-3 had already addressed. The
addition of non-emergency communications, which are not mentioned in
Recommendation 26 at all, has expanded the scope of the standard beyond that
called for by the recommendation. The addition of non-emergency communications
has added additional compliance burden for the responsible entities without clearly
improving the reliability of the BES.
Dominion
No
We do not agree that the blackout recommendation calls for the use of 3 part
communication for every Operating Instruction and note that neither the NERC Board
nor the OPCP SDT has provided any evidence that indicates a direct correlation
between errors due to communication problems and events that adversely impacted
the BES. Therefore we find it difficult to support reliability standard requirements
that require 3 part communication for every Operating Instruction and enforce
compliance with same.
ACES Standards Collaborators
No
(1) We believe recommendation number 26 of the 2003 Blackout Report continues to
be misinterpreted. The recommendation is focused on how the ERO should
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
32
Organization
Yes or No
Question 2 Comment
communicate with governmental agencies. It states, “Standing hotline networks, or a
functional equivalent, should be established for use in alerts and emergencies (as
opposed to one-on-one phone calls) to ensure that all key parties, [including state
and local officials] are able to give and receive timely and accurate information.” The
recommendation does not state anywhere to utilize three-part communication.
COM-002-4 does not address the development of hotline networks or “upgrading
communication system hardware where appropriate” for contacting governmental
agencies, including state and local officials.
Luminant
No
Recommendation 26 of the August 2003 Blackout Report was to "Tighten
communications protocols, especially for communications during alerts and
emergencies. Upgrade communication system hardware where appropriate."
Technology is now available and already in use in some places that allow recipients of
an All-Call/Burst Message type Operating Instruction to press a button on the phone
keypad to acknowledge understanding of the Operating Instruction. This allows the
issuer a quick and easy way to confirm the understanding of all recipients of the
Operating Instruction. Allowing the issuer of an Operating Instruction to seek
confirmation from only one recipient in R7 ignores the recommendation from the
Black Out Report to use new technology.
Georgia Transmission
Corporation
No
Comments: GTC recognizes FERC Order 693 directs the revision of COM-002 to
include the DP and specifically states how essential it is that the TOP, BA and RC have
communications with DPs. Additionally, GTC observes Order 693 also identifies the
need for tightened communications protocols, especially for communications during
alerts and emergencies and that such protocols shall be established with uniformity
as much as practical on a continent wide basis to eliminate possible ambiguities in
communications during emergency conditions. If the Standard requires the use of 3
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
33
Organization
Yes or No
Question 2 Comment
part communications by the issuers of Operating Instructions, then it would seem
sensible that receivers of Operating Instructions be trained for awareness and proper
participation of such protocols. GTC sees parallels of this approach in other Standards
such as restoration training of DPs identified in the TOPs restoration plan as required
in EOP-005-2. GTC believes the current proposal of COM-002-4 still contains
ambiguities that should be addressed before GTC can provide an affirmative ballot.
GTC is offering 3 alternatives such that if any of them is adopted by the OPCP SDT,
GTC would modify our position to cast an affirmative vote in the next recirculation.
Alternative 1 (Modify the DP applicability): Applicability Section:4.1.2 Distribution
Provider: GTC is recommending an alternative that parallels the recently FERC
approved CIP-003-5 that we believe accurately captures those DPs that receive
Operating Instructions associated with the reliability of the BES when in an
Emergency. The following alternative to clarify those Distribution Providers that have
an impact on the BES is recommended:4.1.2 Distribution Provider that:4.1.2.1 Has
capability to shed 300 MW or more of load in a single manually initiated
operation.4.1.2.2 Has switching obligations related to Any Cranking Path and group of
Elements meeting the initial switching requirements from a Blackstart Resource up to
and including the first interconnection point of the starting station service of the next
generation unit(s) to be started. Alternative 2 (Modify the DP applicability per above,
modify R3; Eliminate R6): Alternative 2 is an extension of alternative 1 for additional
clarities. Requirement 3: Revise R3 to insert the words [during an Emergency] within
the sentence “...who can receive an oral two-party, person-to-person Operating
Instruction [during an Emergency] prior to that individual operator...”. Additionally,
replace the word “receive” with the word “request” in the first bullet of R3. The word
“receive” is ambiguous and the word “request” is consistent with the receiver using
his words to request a confirmation. GTC maintains that R3 is sufficient to satisfy
FERC Order 693 for the DP applicability during emergencies, and would ensure
uniformity on a continent wide basis to eliminate possible ambiguities in
communications during emergency conditions. GTC prefers the elimination of R6.
GTC does not believe that a receiver of an Operating Instruction in the field
Consideration of Comments: Project 2007-02 COM-002-4
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34
Organization
Yes or No
Question 2 Comment
performing field switching activities should be required to document evidence of
following the oral communication practices. Issuers of Operating Instructions are
already recording the Operating Instruction communications and have the capability
to do so. Issuers are also required to ensure the receiver responds accordingly per R5.
Issuers are required to confirm the receiver’s response is correct or else reissue if
incorrect; issuers can also take an alternative action. Having the receiver document
the implementation of these practices for compliance is redundant and duplicative to
the issuer’s requirements. This is an unnecessary, administrative requirement that
introduces a double jeopardy situation that does not enhance the reliability of the
BES. The OPCP SDT should recognize that all reliability bases are covered with the
training requirements of the issuers in R1, the training requirement of the receivers
in R3, and the performance of these are monitored via the issuers recording
capabilities in R5 and R7. With this approach, issuers can be satisfied that receivers
are prepared to receive instructions in accordance with their training, and the options
the issuers have per R5 in a live scenario. The receivers could not expose or cause a
non-compliance situation to the issuers. However, the issuers could expose the
receivers to a non-compliance situation if a recording is lost or damaged and the
receiver was on hiscell phone in the field taking orders and performing switching,
hence the double jeopardy and GTC’s plea to remove this requirement 6.Alternative
3 (Modify the DP applicability above, Modify R3 above, Modify R6, create separate
DP requirement):Requirement 6: If the OPCP SDT decides that R6 must remain, then
GTC requires the following changes to modify our negative vote to affirmative. GTC
appreciates the drafting team making concessions to eliminate the need for DPs and
GOPs being required to have documented communication protocols. Additionally,
GTC appreciates the drafting team’s willingness to limit the scope of performing the 3
part communications to those Operating Instructions received during an Emergency.
These drafting team concessions are a testament to the team, along with industry, of
understanding that the DP will typically have a very limited role in receiving
Operating Instructions from the BA or TOP to protect the BES during an Emergency.
This role is typically limited to operating non-BES equipment (load serving stations) to
Consideration of Comments: Project 2007-02 COM-002-4
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35
Organization
Yes or No
Question 2 Comment
shed load or reduce voltage to prevent the failure of transmission facilities or
generation supply that could adversely affect the reliability of the BES. GTC would
submit that the TOP would further limit the DPs role to “manual” load shed type
situations when the “automatic” load shed schemes misoperate or malfunction as
designed. This is highlighted in the NERC functional model which identifies this real
time function of the DP “Implements voltage reduction and sheds load as directed by
the Transmission Operator or Balancing Authority”. During an Emergency, which
NERC defines as any abnormal condition that requires automatic or immediate
manual action to prevent or limit the failure of transmission facilities or generation
supply that could adversely affect the reliability of the BES, the aforementioned
function is what the DP will be called upon to implement. The ambiguity that arises is
captured within the various types of utility registrations with NERC, and GTC believes
the OPCP SDT can accommodate two distinct types of DPs which GTC believes to be
critical to pass this Standard. GTC observed there are 298 entities in the NERC registry
that are true DP function only. Most of these are DP/LSE and would not own BES
assets, but they would be directly connected to the BES, hence registration. These
entities own load serving substations and implementing voltage reduction or
shedding load in an Emergency would not be ambiguous. However, GTC observed
there are 242 entities in the NERC registry that are registered DPs, and also registered
TOs that own BES assets. To these integrated entities, the scope of communications
during an Emergency would be more ambiguous, as these entities may perform
actions at transmission stations on a routine basis that the other DP only type entities
would not have to consider. With the addition of R6 as written, these entities have an
amplified burden of compliance risk associated with their TO registration even
though R6 applies to them as a DP. This burden is the separation of those Operating
Instructions performed at transmission stations which occurs more often than the
Emergency event which requires a manual operation for reduction of voltage or load
shed at load serving stations. GTC believes this ambiguity is significant enough to
justify the separation of the DP from R6 to provide a standalone requirement
commensurate to the DPs function as documented in the NERC functional model.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 2 Comment
Proposed R6 language: Remove Distribution Provider from R6. Create a separate
standalone requirement for the DP.R#. Each Distribution Provider that receives an
oral two-party, person-to-person Operating Instruction to implement voltage
reduction or shed load during an Emergency, excluding written or oral single-party to
multiple-party burst Operating Instructions, shall either:* Repeat, not necessarily
verbatim, the Operating Instruction and request confirmation from the issuer that
the response was correct, or* Request that the issuer reissue the Operating
Instruction.
Response: Please see the Summary Responses to Question 1 and Question 2.
Nebraska Public Power District
No
Recommendation 26 calls for work to be done to improve the effectiveness of
communications in emergency situations. The purpose of the standard is to improve
communications. However, the focus of the standard is primarily 3-part
communications. There is no supporting documentation or data that 3-part
communications improves the effectiveness of communications. Focusing on 3-part
communications provides an easy target from a compliance perspective but all it
teaches us is to mechanically repeat back what we have been instructed to do. We’re
focusing on the ‘how’ and ‘what’ rather than the ‘why’. Keeping the ‘why’ in mind
improves communications and the reliability of the BES. Keeping the ‘why’ in mind
also leads to improved situational awareness. Improving effective communications is
difficult to quantify in a standard and even more difficult to measure. We may be
better off focusing on the principles contained in the OC’s Reliability Guideline
System Operator Verbal Communications - Current Industry Practices.
Georgia System Operations
Corporation
No
GSOC recommends modifying R1 so that it applies to all Operating Instructions but
requires that those being issued to alleviate or avoid an Emergency be specifically
identified as such and that the issuer explicitly request recipient confirm
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 2 Comment
understanding through use of 3 part communication. This would require a revised
R1.1Proposed R1: ADD: Require that its operating personnel identify, at the time of
issuance, when the Operating Instruction is being issued to alleviate or avoid an
Emergency. Proposed R1.2: ADD: Request recipient use 3 part communication when
the Operating Instruction is being issued to alleviate or avoid an Emergency.
Proposed R1.3: change the word “correct” to “understood” Requirement 2: GSOC
believes R2 should be eliminated as redundant with the systematic approach to
training requirements of PER-005-2(Operating Personnel Training) which are
applicable to all Bas, RCs and TOPs. Communication protocols must be included in
each company’s specific reliability-related task list. GSOC believes the current
proposal of COM-002-4 still contains ambiguities that can be resolved with the
following alternative. GSOC recognizes the following alternative in that it parallels the
recently FERC approved CIP-003-5. GSOC believes this alternative more accurately
captures those DPs that receive Operating Instructions associated with the reliability
of the BES. 4.1.2 Distribution Provider that: 4.1.2.1 Has capability to shed 300 MW or
more of load in a single manually initiated operation.4.1.2.2 Has switching obligations
related to Any Cranking Path and group of Elements meeting the initial switching
requirements from a Blackstart Resource up to and including the first interconnection
point of the starting station service of the next generation unit(s) to be started.
Response: The OPCP SDT disagrees with the suggested edits to Requirement R1. R1
currently requires entities to set protocols for use when issuing Operation
Instructions. The Requirement calls for the development of protocols to cover ALL
Operating Instructions. How an entity must use the protocols for Operating
Instructions during Emergencies is covered by a separate requirement. Please see
the Summary Response to Question 1 for responses to your comments regarding
the inclusion of Distribution Providers and training.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 2 Comment
Electric Reliability Council of
Texas, Inc.
No
This standard is not responsive to the Blackout Recommendation #26. The
prevention of miscommunication is the current focus of this standard, while nothing
in the Blackout Report commented on an instruction not being followed due to
miscommunication. Rather, the Blackout Report focused on a lack of situational
awareness based on one entity not understanding what the other entity was
describing because different entities used different terminology. Flow of
communications or “who” should be notified was also lacking in addition to “what”
needed to be communicated. The report highlighted that effective communication
was based on communication of important and prioritized information to each other
in a timely way. In essence, this focuses on communication protocols to prevent
miscommunications while Recommendation #26 focused on effective communication
protocols that improve situational awareness, where the former is process and the
latter is substantive. That being said, and regardless of whether COM-002-4
addresses the August 2003 Blackout Report Recommendation number 26 or not,
ERCOT ISO can support the COM-002-4 standard. However, ERCOT ISO believes the
draft standard could be improved and offers suggestions in Question 4 below, for the
OPCP SDT’s consideration.
Oncor Electric Delivery
Company LLC
No
COM-002-4 goes beyond the August 2003 Blackout Report Recommendation number
26, FERC Order 693 for neither identify requirements for normal operations. EOP001-2, R3.1 and COM-002-2, R2 already address the requirements of the Blackout
Report and FERC Order 693. The intent of the 2003 Blackout recommendation was to
provide tighter communication during emergency situations. Due to the ambiguity
that exists between Operating Instruction and Operating Instruction during an
Emergency, we believe that this recommendation was not addressed. In addition, the
NERC BOT directed the NERC Operating Committee (OC) to evaluate the COM
standards (previously COM-003) and responses from the Reliability Issues Steering
Committee (RISC), the Independent Experts Review and NERC Management. Their
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 2 Comment
report issued September 23, 2013 to the NERC BOT Chairman identifies the
importance of clear communications but found no evidence including the NERC event
analysis process nor recent events which supports that non-emergency
communications represents a reliability gap. The OC created a guideline for verbal
communications which provides industry best practices and recommended utilizing
the guideline to promote continuous improvement versus implementing a mandatory
standard.
NRECA
No
See response to Question 1
Exelon Corp and its affiliated
business units
No
2003 Blackout Report Recommendation No. 26 reads:”Tighten communications
protocols, especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate (footnote omitted). NERC
should work with reliability coordinators and control area operators to improve the
effectiveness of internal and external communications during alerts, emergencies, or
other critical situations, and ensure that all key parties, including state and local
officials, receive timely and accurate information. NERC should task the regional
councils to work together to develop communications protocols by December 31,
2004, and to assess and report on the adequacy of emergency communications
systems within their regions against the protocols by that date.”While Exelon
believes that COM-002-4 goes beyond the Recommendation and includes the
requirement to implement communication protocols for operating BES elements in
non-emergency and other non-critical situations, Exelon also recognizes that the
NERC Board believes that the words “especially for” in the recommendation are the
reason to include a standard for normal communications. We also understand that in
paragraph 540 of Order No. 693, FERC directed the ERO to expand the applicability of
the communication standard to distribution providers (DP’s) but that directive tied
Consideration of Comments: Project 2007-02 COM-002-4
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40
Organization
Yes or No
Question 2 Comment
back to communications protocols “especially for communications during alerts and
emergencies.” Although Recommendation 26 addresses “key parties” and FERC
directive addresses DP’s in the context of Blackout Recommendation No. 26, we
don’t believe that either was intended to include DP’s and GOP’s for non-emergency
Operating Instructions communications.
The United Illuminating
Company
No
Ingleside Cogeneration LP
Yes
COM-002-4 adds requirements that call for protocols that add precision to operations
communications as called for in both documents. However, in the latest draft, ICLP
believes the compliance approach has been modified in a manner that ensures that
routine Operating Communications are conducted using a common protocol - but do
not involve significant tracking resources. In addition, the use of operator training
and regular review of its effectiveness is consistent with other NERC standards
related to operator capabilities. As it is written now, CIP-002-4 introduces new
expectations related to routine communications, but only puts incremental pressures
on existing processes and equipment necessary to address them.
CenterPoint Energy Houston
Electric LLC
Yes
CenterPoint Energy agrees that the COM-002-4 standard addresses both the August
2003 Blackout Report Recommendation 26 and FERC Order 693.
SERC OC Review Group
We are concerned that this draft goes further than mentioned in the blackout
recommendation that NERC should work with reliability coordinators and control
area operators to improve the effectiveness of internal and external communications
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
41
Organization
Yes or No
Question 2 Comment
during alerts, emergencies, or other critical situations. This group feels that the
modifications recommended will add further clarity in communications and work
towards the goal identified in the Black Report recommendation number 26.
Salt River Project
Yes
Southern Company; Southern
Company Services,Inc;
Alabama Power Company;
Georgia power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation and
Energy Marketing
Yes
Florida Municipal Power
Agency
Yes
Arizona Public Service Co.
Yes
DTE Electric
Yes
Bonneville Power
Administration
Yes
Idaho Power Company
Yes
Public Utility District No.1 of
Snohomish County
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
42
Organization
Yes or No
Liberty Electric Power LLC
Yes
Wisconsin Electric Power
Company
Yes
Clark Public Utilities
Yes
Virginia State Corporation
Commission, Member OC
Yes
Manitoba Hydro
Yes
American Transmission
Company, LLC
Yes
Platte River Power Authority
Yes
MISO
Yes
PJM Interconnection
Yes
Northeast Utilities
Yes
Tri-State Generation and
Transmission Association Inc.
Yes
The Empire District Electric
Company
Yes
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
Question 2 Comment
43
3.
Do you agree with the VRFs and VSLs for the Requirements? If not, please explain.
Summary Consideration: The OPCP SDT thanks all commenters who submitted comments for Question 3. The following is provided as a
summary response to the comments on Question 3. Any necessary additional responses are provided to individual commenters below.
It should be noted that VSLs must be developed based on established criteria. Please refer to the “VRF/VSL Justification” document
posted with the standard on the project page for additional information.
Several commenters stated that they did not feel a Severe VSL was appropriate for Requirement R1. The OPCP SDT has reviewed these
comments but maintains the position that if an entity fails to include three-part communication in its communication protocols or the
entity does not have any documented communication protocols, then that violation would warrant a Severe VSL as those elements
represent the most significant elements of Requirement R1. Feedback received during development indicated a preference for a
gradated VSL for Requirement R1 with higher importance placed on more critical protocols.
Other comments noted the Lower VSL for Requirement R4 is triggered by an entity failing to evaluate its documented communication
protocols for Requirement R1 every 12 calendar months, but there is not a cap on the amount of time that may pass between
evaluations and the violation results in a greater VSL. The OPCP SDT discussed the issue and determined that the requirement to
perform the review is more important than penalizing an entity for the amount of time they missed the time window. The purpose of
the requirement is to encourage entities to perform periodic reviews each year. The team determined that 12 months was the
appropriate maximum period and that missing the 12-month time window should be the only demarcation point necessary.
Commenters also stated they felt the VSLs for Requirements R5–R7 were not appropriate because the difference between a Severe VSL
and a Moderate VSL is triggered by whether or not an Emergency situation occurred. The OPCP SDT provided justification for the VSLs
in the “VRF/VSL Justification” document posted on the project page. If an entity, when issuing an Operating Instruction during an
Emergency, did not use three-part communication or take an alternative action if the receiver does not respond, yet instability,
uncontrolled separation, or cascading failures did not occur as a result, the entity violated the requirement with a “Medium” VSL. The
value of “Medium” is justified based upon a significant element (or a moderate percentage) of the required performance being missing,
but the performance or product measured still has significant value in meeting the intent of the requirement, which is to avoid action or
inaction that is harmful to the reliability of the Bulk Electric System. If an entity, when issuing an Operating Instruction during an
Emergency, did not use three-part communication or take an alternative action if the receiver does not respond, and instability,
uncontrolled separation, or cascading failures occurred as a result, the entity violated the requirement with a “Severe” VSL. The value of
“Severe” is justified because the performance outcome does not meet the intent of the requirement.
In response to comments, the OPCP SDT made non-substantive clarifying changes to Measures M2, M4, M6, and M7.
Consideration of Comments: Project 2007-02 COM-002-4
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44
Organization
Yes or No
Question 3 Comment
Northeast Power Coordinating
Council
No
Regarding Requirement R4, the LOW VSL suggests that an entity is assigned a LOW
VSL if assessments are conducted more than 12 months apart. There is no maximum
or “cap” to the delayed assessment, and hence an entity may be 18, 19 or more
months late in conducting the next assessment. In other standards this could well be
assessed a MEDIUM or HIGH or even a SEVERE violation, depending on the time
period that an entity failed the 12 month update requirement. Absent this “cap”, or
staggered caps, the proposed HIGH and SEVERE VSLs can only be assessed based on
whether or not there was ever an assessment, even if the last assessment was done 3
or 4 years prior to an audit. This is inconsistent with the general guideline for VSLs.
Regarding Requirement R5, the MEDIUM VSL and SEVERE VSL are identical, except
the latter has a condition that is associated with the impact of the violation. This is
inconsistent with the intent of the VSL, which is to assess the “extent to which” the
requirement was violated, not the impact of the violation which should be captured
by the VRF. This is also inconsistent with the VSL principle and guideline. Suggest
removing the MEDIUM VSL, and the condition under the proposed SEVERE VSL be:
“AND instability, uncontrolled separation, or cascading failures occurred as a result.”
The same comments apply for Requirements R6 and R7.We believe that the
VRFs/VSLs should be modified to better reflect the stated intent of the NERC Board of
Trustees November 19, 2013 Resolution, which is to enforce ‘zero tolerance’ only for
failure to use 3 part communications by the issuer or recipient of an Operating
Instruction when it is issued to alleviate or avoid an Emergency.
NERC Standards Review
Forum
No
R1, The NSRF does not understand why there is a Severe VSL for normal everyday
Operating Instructions. This Severe VSL is imposing the “zero defect” language that
Consideration of Comments: Project 2007-02 COM-002-4
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45
Organization
Yes or No
Question 3 Comment
the industry is trying to move away from. We understand if there were no protocols
as in “The responsible entity did not develop any documented communications
protocols as required in Requirement R1”, but not the sub requirements of R1.2 and
R1.3. The highest VSL should be High. Save the Severe VSL for R5, R6, and R7.
Colorado Springs Utilities
No
We do not agree with the following VSLs:1) R4: The LOW VSL suggests that an entity
is assigned a LOW VSL if assessments are conducted more than 12 months apart.
There is no max or “cap” to the delayed assessment and hence an entity may be 18,
19 or more months late in conducting the next assessment. In other standards, this
could well be assessed a MEDIUM or HIGH or even a SEVERE violation, depending on
the time period that an entity failed the 12 month update requirement. Absent this
“cap”, or staggered caps, the proposed HIGH and SEVERE VSLs can only be assessed
based on whether or not there was ever an assessment, even the last assessment
was done 3 or 4 years prior to an audit. This is inconsistent with the general guideline
for VSLs.2)
R5: The MEDIUM VSL and SEVERE VSL are identical, except the latter has a condition
that is associated with the impact of the violation. This is inconsistent with the intent
of the VSL, which is to assess the “extent to which” the requirement was violated, not
the impact of the violation which should be captured by the VRF. This is also
inconsistent with the VSL principle and guideline. We suggest removing the MEDIUM
VSL, and the condition under the proposed SEVERE VSL that: “AND Instability,
uncontrolled separation, or cascading failures occurred as a result.”3) R6: Same
comments as in R5.4) R7: Same comments as in R5.
Southern Company; Southern
Company Services,Inc;
Alabama Power Company;
No
R3 VSL is listed as high and severe; The concern is that if an operator receives
instruction and performs accurately using 3-part, but can’t show initial training for
Operating Instruction and Operating instruction during an Emergency, would this
Consideration of Comments: Project 2007-02 COM-002-4
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46
Organization
Yes or No
Georgia power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation and
Energy Marketing
Question 3 Comment
warrant a high or severe VSL. While there is the potential of risk if Operating
Instructions are received prior to being trained, this should not somehow imply that
incorrect operations were performed as a result of no training. The severe category
should be reserved only for those instances in which Operating Instructions were
received prior to being trained *and* which resulted in an emergency operation or
reliability issue. As a result, we suggest “demoting” each existing VSL to a lower level,
and editing the High and Severe VSL and limit it to only those instances that resulted
in an emergency operation or reliability issue (suggestions provided below). Low - An
individual operator at the responsible entity receiving an Operating Instruction prior
to being trained. Moderate - An individual operator at the responsible entity received
an Operating Instruction during an Emergency prior to being trained. High - An
individual operator at the responsible entity received an Operating Instruction prior
to being trained *and* resulting in an emergency operation or reliability issue. Severe
- An individual operator at the responsible entity received an Operating Instruction
during an Emergency prior to being trained *and* resulting in an emergency
operation or reliability issue.
DTE Electric
No
The evidence needed to avoid violation is not clear. The VSL for R2 is not reasonable
and an auditing nightmare. It should state an operator did not receive training on the
documented communication protocol. Adding "prior to issuing an operating
instruction" cannot be determined without excessive investigation. A check that all
operators received training is appropriate. Same issue with R3 as listed for R2.
SPP Standards Review Group
No
We suggest changing the Moderate VSLs for R5, R6 and R7 to Lower. If the failure to
completely follow through with the protocols contained in R1 had no adverse impact
on the situation, then this VSL is purely administrative and is not deserving of being
Moderate. The Lower and Moderate VSLs for R1 contain specific details regarding
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 3 Comment
each of the Parts referenced in each of the VSLs. In the High and Severe VSLs for R1
only reference is made to the Parts while the details contained in the Parts is not
included in the VSLs. Either the details should be removed from the Lower and
Moderate VSLs or the details need to be included in the High and Severe VSLs.
Dominion
No
We believe that the VRFs/VSLs should be modified to better reflect the stated intent
of the NERC Board of Trustees November 19th, 2013 Resolution, which is to enforce
‘zero tolerance’ only for failure to use 3 part communications by the issuer or
recipient of an Operating Instruction when it is issued to alleviate or avoid an
Emergency.
ACES Standards Collaborators
No
(1) We disagree with some of the requirements of including training and several
aspects of the communication protocols. Since we disagree with the underlying
requirements, we also disagree with the corresponding VSLs and VRFs.
ISO/RTO Council Standards
Review Committee
No
We do not agree with the following VSLs:i) R4: The LOW VSL suggests that an entity is
assigned a LOW VSL if assessments are conducted more than 12 months apart. There
is no max or “cap” to the delayed assessment and hence an entity may be 18, 19 or
more months late in conducting the next assessment. In other standards, this could
well be assessed a MEDIUM or HIGH or even a SEVERE violation, depending on the
time period that an entity failed the 12 month update requirement. Absent this
“cap”, or staggered caps, the proposed HIGH and SEVERE VSLs can only be assessed
based on whether or not there was ever an assessment, even the last assessment
was done 3 or 4 years prior to an audit. This is inconsistent with the general guideline
for VSLs.ii) R5: The MEDIUM VSL and SEVERE VSL are identical, except the latter has a
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 3 Comment
condition that is associated with the impact of the violation. This is inconsistent with
the intent of the VSL, which is to assess the “extent to which” the requirement was
violated, not the impact of the violation which should be captured by the VRF. This is
also inconsistent with the VSL principle and guideline. We suggest removing the
MEDIUM VSL, and the condition under the proposed SEVERE VSL that: “AND
Instability, uncontrolled separation, or cascading failures occurred as a result.”iii) R6:
Same comments as in R5.iv) R7: Same comments as in R5.
Liberty Electric Power LLC
No
The "Moderate" VSL for R6 should be modified in the same manner as the "Severe"
VSL. In addition to repeating the Directive, the RE needs to fail to take action as
directed. Suggest the following language: "AND the RE failed to take action as
requested by the issuer of the Operating Instruction".
NRECA
No
Will need to be modified dependent on applicability modifications.
Georgia Transmission
Corporation
No
Modify in accordance with selected alternative drafted above.
Independent Electricity
System Operator
No
We do not agree with the following VSLs:i) R4: The LOW VSL suggests that an entity is
assigned a LOW VSL if assessments are conducted more than 12 months apart. There
is no max or “cap” to the delayed assessment and hence an entity may be 18, 19 or
more months late in conducting the next assessment. In other standards, this could
well be assessed a MEDIUM or HIGH or even a SEVERE violation, depending on the
Consideration of Comments: Project 2007-02 COM-002-4
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49
Organization
Yes or No
Question 3 Comment
time period that an entity failed the 12 month update requirement. Absent this
“cap”, or staggered caps, the proposed HIGH and SEVERE VSLs can only be assessed
based on whether or not there was ever an assessment, even the last assessment
was done 3 or 4 years prior to an audit. This is inconsistent with the general guideline
for VSLs.ii) R5: The MEDIUM VSL and SEVERE VSL are identical, except the latter has a
condition that is associated with the impact of the violation. This is inconsistent with
the intent of the VSL, which is to assess the “extent to which” the requirement was
violated, not the impact of the violation that should have been reflected by the VRF.
This is also inconsistent with the VSL principle and guideline. We suggest removing
the MEDIUM VSL, and the condition under the proposed SEVERE VSL that: “AND
Instability, uncontrolled separation, or cascading failures occurred as a result.”iii) R6:
Same comments as in R5.iv) R7: Same comments as in R5.
American Electric Power
No
The AND qualifier provided for R5 which qualifies that Instability, uncontrolled
separation, or cascading failures occurred, should also be used for R3.
CenterPoint Energy Houston
Electric LLC
No
CenterPoint Energy does not agree with the Severe VSL for Requirement R1. The
Company strongly believes that the focus of any Reliability Standard should be on
enhancing the reliable operation of the BES and not on documents. Simply failing to
document a procedure should never warrant a Severe VSL as long as the entity is
operating according to the Standard.
Georgia System Operations
Corporation
No
R1 - GSOC requests that there not be applied a Severe VSL for normal everyday
Operating Instructions.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 3 Comment
Electric Reliability Council of
Texas, Inc.
No
R2 and R3 VSLs should not have the “during an Emergency” distinction between a
high and severe VSL. VSL’s grade the severity or “how bad” did an entity violate a
requirement. The risk and situation of non-compliance is included in the VRF and not
the VSL. ERCOT ISO would recommend percentage indicator across the severity
levels as detailed in the VSL guideline document.R5-R7 VSLs should remove
“Instability, uncontrolled separation, or cascading failures occurred as a result.” as
that stipulation is not appropriate in the VSLs. The resulting impact of noncompliance is addressed in the enforcement process and not in how severe an entity
did not comply with a requirement. ERCOT ISO suggests a binary or severe only VSL
to coincide with the VSL Guideline document. Additionally, ERCOT ISO would
recommend adding “at least” in the R5 VSL to better clarify that a minimum of one of
the three actions is required and not all three.The responsible entity that issued an
Operating Instruction during an Emergency did not take ‘at least’ one of the following
actions:
ReliabilityFirst
No
ReliabilityFirst submits the following comments related to the VSL for the OPCP SDTs
consideration:1. Requirement R4 VSL - For the Lower VSL, ReliabilityFirst
recommends gradating the number of months an entity is late in assessing adherence
and effectiveness of the documented communications protocols. For example, there
is a big difference if an entity is late by one month or 12 months. As drafted, an
entity that is late by 12 months would still fall under the Lower VSL. ReliabilityFirst
recommends gradating the VSLs in three month intervals. For example, the last
“AND” text for the Lower VSL would read: “The responsible entity exceeded twelve
(12) but less than or equal to fifteen (15) calendar months between assessments.”
The Moderate VSL would read; “The responsible entity exceeded fifteen (15) but less
than or equal to eighteen (18) calendar months between assessments.” The High and
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 3 Comment
Severe VSLs would follow the same rationale.2. Requirement R5 VSL - Requirement
R5 does not speak to instability, uncontrolled, separation, or cascading failures
occurring as a result of correctly issuing an oral two-party, person-to-person
Operating Instruction. To be consistent with the requirement, ReliabilityFirst
recommends deleting the text after the AND qualifier and deleting the Moderate VSL.
Hence, there will only be one Severe VSL for this requirement.3. Requirement R6 VSL
- Similar comment as the Requirement R5 VSL4. Requirement R7 VSL - Similar
comment as the Requirement R5 VSL
Manitoba Hydro
Yes
Salt River Project
Yes
Florida Municipal Power
Agency
Yes
Although Manitoba Hydro agrees with the VRFs and VSLs for the Requirements, we
have the following comments: 1) VSLs, R2 - the term ‘individual operator’ is used in
this VSL where throughout the standard operating personnel is used. 2) VSLs, R5 text of VSLS refer to Requirement R6 instead of R5.3) VSLs, R6 - inconsistent drafting
as the words ‘that received an oral, .....’ is not included here, but does appear in the
VSL for R7.4) VLSs, R5, R6, R7 - the final criteria for a Severe VSL is for a specific
outcome of non-compliance which does not seem appropriate when measuring
compliance. Depending on the outcome of the circumstances, the VSL may be High
or Severe. The outcome itself is not something that is related to the entity’s
compliance with the standard. The entity may take the same action and comply to
the same degree and by virtue of the outcome alone they are moved from a High to a
Severe VSL.
Consideration of Comments: Project 2007-02 COM-002-4
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52
Organization
Yes or No
Arizona Public Service Co.
Yes
Bonneville Power
Administration
Yes
Luminant
Yes
Idaho Power Company
Yes
Public Utility District No.1 of
Snohomish County
Yes
Wisconsin Electric Power
Company
Yes
Ingleside Cogeneration LP
Yes
Clark Public Utilities
Yes
Virginia State Corporation
Commission, Member OC
Yes
American Transmission
Company, LLC
Yes
Platte River Power Authority
Yes
MISO
Yes
PJM Interconnection
Yes
Consideration of Comments: Project 2007-02 COM-002-4
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Question 3 Comment
53
Organization
Yes or No
Northeast Utilities
Yes
Oncor Electric Delivery
Company LLC
Yes
Tri-State Generation and
Transmission Association Inc.
Yes
The Empire District Electric
Company
Yes
SERC OC Review Group
Question 3 Comment
We believe that the VRFs/VSLs should be modified to better reflect the stated intent
of the NERC Board of Trustees November 19th, 2013 Resolution, which is to enforce
‘zero tolerance’ only for failure to use 3 part communications by the issuer or
recipient of an Operating Instruction when it is issued to alleviate or avoid an
Emergency. VSL for R1: Modify Severe to include any instance where entity either
(1) failed to identify, at the time of issuance, that the Operating Instruction is being
issued to alleviate or avoid an Emergency or (2) failed to request recipient use 3 part
communication when the Operating Instruction was issued to alleviate or avoid an
Emergency Current VSL for R1 language: The responsible entity did not include
Requirement R1, Part 1.2 in its documented communications protocols OR The
responsible entity did not include Requirement R1, Part 1.3 in its documented
communications protocols OR The responsible entity did not develop any
documented communications protocols as required in Requirement R1. Proposed VSL
for R1 language: Moderate - The responsible entity did not require the issuer and
receiver of an oral or written Operating Instruction to use the English language,
unless agreed to otherwise, as required in Requirement R1, Part 1.2. An alternate
language may be used for internal operations. Severe - The responsible entity did not
include Requirement R1, Part 1.1, in its documented communications protocols OR
Requirement R1, Part 1.3 in its documented communications protocols OR The
Consideration of Comments: Project 2007-02 COM-002-4
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Question 3 Comment
responsible entity did not include Requirement R1, Part 1.4 in its documented
communications protocols OR The responsible entity did not develop any
documented communications protocols as required in Requirement R1 OR the
responsible entity either (1) failed to identify, at the time of issuance, that the
Operating Instruction is being issued to alleviate or avoid an Emergency or (2) failed
to request recipient use 3 part communication when the Operating Instruction was
issued to alleviate or avoid an Emergency. VSL for R3: This Group recommends that
the “High VSL for R3” be deleted. The reason for the High VSL deletion is to align with
the concept that the standard should provide that compliance with the standard
should only entail assessing whether an entity has utilized their documented
communications for Operating Instructions that are not issued during an
Emergency.VSL for R2, R5, R6, and R7: If the OPCP SDT modifies the requirements
based on this Group’s recommendation VSL for R2, R5, R6, and R7 can be deleted
except for any sections that are applicable in revised requirements.
Consideration of Comments: Project 2007-02 COM-002-4
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4.
Do you have any additional comments? Please provide them here.
Summary Consideration: The OPCP SDT thanks all parties who took the opportunity to comment on Question 4. The responses to
comments submitted for Question 4 are provided in individual responses below. Many of the same themes carry from Question 1.
Organization
Yes or No
Salt River Project
No
Southern Company;
Southern Company
Services,Inc; Alabama Power
Company; Georgia power
Company; Gulf Power
Company; Mississippi Power
Company; Southern
Company Generation and
Energy Marketing
No
Question 4 Comment
R1.2: Correct the formatting of the third bullet to match the first two so that it is clear
that there are three options permitted not just two with a sub bullet to number two.
R3: Is worded a little confusing. Suggestion would be to add the text below. Each
Distribution Provider and Generator Operator shall conduct initial training for each of
its operating personnel who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator receiving an oral two-party,
person-to-person Operating Instruction that requires them to either: [Violation Risk
Factor: Low][Time Horizon: Long-term Planning] o Repeat, not necessarily verbatim,
the Operating Instruction and receive confirmation from the issuer that the response
was correct, or o Request that the issuer reissue the Operating Instruction.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
R4 - In NERC’s own Q&A document for RAI prepared by the Risk-Based Reliability
Compliance Working Group (RBRCWG), the following statements are made: “An entity
can voluntarily establish internal controls designed to reduce its control risk, which
could have a positive influence on the scoping of compliance monitoring by the
Regional Entity. Conversely, the entity can voluntarily elect to not establish internal
controls or share them with the Regional Entity.” This is inconsistent with the direction
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Organization
Yes or No
Question 4 Comment
of the proposed Standard COM-002-4, R4. This not only requires an internal control,
but also requires that the control be shared with the Regional Entity (during audits).
Also, consider that an entity can develop and implement a robust communication
protocol consistent with COM-002-4 requirements and flawlessly follow its
communication protocol, yet be found in violation of COM-002-4 by failing to
demonstrate that it has adequate (subjective) management (internal) controls in
place. This is inconsistent with the RAI guidance provided by NERC regarding the
voluntary nature of internal controls. So, in principle, internal controls should not be
dictated in a reliability standard. This goes against the principle of “Results-Based”
standards. The intended result is effective communications. This can be attained with
Requirements 1 through 3. No one will argue that internal controls won’t help ensure
that the desired results are achieved. However, Requirement 4 is not absolutely
necessary for the results to be achieved, and therefore, should not be included in the
standard and should be removed.
Response: The OPCP SDT will share this comment with the NERC staff coordinating
the RAI documents. It is not an accurate statement that an entity can be found to
have violated COM-002-4 by failing to demonstrate that it has adequate controls in
place. The entity will be measured based on the language of the requirement, which
requires an assessment, feedback to operating personnel, and corrective actions as
appropriate.
Definition of Operating Instruction: The term “command” in the definition of
Operating Instruction implies authority, and Southern believes it should be made clear
that Operating Instructions (for purposes of this standard) are commands issued by
those functional entities that are expressly granted the responsibility and authority by
the NERC Reliability Standards to take actions or direct the actions of others to ensure
the reliability of the BES. These are the Balancing Authority, Reliability Coordinator
and Transmission Operator only. No other functions are expressly authorized in the
NERC Reliability Standards to issue a command. Our proposed definition Operating
Instruction should be: Operating Instruction - A command originated by a Balancing
Authority, Transmission Operator or Reliability Coordinator responsible for the Real-
Consideration of Comments: Project 2007-02 COM-002-4
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Question 4 Comment
time operation of the interconnected Bulk Electric System to change or preserve the
state, status, output, or input of an Element of the Bulk Electric System or Facility of
the Bulk Electric System. (A discussion of general information and of potential options
or alternatives to resolve Bulk Electric System operating concerns is not a command
and is not considered an Operating Instruction.)
Response: Definitions must be written to provide flexibility to be used in other
Reliability Standards. Therefore, the proper place to note the functional entities is
the requirement text itself. The requirements in the standard provide the bounds
that only Operating Instructions issued by BAs, TOPs, and RCs are applicable to the
standard.
Measures:M4: The inclusion of Emergency here is inappropriate due to the noninclusion of Emergency in R4. Also change the RSAW to reflect this change as well.
Suggested rewording:”Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide evidence of its assessments, including
spreadsheets, logs or other evidence of feedback, findings of effectiveness and any
changes made to its documented communications protocols developed for
Requirement R1 in fulfillment of Requirement R4. The entity shall provide evidence
that it took appropriate corrective actions as part of its assessment for all identified
instances where operating personnel did not adhere to the protocols developed in
Requirement R1”
Response: Requirement R4 is written broadly to cover assessment of Operating
Instructions under all operating conditions. The measure adds some additional
clarity on certain situations that are of particular interest and almost certainly would
call for corrective action. However, the OPCP SDT team revisited the language of M4
and revised the language to better track the requirement language. The drafting
team also addressed this issue in the FAQ document posted on the project page. The
following response was provided: “The purpose of COM-002-4 is ‘To improve
communications for the issuance of Operating Instructions with predefined
communications protocols to reduce the possibility of miscommunication that could
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 4 Comment
lead to action or inaction harmful to the reliability of the Bulk Electric System (BES).’
If the deviation from the protocol contributed to an emergency, the purpose of this
standard was not met. The entity must determine what caused that deviation and
address any necessary corrective actions.”
Definition of Emergency Any abnormal system condition that requires automatic or
immediate manual action to prevent or limit the failure of transmission facilities or
generation supply that could adversely affect the reliability of the Bulk Electric System.
If read literally, EVERY breaker operation on the system IS an EMERGENCY. This causes
a great deal of concern. From a DP and GOP standpoint, the RSAW and technical
justification wording states that an attestation that no emergency had been called
requiring a three part response would suffice for evidence. The rationale and
technical justification document has some very good explanations of the INTENT of the
drafting team and how they want the industry to view the standard requirements. If
the standard and the subsequent audits adhered ONLY to what was in the justification
document, then there should be little or no concerns. Unfortunately, the justification
document carries no statutory weight and the standard as written does.
Response: Since an entity will be required to file a Reportable Event for damage or
destruction of a Facility (damage or destruction of a Facility within its Reliability
Coordinator Area, Balancing Authority Area, or Transmission Operator Area that
results in actions to avoid a BES Emergency), BES Emergency requiring public appeal
for load reduction, BES Emergency requiring system-wide voltage reduction, BES
Emergency requiring manual firm load shedding, and BES Emergency resulting in
automatic firm load shedding per EOP-004-2, entities will be aware of the
Emergency. This does not include every breaker operation.
Arizona Public Service Co.
No
DTE Electric
No
None
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Bonneville Power
Administration
No
Idaho Power Company
No
Virginia State Corporation
Commission, Member OC
No
SERC OC Review Group
Yes
Question 4 Comment
The SERC OC Review Group understands the position that the OPCP SDT is working in
and greatly appreciates the patience and dedication shown in developing this draft
standard. Thank you. The comments expressed herein represent a consensus of the
views of the above named members of the SERC OC Review Group only and should not
be construed as the position of the SERC Reliability Corporation, or its board or its
officers.
Response: The OPCP SDT thanks you for your comments.
North American Generator
Forum - Standards Review
Team (NAGF-SRT)
Yes
1) R1.3 and R3 should also allow the receiver of an Operating Instruction to respond
by explaining that a requested action cannot be performed (e.g., due to safety,
equipment, regulatory, or statutory requirements as described in TOP-001 R3 and IRO001 R8). The requirement to either repeat or request that the instruction be reissued
does not account for the realistic situation that an entity may not be able to perform
an Operating Instruction.
Response: Requirement R1 only describes what should be covered in an entity’s
documented communication protocols. R3 only includes the bullets to identify what
an operator must be trained to do. Therefore, what action an entity may take is not
relevant for these requirements. However, to address the concern, it is important
that the issuer and receiver understand the Operating Instruction prior to
determining whether the action can or cannot be completed. 2) Specific to R.6,
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consideration should be given to revise the verbiage from, “during an Emergency” to
“identified by the sender as constituting an Emergency directive.” The rational for the
recommendation is offered to provide clarity to the Requirement, as it is anticipated
that there will be cases when it is not clear the Operating Instruction is associated with
an Emergency. Additionally, the definition of “Emergency” in the NERC Glossary is
broad and consequently it may be difficult, at times, to determine which inputs are
subject to COM-002-4 requirements, especially if the TO or TOP calls a plant operator
directly rather than going through the respective dispatchers. Note: On the 1/17/14
COM-002-4 OPCP SDT webinar the question was asked, how a DP or GOP would know
that an Operating Instruction occurred during an Emergency. The drafting team stated
that after every Operating Instruction the DP should call its TOP to determine if the
Operating Instruction occurred during and Emergency. The NAGF-SRT once again
reiterates that it would be more efficient and the industry would benefit as a whole, if
the sender of the Operational Instruction, states the instruction is associated with an
Emergency.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “Separately listing out
Requirements R5, R6, and R7 and using ‘Operating Instruction during an Emergency’
in them does not require a different set of protocols to be used during Emergencies
or mandate the identification of a communication as an ‘Operating Instruction
during an Emergency.’ The same protocols are required to be used in connection
with the issuance of Operating Instructions for all operating conditions. Their use is
measured for compliance/enforcement differently using the operating condition as
an indicator of which compliance/enforcement approach applies. In other words, it
is not the drafting team’s expectation that the operator must differentiate between
Emergency and non-Emergency Operating Instructions.” In order to draft
appropriate VSLs, separate requirements were needed for the different operating
conditions. The protocols are the same for all operating conditions. The OPCP SDT
did not intend the phrase “during an Emergency” to carry an obligation to identify
the communication as one that constitutes an Emergency directive.
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Question 4 Comment
Please see the response to Question 1, which addresses the concern regarding the
identification of an Emergency.
3) Specific to Measures M5 and M6, which contain language associated with the issuer
and the recipient both maintaining evidence of two-party communication respectively.
It is recommended that M5 be revised such that the all associated evidence is
maintained by the issuer and M6 be deleted in its entirety. Consolidating the evidence
requirements would benefit the industry by reducing duplication of efforts, associated
with maintaining evidence by different entities, in support of the same requirement.
Response: Each entity must provide its evidence of compliance. No entity can be
required to provide evidence for another entity’s compliance.
Northeast Power
Coordinating Council
Yes
Regarding Part 1.4, it must be considered that some ISOs issue multiple-party burst
Operating Instruction to Generator Operators through electronic means.
Response: Requirement R1, Part 1.4 only applies to written or oral single-party to
multiple-party burst Operating Instructions. An electronic signal is not covered in
this standard. If the electronic communication is written, the entity must put in
place the ability to ensure that the Operating Instruction was received by at least
one receiver of the Operating Instruction.
Regarding Part 1.6, the requirement is vague and needs to be clarified for Registered
Entities to know how to comply. How would one “specify the nomenclature” system
wide?
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “COM-002-4, while
reintroducing the concept of line identifiers, limits the scope to only Transmission
interface Elements or Transmission interface Facilities (e.g. tie lines and tie
Consideration of Comments: Project 2007-02 COM-002-4
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Question 4 Comment
substations) for Operating Instructions. This supports both parties being familiar
with each other’s interface Elements and Facilities, minimizing hesitation and
confusion when referring to equipment for the Operating Instruction.” The
nomenclature is not specified “system-wide.”
Regarding Requirements R2 and R3, those “training” requirements aren’t necessary.
Responsible Entities must adhere to the Requirements of NERC Standards and how
they accomplish this should not be dictated by a standard’s requirement. Under RAI
principles, NERC and Regions can determine what type of monitoring is appropriate for
Responsible Entities’ compliance with the new COM Standard based on the quality of
their Training programs. This would further support reliability by changing the
requirement from a one-time audit (i.e., initial training) to an ongoing assessment. The
proposed standard still contains requirements that mandate the use of, and training to
include 3 part communications during issuance of all Operating Instructions, including
those issued during non-Emergency situations. As stated in the Rationale and
Technical Justification document the proposed Measures and RSAW don’t specifically
require that auditors verify compliance of this for the Requirements (and associated
Measures), however a strict read leads us to a different conclusion. Under the RSAW
for R1 it states that the entity shall provide its documented communications protocols
developed for this requirement and the auditor shall review the documented
communications protocols provided by the entity and ensure they address the Parts of
R1 (including the use of 3 part communications). The RSAW contains similar actions
relative to Requirements R2 and R3 in that the entity is to provide evidence consisting
of agendas, learning objectives, or course materials that it provides pursuant to these
requirements. Given this, an auditor can enforce to a ‘zero defect tolerance’ if the
auditor chooses to do so, and in fact would argue that an audit would be deficient if it
failed to validate whether the learning objective included ensuring that 3 part
communication was used during issuance or receipt of each Operating Instruction.
Suggest that the training requirements contained with R2 and R3 be removed and
placed within the PER-005 Operations Personnel Training standard. PER-005 should be
the home of all system operator related training requirements.
Consideration of Comments: Project 2007-02 COM-002-4
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Yes or No
Question 4 Comment
Response: Please refer to the summary response in Question 1 above.
There are no clear and concise differences between Requirements R1, R5 and R6. This
creates uncertainty as to whether the Operating Instruction is being issued to alleviate
or avoid an Emergency. Absent a Requirement that the issuer make a definitive
statement as to whether an Operating Instruction is being issued to alleviate or avoid
an Emergency, neither the recipient (during) nor an auditor (after) would be able to
make such determination. Suggest revising Requirement R1 so that it applies to all
Operating Instructions, but requires that those being issued to alleviate or avoid an
Emergency be specifically identified as such and that the issuer explicitly request that
the recipient confirm their understanding through use of 3 part communication.
Remove Requirements R5, R6 and R7 (incorporating items deemed necessary by the
OPCP SDT as bullets or Parts of R1).Suggested rewording for Part 1.1:1.1. Require that
its operating personnel identify, at the time of issuance, that the Operating Instruction
is being issued to alleviate or avoid an Emergency. o Request recipient use 3 part
communication when the Operating Instruction is being issued to alleviate or avoid an
Emergency.Revise M1, VRF/VSLs and RSAW so that strict compliance with use of 3 part
communication is only applied when an Operating Instruction is issued to alleviate or
avoid an Emergency as identified by the issuer at the time of issuance. Suggested
revisions to M1:M1. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator shall provide its documented communications protocols
developed for Requirement R1. For each Operating Instruction issued to alleviate or
avoid an Emergency; entity shall provide evidence that it identified such at time
Operating instruction was issued (R1.1) and requested recipient use of 3 part
communication (R1.2). VSL for R1 - modify Severe to include any instance where entity
either (1) failed to identify, at the time of issuance, that the Operating Instruction is
being issued to alleviate or avoid an Emergency or (2) failed to request recipient use 3
part communication when the Operating Instruction was issued to alleviate or avoid
an Emergency
Response: The OPCP SDT has not modified Measure M1 as suggested above because
the entity’s performance is limited to the development of the protocols. The OPCP
Consideration of Comments: Project 2007-02 COM-002-4
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Question 4 Comment
SDT addressed this issue in the FAQ document posted on the project page. The
following response was provided: “Separately listing out Requirements R5, R6, and
R7 and using ‘Operating Instruction during an Emergency’ in them does not require a
different set of protocols to be used during Emergencies or mandate the
identification of a communication as an ‘Operating Instruction during an Emergency.’
The same protocols are required to be used in connection with the issuance of
Operating Instructions for all operating conditions. Their use is measured for
compliance/enforcement differently using the operating condition as an indicator of
which compliance/enforcement approach applies. In other words, it is not the
drafting team’s expectation that the operator must differentiate between
Emergency and non-Emergency Operating Instructions.”
Measure M4 requires compliance demonstration beyond Requirement R4.
Specifically, entities must provide evidence that appropriate corrective action was
taken for all instances where an operating personnel’s non-adherence to the protocols
developed in Requirement R1 is the sole or partial cause of an Emergency.
Response: The OPCP SDT has adjusted the language of Measure M4 to better align
with the language in Requirement R4.
The format of the standard should be changed to conform to the current NERC
direction-the measures get listed with the associated requirement, and the rationale
get included in the standard, not a separate document.
NERC Standards Review
Forum
Yes
1. Per section one of this document, the OPCP SDT states: The Project 2007-02 OPCP
SDT removed the term “Reliability Directive” in order to avoid complications that
may result from the Notice of Proposed Rulemaking issued by the Federal Energy
Regulatory Commission on November 21, 2013 proposing to remand the definition
of “Reliability Directive.” But within the latest Implementation Plan, there still is
the prerequisite of approving the term “Reliability Directive”. Please update
whichever documentation that should be corrected in order to provide the
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 4 Comment
industry with accurate information so that we can determine if this Standard
supports the reliability of the BES.
Response: The OPCP SDT thanks you for your comment. However the clean version
of the Implementation Plan does not contain the words “Reliability Directive.” The
words do appear in the redline to the last posted version in strikethrough.
Colorado Springs Utilities
Yes
Comments: 1. R1.4. - [Documented communications protocols for its operating
personnel that issue and receive Operating Instructions shall, at a minimum] Require
its operating personnel that issue a written or oral single-party to multiple-party burst
Operating Instruction to confirm or verify that the Operating Instruction was received
by at least one receiver of the Operating Instruction. o Some ISO’s issues multipleparty burst Operating Instruction to Generator Operators through electronic means.
Associated real-time requirement: R7. Each Balancing Authority, Reliability
Coordinator, and Transmission Operator that issues a written or oral single-party to
multiple-party burst Operating Instruction during an Emergency shall confirm or verify
that the Operating Instruction was received by at least one receiver of the Operating
Instruction. Comment: The SRC does not believe this requirement is necessary for
reliability. Moreover, the Standard Drafting Team has not provided any , nor have we
been made aware of the substantiated rationale for keeping this Requirement except
that the OPCP SDT believes is it necessary.
Response: The OPCP SDT asserts that it is important that the issuer of a written or
oral single-party to multiple-party burst Operating Instruction makes sure that the
communication channel was complete. This can be accomplished by confirming with
at least one party that the communication was received.
2. R1.6. - [Documented communications protocols for its operating personnel that
issue and receive Operating Instructions shall, at a minimum] Specify the
nomenclature for Transmission interface Elements and Transmission interface
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Question 4 Comment
Facilities when issuing an oral or written Operating Instruction. Comment: This
requirement is vague and needs to be clarified for Registered Entities to know how to
comply with it; how would one “specify nomenclature” system-wide? Comment: This
requirement was dropped from TOP-002-2a, requirement 18. Communication on
transmission equipment must be equipment specific. Nomenclature should not be
used, rather entities should always be correctly communicating using the unique and
specific equipment identifiers. Adding nomenclature will reduce not improve
reliability.
Response: Please see the summary response to Question 1.
3. R2. and R3. - ...”shall conduct initial training for each of its operating personnel
...”Comment: The SRC does not believe a training Requirement is necessary;
Responsible Entities must adhere to the Requirements of NERC Standards and how
they accomplish this should not be dictated by a Standard Requirement. Under RAI
principles, NERC and Regions can determine what type of monitoring is appropriate of
Responsible Entities’ compliance with the new COM Standard based on the quality of
their Training programs. This would further support reliability by changing the
requirement from a one-time audit (i.e., initial training) to an ongoing assessment.
Response: Please see the summary response to Question 1.
Florida Municipal Power
Agency
Yes
FMPA is voting “affirmative” on this standard, yet we have concerns with the RSAW
language and lack of criteria on how an entity will be assessed and audited. There is
language in the RSAW “Notes to Auditor” for multiple requirements (R4-R7) that is of
concern. (See example below) The RSAW language is not clear regarding the nature
and extent of audit procedures that will be applied because there is reference to
scoping the audit based on “certain risk factors to the Bulk Electric System”. It is not
clear what “risk factors” will be used. As an example in R5 auditing “can range from
exclusion of a requirement from audit scope to the auditor reviewing, in accordance
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Organization
Yes or No
Question 4 Comment
with the above Compliance Assessment Approach, evidence associated with the
entity’s responses to numerous Operating Instructions issued during Emergencies.”
This is essentially a zero tolerance approach, yet, also appears to be an attempt to
apply Reliability Assurance Initiative (RAI) concepts, that have not been finalized and
communicated to the industry. It is uncertain whether these concepts have been fully
developed yet; and therefore, this leaves too much auditor discretion, without
providing the industry information or criteria on how “risk” will be assessed.
Stakeholders continue to await the details of these RAI concepts that are being utilized
in RSAWS. Clarity is needed around how an entity’s risk to the BES will be assessed due
to compliance or non-compliance with this standard. This would also beneficial for an
entity to know, so that they can lessen that risk, as appropriate. Example language
from RSAW: “The extent of audit procedures applied related to this requirement will
vary depending on certain risk factors to the Bulk Electric System. In general, more
extensive audit procedures will be applied where risks to the Bulk Electric System are
determined by the auditor to be higher for non-compliance with this requirement.
Based on the auditor’s assessment of risk, as described above, specific audit
procedures applied for this requirement may range from exclusion of this requirement
from audit scope to the auditor reviewing, in accordance with the above Compliance
Assessment Approach, evidence associated with the entity’s responses to numerous
Operating Instructions issued during Emergencies. “
Response: The OPCP SDT thanks you for your comments. We will convey the RSAW
comments to the RSAW drafting team. For more information about the NERC RAI
program, please refer to the February 5, 2014 agenda for the Board of Trustees
Compliance Committee. An update on RAI was provided. In addition, information
about RAI may be found here: http://www.nerc.com/pa/comp/Pages/ReliabilityAssurance-Initiative.aspx.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
PPL NERC Registered
Affiliates
Yes or No
Question 4 Comment
Yes
These comments are submitted on behalf of the following PPL NERC Registered
Affiliates: Louisville Gas and Electric Company and Kentucky Utilities Company; PPL
EnergyPlus, LLC; PPL Electric Utilities Corporation; and PPL Generation, LLC, on behalf
of its NERC registered entities. The PPL NERC Registered Affiliates are registered in six
regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following
NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.
Each of the PPL NERC Registered Affiliates recognize the need for and support the use
of three part communications for Operating Instructions. However, we are abstaining
from voting on this standard because we believe that the current version of COM-0024 requires change to ensure consistency with the OPCP SDT’s intent. If these
clarifications are made, the PPL NERC Registered Affiliates would support the
proposed standard.
First, the PPL NERC Registered Affiliates request that the OPCP SDT revise Measure
M.4 to specifically state that sampling is allowed in performing the assessments
required by Requirements R.4.1 and R.4.2. This is consistent with the OPCP SDT’s oral
statements during the January 17, 2014 webinar and the FAQ (“An entity could
perform an assessment by listening to random samplings of each of their operating
personnel issuing and/or receiving Operating Instructions....”). Additionally, for
consistency and to avoid ambiguity, the OPCP SDT should also conform the wording in
Measure M.4 to Measures M.5-M.7 (i.e., “Such evidence may include, but is not
limited to,...”). Therefore, we recommend that the OPCP SDT revise Measure M.4 as
follows: M4. Each Balancing Authority, Reliability Coordinator, and Transmission
Operator shall provide evidence of its assessments. Such evidence may include, but is
not limited to, sampling results, spreadsheets, logs or other evidence of feedback,
findings of effectiveness and any changes made to its documented communications
protocols developed for Requirement R1 in fulfillment of Requirement R4....
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “An entity could perform an
assessment by listening to random samplings of each of their operating personnel
Consideration of Comments: Project 2007-02 COM-002-4
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Question 4 Comment
issuing and/or receiving Operating Instructions. If there were instances where an
Operator deviated from the entity’s protocols, the entity would provide feedback to
the operator in question in any method it sees as appropriate. An example would be
counseling or retraining the operator on the protocols.
An entity could assess the effectiveness of its protocols by reviewing instances
where operators deviated from those protocols and determining if whether the
deviations were caused by operator error or by flaws in the protocols that need to
be changed.” The OPCP SDT asserts that this, in conjunction with the RSAW,
provides sufficient clarity.
Second, the PPL NERC Registered Affiliates request that the OPCP SDT clarify in the
proposed standard that only a failure to use three-part communications during an
Emergency is a violation of COM-002-4. Therefore, we recommend that the standard’s
requirements be further revised to indicate that if an entity does not adhere to its
documented communications protocols developed in accordance with Requirement
R.1 during a non-Emergency, such action shall not be considered a noncompliance
event under Requirement R.1.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The standard uses the phrase
‘Operating Instruction during an Emergency’ in certain Requirements (R5, R6, and
R7) to provide a demarcation for what is subject to a ‘zero tolerance’
compliance/enforcement approach and what is not. This is necessary to allow the
creation of Violation Severity Levels for each compliance/enforcement approach.
Where ‘Operating Instruction during an Emergency’ is not used, an entity will be
assessed under a compliance/enforcement approach that focuses on whether or not
an entity met the initial training Requirement (either R2 or R3) and whether or not
an entity performed the assessment and took corrective action according to
Requirement R4. The proposed COM-002-4 does not contain a Requirement to
adhere to all documented communications protocols during non-Emergency
conditions. Under COM-002-4, the assessment and training documentation will
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provide auditors assurance that responsible entities are using their documented
communications protocols and taking corrective actions as necessary.”
Duke Energy
Yes
(1)Duke Energy suggests rewording R1.6 as follows: ”Specify the nomenclature to be
used for Transmission interface Elements and Transmission interface Facilities when
issuing an oral or written Operating Instruction to neighboring entities.” While the
Technical Justification document suggests that R1.6 applies to communication with
neighboring entities, it is unclear that this requirement, as worded in the current draft
of COM-002-4, is specifically discussing communication with neighboring entities.
Response: The OPCP SDT asserts that the existing language provides sufficient
clarity.
(2)M2 should include “initial training” and be reworded as follows in order to maintain
consistency with the requirement:”Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall provide initial training records related to its
documented communications protocols developed for Requirement R1 such as
attendance logs, agendas, learning objectives, or course materials in fulfillment of
Requirement R2.”
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Measure M2.
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SPP Standards Review Group
Yes or No
Question 4 Comment
Yes
The removal of Reliability Directive from the definition of Operating Instruction has
removed clarity from a compliance viewpoint. Without this clarity, which could also be
provided by requiring a statement which identifies the Emergency situation as an
Emergency, the operator does not know that he is in an Emergency situation. Although
the operator’s response may be the same as it is in a non-emergency, the compliance
hook of zero tolerance is there. We need a mechanism in place that we can use to
identify when we are in an Emergency situation which prevents Monday-morning
quarterbacking during an audit regarding whether an Emergency actually occurred or
not. Reliability Directive gave us that indication. We recommend requiring an
Operating Instruction that is issued during an Emergency situation be identified as
‘This is an Emergency.’
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “Separately listing out
Requirements R5, R6, and R7 and using ‘Operating Instruction during an Emergency’
in them does not require a different set of protocols to be used during Emergencies
or mandate the identification of a communication as an ‘Operating Instruction
during an Emergency.’ The same protocols are required to be used in connection
with the issuance of Operating Instructions for all operating conditions. Their use is
measured for compliance/enforcement differently using the operating condition as
an indicator of which compliance/enforcement approach applies. In other words, it
is not the drafting team’s expectation that the operator must differentiate between
Emergency and non-Emergency Operating Instructions.”
Additionally, since an entity will be required to file a Reportable Event for damage or
destruction of a Facility (damage or destruction of a Facility within its Reliability
Coordinator Area, Balancing Authority Area, or Transmission Operator Area that
results in actions to avoid a BES Emergency), BES Emergency requiring public appeal
for load reduction, BES Emergency requiring system-wide voltage reduction, BES
Emergency requiring manual firm load shedding, and BES Emergency resulting in
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automatic firm load shedding per EOP-004-2, entities will be aware of the
Emergency.
Recommendation 26 calls for work to be done to improve the effectiveness of
communications in emergency situations. The purpose of the standard is to improve
communications. However, the focus of the standard is primarily 3-part
communications. There is no supporting documentation or data to support the
position that 3-part communications improves the effectiveness of communications.
Focusing on 3-part communications provides an easy target from a compliance
perspective but all it teaches us is to mechanically repeat back what we have been
instructed to do. We’re focusing on the ‘how’ and ‘what’ rather than the ‘why’.
Keeping the ‘why’ in mind improves communications and the reliability of the BES.
Keeping the ‘why’ in mind also leads to improved situational awareness. Improving
effective communications is difficult to quantify in a standard and even more difficult
to measure. We may be better off focusing on the principles contained in the OC’s
Reliability Guideline System Operator Verbal Communications - Current Industry
Practices.
Response: The OPCP SDT thanks you for your comment.
We suggest that R2 and R3 are already provided for in PER-005 and therefore are
redundant in this standard. If there is a need to include a training requirement in this
standard, that requirement could consist of a statement to include protocol training in
the entity’s reliability task list.
Response: Please see the summary response for Question 1.
Measure 4 adds an additional requirement regarding the failure to follow protocols
which in turn leads to an Emergency. The Measure basically requires the responsible
entity to assess those particular situations even though they are not specifically called
out in the requirement. We recommend adding the following sentence at the end of
R4.1: ‘Such assessment shall include, at a minimum, any instance that is an
Emergency.’
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Response: The OPCP SDT considered the suggested edits. The OPCP SDT chose to
revise Measure M4 to better align with the language in Requirement R4.
We recommend that the drafting team consider moving R4 back to language similar to
that contained in R5 of Posting 7. This language is much clearer and eliminates
Paragraph 81 concerns of administrative burden associated with the required 12month assessments and removes the ambiguity of ‘corrective actions’ and ‘as
appropriate’.
In the last line of the Evidence Requested table in the R2 section of the RSAW, the
following evidence is requested: ‘Organization chart or similar artifact identifying the
operating personnel responsible for the Real-time operation of the interconnected
Bulk Electric System and the date such personnel began operating the Real-time Bulk
Electric System.’ This implies that an entity will be found non-compliant if operating
personnel operate the Real-time BES prior to receiving training on issuing Operating
Instructions. This is not what is stated in the requirement. This entry should be
reworded to the following: ‘Organization chart or similar artifact identifying the
operating personnel responsible for the Real-time operation of the interconnected
Bulk Electric System and the date such personnel began issuing Operating
Instructions.’ Similarly, this change needs to be made in the Compliance Assessment
Approach Specific to COM-002-4, R2 table. That entry should read: ‘Verify applicable
operating personnel, or a sample thereof, received the required training prior to the
date they began issuing Operating Instructions by agreeing selected personnel names
to training records.’
Response: The OPCP SDT has provided your comments to the RSAW team.
Bureau of Reclamation
Yes
Reclamation requests that R5 include a bullet requiring the issuer of an Operating
Instruction during an Emergency to identify the situation as an Emergency. This is
important because R6 requires recipients of Operating Instructions to repeat the
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Question 4 Comment
instructions during Emergencies, but it may not be clear to the recipient that an
Emergency is occurring.
Response: Please see the summary response for Question 1.
Reclamation reiterates that R1.3 and R3 should also allow the receiver of an Operating
Instruction to respond by explaining that a requested action cannot be performed
(e.g., due to safety, equipment, regulatory, or statutory requirements as described in
TOP-001 R3 and IRO-001 R8). The requirement to either repeat or request that the
instruction be reissued does not account for the realistic situation that an entity may
not be able to perform an Operating Instruction. The drafting team could choose to
address this point with a footnote explaining that the requirement to repeat the
instruction does not obligate the recipient to perform the action if he repeats the
instruction, but then explains that he cannot perform the action because doing so
would violate safety, equipment, regulatory, or statutory requirements.
Response: Requirement R1 only describes what should be covered in an entity’s
documented communication protocols. Requirement R3 only includes the bullets to
identify what an operator must be trained to do. Therefore, what action an entity
may take is not relevant for these requirements—actions are addressed by other
standards (e.g. IRO-001 and TOP-001). However, to address the concern, it is
important that the issuer and receiver understand the Operating Instruction prior to
determining whether the action can or cannot be completed.
Dominion
Yes
The proposed standard still contains requirements that mandate the use of, and
training to include, 3 part communications during issuance of all Operating
Instructions, including those issued during non-Emergency situations. While Dominion
agrees that the OPCP SDT has stated in its Rationale and Technical Justification
document that the proposed measures and RSAW don’t specifically require that
auditors verify compliance of this for the requirements (and associated measures), a
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strict read leads us to a different conclusion. Under the RSAW for R1 it states that the
entity shall provide its documented communications protocols developed for this
requirement and the auditor shall review the documented communications protocols
provided by entity and ensure they address the Parts of R1 (including the use of 3 part
communications). The RSAW contains similar actions relative to R2 and R3 in that the
entity is to provide evidence consisting of agendas, learning objectives, or course
materials that it provides pursuant to these requirements. Given this, Dominion
believes an auditor can enforce to a ‘zero defect tolerance’ if it chooses to do so and in
fact would argue that an audit would be deficient if it failed to validate whether the
learning objective included insuring that 3 part communication was used during
issuance or receipt of each Operating Instruction.
Response: The OPCP SDT disagrees. Requirement R1 is limited to what protocols
must be included in the documented protocols of an entity. Requirements R2 and
R3 require training. Requirement R4 requires an assessment of the use of the
protocols.
Dominion also finds there are not clear and concise differences between requirements
1, 5 and 6 resulting in uncertainty as to whether the Operating Instruction is being
issued to alleviate or avoid an Emergency. Dominion is concerned that, absent a
requirement that the issuer make a definitive statement as to whether an Operating
Instruction is being issued to alleviate or avoid an Emergency, neither the recipient
(during) nor an auditor (after) would be able to make such determination. Having said
this, we could support the standard if it were revised in a fashion similar to that
described below. 1. Modify requirement 1 so that it applies to all Operating
Instructions but requires that those being issued to alleviate or avoid an Emergency be
specifically identified as such and that the issuer explicitly request recipient confirm
their understanding through use of 3 part communication.
Response: The OPCP SDT reiterates that Requirement R1 only concerns what
protocols must be included in the documented protocols. The drafting team
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believes that there is sufficient clarity among Requirements R1, R5, and R6 on the
performance required.
2. Remove requirements 5, 6 & 7 (incorporating specific items deemed necessary by
the OPCP SDT as bullets or sub-requirements of R1).
Response: Please refer to prior response.
3. Revise measures, VRFs/VSLs and RSAW so that strict compliance with use of 3 part
communication is only applied when an Operating Instruction is issued to alleviate or
avoid an Emergency as identified by the issuer at the time of issuance.
Response: Please refer to prior response.
4. Measure M4 requires compliance demonstration beyond Requirement R4.
Specifically, entities must provide evidence that appropriate corrective action was
taken for all instances where an operating personnel’s non-adherence to the protocols
developed in Requirement R1 is the sole or partial cause of an Emergency...,
Response: The OPCP SDT has modified the language in Measure M4 to better align
with the language in Requirement R4.
Examples of suggested changesR1. Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall develop documented communications protocols for
its operating personnel that issue and receive Operating Instructions. The protocols
shall, at a minimum: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]1.1. Require that its operating personnel identify, at the time of issuance,
when the Operating Instruction is being issued to alleviate or avoid an Emergency 1.2.
Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions: o Confirm the receiver’s
response if the repeated information is correct. o Reissue the Operating Instruction if
the repeated information is incorrect or if requested by the receiver. o Take an
alternative action if a response is not received or if the Operating Instruction was not
understood by the receiver. o Request recipient use 3 part communication when the
Operating Instruction is being issued to alleviate or avoid an Emergency 1.3 Require its
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Question 4 Comment
operating personnel that issue and receive an oral or written Operating Instruction to
use the English language, unless agreed to otherwise. An alternate language may be
used for internal operations.1.4. Require its operating personnel that issue a written
or oral single-party to multiple-party burst Operating Instruction to confirm or verify
that the Operating Instruction was received by at least one receiver of the Operating
Instruction.1.5. Specify the instances that require time identification when issuing an
oral or written Operating Instruction and the format for that time identification.1.6.
Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.M1. Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall provide
its documented communications protocols developed for Requirement R1. For each
Operating Instruction issued to alleviate or avoid an Emergency; entity shall provide
evidence that it identified such at time Operating instruction was issued (R1.1) and
requested recipient use of 3 part communication (R1.2). o VSL for R1 - modify Severe
to include any instance where entity either (1) failed to identify, at the time of
issuance, that the Operating Instruction is being issued to alleviate or avoid an
Emergency or (2) failed to request recipient use 3 part communication when the
Operating Instruction was issued to alleviate or avoid an Emergency
ACES Standards
Collaborators
Yes
(1) We disagree with training requirements as they are redundant with PER-005.
Similar to a FERC directive, the drafting team should be able to provide the BOT with
technical justification that other alternatives exist to developing a new requirement
such as pointing to an existing requirement. Training is already included in the PER
requirements. The drafting team should provide the feedback from industry and show
that there is an already existing enforceable standard that covers this issue of training
and there are no gaps in reliability.
Response: Please see the summary response to Question 1.
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(2) We do not think the Distribution Provider should be an applicable function. Most
Distribution Providers simply do not have a materially impact on BES reliability. We
suggest an alternative to have the standard apply to those DP that may impact the
BES. According to the FERC-approved CIP version 5 standards, a Distribution Provider
is subject to the standards if the DP has UFLS/UVLS systems that have the capability of
shedding 300 MW or more of load. We ask the drafting team to consider revising the
applicability section to mirror the CIP standards. There was technical justification
provided during the development of those standards, NERC and FERC both approved
those standards, and therefore, a precedent exists for this reasonable approach to
focusing on entities that pose an impact, however minimal, to the BES.
Response: Please see the summary response to Question 1.
(3) Many DPs have no practical way to demonstrate compliance with “repeat backs.”
Many DPs do not have recording systems for the telephonic communications. This
puts the DP in a position to request the voice recordings or attestations from the
issuer. The issuer is not obligated to provide the data and, in fact, history has shown
that many registered entities will not provide this type of data to a third party for fear
of compliance issues being identified with the issuer. Thus, from a practical
perspective the standard puts the DP in the position of having to use weak evidence to
demonstrate compliance. This is an unreasonable burden on the DP.
(4) We recommend that the drafting team remove references to “taking alternative
actions.” This is ambiguous and could potentially tie in actions that should be taken in
accordance to directives in IRO-001 and TOP-001. COM-002 is related only to
communications, so taking alternative actions must be limited to alternative
communications.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “If an operator issues an Operating
Instruction during an Emergency and, based on the response from the receiver, or lack
thereof, chooses to take an alternative action, that operator has satisfied Requirement
R5 and is not in violation.
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The following scenario is provided as an example of an alternative action:
A Transmission Operator (TOP) calls a Generator Operator (GOP) to reduce generation
due to an Emergency. The GOP does not respond verbally. At that point the TOP could:
• Ask if the GOP understood the Operating Instruction (alternative action).
• Hang up and redial the GOP, assuming that the communication line was dead
(alternative action),
• Request a different generator that is effective to reduce (alternative action); or
• Call a different contact at the GOP (alternative action).”
(5) We suggest that the “assess adherence and assess effectiveness” language in R4 be
removed from COM-002-4. This language is similar to the “Identify, Assess and
Correct (IAC)” language that was included in the CIP V5 standards. The removal or
modification of this language was included in the Final Rule on NERC CIP V5 Standards
(Order No. 791). FERC stated that IAC language and concepts would be best addressed
in the NERC compliance processes, such as through the NERC Reliability Assurance
Initiative (RAI), rather than standards requirements.
Response: Please see the summary response to Question 1.
(6) Thank you for the opportunity to comment.
ISO/RTO Council Standards
Review Committee
Yes
1. R1.4. - [Documented communications protocols for its operating personnel that
issue and receive Operating Instructions shall, at a minimum] Require its operating
personnel that issue a written or oral single-party to multiple-party burst Operating
Instruction to confirm or verify that the Operating Instruction was received by at least
one receiver of the Operating Instruction. o Some ISO’s issues multiple-party burst
Operating Instruction to Generator Operators through electronic means Associated
real-time requirement: R7. Each Balancing Authority, Reliability Coordinator, and
Transmission Operator that issues a written or oral single-party to multiple-party burst
Operating Instruction during an Emergency shall confirm or verify that the Operating
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Instruction was received by at least one receiver of the Operating Instruction. NOTE ERCOT does not support the following Comment: The SRC members (excluding ERCOT)
do not believe this requirement is necessary for reliability. Moreover, the Standard
Drafting Team has not provided any, nor have we been made aware of the
substantiated rationale for keeping this Requirement except that the OPCP SDT
believes is it necessary.
Response: The OPCP SDT asserts that it is important that the issuer of a written or
oral single-party to multiple-party burst Operating Instruction makes sure that the
communication channel was complete. This can be accomplished by confirming with
at least one party that the communication was received.
2. R1.6. - [Documented communications protocols for its operating personnel that
issue and receive Operating Instructions shall, at a minimum] Specify the
nomenclature for Transmission interface Elements and Transmission interface
Facilities when issuing an oral or written Operating Instruction.Comment: This
Requirement is vague and needs to be clarified for Registered Entities to know how to
comply with it; how would one “specify nomenclature” system-wide? Even though
the posted “Rationale and Technical Justification” (RTJ) document notes that R1.6 is
limited in scope to only Transmission interface Elements or Transmission interface
Facilities (e.g. tie lines and tie substations), this RTJ document should define these
terms and substantiate to what registered entities this needs to apply. For example, if
the intent is to apply this requirement to Inter-Area tie-lines, then it should probably
be limited to Reliability Coordinator-to-Reliability Coordinator communications. If the
intent is to apply this requirement to every type of transmission - say generation
interconnection facilities - it should be clear so that Registered Entities can clearly
understand the burdens associated with this new Requirement.
Response: Please see the summary response to Question 1.
3. R2. and R3. - ...”shall conduct initial training for each of its operating personnel
...”Note - ERCOT and IESO do not support the following Comment: The SRC members,
(excluding ERCOT and IESO) do not believe a training Requirement is necessary;
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Responsible Entities must adhere to the Requirements of NERC Standards and how
they accomplish this should not be dictated by a Standard Requirement. Additionally,
to the extent that the OPCP SDT concludes that training on 3-part communication is
necessary to ensure an adequate level of reliability, then any training requirements
should this would already be covered under the PER Standard, which requiresing
training on job tasks. To the extent training requirements should be imposed on
GOP/DP personnel, the PER Standard could be slightly modified to include them.
Overall, if NERC is going to add additional training requirements, they should be
located in PER to avoid complexity in the organization of NERC Standards. Finally,
under RAI principles, NERC and Regions can determine what type of monitoring is
appropriate of Responsible Entities’ compliance with the new COM Standard based on
the quality of their Training programs. This would further support reliability by
changing the requirement from a one-time audit (i.e., initial training) to an ongoing
assessment. In conclusion, even though the BOT resolved that there should be training
associated with the COM requirements, it would be beneficial to address the BOT’s
concern through existing Standards (PER). Basic principles of drafting regulation
should strive to avoid making the organization and relationship among NERC
Standards more complex than need to be.
Response: Please see the summary response to Question 1.
4. Measurement 6. Meaurement 6 needs to be revised so that it is consistent with
NERC Enforcement policies. Specifically, the last sentence needs to be rewritten so
that “Such evidence may include, but is not limited to, dated and time-stamped voice
recordings[,] dated operator logs, an attestation from the issuer of the Operating
Instruction, voice recordings (if the entity has such recordings), memos and
transcripts.” NERC has repeatedly affirmed that a Registered Entity may provide an
attestation that it has complied with a Standard. See NERC Compliance Process
Bulletin#2011-001 (“Data Retention Requirements”) (May 20, 2011), at p 3 (in the
context of explaining that the CMEP requires a registered entity to demonstrate that it
was compliant through the entire audit period, NERC stated that some examples of
evidence may include “An attestation of any employee who has participated in the
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activity on a regular basis throughout the audit period, supported by other
corroborating evidence (such as schedules, emails and other applicable
documentation). Recipients of oral Operating Instructions during an Emergency have
ample means of maintaining records, providing corroborating material, etc...
demonstrating that they adhered to the emergency Operating Instruction. To
establish an expectation that other Registered Entities may be maintaining audit
evidence for the Registered Entity to which the Requirement applies is inconsistent
with NERC’s enforcement rules and establishes a flawed practice and expectation with
regard to recordkeeping requirements and “audit trails.”
Response: The list of examples of evidence is not exhaustive. The measure simply
provides examples.
Luminant
Yes
1). R1.3 and R3 should also allow the receiver of an Operating Instruction to respond
by explaining that a requested action cannot be performed (e.g., due to safety,
equipment, regulatory, or statutory requirements as described in TOP-001 R3 and IRO001 R8). The requirement to either repeat or request that the instruction be reissued
does not account for the realistic situation that an entity may not be able to perform
an Operating Instruction.
Response: Please see the summary response to Question 1.
2). Specific to R.6, consideration should be given to revise the verbiage from, “during
an Emergency” to “identified by the sender as constituting an Emergency directive.”
The rational for the recommendation is offered to provide clarity to the Requirement,
as it is anticipated that there will be cases when it is not clear the Operating
Instruction is associated with an Emergency. Additionally, the definition of
“Emergency” in the NERC Glossary is broad and consequently it may be difficult, at
times, to determine which inputs are subject to COM-002-4 requirements, especially if
the TO or TOP calls a plant operator directly rather than going through the respective
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dispatchers.Note: On the 1/17/14 COM-002-4 OPCP SDT webinar the question was
asked, how a DP or GOP would know that an Operating Instruction occurred during an
Emergency. The drafting team stated that after every Operating Instruction the DP
should call its TOP to determine if the Operating Instruction occurred during and
Emergency. Luminant once again reiterates that it would be more efficient and the
industry would benefit as a whole, if the sender of the Operational Instruction, states
the instruction is associated with an Emergency.
Response: Please see the summary response to Question 1.
As a clarifier, the OPCP SDT provided the response during the webinar that, if a
receiver was unsure whether there was an Emergency or not, the receiver could ask
the issuer for clarification.
Public Utility District No.1 of
Snohomish County
Yes
While the Public Utility District No.1 of Snohomish County supports this draft of COM002-4, we see an issue with R2 and R3 of this standard. These requirements both deal
with entities conducting training for its personnel, and feel it would be more
appropriate if they were addressed in the PER family of standards.The Public Utility
District No.1 of Snohomish County also supports the comments submitted by the SERC
OC Review Group.Thank you very much.
Response: Please see the summary response to Question 1.
The United Illuminating
Company
Yes
PER-005-2 introduced the concept of a Transmission Owner local control center that
issues and receives instructions independent of a TOP, RC or BA. COM-002-4 should
apply to Transmission Owners.
Response: The OPCP SDT thanks you for your comment. Please refer to question 9
in the FAQ document posted on the project page for a response to your comment.
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Liberty Electric Power LLC
Yes or No
Question 4 Comment
Yes
COM-002 remains a zero defect standard, and there is no FERC directive to provide a
zero defect standard in response to either blackout recommendation 26 or Paragraph
535 of Order 693. Further, there is no requirement for the issuer of an Operating
Instruction in an Emergency to indicate the Emergency status. The webinar response
to queries over the lack of Emergency Status Indication was to suggest the RE "call and
inquire" if the OI was in fact a Directive. This adds to the regulatory burden while
offering zero benefit. Identification of an Emergency has positive effects far beyond
three part communications. The realization of risk to the BES should create a
heightened sense of urgency among all parties. The standard must require
announcement of Emergency status in order to penalize RE's for actions which are not
violations in a non-Emergency situation.
Response: Please see the summary response to Question 1.
As a clarifier, the OPCP SDT provided the response during the webinar that, if a
receiver was unsure whether there was an Emergency or not, the receiver could ask
the issuer for clarification.
Wisconsin Electric Power
Company
Yes
The proscribed training requirements embedded in R2 and R3 should be removed.
The existence and usage of protocols should be the primary focus of the standard and
regulatory review, creating a training requirement within the standard shifts focus to
training content and administration. Additionally, PER-005-1 requires the Balancing
Authority, Reliability Coordinator, and Transmission Operator to have a systematic
approach to training (SAT). The adoption and management of a SAT would
presumably include communications protocols as a task for potential training. The
current draft version of PER-005-2 includes a similar requirement for a SAT applicable
to the Generator Operator.
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Question 4 Comment
Response: Please see the summary response to Question 1.
The annual assessment and corrective action process defined in R4 should be made
applicable to Operating Instructions during an Emergency. Although the NERC Glossary
of terms provides a definition of Emergency, two reasonable people looking at a
situation can disagree as to when an Operating Instruction is issued during an
Emergency. Creating a zero defect standard applicable to inherently ambiguous
situations shifts focus from the adoption of communication protocols to discussion of
when an Operating Instruction is issued during an Emergency. During an entities
annual assessment process, the focus would be on classification of an Emergency
instead of process improvement for communications. An alternate approach would be
to draft the standard so as to require the explicit identification of an Operating
Instruction and/or Emergencies so as to remove the ambiguity.
Response: Please see the summary response to Question 1.
Finally, the definition of Operating Instruction references a command issued by
operating personnel, without sufficiently defining operating personnel.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity. The requirements in the standard define which
operating personnel are applicable to the standard.
NRECA
Yes
NRECA suggests that the “assess adherence and assess effectiveness” language in R4
be removed from COM-002-4. This language is similar to the “Identify, Assess and
Correct (IAC)” language that was included in the CIP V5 standards. The removal or
modification of this language was included in the Final Rule on NERC CIP V5 Standards
(Order No. 791). FERC stated that IAC language and concepts would be best addressed
in the NERC compliance processes, such as through the NERC Reliability Assurance
Initiative (RAI), rather than standards requirements.
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Question 4 Comment
Response: Please see the summary response to Question 1.
Ingleside Cogeneration LP
Yes
ICLP would like to see the innovative approach that the drafting team used to develop
COM-002-4 applied to other standards as well. The issue that continues to arise is not
so much whether mandatory requirements are based upon sound reliability principles,
but how they can be reasonably enforced. In this case, it is clear that many entities do
not have the tools or resources to examine every Operating Instruction in detail in
order to assure 100% compliance with a rigorous communication protocol.
Conversely, training and retention programs are common - and have proven to be an
effective means to drive consistent Operator performance.
Response: The OPCP SDT thanks you for your comment.
Clark Public Utilities
Yes
For the purposes of Requirements 5 and 6, Clark believes it should be an obligation of
the issuer of Operating Instruction given during an emergency to identify it as an
Emergency Operating Instruction. It should not an obligation of the reciever to
determine after-the-fact whether an Operating Instruction is an Emergency or not. All
Operating Instructions issued by a BA, RC, or TOP should be regarded with importance
but a specification by the issuer that the instruction is in response to an Emergency
will alert the receiver that a particular Operating Instruction action requirement has a
role in the overall reliability of the BES resulting in a higher level of BES reliability.
Response: Please see the summary response to Question 1.
Manitoba Hydro
Yes
1) The protocols at minimum should require full name identification.
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Question 4 Comment
Response: The OPCP SDT considered your suggestion but asserts that the
requirement for “full name identification” does not need to be a mandated
communication protocol.
2) R2 - the description of the applicable operating personnel (i.e. that are responsible
for Real-Time operation of the interconnected BES) is different in this part than others
(that state it’s for operating personnel that issue and receive certain Operating
Instructions). Is that purposeful?
Response: The OPCP SDT chose that language in Requirement R2 to designate what
personnel must be trained.
3) R5, R6, R7 and R8 - the numbering seems to be mixed up.
Response: The OPCP SDT is not sure to what you are referring. The standard has no
Requirement R8.
4) M2 and M3 - are not drafted consistently given the consistency in drafting of
requirements R2 and R3. M3 refers to ‘its initial’ training records while M2 does not
and M3 refers to training records ‘for its operating personnel’ while M2 does not.
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Measure M2.
5) M4 - contains a section of text that is not reflective of the requirement itself and has
no basis for appearing in the measure. The requirement states only that the entity
need only take corrective action to address deviations. The extra text that discusses
instances where non adherence is the sole or partial cause of an Emergency should be
deleted.
Response: The OPCP SDT clarified the language in Measure M4 to better align with
the language in Requirement R4.
6) M6, M7 - the words ‘if the entity has such recordings’ seem unnecessary. This
qualifying language isn’t attached to any other type of evidence that is listed as a
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Question 4 Comment
possibility; presumably all of those are subject to the same qualifier and would only be
presented as evidence if the entity had them.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
Georgia Transmission
Corporation
Yes
Comments: GTC suggests that the “assess adherence and assess effectiveness”
language in R4 be removed from COM-002-4. This language is similar to the “Identify,
Assess and Correct (IAC)” language that was included in the CIP V5 standards which
FERC directed the removal of. The removal or modification of this language was
included in the Final Rule of NERC CIP V5 (Order No. 791). FERC stated that IAC
language was “overly-vague, lacking definition and guidance is needed” and that these
control concepts would be best addressed in the NERC compliance processes, such as
through the NERC Reliability Assurance Initiative (RAI), rather than standards
requirements.
Response: Please see the summary response to Question 1.
Lastly, GTC recommends a revision to the NERC Glossary term Emergency. GTC
recommends the removal of the terms “or limit” within this definition. One could
argue that every single Operating Instruction is utilized to limit failures of transmission
facilities. Emergency should be more appropriately defined without this
ambiguity:Proposed:Emergency or BES Emergency: Any abnormal system condition
that requires automatic or immediate manual action to prevent the failure of
transmission facilities or generation supply that could adversely affect the reliability of
the Bulk Electric System.
Response: The OPCP SDT considered your suggestion but asserts that the existing
definition of Emergency provides sufficient clarity.
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American Transmission
Company, LLC
Yes or No
Question 4 Comment
Yes
ATC recommends changing the language in Requirement 4 to read as follows:” Each
Balancing Authority, Reliability Coordinator, and Transmission Operator shall at least
once every calendar year, and no more than every 15 months: “ ..............This would be
consistent with the NERC’s annual requirement assessment made in NERC’s
Compliance Application Notice (CAN)- 0010 issued on November16, 2011. In doing so,
it should drive consistency among the CEA on how it is enforced.
Response: The OPCP SDT thanks you for your comments. The OPCP SDT considered
your suggestion but asserts that the existing language provides sufficient clarity.
Independent Electricity
System Operator
Yes
Recently, FERC directed NERC to eliminate the ambiguity with language “identify,
assess, and correct” deficiencies for the CIP standards. Although it supported NERC’s
move away from a “zero tolerance” approach to compliance, FERC wanted NERC
provide more guidance regarding enforceability with the self-identify/assess/correct
approach to compliance. NERC may want to consider that FERC may raise the same
concerns with this proposed standard.
Response: Please see the summary response to Question 1.
According to the draft standard, if DPs and GOPs receive an Operating Instruction,
they can provide an attestation from the issuer of the Operating Instruction to
demonstrate compliance - they do not need to develop documented communications
protocols. The lighter compliance burden on DPs and GOPs may result in a higher
administrative burden for the RC/BA/TOP to provide attestations.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The Measures provide various
options that the drafting team considered as ways to demonstrate compliance for
Requirement R6. It is not an exhaustive list, and in no way places an expectation on
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Question 4 Comment
any entity that they must provide evidence of another party's compliance. It simply
provides a few options to consider.”
Pepco Holdings Inc.
Yes
Please provide the rational as to why the standard is not applicable to TOs.
Response: The OPCP SDT thanks you for your comment. Please refer to question 9
in the FAQ document posted on the project page for a response to your comment.
American Electric Power
Yes
AEP believes the most recent changes represent a major step back in regards to clarity
(as compared to the draft proposed in October 2013), and has driven us to change our
voting position from affirmative to negative. We are concerned by the removal of
Reliability Directive, and instead, now basing requirements on whether or not the
communications are made during an Emergency. Who determines whether or not an
Emergency state exists, and in addition, how would that be communicated? AEP
recommends returning to the fundamentals and approach taken in the previous draft.
If the phase “Reliability Directive” is to be remanded, we encourage the drafting team
to pursue alternative language which would not require the need to know whether or
not the communications are being made during an “Emergency”. For example,
perhaps the drafting team could change R1 (as taken from the October 2013 draft) to
state something like the following: “Require the issuer to identify the action as a
directive or instruction...”.R4.
Response: Please see the summary response to Question 1.
2: Though M4 specifies the kinds of evidence needed to meet R4, we believe it would
be too subjective in determining whether or not the entity’s efforts properly assessed
the effectiveness of the documented communications protocols.
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Question 4 Comment
Response: The measures provide various options that the OPCP SDT considered to
demonstrate compliance for Requirement R4. It is not intended to be an exhaustive
list.
Utility Services, Inc
Yes
Smaller DPs and GOPs will have a significant problems demonstrating compliance with
Requirement 6 as written.
1. As there is no requirement to notify these entities that an Operating Instruction is
being issued during an Emergency, they will not be aware of which communications
will be subject to compliance review.
2. Since these entities typically do not record phone conversations they would have to
rely on other forms of evidence. Log book enties will not document if three part
communication was used and since the entities are not made aware of Emergency
conditions, they will not know to maintain a higher level of documentation to
demonstrate compliance.
3. Approaching the issuer for confirmation of OIs during Emergency conditions and
seeking Attestations from these entities will create a significant administrative burden
not only for the small entities, but for the Issuer of the OI as well.
4. Any additional tasks that must be performed during Emergency situations runs
contrary to the intent of the standard, which is to normalize communication protocols
during all situations, and not have separate procedures during normal and Emergency
conditions.
Response: Please see the summary response to Question 1.
Platte River Power Authority
Yes
Platte River takes exception to the requirement for alpha-numeric clarifiers for
communications.
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Question 4 Comment
Response: The OPCP SDT thanks you for your comment but notes the requirement
for alpha-numeric clarifiers was from a previous draft of this standard and is no
longer contained in the current version.
Nebraska Public Power
District
Yes
1) Applicability for Distribution Providers (DP’s) should be qualified similar to
qualification used for DP applicability in version 5 of CIP-003. Applicability needs to be
focused on DP employees that may receive instructions relative to the BES.
Response: Please see the summary response to Question 1.
2) R1: Since Requirements R5, R6 and R7 are zero tolerance, R1 protocols should state
that when there is an emergency condition on the system that those issuing Operating
Instructions during an emergency shall state that “this is an emergency”. Reason
Number 1, there needs to be a triggering mechanism that tells both the issuer and
receiver that 3 part communication is zero tolerance and in effect during an
emergency; Reason Number 2, there is question in the industry as to when the
“emergency” begins and ends; and Reason Number 3 the RSAW for R5, R6 and R7 are
telling the auditor (in the auditors note) to predetermine before an audit what are
emergencies on an entities system, which could potentially create an issue of what is a
determined emergency between the auditor and the entity. By inserting a triggering
mechanism as suggested will create a demarcation for operating instructions during
emergencies.
Response: Please see the summary response to Question 1.
3) R2 and R3 are already provided for in PER-005 and therefore are redundant in this
standard. If there is a need to include a training requirement in this standard, that
requirement could consist of a statement to include protocol training in the entity’s
reliability task list.
Response: Please see the summary response to Question 1.
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4) R4 as written puts a huge administrative burden on entities to administer
assessments of ‘each’ of its operating personnel that issue and/or receive Operating
Instructions. As in previous drafts of this Standard, entities should determine and
document their own assessments to the Standard and so that adherence and
effectiveness fits their program. In addition, the 12-month requirement in the
Standard now provides for an administrative burden and compliance trap in order to
remain compliant to the 12-month requirement. We’re a TOP and do many switching
orders a day with operating personnel throughout the state. R4 requires us to assess
adherence to communications protocols by our operating personnel (see FAQ #22 says
"each" issuer/reciever) that receive these operating instructions and provide feedback
to the operating personnel, and take corrective actions when appropriate. Currently,
we have over 800 switch personnel, and some of these are not NPPD employees. We
utilize personnel from some of our public power partners, such as rural power districts
and municipalities. The 12 calendar month clock will be different for each person. So,
day-to-day will be a challenge to ensure we capture compliance documentation on
each person that changes the state of a BES element. The drafting team should
revert back language similar to R5 of posting #7 (with exception to the “implement”
language) so that entities can manage their own compliance controls and can develop
assessments that fit their program. NPPD would suggest the following for
Requirement 4:R4. Each BA, RC and TOP shall have a documented method to evaluate
the communication protocols developed in R1 that: 4.1 Assess adherence to the
communications protocols developed in R1; 4.2 Assess the effectiveness of the
communications protocols in R1; 4.3 Provide feedback to issuers and receivers of
Operating Instructions; and 4.4 Modify communication protocols as necessary as a
result evaluated communication
protocols in this R4.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “An entity could perform an
assessment by listening to random samplings of each of their operating personnel
issuing and/or receiving Operating Instructions. If there were instances where an
Operator deviated from the entity’s protocols, the entity would provide feedback to
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the operator in question in any method it sees as appropriate. An example would be
counseling or retraining the operator on the protocols.
An entity could assess the effectiveness of its protocols by reviewing instances where
operators deviated from those protocols and determining if whether the deviations
were caused by operator error or by flaws in the protocols that need to be changed.”
The posted RSAW provides additional guidance on sampling. There was never an
intention that every communication of an Operating Instruction must be assessed.
CenterPoint Energy Houston
Electric LLC
Yes
CenterPoint Energy would like to thank the COM-002-4 Standard Drafting Team and
appreciates the OPCP SDT’s time and effort dedicated in the development of this
standard, in engaging the industry, and incorporating industry feedback into the
standard. The removal of the requirement to identify an Operating Instruction in an
emergency or a Reliability Directive to the receiver is viewed as a positive change.
CenterPoint Energy believes that operating personnel’s focus should always be on
monitoring and controlling the reliability of the BES rather than a compliance burden
of correctly identifying and aligning company specific communication protocols to
normal versus emergency operations. Overall, CenterPoint Energy agrees with the
standard, but still has general concerns. The Company believes the prescriptiveness of
the requirements: particularly R1.1 thru R1.6 exceeds the necessary components
needed in establishing communication protocols for tightened reliable
communications.
Response: The OPCP SDT thanks you for your comment. The OPCP SDT asserts that
Requirement R1 Parts 1.1 to 1.6 are an essential set of communication protocols and
are not overly prescriptive.
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MISO
Yes or No
Yes
Question 4 Comment
We recommend the drafting team: (1) Remove the attestation for another provision
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The Measures provide various
options that the drafting team considered as ways to demonstrate compliance for
Requirement R6. It is not an exhaustive list, and in no way places an expectation on
any entity that they must provide evidence of another party's compliance. It simply
provides a few options to consider.”
(2) Restrict the zero-defect component of the standard to those operating instructions
directly related to the emergency (e.g. redistpach instructions for IROLs,
committtment instructions during EEAs, synchronizing during restoration, etc.)
Response: Please see the summary response to Question 1.
(3) Maintain Reliability Directives in the toolkit as the clear indicator of an Operating
Instruction that is directly applicable to the emergency.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The OPCP SDT debated
whether to remove the term ‘Reliability Directive’ in response to comments
suggesting it should be removed from the definition of ‘Operating Instruction’ and in
light of FERC’s issuance of the TOP/IRO Notice of Proposed Rulemaking (NOPR),
which proposes to remand the definition of ‘Reliability Directive’ along with the
proposed TOP and IRO standards. To avoid unnecessary complications with the
timing of the NOPR and posting Draft 8, the OPCP SDT consulted with the Project
2007-03 Real-time Transmission Operations and the Project 2006-06 Reliability
Coordination Standard Drafting Teams to ask whether they believed removal of the
term ‘Reliability Directive’ in the COM-002-4 standard would cause concerns. Both
teams agreed that the COM-002-4 standard did not need to require a protocol to
identify Reliability Directives as such and that the definition of Operating Instruction
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could be used absent the term Reliability Directive in COM-002-4 to set the
protocols. The OPCP SDT ultimately voted to remove the term. The OPCP SDT also
decided to incorporate the phrase “Operating Instruction during an Emergency” in
certain Requirements, where needed, to identify Requirements that are subject to a
zero-tolerance compliance/enforcement approach.”
We believe that DPs and LSEs don’t need stringent requirements.
They just need to follow Directives or explain why they cannot. We understand that
the drafting team is trying to meet a deadline, however we'd support the drafting
team addressing all of the industry comments even if it requires more time to get this
standard right.
Response: COM-002-4 is not applicable to LSEs. DPs only have two applicable
requirements.
PJM Interconnection
Yes
PJM supports the draft standard as it strikes a good balance between the industry and
the NERC BOT November, 2013 resolutions. The standard provides the industry some
flexibility regarding how communication protocols are developed. It also makes it
cleaner and easier for operators to use the same protocol for all Operating
Instructions, whether in an emergency or not, while not burdening System Operators
with issues around how compliance will be measured. PJM does not support the
addition of a new training requirement under R1. PJM recommends that all training
requirements be included in one standard and not spread throughout families of
standards. Consolidation of all training requirements under a single training standard
will help in development of a clear, more organized training process.
Response: Please see the summary response to Question 1.
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Georgia System Operations
Corporation
Yes or No
Question 4 Comment
Yes
With consideration that an Emergency may not be initially recognized by system
operators for several minutes, GSOC requests Requirements R5 thru R7 include the
word “recognized” precede the work “Emergency”. GSOC cites the newly effective
EOP-004-2, R2 currently affords this consideration. It requires reporting “within 24
hours of recognition of meeting an event type threshold”. In addition, GSOC
recommends R5 thru R7 replace the words “during an Emergency” with “addressing a
recognized Emergency” so as to avoid confusion should there be Operating
Instructions issued during an Emergency that may have nothing to do with an
Emergency.
Response: Please see the summary response to Question 1.
GSOC suggests that the “assess adherence and assess effectiveness” language in R4 be
removed from COM-002-4. This language is similar to the “Identify, Assess and Correct
(IAC)” language that was included in the CIP V5 standards. The removal or
modification of this language was included in the Final Rule on NERC CIP V5 Standards
(Order No. 791). FERC stated that IAC language and concepts would be best addressed
in the NERC compliance processes, such as through the NERC Reliability Assurance
Initiative (RAI), rather than standards requirements
Response: The OPCP SDT asserts that there is a substantive enough difference in the
language of COM-002-4 and CIP version 5 so as not to be problematic. FERC stated
concern was with the ambiguity around “identify, assess, and correct.” The OPCP
SDT added clarifying language in the requirements to specify the actions that an
entity is expected to take.
Electric Reliability Council of
Texas, Inc.
Yes
ERCOT ISO believes the draft standard could be improved and offers the following
suggestions for the OPCP SDT’s consideration.
Definition of Operating Instruction. The definition of Operating Instruction could be
improved by making the following changes:1) Delete the word “interconnected”
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before BES in the first sentence. It is not used instances where BES is used. Unless
there is a substantive reason for using interconnected in some BES references and not
others, the standard should be consistent to mitigate ambiguity;2) “Potential Options”
in the parenthetical is redundant - delete “potential”. Also, “option” and
“alternatives” in the parenthetical are also redundant - delete one of them;3) The
parenthetical doesn’t need to be a parenthetical - make it the last sentence in the
definition.As revised, the definition would read as follows:Operating Instruction - A
command by operating personnel responsible for the Real-time operation of the Bulk
Electric System (BES) to change or preserve the state, status, output, or input of an
Element of the BES or Facility of the BES. A discussion of general information to
resolve BES operating concerns is not a command and is not considered an Operating
Instruction.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
Purpose Section: The purpose statement could be improved by making the following
changes:1) Delete “the issuance of” in the first sentence. It is inherent that a
communication is “issued”. Therefore, this language is superfluous and should be
deleted to mitigate any potential ambiguity;2) Delete “predefined” in the first
sentence. This adjective is not needed - the existence of communication protocols
means they are predefined. Therefore, this is superfluous language and should be
deleted to mitigate potential ambiguity. As revised, the purpose section would read as
follows:Purpose: To improve communications for Operating Instructions with
communications protocols to reduce the possibility of miscommunication that could
lead to action or inaction harmful to the reliability of the Bulk Electric System (BES).
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
Requirements SectionR1
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1) ERCOT ISO disagrees with changing “have” to “develop” in the first sentence. The
point of this requirement is to have protocols that meet the minimum requirements.
Obviously, in order to have the protocols an entity would need to develop them, but
that is not the focus - as noted, having the protocols is the intent;2) Change “and” to
“or” in the following - “...for its operating personnel that issue or receive Operating
Instructions...” The intent is to make the obligation to have protocols applicable to all
operating personnel of the relevant functions. It may be that some functions only
issue or only receive operating instructions. In those cases this requirement would not
apply to those entities because the requirement is conjunctive - issue and receive. By
making it disjunctive by using “or” the requirement applies to all circumstances - i.e.
issue and receive or just issue or just receive;3) The change suggested in (2) above
should be made in R1.1 as well;
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
4) Also in R1.1, the triggering condition for using another language besides English i.e. “unless otherwise agreed to” - is unclear in terms of how that would work. How do
you demonstrate that such an agreement is in place? Also, practically speaking, the
ability to reach such an agreement assumes that all operators are capable of speaking
the alternative language. It seems way too complicated because it would depend on
the languages spoken by the different operators at different entities, and their
schedules would have to be coordinated. These issues are less of a concern for
allowing alternative languages for internal communications because the entity’s
personnel know one another and are located in the same place/organization. ERCOT
ISO appreciates the intent of allowing for this exception, but it is difficult to see how it
would work in practice, and even assuming it could work, the requirement is unclear
as to what sort of agreement would be required;
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The drafting team included this
part to carry forward the same use of English language included in COM-001-1,
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Requirement R4 and to retire this requirement from COM-001. The requirement
continues to permit the issuer and receiver to use an agreed to alternate language.
This has been retained since use of an alternate language on a case-by-case basis
may serve to better facilitate effective communications where the use of English
language may create additional opportunities for miscommunications. Part 1.1
requires the use of English language when issuing oral or written (e.g. switching
orders) Operating Instructions. This creates a standard language (unless agreed to
otherwise) for use when issuing commands that could change or preserve the state,
status, output, or input of an Element of the Bulk Electric System or Facility of the
Bulk Electric System. It also clarifies that an alternate language can be used
internally within the organization. The phrase has been modified slightly from the
language in COM-001-1, Requirement R4 to incorporate the term ‘Operating
Instruction,’ which defines the communications that require the use of the
documented communications protocols.”
5) R1.2 - Change “repeated information” to “response”. First, this change promotes
consistency in terminology. Second, it is more consistent with the intent that the
receiver is not required to repeat the directive verbatim - response contemplates
flexibility as long as intent is there, while repeated information seems to require a
verbatim reply;
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
6) The last bullet in R1.2 requires the issuer to take an alternative action if a response
is not received or if the instruction is not understood. It is unclear what this means. Is
the obligation related to trying to re-issue the instruction, or does it require the issuer
take an alternative operating action? This is a communications standard, not an
operations standard. Accordingly, the intent of this bullet should be clarified, and if it
requires the issuer to take an alternative operating action, ERCOT ISO questions
whether that obligation should be in a COM standard. Operational requirements are
already covered in other standards, and if entities act under those other standards
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then the relevant communications protocols would apply to those “alternative”
operating actions. ERCOT ISO believes that the “alternative action” described in the
third bullet of R1.2 and R5 should be limited only to communications and not
operating actions. ERCOT ISO would recommend replacing R1.2 and R5 third bullet
with the following: Attempt an alternative means to communicate the Operating
Instruction if a response is not received or if the Operating Instruction was not
understood by the receiver, if deemed necessary by the issuer .ERCOT ISO also
recommends including “or receiving” to capture that the training should be prior to
that individual operator issuing ‘or receiving’ an Operating Instruction to address the
subparts of R1 that deal with receiving Operating Instructions.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “If an operator issues an
Operating Instruction during an Emergency and, based on the response from the
receiver, or lack thereof, chooses to take an alternative action, that operator has
satisfied Requirement R5 and is not in violation.” It does not require an alternate
action, but it allows the operator to take an alternate action if necessary and not be
in violation of the requirement for three-part communication.
7) R1.4 - Delete “single-party”. It is clear that an issuer is one entity without having to
add “single-party”. Accordingly, this is superfluous language and should be deleted to
mitigate ambiguity. If this deletion is made, “operating instruction” would have to be
moved to where “single-party” was in the sentence;8) R1.4 requires the issuer to
“confirm” or “verify” that the instruction was received by at least one entity. They are
the same thing - delete one of them for clarity and to mitigate ambiguity;
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
9) R1.5 requires the communication protocols to specify the instances where time
identification is required and to specify the format for time identification. As written,
this appears to require the protocols to specifically list all relevant instances and,
where relevant, requires the use of a specific time ID format. The OPCP SDT should
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consider revising this so the requirement imposes a general obligation for the
protocols to time ID instructions when necessary, but not require the establishment of
an exclusive list. This will accomplish the goal of time stamping and provide the entity
with flexibility to implement the requirement, which will also mitigate the need to
revise protocols if an entity determines prospectively that time ID is not needed in
some instances on the list and is needed in other instances that are not on the list.
Similarly, the protocols should not require a specific format. Providing flexibility with
respect to format will mitigate the potential for form over substance violations of the
protocols - time ID is the point, not the format;
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The OPCP SDT has included this
part to add necessary clarity to Operating Instructions to reduce the risk of
miscommunications. The inclusion of ‘specify when time identification required’
allows for an entity to evaluate its particular circumstances and communications to
determine when it may be appropriate to use time identification in its Operating
Instructions. The drafting team recognized from comments the need to provide this
flexibility while still requiring an entity to address this part in its documented
communication protocols. Clarifying time and time zone (where necessary)
contributes to reducing misunderstandings and reduces the risk of a grave error
during BES operations. This is not exclusively for entities in multiple time zones, but
Operating Instructions between entities in multiple time zones is one example of
instances that may need time identification when issuing and receiving Operating
Instructions.”
10) R1.6 requires the protocols to establish nomenclature for transmission elements.
It is unclear how this will facilitate clearer communications unless all entities that are
issuers or recipients of instructions use the same nomenclature. As drafted, it appears
that it is an independent obligation that applies to each entity. If that is the case, each
entity could use different nomenclature, which arguably could have a negative impact
on communications.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
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3
Organization
Yes or No
Question 4 Comment
Response: Please see the summary response to Question 1.
R4 1) ERCOT ISO understands the inclusion of R4 as a means to make normal
operations Operating Instructions not subject to zero tolerance enforcement.
However, ERCOT ISO has reservations concerning potential subjectivity surrounding
who determines “appropriate” and “as necessary”. As a general comment, these
types of “internal controls” requirements are better handled through the RAI initiative
and subsequent CMEP processes. However, if the language remains, ERCOT ISO
believes the clarity and effectiveness of the standard will benefit by clarifying that the
entity who is conducting the assessments determine the appropriateness and
necessity, and that the role of the ERO is simply to review if such activities were
performed. ERCOT ISO recommends modifications as below. 4.1. Assess adherence
by its operating personnel that issue or receive Operating Instructions to the
documented communications protocols ‘required’ in ‘by the subparts’ of Requirement
R1, , provide feedback to those operating personnel and take corrective action, as
‘deemed’ appropriate ‘by the entity’ to address deviations from the documented
protocols.4.2. Assess the effectiveness of its documented communications protocols
‘required’ in ‘by the subparts of’ Requirement R1, for its operating personnel that
issue or receive Operating Instructions and modify its documented communication
protocols, as ‘deemed’ necessary ‘by the entity’. Additionally, ERCOT ISO recommends
including language to specify that R4 only be required to apply to those
communication protocols that are identified in the subparts of R1, and not to other
practices that an entity may choose to employ or improve upon. This clarification will
mitigate creating a “fill in the blank” type standard approach for future potential
changes to the R1 documented communication protocols.
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Requirement R4.
R51) How does the term “Emergency” in this requirement align with/relate to the
term “Reliability Directive” in other standards, both in terms of meaning and scope of
related responsibilities - is there overlap that could create ambiguity or unnecessary
Consideration of Comments: Project 2007-02 COM-002-4
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Yes or No
Question 4 Comment
redundancy? There is a concern regarding the use of “Operating Instruction during an
Emergency”. While ERCOT ISO understands the rationale behind replacing Reliability
Directive with the new terminology based on the FERC NOPR potentially remanding
the term, to avoid overlap/redundancy/confusion if this is retained, any potential
conflicts must be addressed through other projects. Use of Reliability Directive up
until this draft created clear synergy between COM-003/002 and the IRO/TOP
revisions. If the term is not remanded, ERCOT ISO would support a more uniform
approach by including Reliability Directive;
Response: Please see the summary response to Question 1.
2) Change “repeated information” to “response” in first two bullets. See comment 5 in
R1 comments above for rationale for this suggested change;3) Third bullet - see
comment 6 under R1 comments - same comment for the third bullet under R5;
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
R71) Delete “single party” and delete either “confirm” or “verify” - see comments 7
and 8 under R1 for rationale for these suggested revisions.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
Measures
M4 is too prescriptive and inappropriately imposes requirements on the entity. This
measure should align with previous comments concerning R4. M4 should be modified
to reflect appropriate measures or types of evidence that should be provided without
being overly prescriptive with respect to the level of quality of evidence. Additionally
each part should be included and reflect the requirements without imposing
additional requirements.
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Measure M4. In addition, the list of evidence is
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
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Organization
Yes or No
Question 4 Comment
not an exhaustive list and in no way places an expectation on any entity that they
must provide evidence of another party's compliance. It simply provides a few
options to consider.
M5-M7 should not identify attestations from the issuer or include “dated and time
stamped” as part of the measure. Compliance should be demonstrated by the
relevant entity - third parties should not be required either directly or indirectly to
support the compliance activities of another entity by providing attestations. “Dated
and time stamped” goes to the quality of evidence and is not appropriate for a
measure. ERCOT ISO comments that inclusion of attestations, documented
observations, procedures, or other equivalent evidence would improve M5-M7.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The Measures provide various
options that the drafting team considered as ways to demonstrate compliance for
Requirement R6. It is not an exhaustive list, and in no way places an expectation on
any entity that they must provide evidence of another party's compliance. It simply
provides a few options to consider.” The same comment applies to Measures M5
and M7.
Indiana Municipal Power
Agency
Yes
Requirement R3 is not clear in defining if it covers all Operating Instructions received
by a Distribution Provider and Generator Operator. Distribution Providers and
Generator Operators can receive Operating Instructions from outside parties
(Balancing Authority, Reliability Coordinator, and Transmission Operator) and from
internal parties (its own Market Operations). The current word in Requirement 3
requires Distribution Providers and Generator Operators to repeat back both outside
and internal parties Operating Instructions. IMPA does not believe this was the intent
of the OPCP SDT since there are no requirements that cover Distribution Providers or
Generator Operators issuing Operating Instructions (the Generator Operator’s Market
Operations issuing an Operating Instruction to its generating power plant; Generator
Consideration of Comments: Project 2007-02 COM-002-4
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Yes or No
Question 4 Comment
Operators cannot issue Operating Instructions to any Registered Entities such as the
Balancing Authority or Reliability Coordinator). IMPA also believes that operating
personnel need to know at the time an instruction is given if it is an Operating
Instruction or a Directive. This clarification needs to come from the entity giving the
instruction and reviewing the call afterwards to make that determination is very
problematic.
Response: The OPCP SDT thanks you for your comments and has considered them.
The definition of Operating Instruction is “A command by operating personnel
responsible for the Real-time operation of the interconnected Bulk Electric System to
change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System
operating concerns is not a command and is not considered an Operating
Instruction.)” Conversations concerning market dispatch are not considered
Operating Instructions. The OPCP SDT addressed the issue of identifying
Emergencies in the FAQ document posted on the project page. The following
response was provided: “Separately listing out Requirements R5, R6, and R7 and
using ‘Operating Instruction during an Emergency’ in them does not require a
different set of protocols to be used during Emergencies or mandate the
identification of a communication as an ‘Operating Instruction during an Emergency.’
The same protocols are required to be used in connection with the issuance of
Operating Instructions for all operating conditions. Their use is measured for
compliance/enforcement differently using the operating condition as an indicator of
which compliance/enforcement approach applies. In other words, it is not the
drafting team’s expectation that the operator must differentiate between
Emergency and non-Emergency Operating Instructions.”
Consideration of Comments: Project 2007-02 COM-002-4
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New York Independent
System Operator
Yes or No
Yes
Question 4 Comment
The NYISO would like to request confirmation that Operating Instructions are limited
to verbal or written communications and that electronic dispatch signals are not in
scope for this standard. The NYISO would also note that we support comments
submitted by both the IRC/SRC and NPCC/RSC.
Response: The OPCP SDT thanks you for your comments. The definition of Operating
Instruction was intentionally written broadly to include many forms of
communication. The requirements in COM-002-4 only apply to oral and written
Operating Instructions. Electronic dispatch signals are not in the scope of COM-0024.
Northeast Utilities
Yes
Comment 1 Systematic Approach to Training is already covered in PER-005-1 and
including a requirement for training would seem to be redundant.
Response: Please see the summary response to Question 1.
Comment 2 The applicability of Distribution Provider (DP) functional responsibility
presents potential for confusion. New England LCC’s (Transmission Operators) operate
at the direction of ISO-NE the Regional Transmission Operator (RTO) and enforcing the
communication protocols to distribution companies/distribution providers may
present challenges, identifying, documenting and implementing COM-002-4 to the DP.
Response: Please see the summary response to Question 1.
Comment 3 The language used in Requirement 1.6 is vague and needs to be clarified
for Registered Entities to know how to comply with it. How would one “specify
nomenclature” system-wide?
Response: Please see the summary response to Question 1.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Oncor Electric Delivery
Company LLC
Yes or No
Question 4 Comment
Yes
Oncor recommends Requirement 4 and Measurement 4 be removed. The “assess
adherence and assess effectiveness” language mirrors the same concepts as the
“Identify, Assess and Correct (IAC)” language that was included in the CIP V5 standards
which FERC directed the removal of. The removal or modification of this language was
included in the Final Rule of NERC CIP V5 (Order No. 791). FERC stated that IAC
language was “overly-vague, lacking definition and guidance is needed” and that these
control concepts would be best addressed in the NERC compliance processes, such as
through the NERC Reliability Assurance Initiative (RAI), rather than standards
requirements. Reliability Standards must be revised to focus on strategic and critical
reliability objectives incorporating requirements for meeting and sustaining reliability
of the BES. The current state of Standards must transition from a prescriptive zero
tolerance approach to results-based requirements which assure the reliability and
security of the critical infrastructure. A reliability results-based approach should not
be an additive to the Reliability Standards; hence, controls requirements should not be
incorporated within the Standards, rather controls should be considered at the
Program level. Reliability Standards should define the results (“what”) Entities are
mandated to meet and maintain and the “how” should be handled by each Entity for
there is not a “one size fits all”. Incorporating detective controls as requirements and
prescriptive measurements can lead to unintended consequences and again, an
additive versus a process that helps provide a registered entity with reasonable
assurance they comply with the Standard(s) or the operating function(s) and processes
that the Standard(s) require.
Response: Please see the summary response to Question 1.
Rewording of R1.6 as follows: “Specify the nomenclature to be used for Transmission
interface Elements and Transmission interface Facilities when issuing an oral or
written Operating Instruction to Neighboring Entities.” While the Technical
Justification document suggests that R1.6 applies to communication with neighboring
entities, it is unclear that this requirement, as worded in the current draft of COM002-4, is specifically discussing communication with neighboring entities.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
10
9
Organization
Yes or No
Question 4 Comment
Response: Please see the summary response to Question 1.
M2 should include “initial training” and be reworded as follows in order to maintain
consistency with the requirement: “Each Balancing Authority, Reliability Coordinator,
and Transmission Operator shall provide initial training records related to its
documented communications protocols developed for Requirement R1 such as
attendance logs, agendas, learning objectives, or course materials in fulfillment of
Requirement R2.”
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Measure M2.
Exelon Corp and its affiliated
business units
Yes
o A “qualified” application of COM-002-4 for a DP that performs voltage reduction or
load shedding as directed by an RC, BA or TOP could clarify the standard and place the
emphasis on the functional entities that matter most.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
o Remove R6 and M6.The BA, RC or TOP, as issuers, record Operating Instructions (OI).
R1.2 requires an entity issuing an OI to confirm the receiver’s response, reissue if
necessary and take alternate action if the receiver does not confirm or understand the
OI. Similarly, per R5, issuers of an OI are required to confirm the receiver’s response,
reissue if necessary and take alternate action if the receiver does not confirm or
understand the OI. There is little reliability benefit in requiring the DP and GOP
receiver documenting their role in this exchange. The training requirement for
receivers of OI’s in R3 is sufficient.
Response: The OPCP SDT chose to include Distribution Providers and Generator
Operators in the Applicability section because they can be on the receiving end of
some Operating Instructions. The OPCP SDT determined that if Distribution
Providers and Generator Operators were not included as applicable entities in this
Consideration of Comments: Project 2007-02 COM-002-4
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0
Organization
Yes or No
Question 4 Comment
standard, it could create a gap. Additionally, it is important that the Distribution
Provider and Generator Operator perform three-part communication when receiving
an “Operating Instruction during an Emergency.” That necessitates Requirement R6.
o If R6 and M6 are not removed.R6. To clarify, suggest that the word “Operating
Instruction” be inserted after “excluding written” so it is clear it is applicable to both
conditions.M6. Need a comma after “voice recordings” so as to separate it from dated
operator logs.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
"Voice recordings" is repeated twice in M6. M7. "Voice recordings" is repeated twice
in M7.
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Measures M6 and M7.
o R6 / M6. Exelon is concerned that demonstrating compliance with R6 may prove
difficult for some entities. A generator operator may not have voice recording
available at the entity’s facility and it may not be possible to procure voice recording
or attestations from the issuer of an Operating Instruction. The measurement says
dated operator logs are acceptable evidence. The RSAW further discusses auditor
discretion and risk assessment respecting this requirement and measure. If audited
per the measurement and RSAW guidance, log entries would be acceptable evidence
but we are concerned that an auditor may find otherwise.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The Measures provide various
options that the drafting team considered as ways to demonstrate compliance for
Requirement R6. It is not an exhaustive list, and in no way places an expectation on
any entity that they must provide evidence of another party's compliance. It simply
provides a few options to consider.”
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
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Organization
Yes or No
Question 4 Comment
o Should this proposal fail to pass ballot, we encourage the drafting team to build on
the positive work done in this version and address the compliance concerns that
remain. All stakeholders would be best served if this standard could incent
improvement in communication through effective self-assessment and applied lessons
learned. This iteration presents an opportunity to truly step away from placing the
compliance burden that judges operators for their use of three-part communication
and to focus on programmatic measures to promote effective communication.
Specifically, replacing R5, R6 and R7 with meaningful assessment criteria to include in
entity review programs could increase the qualitative components of the program,
focus on efforts to improve effective communication and remove the zero tolerance
compliance approach that currently exists. o While it’s been difficult to keep
“starting over” with new standard language approaches, we believe that this version
sets solid groundwork to address the hurdles and conflicts of previous approaches.
Should more time be allowed to continue development of this most recent proposal,
we would welcome the chance to discuss our ideas further.
Xcel Energy
Yes
Xcel Energy is voting negative because the standard no longer contains clarity for all
parties on when they have entered an emergency state and therefore 3-part
communication would be required. Since the requirements to conduct 3-part
communication on emergency operating instructions will remain zero tolerance, it is
important that the line of when the entity entered an emergency state be clear to the
registered entities involved as well as ERO compliance and enforcement personnel.
We think incorporating some of the mechanics from COM-002-3 could easily remedy
our concerns. Alternatively, please consider requiring an Operating Instruction that is
issued during an Emergency situation be identified as ‘This is an Emergency.'.
Response: Please see the summary response to Question 1.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
ReliabilityFirst
Yes
Question 4 Comment
ReliabilityFirst submits the following comments for consideration:
1. Requirements R1, R2, R3 and R4 - The term “operating personnel” is used
throughout the draft standard. This term is undefined and it is unclear to which
individuals the communications protocol applies. ReliabilityFirst recommends defining
this term to eliminate any confusion and remove any questions around who
encompasses “operating personnel”. ReliabilityFirst suggests replacing the term
“operating personnel” with the draft PER-005-2 definition of “System Operator” (e.g.,
“An individual at a Control Center of a Balancing Authority, Transmission Operator, or
Reliability Coordinator, who operates or directs the operation of the Bulk Electric
System in Realâ€time.”). ReliabilityFirst believes it is the intent of the standard to
apply to individuals who operate or direct the operation of the Bulk Electric System in
Realâ€time, and not personnel that may be involved in supporting roles.
Response: The OPCP SDT considered the use of the term “System Operator” when
developing the standard. However, since the standard applies to Distribution
Providers and Generator Operators, the term could not be used without altering the
definition, which would impact other standards.
2. Requirement R4a. The intent of Requirement R4
a. R4.1 appears to limit possible violations for deviations to the context of emergency
operations, while only requiring that Responsible Entities to assess and correct
deviations “as appropriate” in the non-Emergency setting. ReliabilityFirst is concerned
that the qualifier “as appropriate” is vague and creates concerns similar to those
expressed by the Commission in Order 791. In Order 791, the Commission supported
the RAI’s goal to develop a framework for the ERO Enterprise’s use of discretion in the
compliance monitoring and enforcement space, but rejected the codification of
“identify, assess, and correct” language within the CIP Version 5 Reliability Standards
because it is vague. ReliabilityFirst is also concerned that the qualifier “as
appropriate” codifies discretion within COM-002-4. ReliabilityFirst believes that
neither discretion nor controls should be codified in Reliability Standards. Rather, the
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 4 Comment
ERO Enterprise should utilize discretion in the compliance monitoring and
enforcement space when determining the relevant scope of audits and whether to
decline to pursue a noncompliance as a violation. With the RAI, the ERO Enterprise is
developing a singular and uniform framework to inform the ERO Enterprise’s use of
discretion in the compliance monitoring and enforcement space.Therefore,
ReliabilityFirst recommends removing the qualifier “as appropriate” from R4.1 and
allowing the ongoing RAI effort to create a meaningful and unambiguous framework
that the ERO Enterprise will utilize to inform its use of discretion in the compliance
monitoring and enforcement of all Reliability Standards. ReliabilityFirst cautions that
codifying discretion in some Reliability Standards may create confusion once the ERO
Enterprise begins to implement RAI discretion in its compliance monitoring and
enforcement work. For example, there may be confusion of whether discretion
codified in certain Requirements of Reliability Standards precludes the ERO
Enterprise’s use of RAI discretion for those Requirements where discretion is not
codified.
Response: The OPCP SDT considered your suggestion and made non-substantive
clarifying changes to the wording of Requirement R4. Concerning your RAI
comment, please see the summary response to Question 1.
b. Flowing from 2.a. above, ReliabilityFirst recommends that Measure 4 be modified to
remove discretion, and should read as follows:M4. Each Balancing Authority,
Reliability Coordinator, and Transmission Operator shall provide evidence of its
assessments, including spreadsheets, logs or other evidence of feedback, findings of
effectiveness and any changes made to its documented communications protocols
developed for Requirement R1 in fulfillment of Requirement R4. The entity shall also
provide evidence that it took appropriate corrective actions as part of its assessment
for all instances of operating personnel’s nonadherence to the protocols developed in
Requirement R1.
Response: The OPCP SDT clarified the language in Measure M4 to better align with
the language in Requirement R4.
Consideration of Comments: Project 2007-02 COM-002-4
Posted: March 27th, 2014
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4
Organization
Yes or No
Question 4 Comment
California ISO
Yes
1. Requirement R4 is an administrative task, not a reliability-related task. The ISO does
not see the value added or where BES reliability is enhanced by R4. 2. The ISO uses an
Automated Dispatch System (ADS) to direct dispatch levels of generation in the ISO
Balancing Authority Area. Though different ADS instructions are sent to multiple
parties (different Generators) each individual instruction is an electronic
communication that is “resource specific” (i.e. - we send one resource an electronic
communication to position its unit at a specific level and another resource a different
electronic communication to position its resource at a different level, etc.) In this
respect the ISO considers the ADS to be a “single-party to single-party” communication
rather than a “single-party to multiple-party burst” communication. The ISO requests
standards drafting team confirmation that it does not interpret R1.4 (or R7 which
contains similar language in the Emergency context) to apply to resource-specific ADS
dispatch instructions.
Response: The OPCP SDT thanks you for your comments. The definition of Operating
Instruction was intentionally written broadly to include many forms of
communication. The Requirements in COM-002-4 only apply to oral and written
Operating Instructions. Electronic dispatch signals are not in the scope of COM-0024.
Tri-State Generation and
Transmission Association Inc.
Yes
Tri-State G&T disagrees with removing the term reliability directive. The proposed
definition for Reliability Directive should be modified to provide technical justification,
as requested in the November 21, 2013 FERC NOPR, and require Reliability
Coordinators to use Reliability Directives to issue instructions to maintain reliable
operations. As addressed in the NOPR, Reliability Directives from an entity responsible
for the reliable operation of the BES should be mandatory at all times, not just during
emergencies. Owners, Operators and others responsible for reliability of the BES have
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 4 Comment
used the term reliability directive effectively for many years. Removing this term does
not enhance the reliability of the BES and places a burden on industry to adjust to
accommodate a new method to accomplish what is done today with reliability
directives. Our proposal is to make Reliability Directives applicable to RC, TOP and
BA’s to ensure reliable operation the BES.
Response: The OPCP SDT addressed this issue in the FAQ document posted on the
project page. The following response was provided: “The OPCP SDT debated
whether to remove the term ‘Reliability Directive’ in response to comments
suggesting it should be removed from the definition of ‘Operating Instruction’ and in
light of FERC’s issuance of the TOP/IRO Notice of Proposed Rulemaking (NOPR),
which proposes to remand the definition of ‘Reliability Directive’ along with the
proposed TOP and IRO standards. To avoid unnecessary complications with the
timing of the NOPR and posting Draft 8, the OPCP SDT consulted with the Project
2007-03 Real-time Transmission Operations and the Project 2006-06 Reliability
Coordination Standard Drafting Teams to ask whether they believed removal of the
term ‘Reliability Directive’ in the COM-002-4 standard would cause concerns. Both
teams agreed that the COM-002-4 standard did not need to require a protocol to
identify Reliability Directives as such and that the definition of Operating Instruction
could be used absent the term Reliability Directive in COM-002-4 to set the
protocols. The OPCP SDT ultimately voted to remove the term. The OPCP SDT also
decided to incorporate the phrase ‘Operating Instruction during an Emergency’ in
certain Requirements, where needed, to identify Requirements that are subject to a
zero-tolerance compliance/enforcement approach.”
The term Operating Instructions should be applicable to Operators who issue
commands to control elements essential to the reliable operation of the BES. We do
not believe the term, as currently defined, should apply to Reliability Coordinators.
According to the NERC Functional Model, Reliability Coordinators are not real time
operators and are not operating personnel. Reliability Coordinators oversee the
reliability of the BES and direct real time operations as needed to assure reliability of
the BES.TSGT requests clarification of the term operating personnel, which positions is
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
Yes or No
Question 4 Comment
this term referring to? As previously stated, if operating personnel are the personnel
that operate BES elements, then operating personnel should not include Reliability
Coordinators since that is not the role they currently provide.
Response: Since Reliability Coordinators “direct Real-time operations as needed to
assure reliability of the BES,” they can issue Operating Instructions and, as such,
must be applicable entities to this standard.
TSGT requests clarification on the proposed multiple-party burst communication. This
method of communication is not widely used and we are concerned that the use of
this type of communication may create additional reliability issues.
Response: Information about multiple-party burst communication may be found in
the Operating Committee “Reliability Guideline: System Operator Verbal
Communications – Current Industry Practices” located
at http://www.nerc.com/comm/OC/Related%20Files%20DL/OC%20Approved_COM002-2%20Guideline_6-242012_For%20Posting_w%20line%20numbers_Clean_Version%202.pdf.
TSGT requests a clarification of time identification in R1.5.
Response: Please see the summary response to Question 1.
The Empire District Electric
Company
Yes
I feel that the requiment to an assessment to communication protocols is somewhat
excessive and should be left as a part of the audit process or following NERCs RAI
directive be left up to the internal compliance department of the company rather than
having this as a requirement in the standard.
Response: Please see the summary response to Question 1.
Consideration of Comments: Project 2007-02 COM-002-4
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Organization
HHWP
Yes or No
Question 4 Comment
Yes
I appreciate the work done on this Standard by the OPCP SDT. The current version of
the draft is much improved. I propose one change before supporting this proposed
standard. That change is in Requirement 4 where I believe the standard would be
improved by replacing the "at least once every twelve (12) calendar months" language
with "at least annually, with no more than X months between reviews." Such a change
to the language or Requirement 4 would allow each entity to determine the best cycle
for its review of adherence to and effectiveness of its communications protocols per
CAN-0010. If that language is used, I believe that 15 months is an appropriate value
for 'X'.
Response: The OPCP SDT considered your suggestion but asserts that the existing
language provides sufficient clarity.
Additional Comments
Avista Utilities
Scott Kinney
Comment:
Although we believe the team made significant improvements to the standard, and support a 3-part communication standard, we are
concerned that the scope of the standard and the sheer number of operating communications may overwhelm entities in terms of
monitoring and evidence retention. COM-002-4 will require all communication channels to not just be recorded (which is done today)
but will require a sampling of the recordings to be reviewed by compliance personal for self-monitoring purposes, provide documented
feedback to operating personnel and provide samples to auditors. This standard may result in the registered entities spending more
time monitoring and collecting data than the realized reliability benefits. Also, the evidence that is produced and provided to the
auditors leaves much open for interpretation. We are concerned an auditor may not be able to differentiate between ‘emergency’ and
‘non emergency’ operating instructions for audit purposes.
Consideration of Comments: Project 2007-02 COM-002-4
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Response: Please see the summary response to Question 1.
END OF REPORT
Consideration of Comments: Project 2007-02 COM-002-4
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20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COM-002-4 – Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting of the SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of COM-003-1 Standard posted November 2009 for Informal Comments
closed January 15, 2010.
7. Version 2 draft of COM-003-1 Standard posted May 2012 for Formal Comments, Initial
Ballot closed June 20, 2012.
8. Version 3 draft of COM-003-1 Standard posted August 2012 for Formal Comments,
Ballot closed September 22, 2012.
9.
Version 4 draft of COM-003-1 Standard posted November 2012 for Formal Comments,
Ballot closed December 13, 2012.
10. Version 5 draft of COM-003-1 Standard posted March 2013 for Formal Comments,
Ballot closed April 5, 2013.
11. Version 6 draft of COM-003-1 Standard posted June 2013 for Formal Comments, Ballot
closed July 19, 2013.
12. COM-003-1 renumbered as COM-002-4. Posting 7, Version 1 draft of COM-002-4
Standard posted October 2013 for Formal Comment, Ballot closed November 7, 2013.
13. On December 12, 2013, the SC approved a waiver of the Standard Processes Manual to
shorten the formal comment and ballot period, from 45 days to 30 days.
14. Version 2, Posting 8, draft of COM-002-4 Standard posted January 2014 for Formal
Comment, Ballot closed February 4, 2014.
Description of Current Draft:
This is the second draft of a revised standard (eighth posting of a communications standard)
requiring the use of standardized communication protocols during normal and emergency
operations to improve situational awareness and shorten response time. The standard drafting
team is posting this standard for a final 10 day ballot period.
Future Development Plan:
Anticipated Actions
Posting 8
March 27, 2014
Anticipated Date
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COM-002-4 – Operating Personnel Communications Protocols
1. Board adopts standard
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May 2014
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COM-002-4 – Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Operating Instruction -A command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. (A discussion of general information and of potential options or alternatives to resolve
Bulk Electric System operating concerns is not a command and is not considered an Operating
Instruction.)
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COM-002-4 – Operating Personnel Communications Protocols
A. Introduction
1. Title: Operating Personnel Communications Protocols
2. Number:
COM-002-4
3. Purpose:
To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4. Applicability:
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
Effective Date: The standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is
twelve (12) months after the date the standard is adopted by the NERC Board of
Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop documented communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a minimum: [Violation
Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
Posting 8
March 27, 2014
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver.
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COM-002-4 – Operating Personnel Communications Protocols
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
conduct initial training for each of its operating personnel responsible for the Realtime operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual
operator issuing an Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall conduct initial training for
each of its operating personnel who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator receiving an oral two-party,
person-to-person Operating Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
at least once every twelve (12) calendar months: [Violation Risk Factor:
Medium][Time Horizon: Operations Planning]
4.1. Assess adherence to the documented communications protocols in Requirement
R1 by its operating personnel that issue and receive Operating Instructions,
provide feedback to those operating personnel and take corrective action, as
deemed appropriate by the entity, to address deviations from the documented
protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
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COM-002-4 – Operating Personnel Communications Protocols
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues an oral two-party, person-to-person Operating Instruction during an
Emergency, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
•
Confirm the receiver’s response if the repeated information is correct (in
accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R7. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction. [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its initial training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its initial training
records for its operating personnel such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence of its assessments, including spreadsheets, logs or other evidence of
feedback, findings of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in fulfillment of
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COM-002-4 – Operating Personnel Communications Protocols
Requirement R4. The entity shall provide, as part of its assessment, evidence of any
corrective actions taken where an operating personnel’s non-adherence to the protocols
developed in Requirement R1 is the sole or partial cause of an Emergency and for all
other instances where the entity determined that it was appropriate to take a corrective
action to address deviations from the documented protocols developed in Requirement
R1.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issued an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from the recipient of the
Operating Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence could include, but is not limited to, dated and timestamped voice recordings, or dated and time-stamped transcripts of voice recordings, or
dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings (if the entity has such
recordings), dated operator logs, an attestation from the issuer of the Operating
Instruction, memos or transcripts.
M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator that
issued a written or oral single or multiple-party burst Operating Instruction during an
Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings (if the entity has such recordings), dated operator logs,
electronic records, memos or transcripts.
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
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COM-002-4 – Operating Personnel Communications Protocols
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Posting 8
March 27, 2014
Page 8 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity
did not specify the
instances that require
time identification
when issuing an oral
or written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.5
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.1. An alternate
language may be used for
internal operations.
The responsible entity did
not include Requirement
R1, Part 1.4 in its
documented
communication protocols.
The responsible entity did not
include Requirement R1, Part
1.2 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
OR
The responsible entity
did not specify the
nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.6.
Draft 8
March 27, 2014
Severe VSL
Page 9 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R2
Long-term
Planning
Low
N/A
N/A
An individual operator
responsible for the Realtime operation of the
interconnected Bulk
Electric System at the
responsible entity issued
an Operating Instruction,
prior to being trained on
the documented
communications protocols
developed in Requirement
R1.
An individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity issued an
Operating Instruction during an
Emergency prior to being trained
on the documented
communications protocols
developed in Requirement R1.
R3
Long-term
Planning
Low
N/A
N/A
An individual operator at
the responsible entity
received an Operating
Instruction prior to being
trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
Draft 8
March 27, 2014
Page 10 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Operations
Planning
Medium
The responsible entity
assessed adherence to
the documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible entity
assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive Operating
Instructions and
modified its
documented
communication
Draft 8
March 27, 2014
Moderate VSL
High VSL
Severe VSL
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions, but
did not provide feedback
to those operating
personnel
The responsible entity did
not assess adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating
Instructions
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions and
provided feedback to those
operating personnel but
did not take corrective
action, as appropriate
OR
The responsible entity did
not assess the
effectiveness of its
documented
communications protocols
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
Page 11 of 15
AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for
its operating personnel that issue
and receive Operating
Instructions.
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
protocols, as
necessary
AND
The responsible entity
exceeded twelve (12)
calendar months
between assessments.
Draft 8
March 27, 2014
Moderate VSL
High VSL
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions, but
did not modify its
documented
communication protocols,
as necessary.
Page 12 of 15
Severe VSL
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R5
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity that
issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
Draft 8
March 27, 2014
High VSL
N/A
Severe VSL
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
Confirmed the
receiver’s response if
the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating Instruction
if the repeated
information was
incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or if
the Operating
Instruction was not
understood by the
receiver.
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the Operating
Instruction was not
understood by the receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Page 13 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R6
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request that
the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
High VSL
N/A
Severe VSL
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or oral
single-party to multipleparty burst Operating
Instruction during an
Emergency did not
confirm or verify that the
Operating Instruction was
received by at least one
receiver of the Operating
Instruction.
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
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COM-002-4 – Operating Personnel Communications Protocols
E. Regional Variances
None
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
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COM-002-4 – Operating Personnel Communications Protocols
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The Standards Committee (SC) approved the Standard Authorization Request (SAR) for
posting on March 1, 2007.
2. The SAR was posted for comment from March 19 through April 17, 2007.
3. The SC sought SAR drafting team nominations April 18 through May 2, 2007.
4. The SAR drafting team posted reply comments to industry comments received on the
first posting of the SAR on June 8, 2007.
5. Standard drafting team appointed by SC Executive Committee on June 28, 2007.
6. Version 1 draft of COM-003-1 Standard posted November 2009 for Informal Comments
closed January 15, 2010.
7. Version 2 draft of COM-003-1 Standard posted May 2012 for Formal Comments, Initial
Ballot closed June 20, 2012.
8. Version 3 draft of COM-003-1 Standard posted August 2012 for Formal Comments,
Ballot closed September 22, 2012.
9.
Version 4 draft of COM-003-1 Standard posted November 2012 for Formal Comments,
Ballot closed December 13, 2012.
10. Version 5 draft of COM-003-1 Standard posted March 2013 for Formal Comments,
Ballot closed April 5, 2013.
11. Version 6 draft of COM-003-1 Standard posted June 2013 for Formal Comments, Ballot
closed July 19, 2013.
12. COM-003-1 renumbered as COM-002-4. Posting 7, Version 1 draft of COM-002-4
Standard posted October 2013 for Formal Comments, Ballot closed November 7, 2013.
13. On December 12, 2013, the Standards Committee SC approved a waiver of the Standard
Processes Manual to shorten the formal comment and ballot period, from 45 days to 30
days.
13.14.
Version 2, Posting 8, draft of COM-002-4 Standard posted January 2014 for
Formal Comment, Ballot closed February 4, 2014.
Description of Current Draft:
This is the second draft of a revised standard (eighth posting of a communications standard)
requiring the use of standardized communication protocols during normal and emergency
operations to improve situational awareness and shorten response time. The standard drafting
team is posting this standard for a shortened 30 day formal Comment and 10 day Ballot period
per the Standards Committee wavierfinal 10 day ballot period.
Future Development Plan:
Posting 8
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COM-002-4 – Operating Personnel Communications Protocols
Anticipated Actions
Anticipated Date
1. Additional ballot of Standard
January 2014
2. Final ballot of Standard
February March 2014
3.1.Board adopts standard
TBDMay 2014
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COM-002-4 – Operating Personnel Communications Protocols
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Operating Instruction -— A command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System to change or preserve the state, status,
output, or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. (A discussion of general information and of potential options or alternatives to resolve
Bulk Electric System operating concerns is not a command and is not considered an Operating
Instruction.)
Posting 8
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COM-002-4 – Operating Personnel Communications Protocols
A. Introduction
1. Title: Operating Personnel Communications Protocols
2. Number:
COM-002-4
3. Purpose:
To improve communications for the issuance of Operating Instructions
with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the
Bulk Electric System (BES).
4. Applicability:
4.1. Functional Entities
5.
4.1.1
Balancing Authority
4.1.2
Distribution Provider
4.1.3
Reliability Coordinator
4.1.4
Transmission Operator
4.1.5
Generator Operator
(Proposed) Effective Date: The standard shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is
not required, the standard shall become effective on the first day of the first calendar
quarter that is twelve (12) months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
B. Requirements
R1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
develop documented communications protocols for its operating personnel that issue
and receive Operating Instructions. The protocols shall, at a minimum: [Violation
Risk Factor: Low][Time Horizon: Long-term Planning]
1.1. Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
Confirm the receiver’s response if the repeated information is correct.
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver.
Posting 8
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COM-002-4 – Operating Personnel Communications Protocols
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
1.3. Require its operating personnel that receive an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the
Operating Instruction was received by at least one receiver of the Operating
Instruction.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
1.6. Specify the nomenclature for Transmission interface Elements and
Transmission interface Facilities when issuing an oral or written Operating
Instruction.
R2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
conduct initial training for each of its operating personnel responsible for the Realtime operation of the interconnected Bulk Electric System on the documented
communications protocols developed in Requirement R1 prior to that individual
operator issuing an Operating Instruction. [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
R3. Each Distribution Provider and Generator Operator shall conduct initial training for
each of its operating personnel who can receive an oral two-party, person-to-person
Operating Instruction prior to that individual operator receiving an oral two-party,
person-to-person Operating Instruction to either: [Violation Risk Factor: Low][Time
Horizon: Long-term Planning]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
at least once every twelve (12) calendar months: [Violation Risk Factor:
Medium][Time Horizon: Operations Planning]
4.1. Assess adherence to the documented communications protocols in Requirement
R1 by its operating personnel that issue and receive Operating Instructions,
provide feedback to those operating personnel and take corrective action, as
deemed appropriate by the entity, to address deviations from the documented
protocols.
4.2. Assess the effectiveness of its documented communications protocols in
Requirement R1 for its operating personnel that issue and receive Operating
Instructions and modify its documented communication protocols, as necessary.
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December March 3027, 2013 2014
Page 5 of 15
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COM-002-4 – Operating Personnel Communications Protocols
R5. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues an oral two-party, person-to-person Operating Instruction during an Emerge
ncy, excluding written or oral single-party to multiple-party burst Operating
Instructions, shall either: [Violation Risk Factor: High][Time Horizon: Real-time
Operations]
•
Confirm the receiver’s response if the repeated information is correct (in
accordance with Requirement R6).
•
Reissue the Operating Instruction if the repeated information is incorrect
or if requested by the receiver, or
•
Take an alternative action if a response is not received or if the Operating
Instruction was not understood by the receiver.
R6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that receives an oral two-party, person-to-person Operating
Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, shall either: [Violation Risk Factor: High][Time
Horizon: Real-time Operations]
•
Repeat, not necessarily verbatim, the Operating Instruction and receive
confirmation from the issuer that the response was correct, or
•
Request that the issuer reissue the Operating Instruction.
R7. Each Balancing Authority, Reliability Coordinator, and Transmission Operator that
issues a written or oral single-party to multiple-party burst Operating Instruction
during an Emergency shall confirm or verify that the Operating Instruction was
received by at least one receiver of the Operating Instruction. [Violation Risk Factor:
High][Time Horizon: Real-time Operations]
C. Measures
M1. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its documented communications protocols developed for Requirement R1.
M2. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide its initial training records related to its documented communications protocols
developed for Requirement R1 such as attendance logs, agendas, learning objectives, or
course materials in fulfillment of Requirement R2.
M3. Each Distribution Provider and Generator Operator shall provide its initial training
records for its operating personnel such as attendance logs, agendas, learning
objectives, or course materials in fulfillment of Requirement R3.
M4. Each Balancing Authority, Reliability Coordinator, and Transmission Operator shall
provide evidence of its assessments, including spreadsheets, logs or other evidence of
feedback, findings of effectiveness and any changes made to its documented
communications protocols developed for Requirement R1 in fulfillment of
Posting 8
December March 3027, 2013 2014
Page 6 of 15
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COM-002-4 – Operating Personnel Communications Protocols
Requirement R4. The entity shall provide, as part of its assessment, evidence of any
corrective actions taken that it took appropriate corrective actions as part of its
assessment for all instances where an operating personnel’s non-adherence to the
protocols developed in Requirement R1 is the sole or partial cause of an Emergency
and for all other instances where the entity determined that it was appropriate to take a
corrective action to address deviations from the documented protocols developed in
Requirement R1.
M5. Each Reliability Coordinator, Transmission Operator, and Balancing Authority that
issued an oral two-party, person-to-person Operating Instruction during an Emergency,
excluding oral single-party to multiple-party burst Operating Instructions, shall have
evidence that the issuer either: 1) confirmed that the response from the recipient of the
Operating Instruction was correct; 2) reissued the Operating Instruction if the repeated
information was incorrect or if requested by the receiver; or 3) took an alternative
action if a response was not received or if the Operating Instruction was not understood
by the receiver. Such evidence could include, but is not limited to, dated and timestamped voice recordings, or dated and time-stamped transcripts of voice recordings, or
dated operator logs in fulfillment of Requirement R5.
M6. Each Balancing Authority, Distribution Provider, Generator Operator, and
Transmission Operator that was the recipient of an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding oral single-party to multipleparty burst Operating Instructions, shall have evidence to show that the recipient either
repeated, not necessarily verbatim, the Operating Instruction and received confirmation
from the issuer that the response was correct, or requested that the issuer reissue the
Operating Instruction in fulfillment of Requirement R6. Such evidence may include,
but is not limited to, dated and time-stamped voice recordings (if the entity has such
recordings), dated operator logs, an attestation from the issuer of the Operating
Instruction, voice recordings (if the entity has such recordings), memos or transcripts.
M7. Each Balancing Authority, Reliability Coordinator and Transmission Operator that
issued a written or oral single or multiple-party burst Operating Instruction during an
Emergency shall provide evidence that the Operating Instruction was received by at
least one receiver. Such evidence may include, but is not limited to, dated and timestamped voice recordings (if the entity has such recordings), dated operator logs,
electronic records, voice recordings (if the entity has such recordings), memos or
transcripts.
D. Compliance
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority
As defined in the NERC Rules of Procedure, “Compliance Enforcement
Authority” means NERC or the Regional Entity in their respective roles of
monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Data Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
Posting 8
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COM-002-4 – Operating Personnel Communications Protocols
where the evidence retention period specified below is shorter than the time since
the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period since
the last audit.
Each Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, and Transmission Operator shall each keep data or evidence for each
applicable Requirement for the current calendar year and one previous calendar
year, with the exception of voice recordings which shall be retained for a
minimum of 90 calendar days, unless directed by its Compliance Enforcement
Authority to retain specific evidence for a longer period of time as part of an
investigation.
If a Balancing Authority, Distribution Provider, Generator Operator, Reliability
Coordinator, or Transmission Operator is found non-compliant, it shall keep
information related to the non-compliance until mitigation is complete and
approved or for the time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
Compliance Monitoring and Assessment Processes
Compliance Audit
Self-Certification
Spot Checking
Compliance Investigation
Self-Reporting
Complaint
1.3. Additional Compliance Information
None
Posting 8
December March 3027, 2013 2014
Page 8 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
R1
Time
Horizon
Long-term
Planning
VRF
Low
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
The responsible entity
did not specify the
instances that require
time identification
when issuing an oral
or written Operating
Instruction and the
format for that time
identification, as
required in
Requirement R1, Part
1.5
The responsible entity did
not require the issuer and
receiver of an oral or
written Operating
Instruction to use the
English language, unless
agreed to otherwise, as
required in Requirement
R1, Part 1.1. An alternate
language may be used for
internal operations.
The responsible entity did
not include Requirement
R1, Part 1.4 in its
documented
communication protocols.
The responsible entity did not
include Requirement R1, Part
1.2 in its documented
communications protocols
OR
The responsible entity did not
include Requirement R1, Part
1.3 in its documented
communications protocols
OR
The responsible entity did not
develop any documented
communications protocols as
required in Requirement R1.
OR
The responsible entity
did not specify the
nomenclature for
Transmission
interface Elements
and Transmission
interface Facilities
when issuing an oral
or written Operating
Instruction, as
required in
Requirement R1, Part
1.6.
Draft 8
December March 3127, 20132014
Severe VSL
Page 9 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
Moderate VSL
High VSL
Severe VSL
R2
Long-term
Planning
Low
N/A
N/A
An individual operator
responsible for the Realtime operation of the
interconnected Bulk
Electric System at the
responsible entity issued
an Operating Instruction,
prior to being trained on
the documented
communications protocols
developed in Requirement
R1.
An individual operator
responsible for the Real-time
operation of the interconnected
Bulk Electric System at the
responsible entity issued an
Operating Instruction during an
Emergency prior to being trained
on the documented
communications protocols
developed in Requirement R1.
R3
Long-term
Planning
Low
N/A
N/A
An individual operator at
the responsible entity
received an Operating
Instruction prior to being
trained.
An individual operator at the
responsible entity received an
Operating Instruction during an
Emergency prior to being
trained.
Draft 8
December March 3127, 20132014
Page 10 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R4
Operations
Medium
Planning
The responsible entity
assessed adherence to
the documented
communications
protocols in
Requirements R1 by
its operating
personnel that issue
and receive Operating
Instructions and
provided feedback to
those operating
personnel and took
corrective action, as
appropriate
AND
The responsible entity
assessed the
effectiveness of its
documented
communications
protocols in
Requirement R1 for
its operating
personnel that issue
and receive Operating
Instructions and
modified its
documented
communication
Draft 8
December March 3127, 20132014
Moderate VSL
High VSL
Severe VSL
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirement R1 by its
operating personnel that
issue and receive
Operating Instructions, but
did not provide feedback
to those operating
personnel
The responsible entity did
not assess adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions
The responsible entity did not
assess adherence to the
documented communications
protocols in Requirements R1 by
its operating personnel that issue
and receive Operating
Instructions
OR
The responsible entity
assessed adherence to the
documented
communications protocols
in Requirements R1 by its
operating personnel that
issue and receive
Operating Instructions and
provided feedback to those
operating personnel but
did not take corrective
action, as appropriate
OR
The responsible entity did
not assess the
effectiveness of its
documented
communications protocols
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions.
OR
The responsible entity
assessed the effectiveness
of its documented
communications protocols
Page 11 of 15
AND
The responsible entity did not
assess the effectiveness of its
documented communications
protocols in Requirement R1 for
its operating personnel that issue
and receive Operating
Instructions.
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
protocols, as
necessary
AND
The responsible entity
exceeded twelve (12)
calendar months
between assessments.
Draft 8
December March 3127, 20132014
Moderate VSL
High VSL
in Requirement R1 for its
operating personnel that
issue and receive
Operating Instructions, but
did not modify its
documented
communication protocols,
as necessary.
Page 12 of 15
Severe VSL
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R5
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity that
issued an Operating
Instruction during an
Emergency did not take
one of the following
actions:
•
•
•
Draft 8
December March 3127, 20132014
High VSL
N/A
Severe VSL
The responsible entity that
issued an Operating Instruction
during an Emergency did not
take one of the following
actions:
Confirmed the
receiver’s response if
the repeated
information was
correct (in
accordance with
Requirement R6).
Reissued the
Operating Instruction
if the repeated
information was
incorrect or if
requested by the
receiver.
Took an alternative
action if a response
was not received or if
the Operating
Instruction was not
understood by the
receiver.
•
Confirmed the receiver’s
response if the repeated
information was correct (in
accordance with
Requirement R6).
•
Reissued the Operating
Instruction if the repeated
information was incorrect
or if requested by the
receiver.
•
Took an alternative action
if a response was not
received or if the Operating
Instruction was not
understood by the receiver.
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Page 13 of 15
COM-002-4 – Operating Personnel Communications Protocols
R#
Time
Horizon
VRF
Violation Severity Levels
Lower VSL
R6
Real-time
Operations
High
N/A
Moderate VSL
The responsible entity did
not repeat, not necessarily
verbatim, the Operating
Instruction during an
Emergency and receive
confirmation from the
issuer that the response
was correct, or request that
the issuer reissue the
Operating Instruction
when receiving an
Operating Instruction.
High VSL
N/A
Severe VSL
The responsible entity did not
repeat, not necessarily verbatim,
the Operating Instruction during
an Emergency and receive
confirmation from the issuer that
the response was correct, or
request that the issuer reissue the
Operating Instruction when
receiving an Operating
Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
R7
Real-time
Operations
High
N/A
The responsible entity that N/A
that issued a written or oral
single-party to multipleparty burst Operating
Instruction during an
Emergency did not
confirm or verify that the
Operating Instruction was
received by at least one
receiver of the Operating
Instruction.
The responsible entity that that
issued a written or oral singleparty to multiple-party burst
Operating Instruction during an
Emergency did not confirm or
verify that the Operating
Instruction was received by at
least one receiver of the
Operating Instruction
AND
Instability, uncontrolled
separation, or cascading failures
occurred as a result.
Draft 8
December March 3127, 20132014
Page 14 of 15
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COM-002-4 – Operating Personnel Communications Protocols
E. Regional Variances
None
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
August 8, 2005
Removed “Proposed” from Effective
Date
Errata
1
February 7,
2006
Adopted by Board of Trustees
Added measures and
compliance elements
2
November 1,
2006
Adopted by Board of Trustees
Revised in accordance
with SAR for Project
2006-06, Reliability
Coordination (RC
SDT). Retired R1,
R1.1, M1, M2 and
updated the compliance
monitoring
information. Replaced
R2 with new R1, R2
and R3.
2a
February 9,
2012
Interpretation of R2 adopted by Board
of Trustees
Project 2009-22
3
November 7,
2012
Adopted by Board of Trustees
Draft 8
December March 3127, 20132014
Page 15 of 15
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
• COM-002-4 – Operating Personnel Communications Protocols
Retirements:
• COM-001-1.1 Requirement R4 – Telecommunications
• COM-002-2 – Communication and Coordination
• COM-002-3 – Communication and Coordination
Prerequisite Approvals
None
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real-time operation of the interconnected Bulk
Electric System to change or preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A discussion of general information and of
potential options or alternatives to resolve Bulk Electric System operating concerns is not a command
and is not considered an Operating Instruction.)
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
None
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Effective Date
COM-002-4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM-001-1.1 Requirement R4, COM-002-2, and COM-002-3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM-002-4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Implementation Plan
Operating Personnel Communications Protocols
COM-002-4
Standards Involved
Approval:
• COM-002-4 – Operating Personnel Communications Protocols
Retirements:
• COM-001-1.1 Requirement R4 – Telecommunications
• COM-002-2 – Communication and Coordination
• COM-002-3 – Communication and Coordination
Prerequisite Approvals
None
Approval of the definition of “Reliability Directive”
Revisions to Glossary
The following term is proposed for addition to the NERC Glossary of Terms:
Operating Instruction —
A command by operating personnel responsible for the Real-time generation control and operation of
the interconnected Bulk Electric System to change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System. (A discussion of general
information and of potential options or alternatives to resolve Bulk Electric System operating concerns
is not a command and is not considered an Operating Instruction.) . A Reliability Directive is one type
of an Operating Instruction.
Applicable Entities
Balancing Authority
Distribution Provider
Generator Operator
Reliability Coordinator
Transmission Operator
Conforming Changes to Other Standards
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
None
Effective Date
COM-002-4 and the definition of “Operating Instruction” shall become effective on the first day of the
first calendar quarter that is twelve (12) months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where approval by an
applicable governmental authority is not required, the standard shall become effective on the first day
of the first calendar quarter that is twelve (12) months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.
Retirement of Existing Standards:
COM-001-1.1 Requirement R4, COM-002-2, and COM-002-3, as applicable, shall be retired at midnight
of the day immediately prior to the effective date of COM-002-4 in the particular jurdisdiction in which
the new standard is becoming effective.
Implementation Plan for Project 2007-02 – Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
Final Ballot Now Open through April 7th, 2014
Now Available
A final ballot for COM-002-4 – Operating Personnel Communications Protocols is open through 8
p.m. Eastern on Monday, April 7th, 2014.
Background information for this project can be found on the project page.
As a result of select industry stakeholder comments, the Operating Personnel Communications
Protocols Standards Drafting Team (OPCP SDT) made minor, non-substantive changes to COM-002-4
after the most recent comment and ballot period in order to clarify the OPCP SDT’s intent and better
align the language in the measures with the requirements. Requirement R4.1 was altered from “as
appropriate” to “as deemed appropriate by the entity” in order to highlight the OPCP SDT’s
intent. In Measure M2 the words “its initial” were added to the sentence “shall provide its initial
training records . . .” in order to align the language in Measure M2 with the language in Requirement
R2. Measure M4 was altered to include the phrase “as part of its assessment” and “of any corrective
actions taken” within the sentence “The entity shall provide, as part of its assessment, evidence of
any corrective actions taken.” Lastly, Measure M6 and M7 were changed to add the parenthetical “(if
an entity has such recordings)” after the words “time-stamped recordings,” and the second entry for
“time-stamped recordings” was removed due to redundancy.
Instructions
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their previously cast votes. A ballot pool member who failed to
cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a ballot
pool member does not participate in the final ballot, that member’s vote cast in the previous ballot
will be carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Next Steps
Voting results for the standard will be posted and announced after the ballot window closes. If
approved, the standard will be submitted to the Board of Trustees for adoption.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
2
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Standards Announcement
Project 2007-02 Operating Personnel Communications Protocols
COM-002-4
Final Ballot Results
Now Available
A final ballot of COM-002-4 – Operating Personnel Communications Protocols concluded at 8 p.m.
Eastern on Monday, April 7, 2014.
The standard achieved a quorum and received sufficient votes for approval. Voting statistics are
listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Ballot Results
Quorum: 78.21%
Approval: 77.62%
Background information for this project can be found on the project page.
Next Steps
The standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
For information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Newsroom • Site Map • Contact NERC
Advanced Search
Log In
Ballot Results
Ballot Name: Project 2007-02 COM-002-4 Final Ballot
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
Home Page
Ballot Period: 3/28/2014 - 4/7/2014
Ballot Type: Final
Total # Votes: 323
Total Ballot Pool: 413
Quorum: 78.21 % The Quorum has been reached
Weighted Segment
77.62 %
Vote:
A quorum was reached and there were sufficient affirmative votes for
Ballot Results: approval.
Summary of Ballot Results
Affirmative
Negative
Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
9
107
1
56
0.675
27
0.325
0
5
19
11
0.8
8
0.8
0
0
0
2
1
97
1
46
0.676
22
0.324
0
4
25
39
1
20
0.741
7
0.259
0
0
12
88
1
47
0.746
16
0.254
0
5
20
50
1
34
0.773
10
0.227
0
1
5
0
0
0
0
0
0
0
0
0
7
0.3
2
0.2
1
0.1
0
0
4
5
0.1
1
0.1
0
0
0
0
4
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
10 Segment
10
Totals
9
0.9
8
0.8
1
0.1
0
0
0
413
7.1
222
5.511
84
1.589
0
17
90
Individual Ballot Pool Results
Ballot
Segment
Organization
Member
1
Ameren Services
Kirit Shah
1
American Electric Power
Paul B Johnson
1
1
American Transmission Company, LLC
Arizona Public Service Co.
Andrew Z Pusztai
Robert Smith
1
Associated Electric Cooperative, Inc.
John Bussman
1
1
1
1
1
1
1
1
1
ATCO Electric
Austin Energy
Avista Corp.
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Glen Sutton
James Armke
Scott J Kinney
Kevin Smith
Gregory S Miller
Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
1
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
1
1
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
John C Fontenot
John Brockhan
1
Central Electric Power Cooperative
1
City of Pasadena
Marco A Sustaita
City of Tacoma, Department of Public Utilities,
Chang G Choi
Light Division, dba Tacoma Power
1
Michael B Bax
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
1
City Utilities of Springfield, Missouri
Jeff Knottek
1
1
1
1
1
1
1
1
1
1
City Water, Light & Power of Springfield
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Shaun Anders
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
1
Dominion Virginia Power
Michael S Crowley
1
Duke Energy Carolina
Doug E Hils
Negative
1
Empire District Electric Co.
Ralph F Meyer
Negative
1
Entergy Services, Inc.
Edward J Davis
Affirmative
1
1
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
William J Smith
Dennis Minton
Affirmative
Affirmative
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
NERC
Notes
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
1
Florida Power & Light Co.
Gainesville Regional Utilities
Mike O'Neil
Richard Bachmeier
1
Georgia Transmission Corporation
Jason Snodgrass
1
Gordon Pietsch
1
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JEA
Ted Hobson
1
KAMO Electric Cooperative
Walter Kenyon
Negative
1
Kansas City Power & Light Co.
Michael Gammon
Negative
1
1
1
1
1
1
1
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
LG&E Energy Transmission Services
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
Stanley T Rzad
Larry E Watt
John W Delucca
Bradley C. Young
Robert Ganley
John Burnett
Martyn Turner
1
M & A Electric Power Cooperative
William Price
1
1
1
1
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnesota Power, Inc.
Joe D Petaski
Danny Dees
Terry Harbour
Randi K. Nyholm
1
N.W. Electric Power Cooperative, Inc.
Mark Ramsey
Negative
1
National Grid USA
Michael Jones
Affirmative
1
Nebraska Public Power District
Cole C Brodine
Negative
1
1
New York Power Authority
New York State Electric & Gas Corp.
Bruce Metruck
Raymond P Kinney
1
Northeast Missouri Electric Power Cooperative Kevin White
1
1
1
1
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
1
1
1
1
1
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine
Affirmative
Affirmative
Affirmative
Michael Moltane
Abstain
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
1
Oklahoma Gas and Electric Co.
Marvin E VanBebber
1
1
1
1
1
1
1
1
1
1
1
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County,
Doug Peterchuck
Jen Fiegel
Brad Chase
Bangalore Vijayraghavan
Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
- SPP Stnd
Review
Team
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
1
Rod Noteboom
1
1
1
1
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Affirmative
Affirmative
Affirmative
Affirmative
1
Santee Cooper
Terry L Blackwell
Negative
1
Seattle City Light
Pawel Krupa
1
Sho-Me Power Electric Cooperative
Denise Stevens
1
1
1
1
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Services, Inc.
Rich Salgo
Long T Duong
Steven Mavis
Robert A. Schaffeld
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
1
Southern Illinois Power Coop.
William Hutchison
Negative
1
Southwest Transmission Cooperative, Inc.
John Shaver
Negative
1
Sunflower Electric Power Corporation
Noman Lee Williams
Negative
1
Tampa Electric Co.
Beth Young
1
Tennessee Valley Authority
Larry G Akens
Negative
1
Trans Bay Cable LLC
Steven Powell
Affirmative
1
Tri-State G & T Association, Inc.
Tracy Sliman
Negative
1
Tucson Electric Power Co.
John Tolo
1
United Illuminating Co.
Jonathan Appelbaum
1
1
Westar Energy
Western Area Power Administration
Allen Klassen
Brandy A Dunn
1
Xcel Energy, Inc.
Gregory L Pieper
2
Alberta Electric System Operator
2
BC Hydro
2
2
2
2
2
2
2
2
2
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
3
Alabama Power Company
Richard J. Mandes
3
Alameda Municipal Power
Douglas Draeger
3
Ameren Services
3
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Mark Peters
Affirmative
COMMENT
RECEIVED
APS
Steven Norris
Affirmative
3
Associated Electric Cooperative, Inc.
Chris W Bolick
Negative
3
3
3
3
3
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Blachly-Lane Electric Co-op
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Bud Tracy
Rebecca Berdahl
3
Dave Markham
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
Affirmative
Abstain
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
3
Central Electric Power Cooperative
Adam M Weber
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of Lodi, California
City of Palo Alto
City of Redding
City of Ukiah
City Water, Light & Power of Springfield
Clearwater Power Co.
Cleco Corporation
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
Elizabeth Kirkley
Eric R Scott
Bill Hughes
Colin Murphey
Roger Powers
Dave Hagen
Michelle A Corley
3
Colorado Springs Utilities
Charles Morgan
3
3
3
3
3
3
3
3
3
3
3
3
3
3
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Entergy
Fall River Rural Electric Cooperative
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Bruce Krawczyk
Peter T Yost
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Joel T Plessinger
Bryan Case
Stephan Kern
Joe McKinney
3
Florida Power Corporation
Lee Schuster
Negative
3
Georgia System Operations Corporation
Scott McGough
Negative
3
3
Great River Energy
Hydro One Networks, Inc.
Brian Glover
David Kiguel
3
KAMO Electric Cooperative
Theodore J Hilmes
3
3
3
3
3
3
3
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lane Electric Cooperative, Inc.
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
Charles Locke
Gregory D Woessner
Mace D Hunter
Rick Crinklaw
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
3
M & A Electric Power Cooperative
Stephen D Pogue
3
3
3
3
3
3
3
3
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Greg C. Parent
Thomas C. Mielnik
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
3
Northeast Missouri Electric Power Cooperative Skyler Wiegmann
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COMMENTS
3
3
Northern Indiana Public Service Co.
Northern Lights Inc.
William SeDoris
Jon Shelby
Affirmative
3
NW Electric Power Cooperative, Inc.
David McDowell
Negative
3
3
3
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Affirmative
Affirmative
3
Owensboro Municipal Utilities
Thomas T Lyons
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Pacific Gas and Electric Company
Pacific Northwest Generating Cooperative
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Raft River Rural Electric Cooperative
Rutherford EMC
Sacramento Municipal Utility District
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
John H Hagen
Rick Paschall
Terry L Baker
Michael Mertz
Thomas G Ward
Robert Reuter
Jeffrey Mueller
Erin Apperson
Heber Carpenter
Thomas Haire
James Leigh-Kendall
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
3
Sho-Me Power Electric Cooperative
Jeff L Neas
3
3
3
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
3
Tennessee Valley Authority
Ian S Grant
3
Tri-County Electric Cooperative, Inc.
Mike Swearingen
3
Tri-State G & T Association, Inc.
Janelle Marriott
3
3
Umatilla Electric Cooperative
Westar Energy
Steve Eldrige
Bo Jones
3
Wisconsin Electric Power Marketing
James R Keller
3
4
4
4
4
4
4
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Shamus J Gamache
Reza Ebrahimian
Kevin McCarthy
4
4
4
4
4
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
Central Lincoln PUD
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
4
Flathead Electric Cooperative
Russ Schneider
Negative
4
4
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Frank Gaffney
Cairo Vanegas
Affirmative
Affirmative
4
Georgia System Operations Corporation
Guy Andrews
Negative
4
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Affirmative
Affirmative
Affirmative
Tim Beyrle
Nicholas Zettel
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
COMMENTS
4
4
Illinois Municipal Electric Agency
Imperial Irrigation District
Bob C. Thomas
Diana U Torres
4
Indiana Municipal Power Agency
Jack Alvey
4
4
4
4
4
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
Northern California Power Agency
Ohio Edison Company
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Tracy R Bibb
Douglas Hohlbaugh
Affirmative
Negative
Affirmative
Affirmative
Affirmative
4
Oklahoma Municipal Power Authority
Ashley Stringer
Negative
4
Old Dominion Electric Coop.
Mark Ringhausen
Negative
4
4
Aleka K Scott
Henry E. LuBean
Affirmative
John D Martinsen
Affirmative
4
4
Pacific Northwest Generating Cooperative
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Mike Ramirez
Hao Li
Affirmative
Affirmative
4
Seminole Electric Cooperative, Inc.
Steven R Wallace
4
4
4
4
4
South Mississippi Electric Power Association
Southern Minnesota Municipal Power Agency
Tacoma Public Utilities
Utility Services, Inc.
West Oregon Electric Cooperative, Inc.
Steven McElhaney
Richard L Koch
Keith Morisette
Brian Evans-Mongeon
Marc M Farmer
4
Wisconsin Energy Corp.
Anthony Jankowski
Negative
4
5
5
5
5
WPPI Energy
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Todd Komplin
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Affirmative
Affirmative
5
Associated Electric Cooperative, Inc.
Matthew Pacobit
5
5
5
Avista Corp.
Edward F. Groce
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
5
Brazos Electric Power Cooperative, Inc.
Shari Heino
5
5
5
5
5
5
5
5
Calpine Corporation
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy, Inc.
Phillip Porter
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
5
Colorado Springs Utilities
Jennifer Eckels
5
5
5
5
5
5
Consolidated Edison Co. of New York
Consumers Energy Company
Cowlitz County PUD
Dairyland Power Coop.
Deseret Power
Detroit Edison Company
Wilket (Jack) Ng
David C Greyerbiehl
Bob Essex
Tommy Drea
Philip B Tice Jr
Christy Wicke
4
5
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
COMMENT
RECEIVED
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Affirmative
Affirmative
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
Dominion Resources, Inc.
Mike Garton
Affirmative
5
Duke Energy
Dale Q Goodwine
Negative
5
Dynegy Inc.
Dan Roethemeyer
Negative
5
5
5
5
5
5
5
5
5
5
5
5
5
E.ON Climate & Renewables North America,
LLC
Electric Power Supply Association
Essential Power, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
John R Cashin
Patrick Brown
Michael Korchynsky
Martin Kaufman
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
Marcela Y Caballero
John J Babik
Brett Holland
Mike Blough
James M Howard
5
Liberty Electric Power LLC
Daniel Duff
5
5
5
5
Dennis Florom
Kenneth Silver
Mike Laney
S N Fernando
Affirmative
Affirmative
David Gordon
Abstain
5
5
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Steven Grego
Mike Avesing
Affirmative
Affirmative
5
Nebraska Public Power District
Don Schmit
5
5
New York Power Authority
NextEra Energy
Wayne Sipperly
Allen D Schriver
Affirmative
Affirmative
5
North Carolina Electric Membership Corp.
Jeffrey S Brame
Negative
5
5
5
5
5
5
5
5
Northern Indiana Public Service Co.
Occidental Chemical
Omaha Public Power District
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
William O. Thompson
Michelle R DAntuono
Mahmood Z. Safi
Richard K Kinas
Richard J. Padilla
Sandra L. Shaffer
Roland Thiel
Matt E. Jastram
5
PowerSouth Energy Cooperative
Tim Hattaway
5
5
5
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southeastern Power Administration
Southern California Edison Co.
Southern Company Generation
Annette M Bannon
Tim Kucey
Steven Grega
Abstain
Affirmative
Michiko Sell
Affirmative
Tom Flynn
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Douglas Spencer
Denise Yaffe
William D Shultz
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
5
5
5
5
5
5
5
5
5
5
5
5
5
5
Dana Showalter
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
Affirmative
Negative
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
5
5
5
5
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Affirmative
Affirmative
Abstain
Negative
5
U.S. Army Corps of Engineers
Melissa Kurtz
Negative
5
5
U.S. Bureau of Reclamation
Westar Energy
Martin Bauer
Bryan Taggart
Affirmative
5
Wisconsin Electric Power Co.
Linda Horn
5
WPPI Energy
Steven Leovy
5
Xcel Energy, Inc.
Liam Noailles
Negative
6
AEP Marketing
Edward P. Cox
Negative
6
Ameren Energy Marketing Co.
Jennifer Richardson
Affirmative
6
APS
Randy A. Young
Affirmative
6
Associated Electric Cooperative, Inc.
Brian Ackermann
6
6
6
6
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
6
Colorado Springs Utilities
Lisa C Rosintoski
Negative
6
6
6
6
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Discount Power, Inc.
Dominion Resources, Inc.
Nickesha P Carrol
Donald Schopp
David Feldman
Louis S. Slade
Affirmative
Affirmative
6
Duke Energy
Greg Cecil
6
6
6
6
6
6
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell
Donna Stephenson
6
Kansas City Power & Light Co.
Jessica L Klinghoffer
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Paul Shipps
Eric Ruskamp
Brad Packer
Brad Jones
Daniel Prowse
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Alan Johnson
David Ried
Scott L Smith
Carol Ballantine
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
Negative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS
SUPPORTS
THIRD
PARTY
COMMENTS
- SERC OC
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
Affirmative
Negative
SUPPORTS
THIRD
PARTY
COMMENTS
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
COMMENT
RECEIVED
NERC
Standards
20140514-5129
FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
6
6
6
6
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
6
Xcel Energy, Inc.
David F Lemmons
8
8
8
8
8
8
Massachusetts Attorney General
Pacific Northwest Generating Cooperative
Utility System Effeciencies, Inc. (USE)
Roger C Zaklukiewicz
Edward C Stein
James A Maenner
Frederick R Plett
Margaret Ryan
Robert L Dintelman
8
Volkmann Consulting, Inc.
Terry Volkmann
9
William M Chamberlain
9
9
10
10
10
10
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
Oregon Public Utility Commission
Public Utilities Commission of Ohio
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
10
ReliabilityFirst Corporation
Anthony E Jablonski
Negative
10
10
10
10
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council
Carter B Edge
Emily Pennel
Donald G Jones
Steven L. Rueckert
Affirmative
Affirmative
Affirmative
Affirmative
6
6
6
6
6
6
9
9
Affirmative
Affirmative
Affirmative
Affirmative
John J. Ciza
Negative
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson
Affirmative
Peter H Kinney
Affirmative
Negative
Affirmative
COMMENT
RECEIVED Alice Ireland
Negative
Affirmative
Affirmative
SUPPORTS
THIRD
PARTY
COMMENTS
Negative
Donald Nelson
Affirmative
Diane J. Barney
Jerome Murray
Klaus Lambeck
Linda Campbell
William S Smith
Alan Adamson
Guy V. Zito
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801
Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation
https://standards.nerc.net/BallotResults.aspx?BallotGUID=646703d1-a823-4689-a36e-949227eb0ee8[4/8/2014 11:44:43 AM]
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Exhibit O
NERC Board of Trustees Input Responses
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
August 30, 2013
Communication Protocols
Response to NERC Board of Trustees Questions by the Independent Experts
Question 1. Proposed COM-002-3 Reliability Standard provides a standard that
addresses communication protocols in an emergency. Are there circumstances that
are not an emergency (as defined in COM-002-3) that can lead to reliability risks if
not appropriately addressed by a standard? If so, what are these circumstances and
how important is it that there be a standard to address them?
Answer 1. Yes, there are circumstances that are not an emergency that can lead to
reliability risks if the communications are not clearly understood and followed. It is
for this reason that the Independent Experts believe that the Standards must
address clear protocols for all circumstances. Some examples are as follows:
Communications where the recipient of the command is expected to act to change or
preserve the state, status, output, or input of an Element or Facility of the Bulk
Electric System can put the BES at risk if the instruction is not understood
correctly. This is possible even if the BES is not currently experiencing an
Emergency or an Adverse Reliability Impact. For example, the action could put
the BES in an insecure state for the next contingency.
While operators must always be aware of the consequences of actions they take,
they should not be required to categorize the current situation or potential
consequence as an Emergency or Adverse Reliability Impact to decide what
communication protocol is appropriate. In addition, it may be clear that action is
required even before the operator has determined that the BES is facing an
Emergency or an Adverse Reliability Impact.
o This confusion will remain if there are different communication protocols
for actions under a Reliability Directive and other situations with the
proposed definition of Operating Instruction.
Most entities require safety related communications, such as closing a breaker,
to use three-part communications regardless of the impact on the BES.
Inconsistent protocols for a subset of reliability related actions can
cause confusion.
For peak human performance, communication protocols should be as consistent
as possible, having no distinction between emergency and non-emergency
situations.
The bottom line is that the Independent Experts believe that it is very important for
the Standards to address communications protocols for non-emergency situations.
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August 30, 2013
Communication Protocols
Response to NERC Board of Trustees Questions by the Independent Experts
Question 2. Does the latest draft of the COM-003-1 Reliability Standard address
such circumstances appropriately? Is it a “quality standard” on the basis of the
criteria that are being used to assess existing and future standards by the
Independent Experts Panel?
Answer 2. As written, COM 003-1 Draft 6 does not address non-emergency
communication appropriately since it allows for the development of non-consistent
communication protocols across RCs as well as providing for a difference in
communication protocols between emergency and non-emergency conditions.
Non-consistent communication protocols can hinder coordination between
adjacent RCs, as well as the TOPs and BAs in their respective RC footprints,
thus negatively impacting reliable operations
The current COM-003-1 as drafted does not align with IRO-014-1, IRO-015-1
and IRO-016-1, which require coordination between RCs, as adjacent RCs
could have different communication protocols.
FERC Order 693 P. 532 determined “We also believe an integral component
in tightening the protocols is to establish communication uniformity as much
as practical on a continent-wide basis. This will eliminate possible
ambiguities in communications during normal, alert and emergency
conditions.”
Providing for a difference in protocol between emergency and nonemergency conditions creates a situation where an Operator must not only
focus on what they are saying but also must make a decision as to what is the
appropriate communication protocol to use.
COM 003-1 R2 and R3 do not support a reliability objective; rather they only
serve to mitigate compliance risk.
The Independent Experts scoring and comments are in Attachment 2. We find that
COM 003-1 draft 6 is not a “quality standard”. Requirement 1 received a content
score of zero out of three and a quality score of 7 out of 12. Requirements 2 and 3
should be deleted. The key deficiencies are as described above.
Question 3. Are there changes you would recommend to improve the current draft
of the COM-003-1 Reliability Standard? Describe how the enhancements would
address any gaps in bulk-power system reliability.
Answer 3. Following is a summary of our recommendations for COM-002-2, COM002-3 and COM-003-1. Example language for an improved combined COM standard
is in Attachment 1.
While the recommendations below allow situations where three-part
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August 30, 2013
Communication Protocols
Response to NERC Board of Trustees Questions by the Independent Experts
communications is not required we believe this will not cause confusion. The
distinction between an Operating Instruction and other communications such as
discussion of alternatives or providing information where no action is to be taken
should be clear.
There should be only one communications protocol standard that covers both
emergency and non-emergency situations.
o Combine COM-002-2, COM-002-3 and COM-003-1.
To the greatest extent practical the standard should provide for a consistent
continent-wide set of communications protocol.
o One exception would be the time zone for verbal and written operating
communications.
Expand applicability of COM 003-1 draft 6 to include GOs and TOs.
Retire the term Reliability Directive in the Glossary of Terms1.
o Develop a new Glossary definition for Operating Instruction:
Communication with the intent to change or maintain the state, status,
output, or input of an Element or Facility of the Bulk Electric System.
Describe the attributes of three-part communications.
Address other communications protocols (see Attachment 1).
Matters used to demonstrate compliance or to mitigate compliance risk should
not be a Requirement in the Standard but should instead be provided elsewhere
in the Standard.
This Standard is a candidate for an internal controls compliance
assessment pilot project where corrected deficiencies are not necessarily
reported as violations.
Some versions of COM-003-1 addressed "all call" or "blast" messages. We believe
that the requirement for three-part communications should only apply to
communications between two parties. It is not practical to have responses to "all
call" or "blast" messages.
Question 4. Should the proposed COM-002-3 Reliability Standard approved by the
Board be rescinded and a new standard developed that addresses communications
during both emergency and non-emergency conditions? If so, what key issues would
1
Retirement of the term Reliability Directive will require minor, non-substantive edits to IRO-001-3,
TOP-001-1 and TOP-001-2.
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August 30, 2013
Communication Protocols
Response to NERC Board of Trustees Questions by the Independent Experts
it address, including an appropriate definition of “non-emergency conditions”?
Answer 4. Yes. The Independent Experts recommend that COM-002-2, COM-002-3
and COM-003-1 be combined to address both emergency and non-emergency
conditions. As proposed by the Independent Experts there is no need to specifically
define “non-emergency conditions.” Please see detailed recommendations in
response to Question 3.
Question 5. Do you have any additional input regarding the development of the
COM-003-1 Reliability Standard for the Board to consider in its deliberations on
next steps?
Answer 5. The Independent Experts considered whether communication protocols
could be managed by the use of a guideline, but determined that a guideline is not
appropriate because:
3-part communications and other uniform communication protocols are
crucial to maintain reliability when the state of the system is changed or
maintained; and
while 3-part communication and other uniform communication protocols are
typically used today, they are not uniformly applied. A guideline would not
ensure application; and
a guideline would not fulfill the FERC directives in Order No. 693.
After reviewing responses to the five questions, the Independent Experts are
recommending the Board should rescind approval of COM-002-3 and direct a
redraft to combine COM-002-2, COM-002-3 and COM-003-1. Given the disparate
views that have delayed completion of this work the Board should describe the
expected attributes of a revised Standard and set a limited timeline for bringing the
revised Standard to the Board for approval.
The Independent Experts also recommend that internal controls become the
cornerstone for compliance assessment of a combined COM standard but should not
be a Requirement in the Standard. The level and method for internal controls is left
to the entity’s discretion but would be a good candidate for a guideline. Controls
might include:
o Implementing a training program;
o Implementing a management process to periodically verify performance;
and
o Taking corrective actions when needed in a timely manner.
The more effective an entity’s controls, the more benefit can be realized by the
entity during compliance assessment. Therefore, the Experts recommend that this
standard become the FERC-approved pilot for risk-based compliance monitoring. In
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August 30, 2013
Communication Protocols
Response to NERC Board of Trustees Questions by the Independent Experts
this pilot, a determination of whether a possible violation (PV) would be assessed
would be based on consideration of an entity’s internal controls, as described below.
Consideration of internal controls and internal compliance programs are basic
auditing concepts and principles designed to be forward-looking. These concepts
follow the Government Auditing Standards.2
Under this compliance assessment method, not all acts of non-compliance with the
Requirements are reported as possible violations or violations. This transfers focus
to accomplishing the reliability related task of providing clear, accurate
communications and eliminates compliance concerns regarding zero-defect
tolerance. While details should be provided in the NERC petition that reflect the
Reliability Assurance Initiative (RAI) effort, high level concepts include:
o Compliance Enforcement Authorities’ (CEAs) would communicate with an
entity to understand the entity’s internal controls.
o The level of evidence review (sample size) would be determined by the
strength of an entity’s internal controls and would be drawn from recent
communications.
o Where non-compliant communications were in the gathered samples, the
CEA would see if the entity’s internal controls had identified the root cause of
the non-compliance and whether the entity had taken corrective action to
address the cause. If so, the CEA would note the non-compliance and verify
that improved internal controls to prevent this cause were effective at the
next compliance assessment. No PV would be assessed.
o Where non-compliant communications were not addressed, were prevalent
or systemic, or were addressed but improved internal controls were not able
to prevent recurrence, a PV would be assessed.
Again, this compliance assessment method would be detailed and included for
FERC approval in the NERC petition for this standard.
2Available
at: http://www.gao.gov/products/GAO-12-331G, April 2012.
Page 5 of 10
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Attachment 1
Example Requirements for Combined COM Standard
Applicable Functional Entities:
Reliability Coordinator
Balancing Authority
Transmission Operator
Generator Operator*
Distribution Provider*
Transmission Owner*
Generator Owner*
*These functional entities are to be subject to this Standard for communication
protocols regarding BES Elements and Facilities, but there is no requirement for these
entities to be certified under PER-003, and applicability to this standard is not
intended to suggest otherwise. For Distribution Providers this Standard only applies
to communication protocols regarding UVLS, UFLS and load shedding equipment.
Revise Definition:
Operating Instruction — Communication with the intent to change or maintain the
state, status, output, or input of an Element or Facility of the Bulk Electric System.
R1. Each Applicable Functional Entity shall use the following three-part protocol
when communicating an Operating Instruction internally or externally:
1.1. The issuer states an Operating Instruction.
1.2. The receiver of an Operating Instruction shall take one of the following
actions:
1.2.1. Repeat the Operating Instruction and wait for confirmation from the
issuer that the repetition was correct.
1.2.2. Request that the issuer reissue the Operating Instruction.
1.3. The issuer shall wait for a response from the receiver. After the response is
received, or if no response is received, the issuer shall take one of the
following actions:
1.3.1. Confirm the receiver’s response if the repeated information is
correct (not necessarily verbatim).
1.3.2. Reissue the Operating Instruction if the repeated information is
incorrect or if the receiver does not issue a response.
1.3.3. Reissue the Operating Instruction if requested by the receiver.
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R2. Each Applicable Functional Entity shall use the following protocols when
communicating an Operating Instruction internally or externally:
2.1. Use the English language for all communications between and among
operating personnel responsible for the real-time control and operation of
the interconnected Bulk Electric System unless otherwise required by law
or regulation.
2.2. Use the 24-hour clock format when referring to clock times.
2.3. To the extent that a common time zone is not in use for each of the three
interconnections – Eastern, Western and ERCOT, every communication
that includes a clock time shall include the time zone.
2.4. Use common nomenclature of interface Elements and/or Facilities.
2.5. Use NATO or other alpha-numeric clarifiers when issuing an oral
Operating Instruction in instances where the nomenclature of Facilities or
Elements are in alpha-numeric format (e.g. a circuit breaker designated
as “12B”).
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Attachment 2
Independent Experts Score for COM 003-1 draft 6
Page 8 of 10
Independent Experts Content Score Details for COM 003-1 draft 6
Page 9 of 10
Independent Experts Quality Score Details for COM 003-1 draft 6
Page 10 of 10
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September 6, 2013
Fred Gorbet, Chair
NERC Board of Trustees
Gerry Cauley, President and CEO
NERC
Gentlemen,
At the August 2013 Board of Trustees meeting, the Reliability Issues Steering Committee (RISC) was
asked by the Board to provide answers to a series of questions related to Operating Personnel
Communication Protocols – COM‐003‐1. The RISC provides the responses below.
Please reach out to me if you have any questions or concerns.
Sincerely,
Chris Schwab
Chair, Reliability Issues Steering Committee
cc: RISC Members
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
RISC Response to Questions from the
August 15, 2013, NERC Board of Trustees Resolution regarding
Operating Personnel Communication Protocols – COM‐003‐1
Question 1.
Proposed COM‐002‐3 Reliability Standard provides a standard that addresses communication
protocols in an emergency. Are there circumstances that are not an emergency (as defined in
COM‐002‐3) that can lead to reliability risks if not appropriately addressed by a standard? If so,
what are these circumstances and how important is it that there be a standard to address them?
Response:
Yes, there is a category of non‐emergency circumstances that could possibly lead to a reliability
risk. Some such circumstances could include the switching of bulk electric system facilities (e.g.,
capacitor banks, etc.), manual ramp‐up or ramp‐down of generation, and oral alerts. However,
the RISC believes that such categorization should be defined by the Operating Committee, as they
have the greatest amount of experience and knowledge in this area.
In the ten years since the 2003 Northeast Blackout, much progress has been made in the area of
communications. The “Arizona‐Southern California Outages on September 8, 2011” report cited 27
causes and recommendations; ineffective or confusing non‐emergency communications was not
listed as a cause. Similarly, the “Report on Outages and Curtailments During the Southwest Cold
Weather Event of February 1‐5, 2011” listed 26 Key Findings and Recommendations for the
electric industry, none of which included ineffective or confusing non‐emergency communications.
Additionally, it appears that NERC event analysis data has not yielded evidence of a reliability gap
regarding non‐emergency communication as a contributing factor to bulk electric system events.
The RISC suggests that the Operating Committee should be tasked with defining the non‐
emergency circumstances that can lead to a reliability risk that threatens the BES. This activity
should be based on review of available data and the application of the expertise and knowledge of
the Operating Committee.
While the RISC recognizes there is limited empirical data indicating that communication errors in
non‐emergency situations have led to reliability problems, the RISC believes a standard will be
developed in response to this concern. The RISC believes it is critical that the standard be
developed based on the risk to reliability associated with whatever special circumstances are
identified.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Question 2.
Does the latest draft of the COM‐003‐1 Reliability Standard address such circumstances
appropriately? Is it a “quality standard” on the basis of the criteria that are being used to assess
existing and future standards by the Independent Experts Panel?
Response:
The COM‐003‐1 standard does address such circumstances, but may not do so at an appropriate
level of prescription, and does not represent a quality standard.
Any standard that is developed should include requirements that are results‐based, minimize
disruptive administrative requirements, and be complementary to any other methods used for
addressing system operator communication.
Question 3.
Are there changes you would recommend to improve the current draft of the COM‐003‐1
Reliability Standard? Describe how the enhancements would address any gaps in bulk‐power
system reliability.
Response:
Please see our answer to question 5.
Question 4.
Should the proposed COM‐002‐3 Reliability Standard approved by the Board be rescinded and a
new standard developed that addresses communications during both emergency and non‐
emergency conditions? If so, what key issues would it address, including an appropriate definition
of “non‐emergency conditions”?
Response:
The RISC does not recommend the Board rescind its approval of the proposed COM‐002‐3. The
RISC does recommend the immediate filing of the COM‐002‐3 standard, as well as the COM‐002‐2
Interpretation, since both will improve reliability of the BES. As work on COM‐003‐1 progresses, it
is critical that it be complementary to COM‐002‐3, and that there are clear delineations between
emergency and non‐emergency communications and the associated obligations created by the
standard.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Question 5.
Do you have any additional input regarding the development of the COM‐003‐1 Reliability
Standard for the Board to consider in its deliberations on next steps?
Response:
The RISC offers the following guiding principles in the development of a COM‐003‐1 standard:
A risk‐informed process should be used to define a risk‐based standard. The standard should
be drafted based on expert opinion and data to recognize the differing risks of the categories
defined by the OC in which a failure to communicate clearly during non‐emergency
circumstances could possibly lead to a threat to the BES.
o For those categories that present the greater risk, it is appropriate to be more
prescriptive and more uniform within and across regions and reliability coordination
areas.
o For those categories that present less risk, it is appropriate to allow more flexibility.
The enforcement regime for such a standard cannot be zero‐tolerance. Focus should be on the
quality of an entity’s communication protocols, the quality of their associated training, and how
the entity ensures their protocols are followed.
There must be clear delineations between emergency and non‐emergency communications and
the associated obligations created by the standards.
The standard should not address protocols for electronic pulsing for Automatic Generation
Control or electronically delivered alerts.
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
NERC Management Response to
the Questions of the NERC Board of Trustees
on Reliability Standard COM-003-1
September 6, 2013
At the August 14-15, 2013 meeting of the Board of Trustees (“Board”) of the North
American Electric Reliability Corporation (“NERC”), the Board considered action on Agenda
Item 7a: Operating Personnel Communication Protocols – COM-003-1 to discuss next steps for
the development of a Reliability Standard1 to respond to the Federal Energy Regulatory
Commission’s (“FERC”) directives in Order No. 693 concerning communications. On August
15th, the Board passed a resolution to consider at its next meeting how best to act with respect
to: (1) the disposition of the Board-approved interpretation of the currently effective COM-002-2
Reliability Standard; (2) the Board-approved COM-002-3 Reliability Standard; and (3) the draft
COM-003-1 Reliability Standard, including whether to exercise the authority the Board has with
respect to actions it can take under Section 321 of the NERC Rules of Procedure.
The Board directed NERC’s Reliability Issues Steering Committee, the Independent
Experts Review Panel, and NERC management to respond to certain questions related to the
draft COM-003-1 Reliability Standard. The following is NERC management’s responses to the
questions posed in the Board resolution.
Question 1
Proposed COM-002-3 Reliability Standard provides a standard that
addresses communication protocols in an emergency. Are there
circumstances that are not an emergency (as defined in COM-0023) that can lead to reliability risks if not appropriately addressed by
a standard? If so, what are these circumstances and how important
is it that there be a standard to address them?
NERC Management Response
Yes, there are non-emergency circumstances that can lead to reliability risks not covered
by the proposed COM-002-3 Reliability Standard that need to be addressed in a mandatory and
enforceable Reliability Standard.
For example, miscommunication by operating personnel could result in switching errors
during routine switching of Bulk Electric System Elements, which could jeopardize the reliable
operation of the Bulk Electric System. Examples of incorrect switching include opening or
closing the wrong Bulk Electric System Element. This incorrect switching could directly cause
or exacerbate a serious reliability impact. Additionally, switching often involves enabling or
disabling protective relaying on Bulk Electric System Elements. If this action is not performed
1
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.
1
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
correctly, the system may be left in a vulnerable state where a future action or system condition
could place the Bulk Electric System in an Emergency or result in an Adverse Reliability Impact.
Ineffective communications during non-emergency conditions could also lead to a lack of
situational awareness for system operators of adjacent systems. This lack of situational
awareness could result in a system operator expecting the Bulk Electric System to be in a certain
configuration to take action on its system that could place the Bulk Electric System in an
Emergency or could have an Adverse Reliability Impact. In fact, a lack of situational awareness
was cited as a common factor in several events that contributed to the August 14, 2003 electric
power blackout in large portions of the Midwest and Northeast United States and Ontario,
Canada (“2003 Blackout”).2 The 2003 Blackout report noted:
“Under normal conditions, parties with reliability responsibility
need to communicate important and prioritized information to
each other in a timely way, to help preserve the integrity of the
grid. This is especially important in emergencies. During
emergencies, operators should be relieved of duties unrelated to
preserving the grid. A common factor in several of the events
described above was that information about outages occurring in
one system was not provided to neighboring systems.”3
The report continues, in the context of Recommendation 26, that on the date of the blackout,
Reliability Coordinator and control area communications regarding conditions in northeastern
Ohio were, in some cases, ineffective, unprofessional, and confusing.4 Such communications
contributed to a lack of situational awareness and precluded effective actions to prevent the
cascade.5 The 2003 Blackout Report notes that consistent application of effective
communications protocols, particularly during alerts and emergencies, is essential to reliability. 6
Furthermore, the need to tighten communications protocols and improve communications
systems was raised by several commenters in response to the interim blackout report.
Regardless of whether the circumstance is an emergency or non-emergency, any
communication that directs a system operator to change or preserve the current state of the Bulk
Electric System has the potential to create a reliability risk. For this reason, it is appropriate and
necessary to develop a Reliability Standard that defines the communication expectations in both
emergency and non-emergency circumstances.7 Unlike a voluntary guideline, a mandatory and
enforceable standard would allow the ERO to hold entities accountable for their communications
2
See U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the
United States and Canada: Causes and Recommendations, available at
http://www.nerc.com/pa/rrm/ea/Pages/Blackout-August-2003.aspx.
3
Id. at 109 (emphasis added).
4
Id. at 161.
5
Id.
6
Id.
7
In 2012, the Operating Committee recognized the need to provide guidance for utilities when developing a
System Operator verbal communications program. This document provides a general framework to assist entities in
identifying the concepts and steps to consider when developing an effective System Operator verbal
communications program. However, the use of the concepts presented in the document is strictly voluntary.
2
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and would allow the ERO to assure that entities are meeting expectations for effective
communications. However, it is not necessary to develop a mandatory and enforceable
Reliability Standard to define protocols for communication for all circumstances. For example,
discussions between system operators of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns, while important and valuable,
do not necessitate coverage by a mandatory and enforceable Reliability Standard.
The following examples of actual events are provided to support the need to develop a
Reliability Standard that covers circumstances that are emergencies and non-emergencies:
Desired Action
Communication
Response
Consequence
Deploy Reserve
Capacity
All call executed.
No clarity in
directive for
action.
No response (no
verbal response
and no specific
actions taken by
all call recipients)
All call repeated
six minutes later
with clarity and
acknowledgment.
Alleviate
overloads
TOP and TO
discussed options
to alleviate
overloads in area.
No directive was
actually given with
a resulting delay in
executing relief
actions.
Shared
Recognition of
System Conditions
The RC attempts
to ensure that
identification of an
abnormal
condition is
communicated to
all system
operators without
delay.
No specific actions
taken because of
confusion or lack
of understanding.
Vital information
was not
exchanged.
Operators’
communications
lacked clarity and
directness, which
led to delays in
executing the
appropriate course
of action. Action
items were not
summarized at the
end of the
discussions,
leading to
confusion over
what appropriate
actions were to be
taken.
The
communications
problems
exacerbated the
Event, because
TOP was unable to
take timely
corrective action
internally and in
coordination with
other entities.
Impact to
Reliability
Frequency
recovery
significantly
delayed until
corrective actions
were implemented
Emergency rating
on a transmission
line was exceeded
for 3 hours and 5
minutes.
Establishment of a
shared
understanding of
system conditions
delayed
restoration.
All of these examples included communications that directed a system operator to change or
preserve the current state of the Bulk Electric System. While the first example included
3
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communications that would have been covered under COM-002-3, the last two examples
included some communications that would not have been covered under COM-002-3, but would
be covered under the proposed COM-003-1 standard.
Question 2
Does the latest draft of the COM-003-1 Reliability Standard
address such circumstances appropriately? Is it a “quality
standard” on the basis of the criteria that are being used to assess
existing and future standards by the Independent Experts Panel?
NERC Management Response
Yes, the latest draft of the COM-003-1 standard does attempt to address the
circumstances described above, but it is not a “quality standard.”
The current draft of COM-003-1 addresses non-emergency communications by requiring
recipients to follow commands that change or preserve the state, status, output, or input of an
Element of the Bulk Electric System (i.e., Operating Instructions). Therefore, in combination
with COM-002-3, which covers communications during emergencies, the current draft of COM003-1 technically addresses the communications of concern as described in the answer to
Question 1.
However, the latest draft of COM-003-1 is not a “quality standard.” While Requirement
R1 does meet some of the quality criteria defined by the Independent Experts Panel, the
Requirement is deficient because it does not include a baseline set of protocols for both
emergency and non-emergency conditions. Requirements R2 and R3 are confusing and appear
to only mitigate compliance risk for applicable entities. Attachment 1 provides an analysis by
NERC management of the requirements included in the latest draft of the COM-003-1 standard
using the criteria established by the Independent Experts Panel. In short, NERC management’s
analysis finds that: (1) the expectations for each function are not clear; (2) the requirements do
not align with the purpose of the Reliability Standard; and (3) the Reliability Standard represents
a “lowest common denominator”8 standard.
The current draft of COM-003-1 is also not a quality standard because it:
1. Artificially distinguishes “Operating Instructions” from “Reliability Directives” to
separate the protocols from those in COM-002-3. This separation gives the
appearance that three-part communications is the only protocol necessary for Reliability
Directives, while several more protocols are necessary for Operating Instructions. It is as
8
Earlier versions of the draft COM-003-1 standard more appropriately addressed the circumstances
identified in the response to Question 1 (Drafts 1-4). Prior drafts established mandatory uniform communication
protocols for use in emergency and non-emergency situations. Later drafts shifted from that approach in response to
industry comments focused on mitigating compliance risk. The standard drafting team, in performing their
responsibility, made modifications to the standard in an attempt to achieve ballot body consensus while attempting
to maintain essential communication protocols.
4
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important, if not more important, that common communications protocols be used for
emergency communications. Taking time to clearly delineate when a Reliability
Directive is issued and differs from an Operating Instruction also may not be a practical
exercise during a real-time situation.
2. Does not strike the proper balance between prescriptiveness and flexibility to
establish communication protocols. COM-003-1 requires entities to self-define the
conditions for which they apply the protocols in Requirement R1 of COM-003-1,
including when three-part communication is necessary. This preserves avenues for
potential miscommunication between parties by not creating a clear baseline of required
protocols for communications.
3. Creates a reverse incentive to issue emergency directives by connecting compliance
risk in COM-003-1 to the issuance of Reliability Directives in COM-002. This
connection between compliance risk in COM-003-1 and the issuance of Reliability
Directives in COM-002-3 creates an incentive to not issue a Reliability Directive to take
emergency action in order to avoid compliance risk under COM-003-1. This connection
should be removed to eliminate the reverse incentive.
4. Requires approval of communications protocols by the Reliability Coordinator. The
current draft of COM-003-1 makes communications protocols subject to the approval of
the Reliability Coordinator. The Reliability Coordinator should not have the
responsibility or the authority to determine third-party protocols. Either the entity should
have the ability to determine the necessary protocols, or the Reliability Standard should
state the protocols.
Question 3
Are there changes you would recommend to improve the current
draft of the COM-003-1 Reliability Standard? Describe how the
enhancements would address any gaps in bulk-power system
reliability.
NERC Management Response
Yes, NERC management recommends combining the proposed COM-002-3 and COM003-1 standards to provide a single standard to address communications protocols for emergency
and non-emergency operations. A recommended draft standard is included in Attachment 2. At
a minimum, the standard should:
Require the use of established communications protocols for operations to be used in
both non-emergency and emergency operations;
Require certain baseline protocols to be used by all entities;9
9
These protocols must include the use of the English language for all communications in order to retire a
similar requirement that remains in COM-001 that is not reflected in the Board-approved proposed Reliability
Standard COM-001-2. This issue was specifically deferred to the proposed COM-003-1 Reliability Standard.
5
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Require that the communications procedure be implemented;
Require training of system operators on the communications procedure and
demonstrate evidence of that training; and
Specify a process to review communications with system operators and provide
feedback on adherence to the communication protocols and identify any necessary
changes to the protocols.
Also, the definition of Operating Instruction should be modified to encompass Reliability
Directives. Merging the definitions eliminates the ambiguity inherent in attempting to clearly
define what classifies as an Operating Instruction and what necessitates the issuance of a
Reliability Directive during real-time conditions. As noted above, these two definitions are
currently artificially distinguished in the current proposed COM-003-1 and COM-002-3. With
this modification, COM-002-3 and COM-003-1 can be combined into a single standard to cover
emergency and non-emergency communications.
Additionally, entities should be accountable for incorrect use of communication protocols
in connection with a Reliability Directive, without exception. For all other Operating
Instructions, compliance should be measured using standard audit practices. During an audit, an
entity should present the method they used to sample communications to determine the
effectiveness of their communication. They should also show how they document and determine
the level of corrective actions in connection with the deficiencies that are identified, and ensure
that operators are consistent in their application of protocols. This approach will provide the
reasonable assurance that, while occasional non-emergency communications may not always
follow every protocol, operators are proficient in the protocol use.
Question 4
Should the proposed COM-002-3 Reliability Standard approved by
the Board be rescinded and a new standard developed that
addresses communications during both emergency and nonemergency conditions? If so, what key issues would it address,
including an appropriate definition of “non-emergency
conditions”?
NERC Management Response
Yes, the Board of Trustees should withdraw its approval of proposed Reliability Standard
COM-002-3. NERC management recommends the drafting of a single standard that addresses
communication during emergency and non-emergency operations. This would provide a holistic
approach to creating communication protocols. The key elements of a single combined standard
have already been identified in the response to Question 3. Withdrawing approval of COM-0023 will allow the combined standard to cover issues such as protocols related to use of one-way
6
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burst messaging systems (i.e., all-calls) that are currently not reflected in the COM-002-3
Reliability Standard.10
Withdrawing approval of COM-002-3 would also allow for any adjustments to COM002-3 needed to prevent conflict between the final language of a COM-003-1 Reliability
Standard and COM-002-3 should the standards remain separate. Otherwise, any further
development of a COM-003-1 standard will face the same difficulty the current standard drafting
team encountered working with the approved language in COM-002-3 to craft a complimentary
COM-003-1.
Question 5
Do you have any additional input regarding the development of the
COM-003-1 Reliability Standard for the Board to consider in its
deliberations on next steps?
NERC Management Response
Yes, additional input for the Board’s consideration on the interpretation of COM-002-2
and compliance concerns related to the development of COM-003-1 is provided below.
First, NERC management recommends holding the filing of the interpretation of COM002-2 until development of a standard covering both emergency and non-emergency conditions
is completed. By submitting the interpretation, NERC places the issue of the proper scope of
COM-002-2 before FERC for decision prior to the completion of further development work,
which could impact the development of a single communications standard. The issue raised in
the interpretation should instead be addressed through an appropriately scoped single standard
proposed for FERC approval. Similarly, if the Board does not withdraw approval of COM-0023, NERC management also recommends holding the filing of COM-002-3 so that FERC will
consider COM-002-3 along with the proposed COM-003-1 standard to reduce the risk of a
remand of COM-002-3.
Second, concerns over creating an operational and compliance environment that requires
mining of hundreds, thousands or millions of routine/normal communications to prove
compliance or make a finding of reasonable assurance of compliance was consistently cited in
comments to all drafts of COM-003-1. NERC plans to address this issue in the compliance
section of the standard and in development of the RSAW concurrently with development of the
standard.
10
The standard drafting team for proposed COM-002-3 deferred the issue of protocols related to use of oneway burst messaging systems (i.e. all-calls) to the COM-003-1 Reliability Standard. All-calls can be calls initiated
by one party to multiple parties where the receiving parties are in a “listen only” mode. All-calls of this nature
cannot be used with a requirement for the use of three-part communication procedures specified in COM-002-3.
During development of COM-003-1, NERC received a number of comments that the introduction of protocols for
all-calls would create a conflict between the requirement in COM-002-3 to use three-part communication and the
specific protocols for all-calls developed in COM-003-1. The result is a lack of protocols for all-calls in both
standards.
7
Attachment 1
NERC Management Analysis of COM-003-1 Draft 6 Using Independent Experts Panel Criteria
Requirement Should it be kept as it is and
Number
not consolidated with other
standards/requirements?
Is it RBS format?
Is it technology
Applicability - are
Does the
Is it a higher
Drafted as one of these
neutral? (Yes/No) the expectations for requirement align solution than the
requirement types:
each function clear? with the Purpose? lowest common
Performance, Risk-based
denominator
(preventative), Capability, &
(considering cost)?
Format for subparts
R1
No - should be collapsed with
COM-002-3
Yes
Yes
Yes
No
No
R2
No
Yes
Yes
No
No
No
R3
No
Yes
Yes
No
No
No
Measurability
Technical basis in
engineering and operations
Complete?
Self-contained
Clear language?
Is RRO clarified?
Can it be
practically
implemented?
Consistent
Terminology
Quality Score
0-12
R1
Yes
No
Yes
Yes
Yes
Yes
8
R2
Yes
No
Yes
No
Yes
Yes
6
R3
Yes
No
Yes
No
Yes
Yes
6
Requirement
Number
Attachment 2
Sample Requirements for a Communication Standard for Non-emergency and
Emergency Operations
Operating Instruction — A command by operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System where the
recipient of the command is expected to act to change or preserve the state, status, output, or
input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. A
discussion of general information and of potential options or alternatives to resolve Bulk
Electric System operating concerns is not a command and is not considered an Operating
Instruction. A Reliability Directive is one form of an Operating Instruction.
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While Distribution Provider is listed below, the standard would only be applicable to
Distribution Providers that operate Bulk Electric System Elements (e.g. under frequency load
shedding and under voltage load shedding).
R1. Each Balancing Authority, Distribution Provider, Reliability Coordinator, and
Transmission Operator shall develop one or more written communications protocols.
The protocols must: [Violation Risk Factor: Low][Time Horizon: Long-term
Planning]
1.1. Require the use of the English language for all communications between and
among operating personnel responsible for the real-time generation control and
operation of the interconnected Bulk Electric System, unless agreed to otherwise.
An alternate language may be used for internal operations.
1.2. Require the issuer of an oral two party, person-to-person Operating Instruction to
wait for a response from the receiver. After the response is received, or if no
response is received, require the issuer to take one of the following actions:
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect or if
the receiver does not issue a response.
Reissue the Operating Communication if requested by the receiver.
1.3. Require the receiver of an oral two party, person-to-person Operating Instruction
to take one of the following actions:
Repeat the Operating Instruction and wait for confirmation from the issuer
that the repetition was correct.
Request that the issuer reissue the Operating Instruction.
1.4. Require the issuer of an oral Operating Instruction to verbally or electronically
confirm receipt from one or more receiving parties when issuing the Operating
Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all-call
system).
1.5. Require the receiver of an oral Operating Instruction to request clarification from
the initiator if the communication is not understood when receiving the Operating
Instruction through a one-way burst messaging system used to communicate a
common message to multiple parties in a short time period (e.g. an all-call
system).
1.6. Include other communications protocols as deemed necessary by the entity.
R2. Each Balancing Authority, Distribution Provider, Reliability Coordinator, and
Transmission Operator shall implement the written communications protocols
developed in Requirement R1. [Violation Risk Factor: High][Time Horizon: Realtime Operations]
R3. Each Balancing Authority, Distribution Provider, Reliability Coordinator, and
Transmission Operator shall train their operating personnel responsible for the real-time
generation control and operation of the interconnected Bulk Electric System on their
written communications protocols specified in Requirement R1. [Violation Risk
Factor: Low][Time Horizon: Long-term Planning]
R4. Each Balancing Authority, Distribution Provider, Reliability Coordinator, and
Transmission Operator shall implement a method to review communications with their
operating personnel responsible for the real-time generation control and operation of
the interconnected Bulk Electric System that provides feedback on adherence to the
documented communication protocols specified in Requirement R1. [Violation Risk
Factor: Low][Time Horizon: Real-time Operations]
R5. Each Balancing Authority, Distribution Provider, Reliability Coordinator, and
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AM for evaluating the
Transmission
Operator shall
implement
a method
documented
communication protocols specified in Requirement R1 that: [Violation Risk Factor:
Low][Time Horizon: Real-time Operations]
5.1. Performs ongoing assessments of adherence to the documented communication
protocols,
5.2. Evaluates the effectiveness of the documented communication protocols, and
5.3. Provides feedback to improve the effectiveness of operator communication, which
may include the addition of communication protocols.
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Exhibit P
Standard Drafting Team Rosters for Project 2006-06 Reliability Coordination COM-001-2 and Project
2007-02 Operating Personnel Communications Protocols COM-002-4
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Team Roster
Project 2006-06 Reliability Coordination
Participant
Entity
William M. Hardy
Southern Company
Earl A. Barber
National Grid
James S. Case
Entergy Services, Inc.
Albert M. DiCaprio
PJM Interconnection
Anthony P. Jankowski
WE Energies
H. Steven Myers
ERCOT
Robert C. Rhodes
Southwest Power Pool, Inc.
Eric Senkowicz
Florida Reliability Coordinating Council
NERC staff
Scott Barfield-McGinnis
North American Electric Reliability Corporation
NERC staff
Stephen Crutchfield
North American Electric Reliability Corporation
Chair
Version
Date
Description
1.0
3/8/2012
New format.
2.0
4/19/2012
Edited by Wendy Kinnard
4/19/2012, Version Draft
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Standard Drafting Team Roster
Project 2007-02 Operating Personnel Communications
Protocols
Participant
Entity
Chair
Lloyd Snyder
Georgia System Operators
Member
Glen Boyle
PJM
Member
Mike Brost
JEA
Member
Tom Irvine
Hydro One
Member
Robert Rhodes
Southwest Power Pool
Member
Stephen Solis
Electric Reliability Council of Texas
Member
Fred Waites
Southern Company
Member
John Stephens
City Utilities of Springfield
NERC Staff
Howard Gugel (Director,
Performance Analysis)
North American Electric Reliability Corporation
NERC Staff
William Edwards (NERC Legal)
North American Electric Reliability Corporation
NERC Staff
Stephen Eldridge (Standards
Development)
North American Electric Reliability Corporation
Version
1.0
Date
Description
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Exhibit Q
Operating Committee Reliability Guideline: “System Operator Verbal Communications – Current
Industry Practices”
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Reliability Guideline:
System Operator Verbal Communications –
Current Industry Practices
Preamble
It is in the public interest for NERC to develop guidelines that are useful for maintaining or enhancing
the reliability of the Bulk Electric System (BES). Reliability Guidelines provide suggested guidance on a
particular topic for use by BES users, owners, and operators according to each entity’s circumstances.
Reliability Guidelines are not to be used to provide binding norms, establish mandatory reliability
standards, or create parameters by which compliance to standards is monitored or enforced.
Introduction
This Reliability Guideline is available to electricity sector organizations responsible for the operation of
the BES. It provides general concepts that may be considered when developing a system operator
verbal communications program. This guideline provides a general framework for identifying the
concepts and steps to consider for an effective system operator verbal communications program. This
document, written in the form of a guideline, is a collection of industry practices compiled by the NERC
Operating Committee (OC). The use of these methodologies and guidelines is strictly voluntary.
Entities should consider goals of going beyond the standards to facilitate a higher level of reliable
operations without the expectation of having to be perfect in meeting the goals for compliance
purposes. As BES communications practices, procedures and technologies change, electric entities are
encouraged to implement such changes as appropriate.
Purpose
The purpose of this guideline is to document and share current verbal BES communications practices
and procedures from across the industry that have been found to enhance the effectiveness of system
operator communications programs. These are not mapped to existing or future mandatory
requirements, but rather are intended to show the breadth of industry practices concerning verbal
communications.
Guideline Details
Components of an effective system operator verbal communications program may include:
I. Verbal Communications Tools
System operators use a variety of tools for communicating information with other system operators.
The tool used for communicating specific information with various recipients depends on a number of
factors, such as the urgency, importance, and intended impact of the information being
communicated. The urgency, importance, and impact of the specific information are highly dependent
on the role and responsibility of each party to the communication. As an example, email may be the
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
appropriate tool if the information exchange is not urgent, while a one-on-one phone call may be the
best method to communicate both urgent and important information. Also, in some cases multiple
tools may be used to communicate the same information to different parties.
Tools used for system operator communications and some typical applications for those tools are as
follows:
1. Voice Communications
a. Public Switched Telephone Network (PSTN) – This is the most common communication tool
for system operators to use to communicate with other system operators and field
personnel. It is highly reliable and secure. Application examples include:
i.
Dedicated conference call arrangements
ii.
Dedicated circuits between facilities
iii.
Multi-party initiated calls
iv.
Speed dial functionality
b. Private Internal Telecommunications Systems – Some utilities have found economies of
scale by installing their own communications network utilizing microwave and/or fiber optic
telecommunications networks. These networks perform the same function as the PSTN
discussed above.
c. Voice Over Internet Protocol (VOIP) – The communication protocols, technologies,
methodologies, and transmission techniques involved in the delivery of voice
communications and multimedia sessions over Internet Protocol (IP) networks, such as the
Internet, rather than the public switched telephone network (PSTN).
d. Cell phones – These are widely used by field personnel to contact system operators. They
are reliable in urban and suburban settings but are less reliable in remote areas. Cell
phones function similarly to traditional phones but are more susceptible to background
noise.
e. Radios – A common communication medium for municipal utilities and vertically integrated
utilities in which uses extend beyond operation of the BES. The communication method for
radios differs from other devices because they are not full duplex devices and, therefore, do
not allow simultaneous transmission from both parties. Also, radio transmissions are
typically not encrypted and are accessible to third parties via scanners, etc.
f. Government Emergency Telecommunications Service (GETS) and Wireless Priority Service
(WPS) – GETS and WPS provide an emergency access and priority processing in the local and
long-distance segments of the PSTN or cellular networks. GETS and WPS are intended to be
used in an emergency or crisis situation when the PSTN or cellular network is congested and
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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the probability of completing a call over normal or other telecommunications means has
significantly decreased.
g. Satellite phones – Typically used as emergency voice communication medium between
functional entities and their respective reliability coordinators. Satellite phones function
similarly to traditional phones and cell phones; however, a clear view of the sky for the
antenna is required. A lesson learned from the industry’s Y2K preparation was that for
satellite phones to be most effective in emergency/outage conditions, entities have to
ensure their phones do not require transmitting through any ground relaying stations (i.e.,
that their phones have direct point-to-point functionality).
h. All Call/Blast Call Functionality – Some entities utilize technology that blasts general
messaging and directives with multiple entities. Blast calls and messaging systems are
effective tools to rapidly share information with multiple parties or to get group action.
2. Other Communications Tools
a. Email – Typically used to communicate information that is not time sensitive. Used to
communicate system status and events to a broad array of support staff/management as
well as interconnected entities.
b. Messaging Systems – An internal system used by reliability coordinators to send messages
to their Balancing Authorities (BA) and Transmission Operators (TOP) or an external system
used by Reliability Coordinators (RC) to send messages to other RC (e.g., the RC Information
System).
c. Fax (short for facsimile) – Sometimes called telecopying, faxing is the telephonic
transmission of scanned printed material (both text and images), normally to a telephone
number connected to a printer or other output device.
II. Policies and Procedures
The following are excerpts of policies and procedures currently in use by a sampling of industry
members. When developing formal communications policies and procedures, the registered entity
may consider addressing the following items:
1. Policy Applicability
a. Who – To whom the procedure applies
b. When – Under what condition the specific communications policy or procedure is to be
used (e.g., normal or emergency conditions)
c. How – Technique to be used for emergency communications versus normal
communications
i.
There are two schools of thought regarding utilization of three-part communication
for routine operating instructions. Every routine communication opportunity has a
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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different impact on the reliability of the BES, and many routine communication
opportunities have no impact on reliability. While the industry has disparate
viewpoints on the necessity of the use of three-part communication for all real-time
communications, most agree that the point is to be effective when it counts for
reliability — not that every communication opportunity has a reliability impact.
1. One thought is that the three-part communication protocol is special and reserved
to address real-time emergencies in order to make those communications stand
out from normal communications.
2. Another school of thought is that the three-part communication protocol is good
practice for both normal and emergency operating instructions.
d. If an entity determines it would utilize the three-part communication protocol for routine
operating instructions, that entity should define when its system operators are expected to
utilize the protocol, including coordinating with entities regarding when the use of threepart communication is expected. In addition, entities could consider beginning the
communication with the phrase “This instruction requires a three-part communication.”
Further, entities should consider providing system operators a general format or a script
that can be applied when using three-way communications. Some entities provide these
written scripts at each system operator position and may ask the receiver to write out the
transmitted directive.
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
4
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2. Use of Three-Part Communication for Routine Operating Instructions1 – The following is an
example of when the three-part communication protocol for routine operating instructions
could be implemented:
SAMPLE TEXT from an internal procedure:
a. For any actionable item, there should be specific three-part communication
by the receiver to ensure there is no misunderstanding of the details
involved. An actionable item is instruction or information conveyed in
which one party is informing the other that:
i.
A physical change needs to be made or has been made to BES facilities
pre- or post-contingency (e.g., generation starts, transmission
reconfigurations, manual redispatches, voltage changes); or
ii.
A change needs to be made in the computer systems used to operate
the BES (e.g., updating operating limits, forecasts, schedules).
3. Elements of Effective Communication
a. Communication Etiquette – At all times, professionalism and professional tone and manner
are essential. Communications are best undertaken in a courteous, business-like fashion.
b. Opening Phrase – It is important that both parties understand with whom they are
speaking; therefore, the person answering the phone or making a call should state the
following information: company, location, name, and function.
c. Acknowledgement – Whenever a call is made or received, the initiating party should clearly
communicate the purpose of the call so that all issues are fully understood and addressed.
d. Content – The person requesting action should speak in a clear and calm manner, review
the information and request three-way communication, if appropriate. If any action is to be
taken, the recipient will fully understand when that action is expected to be taken (e.g.,
now, at a specific time, or “some” time). Closing – At the end of any call, those
communicating want to confirm that what was expected was completed, that no other
activity is required, and whether there is a clear commitment for call-back.
1
While the practice of using three-part communications for routine communications may be a good practice, the failure to use three-part
communications for routine communications is not considered to undermine reliability.
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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4. Barriers to Effective Verbal Communications
a. Sender or receiver not stating his or her name and/or work location when using a telephone
or radio.
b. Sender attempting to communicate with someone already engaged in another
conversation.
c. Sender stating too much information or multiple actions in one message.
d. Sender not giving enough information for the receiver to understand the message.
e. Sender not explicitly verifying that receiver understood the message.
f. Receiver failing to ask for needed clarification of the message, if required.
g. Receiver taking action before the communication is complete.
h. Receiver not writing the message on paper, if there are several items (more than two) to
remember.
i.
Receiver mentally preoccupied with another task (e.g., driving, texting, personal calls).
j.
Message not being stated loudly enough to be heard.
k.
Enunciating words poorly.
l.
Distractions to communications (e.g., background noise).
III. Communications Training for System Operators
Effective communication is one of the most important defenses in the prevention of errors and events.
Training provides an opportunity to ensure that personnel know their company’s requirements and
expectations for verbal communications, and it also reinforces good communication practices through
the use of drills and exercises.
Communications training can be based on company-specific policies and procedures for verbal
communications. The goal of communications training is to ensure effective verbal communications
during real-time operations. The following practices are provided for consideration in the
development of training exercises and drills and for management observation/coaching involving
verbal communications:
1. Classroom Training and Management Review
a. Classroom training can focus on company-specific policies and procedures for verbal
communications. The trainer wants to be clear on what communications protocols are
expected to be followed, when they are expected to be followed, and by whom. The trainer
also wants to emphasize the benefits of following the specific protocols.
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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b. Classroom training on effective communication is most thorough when it addresses the
following: 1) basis for use (why it is used); 2) when to use specific communications protocols
(provide specific examples); 3) roles and responsibilities for each participant (include the
significance of active listening); and 4) behavior expectations of each participant.
c. Effective communication principles can be reinforced during system operator training
simulations, exercises, or drills. Performance objectives or competencies can be established
and measured as part of these activities. Feedback assessments (both self and instructor)
can be part of the communications training process.
d. Management or peer observations (e.g., operator coaching session) can be utilized to
determine if the tools for effective communication are practiced by personnel in the actual
job environment. These observations provide an opportunity to recognize personnel who
meet or exceed expectations for use of effective communication tools. They also provide
an opportunity in a non-punitive environment to coach personnel who need to improve
their use of communication tools. The observations can be considered to determine if
changes or improvements are needed when training on communication tools.
e. Management involvement in system operator training, exercises, and drills can be used to
provide feedback and encourage a strong communications program.
2. Communication Practices – The following beneficial practices are provided for consideration in
the development or modification of training on effective communication:
a. Incorporate a “Communication Topic” as part of each continuing training cycle.
b. Ensure training on communication stresses effective, active listening. Even though the
“Sender or Initiator” of three-part communication is expected to ensure the message is
understood, the individual(s) receiving the message want to be engaged and actively
listening for effective communication to occur.
c. Use quizzes or reminders administered by email or other online testing applications to
emphasize key aspects of effective communication. This tool can also be used to provide
feedback on department or group level understanding of key points.
d. Incorporate internal and external operating experience related to communication as part of
initial and continuing training. The operating experience can be based on: 1) management
observations; 2) performance trends; 3) review of tapes from actual communication,
including system events in which directives were provided; or 4) related events from other
industries.
e. Use small groups or breakouts as part of training to conduct peer reviews of actual
communication. Audio tapes of actual operators can be reviewed by small groups to
identify proper communication and areas for improvement. In addition, system operators
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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may opt to review and critique their own voice recordings to identify lessons learned and
opportunities for improvement.
f. Conduct training seminars or communications workshops that involve operators and other
parties (e.g., receivers) they communicate with to educate all involved parties on the
expectations for effective communication.
g. As part of training, incorporate videos that depict proper usage of tools for effective
communication. Videos depicting operators in “real world” situations demonstrating
proper use of tools for effective communication can enhance buy-in by personnel. Videos
can also be used to depict scenarios in which tools for effective communication are not
properly used. Participants can critique or identify the area(s) for improvement in the use
of the tools for effective communication.
h. Structure field trips or benchmark trips to other industries (e.g., nuclear plants, aviation
control centers) that allow operators to listen to another perspective. This can help
reinforce a good balance on when to use three-part communication.
IV. Performance Assessment
Successful implementation of verbal communications programs often includes the development and
maintenance of a comprehensive series of controls and leadership practices that develop, reinforce,
and maintain effective communication. Examples of some effective elements of control programs are
listed below.
1. For many reasons the electric industry records most of its operational communications. These
recordings provide a rich vehicle for assessment, feedback, and learning when coupled with
periodic reviews of the recordings for the elements of effective communication.
2. In line with feedback and training programs, shift supervisors or operations leaders at many
operating entities assess a specific number of hours of recordings or a specific number of
recordings that may cover various topical areas (e.g., switching evolutions, AVR notifications,
SPS notifications, etc.) within an established period of time (e.g., every quarter or month) for
each of the operators under his or her leadership. Those leaders are then expected to share
their reviews with the operators involved. Such feedback is often most effective when it is
provided soon after an operational event has transpired. Some entities prefer such recording
review sessions be made in an informal coaching session. Other entities have tied effective
communication to the very formal aspect of annual performance goals and the resulting
performance reviews. Periodic assessments, including grading or scoring of calls, can quickly
provide needed feedback to ensure a system operator will be successful in achieving such a
performance goal throughout the course of the year. Entities may choose to reflect that
success in employee performance compensation.
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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3. Recognition Programs – Consider development of positive reinforcement programs that
recognize good system operator communications.
4. System Operator Assessments – Some entities assess the following:
a. Was the operator following the company’s communication policy?
b. When three-part communication was required, were each of the three elements of threepart communication evident?
c. If the receiver did not effectively repeat back the communication the first time, did the
sender pursue the receiver until the receiver did repeat back the elements of the reliability
directive?
d. How professional was the actual communication in both content and tone?
e. The focus of these reviews might involve more than the spoken word, since some entities
also include reviewing the resulting field paperwork. Such reviews help organizations
ensure good housekeeping and see that the complete company policy is being
implemented.
5. Event Analysis
a. If an operating entity has a system event that triggers a category 2 or higher event review in
accordance with the NERC Events Analysis Process, or if the operating entity has any other
event for which it wants to further assess its operations, this circumstance provides the
operating entity an opportunity to delve into assessing the effectiveness of its
communications.
b. When the system event’s recordings are pulled and reviewed, it provides an opportunity for
leaders, operators, and trainers to assess the effectiveness of their communications as
related to that event and, in some cases, to access broader operating practices.
c. Communication often involves parties beyond the organizational structure of one operating
entity. As such, when a third party (the receiver) of a communication has not facilitated
effective communication (either by not following agreed-upon protocol or by
unprofessionalism) this circumstance provides an opportunity for the reviewing leader to
share his or her observations with the receiver’s leader to enable learning across both
operating entities.
V. Aids to Communication
1. Recorders – Typically used to preserve a record of conversations to assist in the review of
incidents. Also used to check conversations to ensure communications are effective and
appropriate.
2. System Operator Logs – Used as a knowledge transfer device between system operators in the
same control room, as well as for management to respond to inquiries about situations that
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
9
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occurred days, weeks or even months afterward. Used in conjunction with all other forms of
communication.
3. Checklists – Used as an aid to ensure consistency in the information contained in routine
communications. A typical use of a checklist is during shift turnover of system operators to
ensure appropriate operating information is communicated to the system operator coming onshift.
4. Standard Verbal Cues - To develop a common understanding of the urgency and attention
required for a verbal communication entities may develop standard phraseology such as:
a. “This is a directive”: This is a simple way to let the receiver know that the next statement
will relay an expected mandatory action and will require a “repeat back” of the order.
b. “I (we) have a problem”: Important information is forthcoming.
c. “I need your help”: Action is needed, albeit not for an emergency.
d. “Are you ready to copy/write?”: When you want the recipient to write down the message.
e. “Say again”: When you need the sender to repeat a message
5. Tailgate Sessions – These are information sharing sessions prior to an important job or
evolution. They are a give and take briefing of the scope of the task to be done, special safety
precautions and an opportunity to ask clarifying questions. The intent of the session is to
ensure everyone knows the goal and has the necessary tools and information. A clear
transition from a tailgate session to formal communications such as a standard verbal cue
should be used.
6. Standard (or Special) Operating Instructions – These may be known by various other names.
Rather than issue a set of complex instructions verbally, the sender provides an advance copy
of written steps. When the order is given, the sender ensures the recipient has the correct document
(name and date/version) and gives the instruction to complete certain steps or the entire procedure.
Related Documents and Links
1. Electric Reliability Organization Event Analysis Process, dated February 2012
ERO Event Analysis Process
2. DOE Standard: Human Performance Improvement Handbook, Volume 2: Human Performance
Tools for Individuals, Work Teams, and Management; DOE-HDBK-1028-2009, dated June 2009
Human Performance Tools for Individuals, Work Teams, and Management
3. Human Performance Tools for Workers: General Practice for Anticipating, Preventing, and
Catching Human Error During the Performance of Work, dated April 2006. Developed by the
Institute of Nuclear Power Operations (INPO 06-002)
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
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4. Reliability Standard COM-002-2 (Communications and Coordination)
Revision History
Date
Version
Number
9/19/2012
1.0
Reason/Comments
Initial Version – Reliability Guideline: System
Operator Verbal Communications – Current
Industry Practices
Reliability Guideline: System Operator Communications – Current Industry Practices
Approved: Operating Committee – September 19, 2012
11
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
COM-001-2 AND COM-002-4
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
May 14, 2014
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
TABLE OF CONTENTS
I.
EXECUTIVE SUMMARY .................................................................................................... 2
II.
NOTICES AND COMMUNICATIONS ................................................................................ 5
III. BACKGROUND .................................................................................................................... 5
A.
Regulatory Framework ..................................................................................................... 5
B.
NERC Reliability Standards Development Procedure ..................................................... 6
IV. Reliability Standard Version History and Commission Directives ........................................ 7
A.
History of COM-001-1 and Associated Commission Directives ..................................... 7
B.
History of COM-002-2 and Associated Directives .......................................................... 9
C.
Revisions to COM Reliability Standards ....................................................................... 13
V.
1.
History of Project 2006-06 ......................................................................................... 13
2.
History of Project 2007-02 ......................................................................................... 14
JUSTIFICATION FOR APPROVAL .................................................................................. 14
A.
Proposed Reliability Standard COM-001-2 ................................................................... 15
1.
Purpose of Proposed Reliability Standard .................................................................. 15
2.
Requirements, Technical Basis and Defined Terms ................................................... 15
3.
Improvements Reflected in Proposed COM-001-2 .................................................... 18
4.
Proposed COM-001-2 Satisfies the Commission’s Directives................................... 20
5.
Revisions to Reliability Standard COM-001-1.1 ....................................................... 22
B.
C.
Proposed Reliability Standard COM-002-4 ................................................................... 23
1.
Purpose of Proposed Reliability Standard .................................................................. 23
2.
Standard Development History ................................................................................. 24
3.
Requirements, Technical Basis, and Defined Terms .................................................. 25
4.
Improvements Reflected in COM-002-4 .................................................................... 40
5.
Proposed COM-002-4 Satisfies the Commission’s Directives................................... 42
Enforceability of Proposed Reliability Standards .......................................................... 44
VI. CONCLUSION ..................................................................................................................... 44
i
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TABLE OF CONTENTS
Exhibit A
Proposed Reliability Standard COM-001-2
Exhibit B
Proposed Reliability Standard COM-002-4
Exhibit C
Implementation Plan and Mapping Document (COM-001-2)
Exhibit D
Implementation Plan (COM-002-4)
Exhibit E
Mapping Document (COM-002-4)
Exhibit F
Order No. 672 Criteria (COM-001-2)
Exhibit G
Order No. 672 Criteria (COM-002-4)
Exhibit H
Rationale and Technical Justification (COM-002-4)
Exhibit I
Frequently Asked Questions Document (COM-002-4)
Exhibit J
Table of Issues and Directives (COM-002-4)
Exhibit K
Analysis of Violation Risk Factors and Violation Security Levels (COM-001-2)
Exhibit L
Analysis of Violation Risk Factors and Violation Security Levels (COM-002-4)
Exhibit M
Summary of Development History and Complete Record of Development (COM001-2)
Summary of Development History and Complete Record of Development (COM002-4)
Exhibit N
Exhibit O
NERC Board of Trustees Input Responses
Exhibit P
Standard Drafting Team Rosters for Project 2006-06 Reliability Coordination and
Project 2007-02 Operating Personnel Communications Protocols
Exhibit Q
Operating Committee Reliability Guideline: “System Operator Verbal
Communications – Current Industry Practices”
ii
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation
)
)
Docket No. ____________
PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARDS
COM-001-2 AND COM-002-4
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”)1 and Section 39.52 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”)3 hereby submits for Commission approval
proposed Reliability Standards COM-001-2 (Communications) (Exhibit A) and COM-002-4
(Operating Personnel Communications Protocols) (Exhibit B). NERC requests that the
Commission approve the proposed Reliability Standards and find that each is just, reasonable,
not unduly discriminatory or preferential, and in the public interest.4 NERC also requests
approval of: (i) new defined terms “Operation Instruction”, “Interpersonal Communication”, and
“Alternative Interpersonal Communication” for inclusion in the NERC Glossary of Terms; (ii)
the Implementation Plans for the proposed Reliability Standards (Exhibits C and D); (iii) the
associated Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibits A,
1
16 U.S.C. § 824o (2012).
18 C.F.R. § 39.5 (2014).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
Unless otherwise designated, capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary of Terms”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.
2
1
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B, K, and L); and (iv) the retirement of the currently-effective Reliability Standards COM-0011.1, EOP-008-1 (Requirement R1), and COM-002-2 as listed in the Implementation Plans.
As required by Section 39.5(a)5 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standards COM-001-2 and COM-002-4,
a summary of the development history for each proposed Reliability Standard (Exhibits M and
N), and a demonstration that the proposed Reliability Standards meet the criteria identified by
the Commission in Order No. 6726 (Exhibits F and G). The NERC Board of Trustees adopted
proposed Reliability Standards COM-001-2 and COM-002-4 on November 7, 2012 and May 6,
2014 respectively.
I.
EXECUTIVE SUMMARY
Proposed Reliability Standards COM-001-2 and COM-002-4 replace and improve upon
the currently effective COM-001-1.1 and COM-002-2 Reliability Standards to establish
requirements for communication capabilities and communications protocols necessary to
maintain reliability. Proposed COM-001-2 establishes a clear set of requirements for what
communications capabilities various functional entities must maintain for reliable
communications.
Proposed COM-002-4 requires entities to have or create a set of documented
communications protocols that include certain minimum mandatory protocols. Proposed COM002-4 improves communications surrounding the issuance of Operating Instructions by
employing predefined communications protocols, thereby reducing the possibility of
5
18 C.F.R. § 39.5(a) (2014).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
6
2
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miscommunication that could lead to action or inaction harmful to the reliability of the Bulk
Electric System. In addition to setting predefined communications protocols, the proposed
Reliability Standard requires use of the same protocols regardless of the current operating
condition. In other words, the same protocols apply during normal, alert, and Emergency
operating conditions, negating the need to identify the current operating condition to determine if
a different set of protocols applies.
Proposed COM-002-4 also requires entities to reinforce
the use of the documented communication protocols through training, assessing adherence by
operating personnel to the documented communication protocols, and providing feedback to
those operating personnel on their use of the protocols. During Emergencies, operating personnel
must use the documented communication protocols for three-part communications without
exception, since clear communication is essential to providing swift and coordinated response to
events that are directly impacting the reliability of the Bulk Electric System.
Proposed Reliability Standards COM-001-2 and COM-002-4 address all of the pertinent
Commission directives from Order No. 693 associated with the Commission’s approval of
COM-001-1.1 and COM-002-2.7 The revisions made to proposed COM-002-4 also address
Recommendation No. 26 from the final report issued by the U.S.-Canada Power System Outage
Task Force to “[t]ighten communications protocols, especially for communications during alerts
and emergencies.”8
7
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 Fed. Reg.
16416, FERC Stats. & Regs. ¶ 31,242, at PP 487-93, 502-04, 508, 512, 514-15, 531-32, 534, 535, and 540, order on
reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
8
U.S.-Canada Power System Outage Task Force, Final Report on the August 14, 2003 Blackout in the
United States and Canada: Causes and Recommendations, April 2004 (“Blackout Report”). On August 15, 2003,
President George W. Bush and then-Prime Minister Jean Chrétien directed the creation of a Joint U.S.-Canada
Power System Outage Task Force to investigate the causes of the blackout and ways to reduce the possibility of
future outages. The U.S.-Canada Task Force convened, investigated the causes of this blackout, and recommended
actions to prevent future widespread outages.
3
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Proposed COM-001-2 satisfies the Commission’s directives and improves upon
Reliability Standard COM-001-1.1 by adding Generator Operators and Distribution Providers as
applicable entities. Proposed COM-001-2 also identifies specific requirements for
telecommunications capabilities for use in all operating conditions that reflect the roles of the
applicable entities and their impact on Reliable Operation. Proposed COM-001-2 further
includes adequate flexibility in its language for compliance with the Reliability Standard to
permit the adoption of new technologies and cost-effective solutions.
Proposed COM-002-4 also satisfies the Commission’s directives and improves upon the
previous Reliability Standard COM-002-2 by adding Distribution Providers as an applicable
entity in the proposed Reliability Standard. Proposed COM-002-4 also meets the Commission’s
directive to require “tightened communications protocols, especially for communications during
alerts and emergencies” by establishing a baseline set of mandatory protocols and focusing
certain requirements on zero-tolerance responsibility for failure to use or misuse of the protocols
for three-part communications during Emergency conditions. Under proposed COM-002-4, all
applicable entities must use the same set of protocols during all operating conditions,
establishing communication uniformity as much as practical on a continent-wide basis.
For the reasons discussed in this Petition, NERC respectfully requests that the
Commission approve the proposed Reliability Standards as just, reasonable, not unduly
discriminatory or preferential, and in the public interest.
4
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II.
NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following:9
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Associate General Counsel
William H. Edwards*
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
III.
Valerie L. Agnew*
Director of Standards
Howard Gugel*
Director, Performance Analysis
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
[email protected]
BACKGROUND
A.
Regulatory Framework
By enacting the Energy Policy Act of 2005,10 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1)11
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
9
Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2014), to allow the inclusion
of more than two persons on the service list in this proceeding.
10
16 U.S.C. § 824o (2012).
11
Id. § 824(b)(1).
5
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States will be subject to Commission-approved Reliability Standards. Section 215(d)(5)12 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a)13 of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should be made effective.
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA14 and Section 39.5(c)15 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
B.
NERC Reliability Standards Development Procedure
The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.16 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
12
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
14
16 U.S.C. § 824o(d)(2).
15
18 C.F.R. § 39.5(c)(1).
16
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
whether a proposed Reliability Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-approved Reliability Standard development process for the
development of the particular proposed Reliability Standard in a proper manner, especially whether the process was
open and fair. However, we caution that we will not be sympathetic to arguments by interested parties that choose,
for whatever reason, not to participate in the ERO’s Reliability Standard development process if it is conducted in
good faith in accordance with the procedures approved by FERC.”).
13
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Development) of its Rules of Procedure and the NERC Standard Processes Manual.17 In its
order certifying NERC as the Commission’s Electric Reliability Organization, the Commission
found that NERC’s proposed rules provide for reasonable notice and opportunity for public
comment, due process, openness, and a balance of interests in developing Reliability Standards18
and thus satisfies certain of the criteria for approving Reliability Standards.19 The development
process is open to any person or entity with a legitimate interest in the reliability of the BulkPower System. NERC considers the comments of all stakeholders, and a vote of stakeholders
and the NERC Board of Trustees is required to approve a Reliability Standard before the
Reliability Standard is submitted to the Commission for approval.
IV.
Reliability Standard Version History and Commission Directives
This section presents the version history of each Reliability Standard beginning with the
version 0 Reliability Standards and the associated Commission directives from Order No. 693.
NERC has also included relevant discussion from the Order No. 693 proceeding that has
relevance to both the directives and the standards development work of the standard drafting
teams to revise the COM-001 and COM-002 Reliability Standards. Discussion of the proposed
Reliability Standards and how the proposed Reliability Standards satisfy the Commission
directives is included below in section V of this Petition.
A.
History of COM-001-1 and Associated Commission Directives
NERC originally implemented Reliability Standard COM-001-0 (Telecommunications)
on April 1, 2005.20 The version 0 Reliability Standard sought to ensure coordinated
17
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
18
116 FERC ¶ 61,062 at P 250.
19
Order No. 672 at PP 268, 270.
20
See NERC Apr. 4, 2006 Petition for Approval of Reliability Standards, Docket No. RM06-16-000 at 33.
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telecommunications among operating entities and established general telecommunications
requirements for operating entities, including equipment testing and coordination. COM-001-0
also: (i) established English as the common language between and among operating personnel;
and (ii) set the policy for using the NERCnet telecommunications system.21 COM-001-0 applied
to Transmission Operators, Balancing Authorities, Reliability Coordinators and NERCNet user
organizations.22 NERC submitted COM-001-0 in its original petition for approval of its
proposed Reliability Standards.23 NERC subsequently submitted a petition24 to include a revised
version 1 of the COM-001 Reliability Standard to add missing compliance elements.25
On May 11, 2006, Commission staff issued its Staff Preliminary Assessment of the North
American Electric Reliability Council’s Proposed Mandatory Reliability Standards
(“Preliminary Assessment”).26 In the Preliminary Assessment, Commission staff made the
following summary comments regarding COM-001-0:
•
COM-001-0 does not contain specific or minimum adequacy, redundancy and diverse
routing requirements for telecommunications facilities;
•
the applicability section does not specify that Generator Operators are subject to
telecommunications requirements; and
•
COM-001-0 contains no Compliance Measures or Levels of Non-Compliance.
21
NERCNet is a Wide Area Network using Frame Relay as its communications medium. It supports the
Interregional Security Network, Interchange Distribution Calculator and the Reliability Coordinator Information
System. NERCnet has been used by NERC since 1997 to allow Reliability Coordinators, Transmission Operators,
and Balancing Authorities and NERCnet user organizations to share Real-time operating reliability data.
22
“NERCnet User Organizations” are defined in COM-001-1.1, Attachment 1 as “[us]ers of NERCnet who
have received authorization from NERC to access the NERC network are considered users of NERCnet resources.
To be granted access, users shall complete a User Application Form and submit this form to the NERC
Telecommunications Manager.”
23
See NERC Apr. 4, 2006 Petition for Approval of Reliability Standards, Docket No. RM06-16-000.
24
See NERC Nov. 16, 2006 Petition for Approval of Reliability Standards, Docket Nos. RM06-16-000 and
RM07-03-000.
25
The Commission approved an errata change to COM-001-1 by delegated letter order on May 13, 2009. As
a result, the currently effective and enforceable version of COM-001 is COM-001-1.1. See N. Am. Elec. Reliability
Corp., Docket No. RD09-2-000 (2009) (delegated letter order).
26
See Staff Preliminary Assessment of the North American Electric Reliability Council’s Proposed
Mandatory Reliability Standards, May 11, 2006, Docket No. RM06-16-000.
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Commission staff explained in the Preliminary Assessment that COM-001 contains a general
requirement to provide “adequate and reliable” telecommunications facilities for all applicable
operating entities. Commission staff concluded that COM-001-0 does not contain specific or
minimum requirements on adequacy, redundancy and diverse routing of the telecommunications
facilities necessary to ensure the exchange of operating information, both internally and among
operating entities. Staff explained that leaving the specification of what constitutes adequate and
reliable telecommunication facilities to operating entities could lead to claims by operating
entities that they comply with the Reliability Standard when in fact they still may not have
“adequate” telecommunications facilities for use during real-time normal and Emergency
operations.27 Further, Commission staff noted that while COM-001 has a redundancy and
diverse routing requirement, it is effective only “where applicable,” and no specification is
provided regarding the circumstances where the requirement actually is applicable.
The Commission approved COM-001-1 in Order No. 693, but the Commission issued
certain directives to improve the Reliability Standard including the additional of certain entities
to the applicability of the standard and identification of specific requirements for
telecommunications facilities.28
B.
History of COM-002-2 and Associated Directives
Reliability Standard COM-002-0 was implemented on April 1, 2005. The stated purpose
of the Reliability Standard was to:
To ensure Balancing Authorities, Transmission Operators, and
Generator Operators have adequate communications and that these
communications capabilities are staffed and available for addressing
a real-time emergency condition. To ensure communications by
operating personnel are effective.
27
28
Id. at 42-43.
Order No. 693 at PP 487-93, 502-04, 508.
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COM-002-0 applied to Reliability Coordinators, Balancing Authorities, Transmission Operators,
and Generator Operators. Reliability Standard COM-002-1 was developed in November 2006 to
replace COM-002-0. COM-002-1 added additional detail on the communications requirements
between and among operating entities and included specific situations that require
communications with other operating entities. COM-002-1 contained two Requirements.
Requirement R1 required each Transmission Operator, Balancing Authority, and Generator
Operator to have communications (voice and data links) with appropriate Reliability
Coordinators, Balancing Authorities, and Transmission Operators. The communications had to
be staffed and available for addressing a real-time emergency condition. In addition, each
Balancing Authority and Transmission Operator had to notify its Reliability Coordinator and
affected Balancing Authorities and Transmission Operators “of any condition that could threaten
the reliability of its area or when firm load shedding is anticipated.” Requirement R2 required
each Reliability Coordinator, Transmission Operator, and Balancing Authority to use three-part
communications. Each entity was required to issue directives in a clear, concise, and definitive
manner; ensure the recipient of the directive repeats the information back correctly; and
acknowledge the response as correct or repeat the original statement to resolve any
misunderstandings.29
NERC submitted COM-002-1 in its original petition for approval of its proposed
Reliability Standards.30 In its subsequent November 15, 2006 petition, NERC submitted COM002-2, which supersedes the version 1 Reliability Standard. COM-002-2 adds Measures and
Levels of Non-Compliance to the version 1 Reliability Standard.
29
Of particular note, the Reliability Standard did not place any obligation on the receiver of a
communication. The responsibility for ensuring proper understanding was placed on the issuer.
30
See NERC Apr. 4, 2006 Petition for Approval of Reliability Standards, Docket No. RM06-16-000 at 32-33.
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The Preliminary Assessment issued by FERC staff also identified shortcomings in the
COM-002-2 Reliability Standard. Commission staff stated that the standard did not contain a
requirement that appropriate operating actions be assessed and approved first and then
implemented in normal and emergency operating conditions in which reliability could be
impacted beyond a local area. Commission staff noted in its explanation “[e]ffective
communications with proper communications protocols among the operating entities are
essential for maintaining reliable system operations.”
Commission staff’s comments relied heavily on recommendations made in the Blackout
Report. The Blackout Report included 46 specific recommendations to address the primary
causes of the blackout to help prevent or minimize the scale of future blackouts. The Blackout
Report also identified eight factors that were common to some of the eight major outage
occurrences from the 1965 Northeast Blackout through the 2003 blackout, including “ineffective
communications.”31 In particular, Recommendation No. 26 reads: “[t]ighten communications
protocols, especially for communications during alerts and emergencies. Upgrade
communication system hardware where appropriate.” Recommendation No. 26 continues:
NERC should work with reliability coordinators and control area
operators to improve the effectiveness of internal and external
communications during alerts, emergencies, or other critical situations,
and ensure that all key parties, including state and local officials,
receive timely and accurate information. NERC should task the
regional councils to work together to develop communications
protocols by December 31, 2004, and to assess and report on the
adequacy of emergency communications systems within their regions
against the protocols by that date.32
The Blackout Report explained that on August 14, 2003, “reliability coordinator and control area
communications regarding conditions in northeastern Ohio were in some cases ineffective,
31
32
Blackout Report at 107.
Id. at 141, 161.
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unprofessional, and confusing.” The Blackout Report concluded that ineffective communications
contributed to a lack of situational awareness and precluded effective actions to prevent the
cascade. The Blackout Report also stated “[c]onsistent application of effective communications
protocols, particularly during alerts and emergencies, is essential to reliability.”33
In its Preliminary Assessment, Commission staff interpreted the Blackout Report
recommendation’s reference to “effective communications” with “tightened communications
protocols” among operating entities to include two key components: (i) effective
communications that are delivered in clear language via pre-established communications paths
among pre-identified operating entities, and (ii) communications protocols which clearly identify
that any operating actions with reliability impact beyond a local area or beyond a Reliability
Coordinator’s area must be communicated to the appropriate Reliability Coordinator for
assessment and approval prior to their implementation to ensure reliability of the interconnected
systems.34 Commission staff concludes that the requirements in COM-002-1 fulfill the
“effective communications” component of the Blackout Report recommendation, but do not
meet the call for “tightened communications protocols.” Specifically, the Commission states that
COM-002-1, or other Reliability Standards, do not contain a requirement that the appropriate
operating actions in normal and emergency operating conditions that may have reliability impact
beyond a local area or Reliability Coordinator’s area must be assessed and approved by the
Reliability Coordinator, before implementation by the operating entities.35
In its comments to the Preliminary Assessment, NERC stated that it did not believe that
“tightened communications protocols” should include the requirement that “the appropriate
33
34
35
Id. at 161.
Preliminary Assessment at 43-44.
Id. at 44.
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operating actions…must be assessed and approved by the reliability coordinator, before being
implemented by the operating entities.”36 NERC further argued that other NERC standards (e.g.,
EOP-001 and TOP-001) require the Transmission Operator, Balancing Authority, and Reliability
Coordinator to coordinate their emergency operating plans and communicate actions with one
another. However, NERC did state, without elaboration, that it “agrees with the need for
development of additional standards addressing consistent communications protocols among
personnel responsible for the reliability of the Bulk-Power System.”
The Commission ultimately approved COM-002-2 in Order No. 693, but the Commission
issued certain directives to improve the Reliability Standard including adding Distribution
Providers as an applicable entity in the Reliability Standard and requiring NERC to create
tightened communications protocols, especially for communications during alerts and
emergencies.37 Section V includes a summary of these directives along with how the proposed
Reliability Standard satisfies the directives.
C.
Revisions to COM Reliability Standards
1.
History of Project 2006-06
Project 2006-06 – Reliability Coordination was established to ensure that reliabilityrelated Requirements that are applicable to the Reliability Coordinator are clear, measurable,
unique and enforceable, and to ensure that this set of Requirements is sufficient to maintain
36
NERC Jun. 26, 2006 Comments to Preliminary Assessment, Docket No. RM06-16-000 at 120 (quoting
Preliminary Assessment) (emphasis added).
37
In addition, the Commission suggests NERC consider certain comments in the Standards Development
Process. The Commission asks NERC to consider the American Public Power Association’s (“APPA”) comments
regarding the Measures and Levels of Non-Compliance when revising the Reliability Standard. APPA notes that the
Levels of Non-Compliance for COM-002-2 are inadequate in two respects: (1) reliability coordinators are not
included in any Level of Non-Compliance and (2) the Levels of Non-Compliance for transmission operators and
balancing authorities in Compliance D.2 do not reference Requirements R1 and R2. Order No. 693 at P 533. The
Commission also suggest that NERC consider comments by Santa Clara, FirstEnergy and Six Cities regarding
specific new improvements to the Reliability Standards. Order No. 693 at 536-39.
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reliability of the Bulk Electric System. Revisions to the COM-001 and COM-002 Reliability
Standards were included within the project scope in order to modify the currently-effective
Reliability Standards, COM-001-1.1 and COM-002-2, to address the applicable directives in
Order No. 693, while adequately addressing the communication needs of Reliability
Coordinators. The project resulted in two proposed Reliability Standards, COM-001-2 and
COM-002-3.
2.
History of Project 2007-02
The purpose of Project 2007-02 – Operating Personnel Communications Protocols was to
create a new Reliability Standard that requires real time system operators to use standardized
communication protocols during normal and emergency operations to improve situational
awareness and shorten response time.38 The Project drafted Reliability Standard COM-003-1 to
accomplish this goal. The Project ultimately resulted in the combination of COM-002-3 from
Project 2006-06 and draft COM-003-1 into a single proposed Reliability Standard, COM-002-4.
V.
JUSTIFICATION FOR APPROVAL
As discussed in Exhibits F and G and below, the proposed Reliability Standards, COM-
001-2 and COM-002-4, satisfy the Commission’s criteria in Order No. 672 and are just,
reasonable, not unduly discriminatory or preferential, and in the public interest. The following
section separately provides: (i) the purpose of the proposed Reliability Standards; (ii) a
description of the requirements in each of the proposed Reliability Standards, the technical basis
supporting the requirements, and a description of proposed defined terms; (iii) a discussion of
38
See Standard Authorization Request, available at
http://www.nerc.com/pa/Stand/Project%20200702%20Operating%20Personnel%20Communications/SAR_Project_
2007-02_Comm_Protocols_1st_Posting_15Mar07.pdf.
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how the proposed Reliability Standards satisfy the outstanding Commission directives from
Order No. 693; and (iv) a discussion of the enforceability of the proposed Reliability Standards.
A.
Proposed Reliability Standard COM-001-2
1.
Purpose of Proposed Reliability Standard
Proposed Reliability Standard COM-001-2 revises the currently effective COM-001-1.1
Reliability Standard. The purpose of proposed Reliability Standard COM-001-2 is to establish
requirements for Interpersonal Communication capabilities necessary to maintain reliability.
Proposed COM-001-2 applies to Reliability Coordinators, Balancing Authorities, Transmission
Operators, Generator Operators, and Distribution Providers.
2.
Requirements, Technical Basis and Defined Terms
The proposed Reliability Standard includes eleven requirements and two new defined
terms, “Interpersonal Communication” and “Alternative Interpersonal Communication,” which
collectively provide a comprehensive approach to establishing communications capabilities
necessary to maintain reliability. The defined terms used in the requirements of proposed COM001-2 are:
Interpersonal Communication – Any medium that allows two or
more individuals to interact, consult, or exchange information.
Alternative Interpersonal Communication – Any Interpersonal
Communication that is able to serve as a substitute for, and does not
utilize the same infrastructure (medium) as, Interpersonal
Communication used for day-to-day operation.
These definitions provide clarity that an entity’s communication capability must be
redundant and that each of the capabilities must not utilize the same medium. The new
definitions, therefore, improve upon the language used in the current COM-001-1.1 Reliability
Standard, which states “[e]ach Reliability Coordinator, Transmission Operator and Balancing
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Authority shall provide adequate and reliable telecommunications facilities for the exchange of
Interconnection and operating information.” COM-001-1.1, Requirement R1, Part R1.4 states
that “[w]here applicable, these facilities shall be redundant and diversely routed.” Use of the
defined terms eliminates the need to use the ambiguous phrases “adequate and reliable” and
“redundant and diversely routed, which were identified in the Preliminary Assessment as
potentially creating ambiguity in the Reliability Standard.
Requirements R1-R6 address the Interpersonal Communication capability and
Alternative Interpersonal Communication capability of the Reliability Coordinator, Transmission
Operator, and Balancing Authority. Each functional entity has a requirement to have an
Interpersonal Communication capability and to designate an Alternative Interpersonal
Communication capability with certain other functional entities as follows:
Requirements R1 and R2 require the Reliability Coordinator to have Interpersonal
Communication capability (R1) and designate Alternative Interpersonal Communication
capability (R2) with all Transmission Operators and Balancing Authorities within its Reliability
Coordinator Area and each adjacent Reliability Coordinator within the same Interconnection.
Requirement R3 requires each Transmission Operator to have Interpersonal
Communication capability with: (i) its Reliability Coordinator; (ii) each Balancing Authority
within its Transmission Operator Area; (iii) each Distribution Provider within its Transmission
Operator Area; (iv) each Generator Operator within its Transmission Operator Area; (v) each
adjacent Transmission Operator synchronously connected; and (vi) each adjacent Transmission
Operator asynchronously connected.
Requirement R4 requires each Transmission Operator to designate Alternative
Interpersonal Communication capability with: (i) its Reliability Coordinator; (ii) each Balancing
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Authority within its Transmission Operator Area; (iii) each adjacent Transmission Operator
synchronously connected; and (iv) each adjacent Transmission Operator asynchronously
connected.
Requirement R5 requires each Balancing Authority to have Interpersonal Communication
capability with: (i) its Reliability Coordinator; (ii) each Transmission Operator that operates
Facilities within its Balancing Authority Area; (iv) each Distribution Provider within its
Balancing Authority Area; (v) each Generator Operator that operates Facilities within its
Balancing Authority Area; and (vi) each Adjacent Balancing Authority.
Requirement R6 requires each Balancing Authority to designate Alternative Interpersonal
Communication capability with: (i) its Reliability Coordinator; (ii) each Transmission Operator
that operates Facilities within its Balancing Authority Area; and (iii) each Adjacent Balancing
Authority.
Requirements R7 and R8 require each Distribution Provider and Generator Operator,
respectively, to have Interpersonal Communication capability with: (i) its Balancing Authority;
and (ii) its Transmission Operator.
Requirement R9 requires the Reliability Coordinator, Transmission Operator, and
Balancing Authority to test its Alternative Interpersonal Communication capability, initiate
repair, or designate a replacement alternative communication capability within two hours
following the test.
Requirement R10 requires the same entities to notify the entities identified in
Requirements R1, R3, and R5 of the detection of a failure of its Interpersonal Communication
capability that lasts 30 minutes or longer. The notification must occur within 60 minutes of the
detection of the failure. The standard drafting team determined that 60 minutes was a reasonable
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timeframe for completing the notification. Some commenters in the standards development
process expressed concern in meeting the 60-minute notification timeframe upon the loss of their
Interpersonal Communication capability. However, the standard drafting team responded that the
notification requirement applies to the Balancing Authority, Reliability Coordinator and
Transmission Operator, which are required to have an Alternative Interpersonal Communication
capability, and should have the ability to accomplish the required notification.
Finally, Requirement R11 requires the Distribution Provider and Generator Operator to
consult with its Balancing Authority and Transmission Operator, upon detecting a failure of its
Interpersonal Communication capability, to determine a mutually agreeable action for the
restoration of its Interpersonal Communication capability. This requirement provides a means
for the Distribution Provider and Generator Operator to have an understanding with the
Balancing Authority and Transmission Operator of how the restoration of the Interpersonal
Communication capability will occur, providing the necessary awareness to all of the status of
the Interpersonal Communication capability.
3.
Improvements Reflected in Proposed COM-001-2
Proposed COM-001-2 improves the currently-effective Reliability Standard by: (1)
eliminating terms that do not adequately specify the desired actions that Reliability Coordinators,
Balancing Authorities, and Transmission Operators are expected to take in relation to their
telecommunication facilities; (2) clearly identifying the need for applicable entities to be capable
of Interpersonal Communication and Alternative Interpersonal Communication, as those terms
are defined and proposed for approval; (3) not requiring specific technology or systems to be
utilized; and (4) including the Distribution Provider and Generator Operator as covered
functional entities.
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First, proposed COM-001-2 eliminates ambiguous terms used in COM-001-1 that do not
adequately specify the desired actions that Reliability Coordinators, Balancing Authorities, and
Transmission Operators are expected to take with respect to each’s telecommunication facilities.
For example, Requirement R1 of COM-001-1 includes the phrase “shall provide adequate and
reliable telecommunications facilities.” Entities explained during the Standards Development
Process that “adequate and reliable” could lend itself to multiple interpretations. The
Commission also raised concern over this phrase in the Preliminary Assessment prior to the
issuance of Order No. 693. Rather than using the term “adequate,” the proposed standard now
specifies the communications capability requirements between entities by function and condition
in Requirements R1 through R8. The term “reliable” is replaced by a specific requirement for
testing (Requirement R9), along with two new requirements for notification of a failure of an
applicable entity’s communication capability (Requirements R10 and R11). Further, use of two
new proposed defined terms – “Interpersonal Communication” and “Alternative Interpersonal
Communication” – resolves the ambiguity caused by the phrases “adequate and reliable” and
“redundant and diversely routed” communications in COM-001-1. COM-001-2 instead requires
the applicable entities to have a clearly defined Interpersonal Communication capability and an
Alternative Interpersonal Communication capability, in addition to specifying, under what
conditions, those entities that must have the capability.
Second, proposed COM-001-2 clearly identifies the need to be capable of both
Interpersonal Communication and Alternative Interpersonal Communication. By clearly
identifying the capability needs, the proposed Reliability Standard eliminates the inferred need
for redundant, emergency telecommunication facilities. In contrast, Requirement R2 of COM001-1, states “[s]pecial attention shall be given to emergency telecommunications facilities and
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equipment not used for routine communications.” While this language contains an inference that
some equipment is maintained for uses other than routine communications, the requirement is
not clear about what capabilities must be maintained. The new term “Alternative Interpersonal
Communication” clarifies this language to explicitly require Interpersonal Communication
capabilities that does not utilize the same infrastructure as the communications infrastructure for
day-to-day operations.
Third, the use of word “capability” in the proposed Reliability Standard ensures the
standard is technologically agnostic, allowing for future changes in technology and advances in
communication to be employed without requiring a change to the Reliability Standard.
Lastly, the proposed Reliability Standard expands the applicability of the Reliability
Standard to cover Distribution Providers and Generator Operators. These functional entities are
now required to have an Interpersonal Communication capability with the listed entities in
Requirements R7 and R8, respectively. This is directly responsive to directives in Order No.
693, as discussed below.
4.
Proposed COM-001-2 Satisfies the Commission’s Directives
In Order No. 693, the Commission issued three directives to NERC to modify certain
aspects of the currently effective COM-001-1 Reliability Standard. Each is explained in turn,
along with how the proposed Reliability Standard satisfies the directive.
The Commission reaffirmed its position taken in the Notice of Proposed Rulemaking that
“Generator Operators” and “Distribution Providers” should be included as applicable entities in
COM-001-1 to ensure there is no reliability gap during normal and emergency operations.39 The
Commission argued that during a blackstart when normal communications may be disrupted, it is
39
Id. at PP 487-93.
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essential that the Transmission Operator, Balancing Authority and Reliability Coordinator
maintain communications with their Distribution Providers and Generator Operators. In
developing requirements for these newly applicable entities, the Commission noted that the
revised Reliability Standard could establish an appropriate range of requirements for
telecommunication facilities that reflect their respective roles on Reliable Operation of the BulkPower System.
The Commission also issued additional directives to revise COM-001-140 to: (i) identify
specific requirements for telecommunications facilities for use in normal and emergency
conditions that reflect the roles of the applicable entities and their impact on Reliable Operation;
and (ii) include adequate flexibility for compliance with the Reliability Standard, adoption of
new technologies and cost-effective solutions.41
Proposed COM-001-2 meets all three of the Commission’s directives issued in Order No.
693. First, NERC has included “Generator Operators” and “Distribution Providers” as covered
applicable entities pursuant to the Commission’s directive.
Second, proposed COM-001-2 meets the Commission’s directive to “identify specific
requirements for telecommunications facilities for use in normal and emergency conditions that
reflect the roles of the applicable entities and their impact on Reliable Operation.” The proposed
Reliability Standard sets requirements to have “Interpersonal Communication” capability and
“Alternative Interpersonal Communication” capability, where noted in the requirements, without
limitation on the operating condition for each of the applicable entities (see Requirements R1R8). By setting parameters for the types of communications capabilities and setting
requirements for maintaining capabilities between certain functional entities, the proposed
40
41
Id. at PP 502-04.
Id. at P 508 (summarizing Commission directives on COM-001-1).
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Reliability Standard sets a clear baseline for communications capability during all operating
conditions. In addition, the proposed Reliability Standard includes requirements for notifying
other functional entities of the loss or failure of certain communications capabilities, further
ensuring that entities are aware of the communications capabilities of other functional entities.
Lastly, the proposed Reliability Standard uses terminology that has sufficient flexibility
for entities to adopt new technologies and cost-effective solutions. The requirements purposely
use the word “capability” in a general sense in order to remain agnostic on the specific
technology an entity must use, allowing opportunity for the adoption of new technology and
cost-effective solutions that may become available for use in the future.
5.
Revisions to Reliability Standard COM-001-1.1
Exhibit C to this petition contains an “Implementation Plan and Mapping Document” for
proposed COM-001-2 that describes the associated retirement of currently effective COM-0011.1 and provides a detailed mapping of how the requirements in COM-001-1.1 translate into
proposed COM-001-2. In summary, proposed COM-001-2 will retire all Requirements of COM001-1.1 upon proposed COM-001-2 becoming effective with the exception of Requirement R4.
Requirement R4 of COM-001-1.1 will be retired by proposed Reliability Standard COM-002-4
because this Requirement was referred to Project 2007-02 for inclusion in COM-003-1, which
addressed communications protocols. Of particular note in the Implementation Plan, the
standard drafting team concluded that Requirement R5 in COM-001-1.1 is redundant with EOP008-1, Requirement R1 and, therefore, has not been carried forward in proposed COM-001-2.
As a result, NERC proposes EOP-008-1, Requirement R1 for retirement.
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Additionally, Requirement R6 of COM-001-1.1 is also being proposed for retirement,
which requires adherence to certain policies and requirements when using NERCnet.42
Specification of the types of tools to be employed and requirements for interfacing with these
tools are best handled by NERC internal policies. This approach preserves NERC’s ability to be
responsive to new technologies and improvements in security of the tool without having to
modify a Reliability Standard to do so. The development of tools should support registered
entities in meeting the intent of a Reliability Standard without creating a burden on acquisition of
specific technology or tools. NERC is currently transitioning NERCnet to industry. Industry
will take on the network infrastructure upgrade and future maintenance and enhancements.
This transition will be complete prior to the effective date of COM-001-2. Policies and
requirements for use of the new tool will be addressed internally by NERC as part of the new
program.
B.
Proposed Reliability Standard COM-002-4
1.
Purpose of Proposed Reliability Standard
Proposed Reliability Standard COM-002-4 revises the currently effective COM-002-2
Reliability Standard and the Board-adopted COM-002-3 Reliability Standard.43 The purpose of
proposed Reliability Standard COM-002-4 is to improve communications for the issuance of
Operating Instructions with predefined communications protocols to reduce the possibility of
miscommunication that could lead to action or inaction harmful to the reliability of the Bulk
Electric System. The proposed Reliability Standard combines proposed Reliability Standard
42
See infra FN 21.
The Board-adopted COM-002-3 Reliability Standard is proposed for retirement in the Implementation Plan
because the proposed Reliability Standard has been combined with proposed COM-003-1 to create proposed COM002-4. COM-002-3 has not been submitted to the Commission for approval, therefore, the currently effective
version of COM-002 in the United States is COM-002-2.
43
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COM-002-3 and the former draft COM-003-1 into a single standard that addresses
communications protocols for operating personnel in Emergency and non-emergency conditions.
2.
Standard Development History
The standard drafting team conducted eight comment and ballot periods in arriving at the
final industry-approved language in the proposed COM-002-4 Reliability Standard. Over that
time, the standard drafting team responded to comments and revised the draft Reliability
Standard based on the consensus view of the standard drafting team following each consideration
of comments. In addition to the required steps outlined in the Standards Development Process,
the standard drafting team conducted stakeholder outreach in order to arrive at a draft Reliability
Standard that meets the stated purpose of the Reliability Standard, addresses the Commission’s
directives, and represents consensus in industry, including:
•
a full-day “Communications in Operations” technical conference held February 1415, 2013 to gather industry input on a consensus communications standard approach;
•
a survey distributed to a sample of industry experts by the Director of Standards
Development and the Standards Committee Chair requesting feedback on the draft
standard in preparation for the eighth additional ballot; and
•
consultation on the use of the term “Reliability Directive” in the COM-002-4 standard
with the Project 2007-03 Real-time Transmission Operations standard drafting team
and the Project 2006-06 Reliability Coordination standard drafting team.
In addition to the outreach above, the standard drafting team received input from the
NERC Board of Trustees on two occasions. On August 15, the Board adopted a resolution,44
which requested input from NERC’s Reliability Issues Steering Committee (“RISC”), the
Independent Experts Review Panel, and NERC management to inform the Board and provide
44
See Draft Minutes of the Board of Trustees, August 15, 2013 at 3-4, available at
http://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/BOT0813m-draft-complete.pdf.
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input into the standard development process. These inputs were provided to the standard
drafting team for its consideration and to the Operating Committee, with a request that the
Operating Committee provide its input to as well. Responses from RISC, the Independent
Experts Review Panel, NERC management, and the Operating Committee are included in
Exhibit O.
At its November 7, 2013 meeting, the Board of Trustees adopted a resolution for the
further development of the COM-003-1 Reliability Standard.45 The resolution provided
additional recommendations to the standard drafting team on the development of a subsequent
revised draft.
3.
Requirements, Technical Basis, and Defined Terms
Following posting six of the proposed COM-002-4 Reliability Standard, NERC staff
prepared a “strawman” draft that combined the COM-002-3 and draft COM-003-1 Reliability
Standards. The “strawman” provided a starting point for the standard drafting team to edit and
adjust as it deemed appropriate based on its own expertise and from the feedback industry
provided during the Standards Development Process.
In proposed COM-002-4, the same protocols are required to be used in connection with
the issuance of Operating Instructions for all operating conditions – i.e., non-emergency and
Emergency communications. However, the proposed Reliability Standard employs the phrase
“Operating Instruction during an Emergency” in certain Requirements (R5, R6, R7) to provide a
demarcation for what is subject to a zero-tolerance compliance approach and what is not. This
separation in the requirement structure is necessary to draft Violation Severity Levels to match
45
See Resolution for Agenda Item 8.i: Operating Personnel Communication Protocols, Nov. 7, 2013,
available at
http://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/Board%20COM%20Resolution
%2011.7.13%20v1%20AS%20APPROVED%20BY%20BOARD.pdf.
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each compliance approach described in the Board’s resolution. Where “Operating Instruction
during an Emergency” is not used, an entity will be assessed under a compliance approach that
focuses on whether an entity meets the initial training Requirement (either R2 or R3) and
whether an entity performed the assessment and took corrective actions according to
Requirement R4.
An entity should expect its operating personnel that issue and receive Operating
Instructions to use the entity’s documented communication protocols for the issuance and receipt
of all Operating Instructions. An entity reinforces its use of the documented communication
protocols through training, assessing adherence by its operating personnel to the documented
communication protocols, and providing feedback to those operating personnel on their use of
the protocols. During Emergencies, operating personnel must use the documented
communication protocols for three-part communications without exception, since clear
communication is essential to providing swift and coordinated response to events that are
directly impacting the reliability of the Bulk Electric System.
a)
Definition of “Operating Instruction”
The current draft of COM-002-4 no longer includes the term “Reliability Directive,”
which was included in previous postings as a subset within the definition of “Operating
Instruction.”46 The proposed definition of “Operating Instruction” reads as follows:
46
On November 21, 2013, the Commission issued a Notice of Proposed Rulemaking, which proposes to
remand certain proposed TOP and IRO standards. Monitoring System Conditions- Transmission Operations
Reliability Standard Transmission Operations Reliability Standards Interconnection Reliability Operations and
Coordination Reliability Standards, NOPR, 145 FERC ¶ 61,158 (2013). The TOP/IRO NOPR is available at:
http://www.nerc.com/FilingsOrders/us/FERCOrdersRules/NOPR_TOP_IRO_RM13-12_RM13-14_RM1315_20131121.pdf. The proposed remand includes the defined term “Reliability Directive.” FERC’s proposal to
remand the term “Reliability Directive” raised possible complications with the draft COM-002-4 Reliability
Standard, which used the proposed definition. The standard drafting team consulted on the use of the term
“Reliability Directive” in the COM-002-4 Reliability Standard with the Project 2007-03 Real-time Transmission
Operations and the Project 2006-06 Reliability Coordination Standard Drafting Teams to ask whether they believed
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A command by operating personnel responsible for the Real-time
operation of the interconnected Bulk Electric System to change or
preserve the state, status, output, or input of an Element of the Bulk
Electric System or Facility of the Bulk Electric System. (A
discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is
not a command and is not considered an Operating Instruction.)
A “command” as used in the definition refers to both oral and written commands by operating
personnel. The standard drafting team purposely did not modify the word “command” with
either “oral” or “written” in order to maintain its broader meaning. Instead, in the requirements
of COM-002-4, the standard drafting team has specified “oral” or “written” as needed to define
which types of Operating Instructions are covered by the requirement. The definition also
includes a clarifying note in parentheses that general discussions are not considered Operating
Instructions. This clarification was requested by and supported by industry for inclusion in the
definition itself.
b)
Applicability
In addition to Balancing Authorities, Reliability Coordinators, and Transmission
Operators, proposed COM-002-4 applies to Distribution Providers and Generator Operators.
The standard drafting team added these entities in the Applicability section because they can be
and in many cases are the recipients of Operating Instructions. The standard drafting team
determined that not including these entities would leave a gap in a communications standard that
addresses operating personnel. The addition of Distribution Providers as an applicable entity also
removal of the term would cause concerns. Both teams agreed that the COM-002-4 standard did not need to require
a specific protocol to identify “Reliability Directives” as such and that the definition of “Operating Instruction”
could be used absent the term Reliability Directive in COM-002-4 to set the protocols. This would leave the TOP
and IRO standard drafting teams the flexibility to address the issues surrounding the term “Reliability Directive” in
response to the FERC TOP/IRO NOPR.
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responds to FERC’s directive in Order No. 693 to add them as applicable entities to the
communications standard.
Recognizing that Generator Operators and Distribution Providers typically only receive
Operating Instructions, the standard drafting team proposed that only Requirements R3 and R6
apply to these entities. Under proposed COM-002-4, Distribution Providers and Generator
Operators are required to: (i) train operators prior to receiving an Operating Instruction; and (ii)
use three part communication when receiving an Operating Instruction during an Emergency.
The Measures for the requirements related to these applicable entities show that Distribution
Providers and Generator Operators can demonstrate compliance for use of three-part
communication when receiving an Operating Instruction during an Emergency by providing an
attestation from the issuer of the Operating Instruction (i.e., a voice recording is not required). If
a Distribution Provider or Generator Operator never receives an Operating Instruction, the
requirements in proposed COM-002-4 would not apply. In both Requirements R3 and R6,
qualifying language triggering performance based on the “receipt” of an Operating Instruction is
included. This construct makes certain that appropriate entities are trained and able to use threepart communication for reliability purposes.
c)
Requirements in Proposed COM-002-4
Proposed COM-002-4 has seven requirements that require certain entities to develop
predefined communications protocols for the issuance of Operating Instructions. Each
requirement and its Parts are discussed in detail below along with the technical basis for the
inclusion of the requirement in the proposed Reliability Standard.
Requirement R1
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Requirement R1 requires entities that can both issue and receive Operating Instructions to
have documented communications protocols that include a minimum set of elements, outlined in
Parts 1.1 through 1.6 of the Requirement. Because Operating Instructions affect Facilities and
Elements of the Bulk Electric System, the communication of those Operating Instructions must
be understood by all involved parties, especially when those communications occur between
functional entities. An EPRI study reviewed nearly 400 switching mishaps by electric utilities
and found that roughly 19% of errors (generally classified as loss of load, breach of safety, or
equipment damage) were due to communication failures.47 This was nearly identical to another
study of dispatchers from 18 utilities that found that 18% of the operators’ errors were due to
communication problems.48 The necessary protocols include the use of the English language
unless agreed to otherwise (except for internal operations), protocols for use of a written or oral
single-party to multiple-party burst Operating Instruction, three-part communications (including
a protocol for taking an alternate action if a response is not received or if the Operating
Instruction was not understood by the receiver), specification of instances that require time
identification, and specification of nomenclature for Transmission interface Elements.
Requirement R1 provides consistency among communications protocols and promotes
effective communications, while also allowing flexibility for entities to develop additional
communications protocols based on its own operating environment. The inclusion of the
elements in Parts 1.1 through 1.6 are necessary to improve communications protocols and drive
uniformity.
47
Beare, A., Taylor, J. Field Operation Power Switching Safety, WO2944-10, Electric Power Research
Institute.
48
Bilke, T., Cause and prevention of human error in electric utility operations, Colorado State University,
1998.
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The term “documented communication protocols” in R1 refers to a set of required
protocols specific to the applicable entity and the entities with whom they must communicate.
An entity should include as much detail as it believes necessary in its documented
communication protocols,49 but the documented communication protocols must address all of the
applicable Parts of Requirement R1. Where an entity does not already have a set of documented
communications protocols that meet the Parts of Requirement R1, the entity must develop the
necessary communications protocols. Entities may also adopt the documented protocols of
another entity as its own communications protocols, but the entity must maintain its own set of
documented communications protocols to meet Requirement R1. Each part of Requirement R1
is discussed below:
1.1.
Require its operating personnel that issue and receive an oral or written
Operating Instruction to use the English language, unless agreed to otherwise. An
alternate language may be used for internal operations.
Use of English language has been carried forward from COM-001-1.1, Requirement R4
as an essential protocol. As noted above, retirement of this requirement in COM-001-1.1 was
specifically referred to Project 2007-02. Part 1.1 continues to permit the issuer and receiver to
use an agreed to alternate language. This has been retained since use of an alternate language, on
a case-by-case basis, may serve to better facilitate effective communications where the use of
English language may create additional opportunities for miscommunications. Part 1.1 requires
the use of English language (unless agreed to otherwise) when issuing oral or written50 Operating
49
On September 19, 2012, the NERC Operating Committee issued a Reliability Guideline entitled: “System
Operator Verbal Communications – Current Industry Practices.” As stated on page one, the purpose of the
Reliability Guideline “. . . is to document and share current verbal Bulk Electric System communications practices
and procedures from across the industry that have been found to enhance the effectiveness of system operator
communications programs.” This guideline serves as an additional source of information on best practices that
entities can draw on in creating the documented communications protocols. The guideline is available at:
http://www.nerc.com/comm/OC/Reliability%20Guideline%20DL/Reliability_Guideline_Final_2012.pdf.
50
An example of a written Operating Instruction is a switching order.
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Instructions. This creates a standard language (either English or an agreed upon alternate
language) for use when issuing commands that could change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric System. Part
1.1 also clarifies that an alternate language can be used internally within the organization. The
wording of the Part has been modified slightly from the language in COM-001-1.1, Requirement
R4 to incorporate the term “Operating Instruction,” which defines the communications that
require the use of the documented communications protocols.
1.2. Require its operating personnel that issue an oral two-party, person-to-person
Operating Instruction to take one of the following actions:
•
•
•
Confirm the receiver’s response if the repeated information is correct.
Reissue the Operating Instruction if the repeated information is incorrect, if the
receiver does not issue a response, or if requested by the receiver.
Take an alternative if a response is not received or if the Operating Instruction
was not understood by the receiver.
1.3.
Require the receiver of an oral two-party, person-to-person Operating Instruction
to take one of the following actions:
•
•
Repeat the Operating Instruction and wait for confirmation from the issuer that
the repetition was correct.
Request that the issuer reissue the Operating Instruction.
Part 1.2 requires communications protocols for the use of three-part communications for
oral two-party, person-to-person Operating Instructions by the issuer. Part 1.3 requires
communications protocols for the use of three-part communications for oral two-party, personto-person Operating Instructions by the receiver. This carries forward the requirement to use
three-part communications in COM-002-2 and COM-002-3 and also adds an option in Part 1.2
for the issuer to take an alternative action to resolve the issue if the receiver does not respond or
understand the Operating Instruction. The addition of this third bullet, which is not included in
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COM-002-2, serves to clarify in the requirement language itself that the issuing entity can take
alternate action in lieu of reissuance, if necessary.
Three-part communication reduces the opportunity for confusion and misunderstanding
when issuing and receiving Operating Instructions during all operating conditions. Because
three-part communication is included as a protocol for both non-emergency conditions and
Emergency conditions, there will be no mental “transition” between protocols when operating
conditions shift from non-emergency to Emergency. The documented communication protocols
for the operating personnel will remain the same during transitions through all operating
conditions. Further, the formal requirement for three-part communication in an entity’s
documented communications protocols will create a heightened sense of awareness in operating
personnel that the task they are about to execute is critical, and recognize the risk to the reliable
operation of the Bulk Electric System is increased if the communication is misunderstood.
1.4.
Require its operating personnel that issue a written or oral single-party to
multiple-party burst Operating Instruction to confirm or verify that the Operating
Instruction was received by at least one receiver of the Operating Instruction.
This Part requires specific communications protocols for the issuance of an Operating
Instruction using a one-way burst messaging system. One-way burst messaging systems are used
to issue Operating Instructions to many entities at once. Because the use of three-part
communications is not practical when utilizing this type of communication, a separate protocol
was added to the proposed Reliability Standard. During the Standards Development Process,
many entities expressed concern that if one-way burst messaging systems were not addressed, it
would imply that three part communication would be required for all participants in the burst
message.
1.5. Specify the instances that require time identification when issuing an oral or
written Operating Instruction and the format for that time identification.
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This Part requires entities to identify the instances where time identification is required
when issuing an oral or written Operating Instruction. Clarifying time and time zone (where
necessary) contributes to reducing misunderstandings and reduces the risk of a grave error during
BES operations, especially when communicating across time zones or specifying an action that
will take place at a future time. The Part forces entities to name the instances in the documented
communications protocols themselves if time identification is used. The standard drafting team
chose this method of identification in lieu of requiring time identification to maintain flexibility
for the entity in designing its communications protocols, but also providing clarity in the
documented communications protocols where it is used.
1.6.
Specify the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction.
Similarly to Part 1.5, Part 1.6 does not prescriptively require the use of nomenclature for
Transmission interface Elements and Transmission interface Facilities when issuing an oral or
written Operating Instruction. The standard drafting team opted to require entities to identify the
nomenclature, if it is used. This Part limits the scope to only Transmission interface Elements or
Transmission interface Facilities (e.g., tie lines and tie substations). This ensures that
communicating parties are readily familiar with each other’s interface Elements and Facilities,
eliminating hesitation and confusion when referring to equipment for the Operating Instruction.
This shortens response time and improves situational awareness. It also permits entities to
jointly develop the nomenclature for their interface.
Requirements R2 and R3
Requirement R2 requires each Balancing Authority, Reliability Coordinator, and
Transmission Operator to conduct initial training for each of their operating personnel
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responsible for the Real-time operation of the Bulk Electric System on the entity’s documented
communication protocols.
Requirement R3 requires Distribution Providers and Generator Operators to conduct
initial training on three part communication for each of their operating personnel who can
receive an oral two-party, person-to-person Operating Instruction prior to that individual operator
receiving an oral two-party, person-to-person Operating Instruction. Distribution Providers and
Generator Operators would have to train their operating personnel prior to placing them in a
position to receive an oral two-party, person-to-person Operating Instruction. Operating
Personnel that would never be in a position to receive an oral two-party, person-to-person
Operating Instruction, therefore, would not need initial training unless their circumstance
changes.
Initial training is included in proposed COM-002-4 in response to the NERC Board of
Trustees resolution, which directs that a training requirement be included. Additionally,
requiring entities that issue and or receive Operating Instructions to conduct initial training with
their operating personnel will ensure that all applicable operators will be trained in three-part
communication. This training will reduce the possibility of a miscommunication, which could
eventually lead to action or inaction harmful to the reliability of the Bulk Electric System.
Ongoing training beyond initial training would fall under an entities’ training program in PER005 or could be separately listed as a type of corrective action under Requirement R4. Training
is also mentioned by Commission staff in its Preliminary Assessment as an important aspect to
effective communications.51
Requirement R4
51
Preliminary Assessment at 43 (citing Blackout Report at 161 which provides that lack of situational
awareness can result from, among other things, inadequate operator training).
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Requirement R4 requires Balancing Authorities, Reliability Coordinators, and
Transmission Operators to, at least once every 12 months, assess adherence by its operating
personnel to the documented communication protocols in Requirement R1 and to provide
feedback to its operating personnel on their performance. This also includes any corrective
action taken, as appropriate, to address deviations from the documented protocols. Requirement
R4 also requires the aforementioned entities to assess the effectiveness of their documented
communications protocols and make changes, as necessary, to improve the effectiveness of the
protocols. An entity may determine that corrective action beyond identification of the misuse of
the documented communications protocols to the operating personnel is not necessary, therefore,
the phrase “as appropriate” is included in the Requirement R4 language to indicate that whether
to take additional corrective action is determined by the entity and not dictated by the
Requirement for all instances of a misuse of a documented communication protocol. In almost
all cases found by an entity, NERC expects that an entity will have some form of corrective
action such as ongoing scheduled training.
Most entities currently engage in some type of assessment activity for their operating
personnel and provide operators with performance feedback on their adherence to the entity’s
documented protocols. Doing so, provides entities an opportunity to evaluate the performance of
their operating personnel and take corrective actions where necessary, which could prevent a
miscommunication from occurring and thus possibly prevent an event which could be harmful to
the reliability of the Bulk Electric System.
The associated Measure M4 for Requirement R4 lists the types of evidence that an entity
can provide to demonstrate compliance and explains when an entity should show the corrective
actions taken. Of particular interest is any corrective action taken where the miscommunication
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is the sole or partial cause of an Emergency and the entity has opted to take a corrective action.
While the Measure lists out this particular set of circumstances to highlight the importance, the
Measure does not modify the Requirement to require corrective action.
Requirement R4 is the primary mechanism for implementation of the documented
communication protocols in proposed COM-002-4 for non-emergency conditions. In order to
meet its obligations under Requirement R4, an entity must be actively employing its documented
communications protocols. However, the requirement also extends to assessing the use of
communications protocols during Emergency communications. Specifically, this requirement
compels entities to assess the adherence of its operating personnel to the pre-defined
communication protocols, provide feedback to its operating personnel based on their
performance, and implement corrective action to address deviations from those protocols or
general ineffectiveness where necessary. Requirement R4 also aims to ensure that the
documented protocol remains current and effective to address potential reliability issues that
could be caused by non-inclusion of a communication protocol not otherwise required by
Requirement R1.
The creation of an assessment obligation and a protocol effectiveness review process that
arises at least once every twelve (12) months provides a short evaluation and correction cycle for
entities. By providing feedback to operators on a regular basis, these entities can evaluate
performance and take necessary corrective action in a timely manner. Specification that the
review must occur “at least once every twelve (12) months” also does not preclude entities from
employing processes that provide feedback in an even shorter timeframe or multiple times per
year as part of their process design.
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The language of the requirement clearly and explicitly delineates the obligations and
expectations entities must meet. Requirement R4 requires that each entity maintain a successful
program and measure its own compliance with its documented communications protocols.
Requirement R4 intentionally does not specify a specific type of review to execute or mandate
that corrective actions be taken. Entities are better equipped to design an appropriate program to
meet their own operating environment and determine whether a corrective action is necessary.
Because almost all entities have these types of programs in place today, this approach also
provides an efficient means of establishing an assessment program by building on the programs
currently in use. The primary purpose of Requirement R4 is to provide assurance that an entity
is using its documented communications protocols, engaging its operators, and periodically
reviewing its communications for improvement. The program required in Requirement R4
requires applicable entities to conduct retrospective review of their communications practices
based on predefined documented communications protocols through an assessment design of
their choosing and requires corrective actions be taken if the entity deems a corrective action
necessary. As a result, Requirement R4 contains clear, unambiguous directions regarding the
obligations placed on the entity.
The assessment process embodied in Requirement R4 has also been used in other
Commission-approved NERC Reliability Standards. For example, Commission-approved
Reliability Standard FAC-003-3 requires applicable entities to have in place “documented
maintenance strategies or procedures or processes or specifications it uses to prevent the
encroachment of vegetation into the MVCD of its applicable lines.” Entities are required to
identify “the existence of a vegetation condition that is likely to cause a Fault at any moment,”
and to remedy the problematic conditions. Requirement R5 states “… the applicable
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Transmission Owner or applicable Generator Owner shall take corrective action to ensure
continued vegetation management to prevent encroachments.” This risk-based requirement
obligates applicable entities to create a current “documented maintenance strategy” to prevent
vegetation encroachment, identify certain constraints, assess the possibility of a potential
encroachment based on the documented strategy, and take necessary corrective action to ensure
continued vegetation management.
In addition, Commission-approved Reliability Standard PRC-005-2 requires that
applicable entities “establish a Protection System Maintenance Program (“PSMP”) for its
Protection Systems,” and then implement and follow these PSMPs to achieve ideal intended
performance. Applicable entities should subsequently “demonstrate efforts to correct identified
Unresolved Maintenance Issues”. These standards also require applicable entities to develop a
tailored baseline target for performance and retroactively measure compliance based on
adherence to this predefined standard.
Additionally, Commission-approved Reliability Standard PRC-006-1 requires applicable
entities to document certain criteria regarding the creation of islands and develop an
underfrequency load-shedding (“UFLS”) program to arrest declining frequency, assist recovery
of frequency following underfrequency events, and provide last resort system preservation
measures. The Reliability Standard requires entities to conduct various assessments to determine
conformity with the UFLS program created pursuant to Requirement R3 of that Reliability
Standard. While a corrective action element is not included in the Reliability Standard language
itself, NERC did clarify during regulatory approval, to the satisfaction of the Commission, that
the language of PRC-006-1 anticipated corrective action.
Requirements R5 and R6
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Requirement R5 requires entities that issue oral two-party, person-to-person Operating
Instructions during an Emergency, excluding written or oral single-party to multiple-party burst
Operating Instructions, to use three-part communication or take an alternate action if the receiver
does not respond or if the receiver did not understand the Operating Instruction. The language of
Requirement R5 specifically excludes written or oral single-party to multiple-party burst
Operating Instructions to make clear that three-part communication is not required when issuing
Operating Instructions in this manner. Requirement R5 applies to each Balancing Authority,
Reliability Coordinator, and Transmission Operator since these are the entities that would be in a
position to issue oral two-party, person-to-person Operating Instructions during an Emergency.
Requirement R6 requires entities that receive an oral two-party, person-to-person
Operating Instruction during an Emergency, excluding written or oral single-party to multipleparty burst Operating Instructions, to repeat (not necessarily verbatim) the Operating Instruction
and receive confirmation from the issuer that the response was correct, or request that the issuer
reissue the Operating Instruction. Requirement R6 includes the same clarifying language as
Requirement R5 for the exclusion of single-party to multiple-party burst Operating Instructions.
Requirement R6 applies to each Balancing Authority, Distribution Provider, Generator Operator,
and Transmission Operator since these are the entities that would be in a position to receive oral
two-party, person-to-person Operating Instructions during an Emergency.
The use of three-part communication when issuing and receiving Operating Instructions
is always important because a miscommunication could create an Emergency. However, the use
of three-part communication is critically important if an Emergency condition already exists, as
further action or inaction could increase the harmful effects to the Bulk Electric System. Clear
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communication is essential to providing swift and coordinated response to events that are
directly impacting the reliability of the Bulk Electric System.
Requirement R7
Requirement R7 requires that when a Balancing Authority, Reliability Coordinator, or
Transmission Operator issues a written or oral single-party to multiple-party burst Operating
Instruction during an Emergency, it must confirm or verify that at least one receiver of the
Operating Instruction received the Operating Instruction. Because written or oral single-party to
multiple-party burst Operating Instruction during an Emergency are excluded from Requirements
R5 and R6, this separate Requirement is necessary to specify the performance an entity must
meet to demonstrate clear communication for the use of written or oral single-party to multipleparty burst Operating Instructions during an Emergency. This prevents a gap in the means used
to issue an Operating Instruction during an Emergency. This requirement is necessary because
without confirmation from at least one receiver, the issuer has no way of confirming if the
Operating Instruction was transmitted and received by any of the recipients. Therefore, the
issuer cannot know whether to resend the Operating Instruction, wait for the recipient to take an
action, or take an alternate action because the recipient cannot perform the action. As a best
practice, an entity can opt to confirm receipt from more than one recipient, which is why the
requirement states “at least one.”
4.
Improvements Reflected in COM-002-4
Proposed COM-002-4 includes a number of improvements over the currently effective
Reliability Standard COM-002-2. These include: (i) removing the ambiguity surrounding the
meaning of “directive” in COM-002-2; (ii) specifying specific minimum protocols that must be
included and used by all applicable entities; (iii) mandating initial training for operating
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personnel; and (iv) adding a process for entities to assess adherence to the documented
communication protocols and take corrective action.
First, proposed COM-002-4 replaces the term “directive” in COM-002-2 with a new
defined term “Operating Instruction.” Use of the defined term clarifies the types of commands
covered by the proposed Reliability Standard, which now includes all commends “by operating
personnel responsible for the Real-time operation of the interconnected Bulk Electric System to
change or preserve the state, status, output, or input of an Element of the Bulk Electric System or
Facility of the Bulk Electric System.” It was not clear whether the term “directive” referred to
either non-emergency and emergency directives, or just emergency directives. This ambiguity
was the subject of the interpretation request to COM-002-2 adopted by the Board of Trustees in
2012.52
Second, proposed COM-002-4 adds additional mandatory communications protocols in
Requirement R1 beyond the use of three-part communication covered by COM-002-2 and the
use of English language found in COM-001-1.1, Requirement R4. The proposed Reliability
Standard adds protocols for: the issuance of a written or oral single-party to multiple-party burst
Operating Instruction; specification of the instances that require time identification when issuing
an oral or written Operating Instruction and the format for that time identification; and
52
On October 1, 2009, a clarification was requested by the ISO-RTO Council of Requirement R2 of COM002-2, specifically asking whether “directives” are limited to actions requested during actual and anticipated
emergency operating conditions, or whether routine operating instructions are also considered “directives.” The
interpretation of Reliability Standard COM-002-2, approved by the NERC Board of Trustees on February 9, 2012,
clarifies that COM-002-2 R2 does not specify the conditions under which a directive is issued, nor does it define
directive. It only provides that the requirements be followed when a directive is issued to address a real-time
emergency. Routine operating instructions during normal operations would not require the communications
protocols for repeat backs as specified in R2. The NERC Board of Trustees rescinded approval of the interpretation
in conjunction with its adoption and successful implementation of proposed COM-002-4 since the proposed
Reliability Standard no longer uses the lower case term “directive.” See Agenda Item 8c of the May 7, 2014 Board
of Trustees Meeting, available at
http://www.nerc.com/gov/bot/Agenda%20highlights%20and%20Mintues%202013/board_agenda_package_May_20
14.pdf.
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specification of the nomenclature for Transmission interface Elements and Transmission
interface Facilities when issuing an oral or written Operating Instruction. Proposed COM-002-4
also includes specific communications protocols for the entity receiving an Operating
Instruction, which is not present in COM-002-2. COM-002-2, by contrast, places the
responsibility for ensuring proper three-part communication on the issuing entity only.
Third, for the first time, the COM-002 Reliability Standard will include requirements to
provide initial training to operating personnel who issue and receive Operating Instructions.
While many entities reported during the Standards Development Process that they already
conduct training of their operating personnel, the inclusion of these requirements codifies the
expectation that all operating personnel be trained on the documented communications protocols
prior to being placed in a position to issue or receive an Operating Instruction. As FERC staff
noted in its Preliminary Assessment and as reflected in the Blackout Report, lack of situational
awareness can result from, among other things, inadequate operator training.53
Finally, the proposed COM-002-4 Reliability Standard adds a requirement for entities to
assess adherence to the documented communication protocols and take corrective action. This
aspect of the proposed Reliability Standard codifies good operating practice to review operator
communications and provide feedback to the operating personnel. The requirement will also
require entities to assess the effectiveness of their documented communications protocols and
determine if additional protocols should be specified based on the observed use of the protocols
in its operating environment. Such a requirement is not present in the prior version of the COM002 Reliability Standard.
5.
53
Proposed COM-002-4 Satisfies the Commission’s Directives
See Preliminary Assessment at 43 (citing Blackout Report at 161).
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In Order Nos. 693, the Commission issued directives to NERC to modify certain aspects
of COM-002-2. Exhibit J of this Petition provides a list of the directives and an explanation of
the standard drafting team’s consideration of each directive. In short, the Commission directed
NERC to include Distribution Providers as an applicable entity in the Reliability Standard. The
Commission stated, “during both normal and emergency operations, it is essential that the
transmission operator, balancing authority and reliability coordinator have communications with
distribution providers.”
Second, the Commission directed NERC to include a requirement for the Reliability
Coordinator to assess and approve actions that have impacts beyond the area views of
transmission operators or balancing authorities, including how to determine whether an action
needs to be assessed by the reliability coordinator. This directive was addressed outside of the
revisions to COM-002-2. It was addressed by modifications to IRO-005 and has been reassigned
to Project 2014-03.
Third, the Commission directed NERC to either modify the COM-002-2 Reliability
Standard to require “tightened communications protocols, especially for communications during
alerts and emergencies” or develop a new Reliability Standard to meet Blackout Report
Recommendation No. 26. The following is a discussion of the outstanding directives addressed
by proposed COM-002-4:
Addition of Distribution Providers (Order No. 693, P 512 and 540 (Part 1)): As noted
above in the discussion of Requirements R3 and R6 and the Applicability section, Distribution
Providers have been added to the coverage of proposed COM-002-4. Coverage within the
requirements has been limited to their position as “receivers” of Operating Instructions.
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Tightened Communication Protocols (Order No. 693, P 531, 534, 535, 540 (Part 3)):
Proposed COM-002-4 satisfies the Commission’s directive regarding establishing “tightened
communication protocols” through the various improvements listed in the section above.
Proposed COM-002-4 improves communications protocols for the issuance of Operating
Instructions in order to reduce the possibility of miscommunication that could lead to action or
inaction harmful to the reliability of the Bulk Electric System. The proposed Reliability Standard
adds clarity to the scope of covered commands with the use of the new defined term “Operating
Instruction. Proposed COM-002-4 also includes additional mandatory protocols that establish
communication uniformity as much as practical on a continent-wide basis, while still
maintaining flexibility for entities to employ additional protocols based on its own operating
environment. The proposed Reliability Standard also “tightens communications protocols” by
employing clear, zero-tolerance approaches for miscommunications of Operating Instructions
issued during Emergencies and by mandating an assessment process aimed at reducing the
number of repeat misuses of communication protocols by operating personnel.
C.
Enforceability of Proposed Reliability Standards
The proposed Reliability Standards, COM-001-2 and COM-002-4 include Measures that
support each requirement to help ensure that the requirements will be enforced in a clear,
consistent, non-preferential manner and without prejudice to any party. The proposed Reliability
Standards also include VRFs and VSLs for each requirement. The VRFs and VSLs for the
proposed Reliability Standards comport with NERC and Commission guidelines related to their
assignment. A detailed analysis of the assignment of VRFs, the VSLs for proposed COM-001-2
and COM-002-4 are included as Exhibit K and Exhibit L.
VI.
CONCLUSION
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For the reasons set forth above, NERC respectfully requests that the Commission:
•
approve the proposed Reliability Standards and other associated elements included in
Exhibits A and B;
•
the new definitions, as noted herein;
•
the VRFs and VSLs (Exhibits A, B, K, and L);
•
approve the Implementation Plans included in Exhibits C and D; and
•
approve the retirement of the currently effective Reliability Standards COM-001-1.1,
EOP-008-1 (Requirement R1), and COM-002-2, as proposed in the Implementation
Plans.
Respectfully submitted,
/s/ William H. Edwards
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
William H. Edwards
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation
Date: May 14, 2014
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CERTIFICATE OF SERVICE
I hereby certify that I have served a copy of the foregoing document upon all parties
listed on the official service list compiled by the Secretary in the RM06-16-000 proceeding.
Dated at Washington, D.C. this 14th day of May, 2014.
/s/ William H. Edwards
William H. Edwards
Counsel for North American Electric
Reliability Corporation
20140514-5129 FERC PDF (Unofficial) 5/14/2014 9:32:53 AM
Document Content(s)
Exhibit A.PDF.........................................................1-27
Exhibit B.PDF.........................................................28-57
Exhibit C.PDF.........................................................58-71
Exhibit D.PDF.........................................................72-74
Exhibit E.PDF.........................................................75-84
Exhibit F.PDF.........................................................85-95
Exhibit G.PDF.........................................................96-106
Exhibit H.PDF.........................................................107-119
Exhibit I.PDF.........................................................120-128
Exhibit J.PDF.........................................................129-136
Exhibit K.PDF.........................................................137-180
Exhibit L.PDF.........................................................181-228
Exhibit M.PDF.........................................................229-2200
Exhibit
PDF.........................................................2201-4907
Exhibit
PDF.........................................................4908-4936
Exhibit
PDF.........................................................4937-4939
Exhibit
PDF.........................................................4940-4951
COM Petition
nal.PDF................................................4952-5000
| File Type | application/pdf |
| Author | Courtney Baughan |
| File Modified | 2018-07-05 |
| File Created | 2014-05-14 |